ML20237D606

Forwards Draft SE Accepting Request to Increase Max Thermal Power from 2,558 Mwt to 2,763 Mwt,About 8 Percent Increase

ML20237D606
Person / Time
Site:	Hatch
Issue date:	08/21/1998
From:	Olshan L NRC (Affiliation Not Assigned)
To:	Summer H GEORGIA POWER CO.
References
TAC-M99393, TAC-M99394, NUDOCS 9808270031
Download: ML20237D606 (73)

Text

______- -_- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

o-Mr. H. L. Sumn:r, Jr. August 21, 1998 Vice Pr:sid:nt - Nucl:ar Hitch Proj:ct Southern Nuclear Generating Company, Inc.

Post Office Box 1295 Birmingham, Alabama 35201-1295

SUBJECT:

DRAFT SAFETY EVALUATION IN SUPPORT OF EXTENDED POWER UPRATE FOR EDWIN 1. HATCH NUCLEAR PLANT, UNITS 1 AND 2 (TAC NOS. M99393 AND M99394)

Dear Mr. Sumner:

By Encl|letter dated August 8,1997]], supplemented by letters dated March 9, May 6, July 6, and l July 31,1998, Southern Nuclear Operating Company (SNC) submitted an application for

)

amendments to License Nos. DPR-57 and NFP-5 for Edwin I. Hatch Nuclear Plant, Units 1 j and 2. Advance information was provided by letter dated April 17,1997. The application requested an increase in the maximum thermal power from 2558 Megawatts thermal (MWt) to 2763 MWt, which is about an 8 percent increase.

Enclosed is a draft of the safety evaluation (SE) that the staff has prepared to support the )

amendment request. A copy of this draft SE is also being sent to the Advisory Committee on Reactor Safeguards in preparation for its August 27,1998, subcommittee meeting, which is being held to discuss the application.

Please provide any comments that you may have on the enclosed draft SE by September 20, 1998. The target date for your response has been agreed upon by Tim Long of your staff. '

Should a situation occur which prevents you from meeting the date, please contact me at 301-415-1419.

Sincerely, j k rIbsbnhroject Manager

Project Directorate 11-2

$8200 DOC 321 PDR Division of Reactor Projects - t/II P Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366 Et closure: As stated

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%*****p#p August 21, 1998 Mr. H. L. Sumner, Jr.

Vice President - Nuclear Hatch Project Southem Nuclear Generating Company, Inc. .

Post Office Box 1295 Birmingham, A!abama 35201-1295 f'

SUBJECT:

DRAFT SAFETY EVALUATION IN SUPPORT OF EXTENDED POWER UPRATE FOR EDWIN 1. HATCH NUCLEAR PLANT, UNITS 1 AND 2 (TAC NOS. M99393 AND M99394)

Dear Mr. Sumner:

By Encl|letter dated August 8,1997]], supplemented by letters dated March 9, May 6, July 6, and July 31,1998, Southem Nuclear Operating Company (SNC) submitted an application for amendments to License Nos. DPR-57 and NFP-5 for Edwin 1. Hatch Nuclear Plant, Units 1 and 2. Advance information was provided by letter dated April 17,1997. The application requested an increase in the maximum thermal power from 2558 Megawatts thermal (MWt) to 2763 MWt, which is about an 8 percent increase.

Enclo' sed is a draft of the safety evaluation (SE) that the staff has prepared to support the amendment request. A copy of this draft SE is also being sent to the Advisory Committee on Reactor Safeguards in preparation for its August 27,1998, subcommittee meeting, which is being held to discuss the application.

Please provide any comments that you may have on the enclosed draft SE by September 20, 1998. The target date for your response has been agreed upon by Tim Long cf your staff.

Should a situation occur which prevents you from meeting the date, please contact me at 301-415-1419.

Sincere b

Leonard N. Olshan, Project Manager Project Directorate 11-2 Division of Reactor Projects - 1/II Office of Nuclear Reactor Regulation Docket Nos. 50-321 and 50-366

Enclosure:

As stated cc w/o encl: See next page i

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Edwin 1. Hatch Nuclear Plant cc:

Mr. Emest L. Blake, Jr. Charles A. Patrizia, Esquire Shaw, Pittman, Potts Paul, Hastings, Jaqofsky & Walker and Trowbridge 10th Floor 2300 N Street, NW. 1299 Pr.insylvania Avenue Washington, DC 20037 Washington, DC 20004-9500 Mr. D. M. Crowe Chairman l

Manager, Licensing Appling County Commissioners {

Southem Nuclear Operating County Courthouse Company, Inc.

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Baxley, Georgia 31513 l P. O. Box 1295 i Birmingham, Alabama 35201-1295 Mr. J. D. Woodard Executive Vice President l Resident inspector Southem Nuclear Operating Plant Hatch Company, Inc.

l 11030 Hatch Parkway N. P. O. Box 1295 1

( Baxley, Georgia 31531 Birmingham, Alabama 35201-1295

]

Regional Administrator, Region ll Mr. P. W. Wells l U.S. Nuclear Regulatory Commission General Manager, Edwin 1. Hatch l Atlanta Federal Center Nuclear Plant l 61 Forsyth Street, SW, Suite 23T85 Southem Nuclear Operating Atlanta, Georgia 30303 Company, Inc.

U.S. Highway 1 North  !

Mr. Charles H. Badger P. O. Box 2010 Office of Planning and Budget Baxley, Georgia 31515 Room 610

, 270 Washington Street, SW. Mr. R. D. Barker l l Atlanta, Georgia 30334 Program Manager Fossil & Nuclear Operations j Harold Reheis, Director Oglethorpe Power Corporation I Department of Natural Resources 2100 East Exchange Place i 205 Butler Street, SE., Suite 1252 P. O. Box 1349 Atlanta, Georgia 30334 Tucker, Georgia 30085-1349

Steven M. Jackson Senior Engineer- Power Supply Municipal Electric Authority of Georgia 1470 Riveredge Parkway, NW ,

Atlanta,~ Georgia 303284684 j l -

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p t UNITED STATES g j NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. Saama anat

..... D R A F T SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. TO FACILITY OPERATING LICENSE DPR-57 AND AMENDMENT NO. TO FACILITY OPERATING UCENSE NPF-5 SOUTHERN NUCLEAR OPERATING COMPANY. INC.. ET AL.

EDWIN 1. HATCH NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366 1.0 OVERVIEW 1.1 Introduction By Encl|letter dated August 8,1997]] (Reference 1), as supplemented March 9,1998, (Reference 2, May 6,1998 (Reference 3), July 6,1998 (Reference 4) and July 31,1998 (Reference 5),

Southern Nuclear Operating Company, Inc. (Southern Nuclear, the licensee), et al., proposed license amendments to change Facility Operating License Nos. DPR-57 and NPF-5 for the Edwin 1. Hatch Nuclear Plant, Units 1 and 2. Advance information was provided by letter dated April 17,1997 (Reference 6). The proposed changes would increase the maximum licensed thermal power level by 8 percent, from the current limit of 2558 megawatts thermal (MWt) to 2763 MWt. The amendment would also approve changes to the technical specifications appended to the operating licenses to implement uprated power operation.

The letters dated March 9, May 6, July 6,1998, and July 31,1998, provided clarifying information that was withiln the scope of the original Federal Register notice and did not change the staff's initial proposed no significant hazards consideration determination.

1.2 Background

Hatch Units 1 and 2 are currently licensed to operate at a maximum reactor power level of 2558 MWt . The licensee, in conjunction with General Electric Company (GE), undertook a program to uprate the maximum reactor power level by 8 percent to 2763 MWt.

The licensee's plant-specific engineering evaluations supporting the power uprate were performed in accordance with guidance contained in the GE licensing topical report (LTR)

NEDC-32424P, " Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate," dated February 1995 (Reference 7). This topical report was previously reviewed and endorsed by the staffin a staff position paper dated February 8,1996, l

(Reference 8). Generic evaluations performed to support the power uprate are addressed in GENE LTR NEDC-32523P, " Generic Evaluations for General Electric Boiling Water Reactors Extended Power Uprate"(Reference 9). The staff has reviewed NEDC-32523P concurrently i

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with the power uprate amendment request submitted for the Monticello Nuclear Generating l Plant and the staff safety evaluation was issued on August ,1998 (Reference 10)

The licensee's submittal was reviewed with consideration given to the recommendations from the Report of the Maine Yankee Lessons Leamed Task Group. This report is documented in SECY-97-042, " Response to OlG Event Inquiry 96-04S Regarding Maine Yankee," dated February 18,1997 (Reference 11). The Task Group's main findings centered around the use i and applicability of the computer codes and analytical methodologies used for power uprate evaluations, The Task Group also recommended that a standard review procedure for power uprate be developed to ensure that all appropriate review areas are addressed. For the BWR extended power uprate program, the staff had previously established review criteria and acceptable computer codes and analytical methodologies used for power uprate evaluations.

In light of the Task Group's recommendations, the staff has expandedthe review criteria to include areas such as human factors and offsite power stability. As a result, the staff concludes that the Maine Yankee Lessons Learned recommendations were appropriately considered in the review of the Hatch power uprate request.

[ 1.3 Approach The proposed power uprate is accomplished by extending the power-flow map within (approximately) equivalent rod and core flow control lines. The proposed rod and flow control l line for the 13 percent power increase corresponds to the 120 percent rod and flow control line relative to the original licensed power of 2436 MWt and approximately 115 percent rod and flow controlling relative to the 5 percent increase power of 2558 MWt. The licensee also stated that the proposed rod and flow control line is consistent to the maximum extended load line limit analysis (MELLLA) rod and flow control line of the original licensed power and that with the extended power uprate, the highest analyzed rod and flow control line will be no higher than that of a BWR/4 MELLLA plant at the original licensed power.

The planned approach to achieve the higher power level consists of: (1) an increase in the core thermal power with a more uniform (flatter) power distribution to create an increased steam flow, (2) a corresponding increase in feedwater flow, (3) no increase in maximum core flow, (4) no increase in reactor operating pressure relative to the 5 percent power uprate, and (5) reactor operation primarily along equivalent rod and flow control lines.

SNC proposed to achieve the power uprate by supplying the higher steam flow to the turbine generator. The licensee had modified the high pressure turbine to accommodate the higher steam supply. SNC also states that improvements in the analytical techniques (i.e. computer codes and data) for several decades of BWR safety technology, plant performance feedback, and improved fuel and core design have resulted in'an significant increase in the margin

. between the calculated safety analysis and the licensing limits. Thus, increase in the safety analysis margin, combined with the excess capability in the as-designed equipments, systems and components, provide the potential to institute higher operating power without major upgrade or modification of the nuclear steam supply system (NSSS) and balance of plant (BOP) hardware.

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2.0 EVALUATION OF SYSTEMS. STRUCTURES AND COMPONENTS i I

The staff's review of the Hatch power uprate amendment request used applicable rules, regulatory guides, Standard Review Plan (SRP) sections, and NRC staff positions regarding the l topics being evaluated. Additionally, the submittal was evaluated for compliance with the j generic BWR power uprate program. Detailed discussions of individual review topics follow.

2.1 Reactor Core and Fuel Performance i 2.1.a Fuel Design and Operation

! I l The licensee stated that a new fuel design is not needed to achieve the extended power uprate.

, However, SNC may employ revised loading pattems, larger batch sizes, and potentially new fuel designs in order to attain additional operating flexibility and to maintain fuel cycle length.

The licensee will continue to meet all fuel and core design limits through planne'd use of fuel

[ enrichment, and b.umable poison, supplemented by control rod pattem and core flow adjustment. The proposed extended power uprate will increase the core power density, and will have some effects on operating flexibility, reactivity characteristics, and energy requirements.

These issues are discussed in the following sections.

2.1.b Thermal Limits Assessment The licensee selected Cycle 14, or reload 13 of Hatch Unit 2 core as a representative core for l the power uprate evaluation. SNC performed anticipated operational occurrence (AOO) transient analyses at the proposed extended power level of 2763 MWt. The licensee determined the most limiting AOO transient event and established the corresponding operating

. limit minimum critical power ratio (OLMCPR) required to assure the regulatory and safety limits f

are not exceeded for a range of postulated transient events. However, the licensee assumed a safety limit minimum critical power ratio (SLMCPR) of 1.12, which was calculated based on Unit 2 reload 13 core.

SNC proposes that the cycle specific operating and safely limit MCPR be calculated during l each reload based on the actual core configuration. In addition, the licensee as part of the i upcoming Cycle 15 reload analysis performed a cycle-specific SLMCPR analysis based on the extended power uprate using staff approved methods stated in the GESTR reference document

( NEDO-24011P-A). The results indicated that the SLMCPR of 1.12 assumed in the uprate

[- analysis was conservative by a value of 0.01. SNC concluded that the SLMCPR evaluation at the extended power, while not based on the actual core at the uprated power, was

_ representative of the cycle -specific reload licensing calculation and the thermal margin design limits will be maintained. Where extended power uprate results in a greater number of bundles operating near the limit, the SLMCPR may be increased to provide the same statistical confidence level that the rods will avoid boiling transition. Transient events will continue to be evaluated against this SLMCPR, using NRC approved procedures, when establishing the operating limit MCPR.

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The licensee performed AOO transient analyses to determine the changes in the MCPR for the postulated transient events based on the assumed SLMCPR of 1.12. The operating limits assure that the safety limits are not exceeded in the event of the limiting postulated transients.

Thermallimit such as the average planar linear heat generation rates (APLHGR) ensure that the design margin for the peak cladding temperature limits for the limiting loss-of coolant analysis (LOCA) and fuel mechanical design basis are maintained.

SNC, in Reference 2, confirmed that the SLMCPR assumed at the uprated power was conservative. Furthermore, the licensee will perform cycle-specific fuel thermal-mechanical limit evaluations based on actual extended power core configuration during the reload analysis.

2.1.c Reactivity Characteristics All minimum shutdown margin requirements that apply to cold (212 deg.F or less) conditions, ,

will be maintained without change. Operation at higher power could reduce the excess reactivity during the cycle. This loss of reactivity is not expected to significantly degrade the ability to manage the power distribution through the cycle to achieve the rerated power level. The lower reactivity will result in an earlier all-rods-out condition. Any reduction in operational shutdown margins may need to be accommodated through core design. The technical specification I requirements for shutdown margin will continue to be met.

1 Power / Flow Operating Map l The extended power / flow operating map includes the operating domain changes for the extended power. SNC stated Hatch was licensed with extended load line limit analysis (ELLLA) before and after the original power uprate. The rod line for an ELLLA plant is approximately 108 percent of the original power and the rod line maximum ELLLA, or MELLLA, is 120 percent of the original power.

Currently, Hatch is analyzed to operate with core flow between 87 percent to 105 percent core flow at 2558 MWt. The 87 percent core flow is consistent with ELLLA and corresponds to approximately the 108 percent rod (flow control) line. For the proposed extended power, the l operating range for core flow will be 91 percent to 105 percent. The proposed rod line for the extended power uprate corresponds to the 120 percent rod line relative to the original licensed power and 115 percent rod line relative to the current 2558 MWt.

l The submittal contained the proposed power flow map which indicates the initial licensed l

power, the 100 percent power stretch operating line, as well as the proposed operating line. 1 According to the licensee, the proposed 91 percent to 105 percent core flow rate will be achieved with the 13 percent power uprate. SNC concluded that all safety analyses for the extended power uprate were performed considering the proposed power-to-flow map.-

2.1.d Stability Unit 2 installed digital power range neutron monitor (PRNM) system with an oscillating power l range monitor (OPRM) and Hatch Unit 1 will install a similar system in Fall of 1998. Currently,

the OPRM for Unit 2 is set to ALARM mode, while the algorithm which are used to detect, suppress and limit cycle oscillations are being validated to the Hatch conditions. However, SNC stated it will arm the OPRM prior to implementing the extended power uprate for Units 1 and 2.

According to SNC, operation at uprated power will not effect the ability of this detect- and suppress OPRM system to mitigate a stability event. The Option ill solution combines closely

l. spaced local power range monitor (LPRM) detectors into cells to effectively detect a core-wide

[ or regional oscillation. Moreover, the licensing methodology used to determine the Option lli setpoints is intended to provide adequate protection for the SLMCPR and the methodology is independent of reactor power. For extended power uprate, the power set point is re-scaled to maintain the same absolute power at the boundary of the enabled (armed) region, but the percent core flow boundary remains unchanged.

2.1.e Reactivity Control 1

The control rod drive (CRD) system controls gross changes in core reactivity by positioning i neutron absorbing control rods within the reactor it is also required to scram the reactor by l rapidly inserting withdrawn rods into the core. The CRD system was evaluated at the uprated l steam flow and dome pressure of 1035 psig with additional 40 psid for the bottom head location. The extended power uprate does not increase the reactor dome pressure in reference to the initial 5 percent power uprate because the high pressure turbine was modified to accommodate the higher steam flow for the extended power uprate.

The structural and functionalintegrity of the CRD mechanism has been designed in

, accordance with the ASME Boiler and Pressure Vessel Code, Section Ill. The design pressure i of the CRD mechanism corresponds to bottom head pressure of 1250 psig during normal l operation and 1375 psig (110 percent) for upset condition. The over pressure transient analysis for the extended power uprate resulted with a bottom head pressure of 1347 psig which remains below the 110 percent ASME Code allowable peak pressure.

l CRD insertion and withdrawal require a minimum pressure differential of 250 psid between the hydraulic control unit (HCU) and the bottom head pressure. During the original 5 percent power uprate analysis, the CRD pumps were evaluated against this requirement and were found to have sufficient capacity. SNC stated that since the implementation of the 5 percent uprate, no visible difference in the CRD system operation occurred. Based on the fact that the dome pressure will not be increased in the current extended power uprate, the CRD mechanism is

, expected to function with no change in performance. The licensee will continue to monitor,

( through various plant TS surveillance requirements, the scram time performance to ensure that the original licensing bases for the CRD system are maintained. This approach is consistent with that proposed by GE in the generic references.

i 2.2 Reactor Coolant System 2.2.a Nuclear System Pressure Relief

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l The nuclear boiler pressure relief system prevents over pressurization of the nuclear system l during abnormal operating transients. The plant safety / relief valves (SRVs) with reactor scram j I provide this protection. j l The operating steam dome pressure is selected to achieve good control characteristics for the l turbine control valves (TCVs) at the higher steam flow condition corresponding to uprated

power. The appropriate SRV set points also ensures that adequate differences between operating pressure and set points are maintained (i.e., the " simmer margin"), and that any l increase in steam dome pressure does not result in an increase in unnecessary SRV actuation.

L j The SRV set points were reevaluated to ensure that the ASME mechanical limits and the I simmer margin are maintained. The licensee does not intend to increase the operating I

[ pressure to achieve the power uprate; therefore, the SRV flow rates and setpoints are acceptable.

l 2.2.b Code Overpressure Protection The results of the over pressure protection analysis are contained in each cycle-specific reload amendment submittal. The design pressure of the reactor pressure vessel (RPV) remains at

1250 psig. The ASME code allowable peak pressure for the reactor vessel is 1375 psig (110 l

percent of the design value), which is the acceptance limit for pressurization events. The limiting pressurization event for Hatch is an main steamline isolation valve (MSIV) closure with

( .a failure of the valve position scram. As part of the extended power uprate over pressure analysis, turbine trip with bypass failure and neutron flux scram was also evaluated and found to be less limiting than the MSIV closure with the failure of direct scram. The MSIV closure was analyzed by the licensee using the NRC approved methods (ODYN), with the following f exceptions: (1) the MSIV closure event be analyzed at 102 percent of the uprated core power and 105 percent of rated steam flow; (2) the maximum initial reactor dome pressure was assumed to be 1058 psig, which is higher than the nominal uprated pressure (1035 psig); and (3) one SRV was assumed to be out of service for consistency with previous analyses. The i SRVs have an assumed opening tolerance of 3 percent above the normal set points. The peak dome pressure for the extended power uprate increases to 1325 psig and the corresponding bottom head pressure is 1347 osig, which are below the allowable peak pressure of 1375 psig.

l-2.2.c Reactor Recirculation System Power uprate will be accomplished by operating along extensions of rod lines on the power / flow l map with no increase in maximum core flow. The cycle-specific core reload analyses will be performed with the most conservative core flow. The evaluation by the licensee of the reactor ,

recirculation system performance at uprated power determined that the core flow can be maintained with no increase in pump speed. The Hatch units are also licensed for increased core flow (ICF) of 105 percent at 100 percent of current power (2436 MWt). Tim licensed core i

flow is not being increased under the extended power uprate. The licensee estimates that the required pump head and pump flow at the uprate condition will increase the power demand of the recirculation motors and the pump NPSH but, these increases are within the capability of the equipment. J l

The cavitation protection interlock will remain the same, since it is based on the feedwater flow rate. These interlocks are based on subcooling in the extemal recirculation loop and thus are a function of absolute thermal power. With power uprate, slightly more subcooling occurs due to the higher feedwater flow; therefore, the cavitation interlock can be maintained.

The licensee evaluated the net positive suction head (NPSH) and stated that at full power, the power uprate does not increase the NPSH significantly nor does it reduce the NPSH margin.

The reactor operating pressure will not be increased in reference to the current 5 percent power ,

uprate.

1 The recirculation drive flow stops were reviewed by the licensee for application to uprated power conditions. Since power uprate has such a small effect on the required flow rate, the drive flow limiter continues to have adequate input and output range with the capability for low and high limit set points.

The licensee concluded that uprated power operation is within the capability of the recirculation system. The licensee reviewed the characteristic pump curves and confirmed the new operating range would be within the pump design operating range.

2.2.d Main Steam isolation Valves (MSIVs)

The MSIVs are required to operate within the Technical Specifications (TS) specified limits at all design and operating conditions upon receipt of a closure signal. The licensee evaluated the MSIVs and concluded that the uprated power conditions do not effect the structural integrity of l the MSIVs or the safety function of the valves. The licensee stated that the closure function and closure timing of the MSIVs would not be effected by the power uprate. The Hatch units' {

evaluation results are consistent with the bases and conclusions of the generic evaluation in j Section 4.7 of Reference 9.

Pe:Tormance will be monitored by surveillance requirements in the TS to ensure that the original j licensing basis for the MSIV's are preserved. The licensee stated that the existing design pressure and temperature bounds the normal operating conditions and review of the over pressure analysis also confirms that the peak pressures remain bounded by the MSIV's design capability.

2.2.e Reactor Core Isolation Cooling System (RCIC) l l

The RCIC provides core cooling when the reactor pressure vessel (RPV) is isolated from the main condenser, and the RPV pressure is greater than the maximum allowable for initiation of a )

low pressure core cooling system. The submittal stated that the recommendations of GE Safety information Letter (SIL) No. 377 have been implemented on the RCIC system. This l modification is intended to achieve the turbine speed control / system reliability desired by (

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Sll 377, and is consistent with the requirements in the staff safety evaluation (SE) of the generic topical report. The purpose of the modification is to mitigate the concem that a slightly higher steam flow rate at the RCIC turbine inlet will challenge the system trip functions such as turbino over speed, high steam flow isolation, low pump suction pressure and high turbine exhaust pressure.

The staff requires that the licensee provide assurance that the RCIC system will be capable of injecting its design flow rates at the higher reactor operating pressures associated with extended power uprate. Additionally, the licensee must also provide assurance that the reliability of this system will not be decreased by the higher loads placed on the system or because of any modifications made to the system to compensate for these increased loads.

In the previous 5 percent power uprate, the licensee evaluated the RCIC system performance for a pressure of 1195 psig, which is the SRV upper set point. For the current extended power uprate, the licensee stated the SRV set point or the RCIC actuation RX pressure would not change and the calculated minimum RCIC injection rate will remain at 400 gpm. The system has also been evaluated for loss of feedwater transient events. The RCIC reliability will be monitored under the Maintenance Rule. The RCIC system evaluation .is consistent with the bases and conclusions of the generic evaluation. I 2.2.f Residual Heat Removal System (RHR) l The RHR is designed to restore and maintain the coolant inventory in the reactor vessel and to I provide primary system decay heat removal following reactor shutdown for both normal and post-accident conditions. The RHR system is designed to operate in the low pressure coolant injection (LPCI) mode, shutdown cooling mode, suppression pool cooling mode, and containment spray cooling mode. The effects of power uprate on these operating modes are discussed in the following paragraphs.

2.2.g Shutdown The operational objective for normal shutdown is to reduce the bulk reactor temperature to 125 degrees F in approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, using two RHR loops. The licensee stated that actual operating experience shows that the actual time is 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. At the uprated power level the decay heat is increased proportionally, thus it will require more time to reach the shutdown temperature. Shutdown cooling calculations performed by the licensee showed that the reactor coolant will reach 125 'F in 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. Therefore, the shutdown cooling will take additional four hours in the extended power uprate operation.

The licensee also evaluated the shutdown cooling mode's system capability for the extended power uprate with one RHR system in service and with 95' F RHR service water temperature.

The results of the analysis showed that the reactor could be cooled to 212' F in less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This evaluation meets the draft Regulatory Guide 1,139 recommendation (212 degrees F reactor fluid temperature) with 1 RHR out of service.

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9 2.2.h Suppression Pool Cooling and Containment Spray Modes The Suppression Pool Cooling (SPC) and Containment Spray (CS) modes are designed to  ;

provide sufficient cooling to maintain the containment and suppression pool temperatures and pressures within design limits during normal operation and after a blowdown in the event of a design basis LOCA.

2.2.1 Fuel Pool Cooling Assist Mode During normal plant shutdown, with the vessel head removed, the RHR system can be aligned to assist the fuel pool cooling and cleanup (FPCC) system to maintain the fuel pool temperature within acceptable limits. The analysis in section 6.3 of the licensee submittalindicates that the fuel pool temperature will remain within limits under power uprate conditions, and therefore the capability of the fuel pool cooling assist mode is acceptable for power uprate.

2.2.] Reactor Water Cleanup (RWCU) System The RWCU system removes solid and designed impurities from recirculated reactor coolant, thus reducing the concentration of radioactive and corrosive species in the reactor coolant. The licensee has stated that there will be a slight increase in the iron concentration and conductivity of the reactor water at the uprated powerlevel. The staff agrees with the licensee's assessment which concludes that these differences are not significant and that the RWCU system is capable of performing its function at the uprated level.

2.3 Emergency Core Cooling Systems (ECCS)

The high pressure core injection (HPCI), RHR (low pressure core injection (LPCI) mode), CS and automatic depressurization system (ADS) are the ECCS required to provide core cooling in the event of LOCA. The following subsections review the impact of the power uprate on the safety function of the ECCS.

2.3.a High Pressure Core Injection (HPCI)

The HPCI system safety function is to provide reactor vessel makeup water inventory during

! small and intermediate break LOCAs. The HPCI system also serves as a back up system for i the RCIC if normal feedwater is lost. The system operates over a pressure vessel range of 150 to 1195 psig, with the latter pressure corresponding to the SRV set points.

The licensee stated that the HPCI turbine design pressure and temperature is 1250 psig at 575* F and the HPCI pump design pressure is 1500 psig. The licensee concluded that the extended power uprate operating conditions are bounded by the HPCI system design conditions.

The licensee also implemented the GE SIL 480 recommendation prior to the 5 percent power uprate. SIL 480 recommends that the HPCI system be modified in order to minimize the potential for system trip during startup transient. For the Hatch units, the HPCI system uses a i a

ramp generator during system startup to provide controlled turbine acceleration and this minimizes the control valve cycling during system initiation.

The licensee provided assurance that the reliability of the HPCI system will not be decreased by the higher loads placed on the system or because of any modifications made to this system to compensate for these increased loads. The reliability of the HPCI system will be monitored under the Maintenance Rule. The staff found the evaluation of the HPCI system acceptable.

2.3.b Low Pressure Core injection System (LPCI mode of RHR)

The hardware for the low pressure portions of the RHR are not affected by power uprate. The upper limit of the LPCl injection setpoints will not be changed for power uprate, therefore this system will not experience any higher pressures. The licensing and design flow rates of the low

. pressure ECCS will not be increased. In addition, the RHR system shutdown cooling mode flow rates and operating pressures will not be increased. Since the system does not experience different operating conditions due to power uprate, there is no impact due to power uprate. The licensee stated that for the Hatch units there is no impact due to the power uprate, except for the NPSH available margin which was discussed in Section 4.2 above. This evaluation is ,

acceptable to the staff.

2.3.c Core Spray System (CS) l The hardware for the low pressure core spray are not affected by power uprate. The upper limit of the CS injection set points will not be changed for power uprate; therefore, this system will not experience any higher pressures. The licensing and design flow rates of the low pressure ECCS will not be increased. These systems do not experience different operating conditions due to power uprate; therefore, there is no impact due to power uprate. Also, the impact of power uprate on the long term response to a LOCA will continue to be bounded by the short term response. The licensee stated that for the Hatch units there is no impact due to the power uprate, except for the NPSH available margin which is discussed in Section 2.a. This evaluation is acceptable to the staff.

i 2.3.d Automatic Depressurization Systems (ADS) l The ADS uses safety / relief valves to reduce reactor pressure following a small break LOCA with HPCl failure. This function allows low pressure coolant injection (LPCI) and core spray (CS) to flow to the vessel.- The ADS initiation logic and ADS valve control are adequate for uprate. Plant design requires a minimum flow capacity for the SRVs, and that ADS initiate after a time delay on either low water level plus high drywell pressure, or on low water level alone.

The ability to perform either of these functions is not affected by power uprate.

2.4 ECCS Performance Evaluation The ECCS are designed to provide protection against hypothetical LOCAs caused by ruptures I in the primary systems piping. The ECCS performance under all LOCA conditions and their analysis models must satisfy the requirements of 10 CFR 50.46 and 10 CFR 50 Appendix K.

1 l

The licensee used the staff approved SAFER /GESTR (SIG) methodology to assess the ECCS capability for meeting the 10 CFR 50.46 criteria. The ECCS-LOCA eva!uation for the extended power uprate was documented in the GE document NEDC-32720P (March 1997) and results were (scussed in tnis section, in the ECCS-LOCA analysis, the licensee assumed the highest power rod in the peak bundle to be at the peak linear heat generation rate (PLHGR). In the current submittal, the licensee stated the fuel type will not be changed and the fuel parameters would remain constant.

Therefore, in this evaluation the PLHGR will not be changed and higher core power distribution would alter the average bundle power, but will not have significant effect on the peak clad temperature (PCT). According to SNC, the licensing basis PCT changed from 1686 *F to 1688 'F for power of 2558 MWt and 2763 MWt respectively.-

l The result of the licensee's ECCS performance evaluation showed that the requirements of 10 CFR 50.46 and 10 CFR 50 Appendix K are satisfied for the extended power uprate. A sufficient number of plant-specific break sizes were evaluated to establish the behavior of both the nominal and Appendix K PCT as a function of break size. Different single failures were also investigated in order to clearly identify the worst cases. The Hatch specific analysis was performed with a conservatively high PLHGR and a conservative MCPR. In addition, some of the ECCS parameters were conservatively established relative to actual measured ECCS performance. The analysis also meets the other acceptance criteria of 10 CFR 50.46.

l Compliance with each of the elements of 10 CFR 50.46 is documented in the GE Licensing Topical Report for the Hatch units. The results for the limiting break and single failure ( the design-basis-accident (DBA)), for the limiting GE13 fuel are presented below. The nominal PCT is 1133 degrees F, the licensing basis PCT is 1688 degrees F, the Appendix K PCT is -

1664 degrees F, and the upper bound PCT is 1464 degrees F. These temperatures meet the requirements of the approved SAFER /GESTR-LOCA methodology stated below. The .

SAFER /GESTR-LOCA methodology requires:

I

+ The Licensing Basis PCT (LBPCT) must be less than 2200 degrees F. This LBPCT is 1 derived by adding appropriate margin for specific conservatism required by Appendix K to the l limiting PCT value calculated using nomina inputs, the nominal PCT (NOMPCT).

. The Upper Bound PCT (UBPCT) must be less than the LBPCT. The UBPCT is the estimated mean of the PCT distribution for the limiting LOCA plus the estimated standard deviation of

! the distribution of PCTs for the limiting case LOCA. The UBPCT calculated in this way is presumed to bound the 95th percentile of the PCT distribution for the limiting case LOCA, and for all LOCAs within the design basis.

. The UBPCT is less than the LBPCT when the limiting nominal PCT is lower than 1600 deg.F.

l Therefore, it is required that the UBPCT be below 1600 deg.F; otherwise, additional plant specific analyses must be done.

A 0.85 MAPLHGR multiplier will be utilized for single loop operation as previously accepted by the staff. The previously multipliers are conservative with respect to the SAFER /GESTR-LOCA results because the S/G model results in more efficient heat removal during the boiling transition phase than the previous evaluation model used to derive these multipliers. The l

f licer,see stated that single loop operation (SLO) is limited to 88 percent of the current power level. At uprated conditions, this corresponds to 83.8 percent of the uprated power level. The licensee provided assurance that the power uprate and fuel reload will not change the limiting break, single failure, or the break spectrum as compared to the existing analysis. Therefore, Hatch Units I and 2 will continue to meet the NRC LOCA licensing analysis and results requirements. The licensee will evaluate and verify the acceptability of the results of the plant specific LOCA analysis at each reload.

2.5 Standby Liquid Control System (SLCS)

The function of the SLCS is to provide the capability of bringing the reactor from full power to a cold xenon-free shutdown assuming that none of the withdrawn control rods can be inserted..

SLCS shutdown capability (boron concentration) is reevaluated for each fuel reload to ensure sufficient shutdown margin is available.

The SLCS is designed for injection at a maximum reactor pressure equal to the minimum SRV set point pressure. The nominal SRV set points and operating pressure will not be changed for the Hatch extended power rerate. The SLCS pumps are positive displacement pumps, where the small pressure increase related to the 3 percent tolerance on the as-found SRV opening pressure does not affect the rated flow to the reactor. Therefore, the capability of the SLCS to provide its backup shutdown function is not affected by power rerate. Also, because there is no increase in system operating pressure, there is no reduction in the SLCS pump relief valve pressure margin, or in the pump motor horsepower requirements. The SLCS performance is evaluated in Section 9.3.1 (Reference 1) for a representative core design.

2.6 Reactor Safety Performance Features The staff requested that the licensee identify all codes / methodologies used to obtain safety limits and operating limits and how they verified that these limits were correct for the appropriate uprated core. The licensee was also requested to identify and discuss any limitations associated with these codes / methodologies that may have been imposed by the staff. In Reference 2, the licensee responded to this staff request. The licensee stated that the restrictions and conditions applicable to GENE's core and fuel design are documented in GESTAR 11, NEDE-24011-P-A-13, Revision 13, " General Electric Standard Application for Reactor Fuel", August 1996 and GESTAR 11, NEDE-24011-P-A-13-US, Revision 13, " General Electric Standard Application for Reactor Fuel (Supplement for the United States)", August 1996. The approved codes and methodologies are specified in this document. The licensee stated that the evaluations were performed and verified by a third party prior to submittal to the NRC. The licensee stated that the limitations, restrictions, and conditions specified in the approving NRC safety evaluations were adhered to when applying the codes to the power uprate analyses. This is acceptable to the staff.

2.6.1 ReactorTransients r

Disturbances of the plant caused by a malfunction, a single failure of equipment, or personnel error are investigated according to the type of initiating event. The licensee used the NRC-approved methodologies outlined in the generic report (NEDC-32424P, Table E-1) to establish

l l

! the transient events to be analyzed for the extended power uprate, the power level to assume and the computer model to use. SNC analyzed the following transient events and Table 9-2 of Enclosure 6 to Reference 1 provides the transient results.

(1) Turbine Trip with Bypass Failure (2) Generator Load Rejection with Bypass Failure (3) Feedwater Controller Failure:

Max Demand Max Demand with Bypass Failure (4) Loss of Feedwater Heating (5) Rod Withdrawal Error l

(6) Slow Recirculation Flow increase The licensee selected Hatch Unit 2 for the reactor transient analysis since the two units have similar vessel size, core power and SRV set points. The Unit 2 reload 13 core served as the bounding representative core and all the analyses were performed at full extended power at the L maximum allowed core flow. The SLMCPR was assumed to remain the same as Unit 2 reload 14 value and the licensee stated the SLMCPR will be evaluated for the specific core designed l

for the extended uprate consistent with Section 3.4 of NEDC-32523P. For all the transients, the licensee assumed one SRV out service and direct or the statistical allowance for 2 percent power uncertainty was included in the analysis.

The licensee analyzed the sensitivity of each limiting transient category to core flow, feedwater temperature and cycle exposure, The limiting transient analysis results for the extended power uprate are summarized in Table 9.2 of Reference 1. The licensee stated that there were no changes to the mitigation trip set points for the pressurization events and the basic characteristic of the transient events did not change with power uprate. However, due to the higher decay heat for the extended power, the automatically actuated system will require slightly more time to restore the water level.

Operator action is only necessary for long term plant shutdown once the water level is restored and no new operator action or shorter response time is needed for the extended power uprate.

The licensee also stated that multipliers for off-rated MCPR and MAPLHGR will be re-evaluated during core reload analysis. The power dependent MCPR and MAPLHGR will provided the basis for instrumentation set points. The power uprate analysis used the staff approved GEMINI methodology for 100 percent initial power and REDY analysis for the 102 percent initial power. The analysis plan proposed by the licensee is acceptable. The staff will verify the acceptability of the results when each reload document is submitted.

I l

i 1

2.7 Special Events 2.7.1 Anticipated Transients Without Scram (ATWS) j I

A generic evaluation of the ATWS event is presented in NEDC-32424P. This evaluation J concludes that the ATWS acceptance criteria for fuel, reactor pressure vessel (RPV), and the containment integrity will not be violated for power uprate if the following are met: reactor power ,

increase is equal to or less than 20 percent; dome pressure increase is equal to or less than 1080 psig; the lowest SRV opening set point up to the TS analytical limit is 1195; ATWS high  ;

pressure set point up to the analytical limit is 1220 psig; the SRV capacity must be greater than

]

76 percent of the initial steam flow rate at 1195 psig opening set point; and equivalent boron injection 86 gpm is available. Based on the analysis in NEDC-32424P, Hatch meets most of the bounding plant parameters, however the SRV capacity is lower. The licensee performed j plant specific A'lWS analyses at the extended power uprate. j 2.7.2 Station Blackout l Plant response and coping capabilities for a station blackout (SBO) event are impacted by I operation at the uprated power level due to the increase in the operating temperature of the l primary coolant system, increase in decay heat, and increase in the main steam safety relief valve set points. There are no changes to the systems and equipment used to respond to an SBO, nor is the coping time changed. The plant Hatch coping time for SBO event is four hours.

i The following areas contain equipment necessary to mitigate the SBO event: Control Room; RCIC and HPCI Equipment Room; Steam Pipe Chase / Steam Tunnel; Drywell and

, Suppression Pool; and RHR Comer Room.

The licensee stated none of the areas will experience any increase in normal temperatures due to the power uprate and following an SBO event equipment necessary for event mitigation will not effected. Assuming the suppression pool cooling was initiated after one hour into the SBO event, when the attemate AC power is assumed available, the peak pool temperature is 167 F.

l If the SBO is initiated four hours later, the peak pool temperature is 194 F. This acceptable l temperature for containment and for the ECCS pump operation.

j Besides the increased heat load effects, there is an increase in the condensate water

, requirements for the vessel makeup for extended power uprate. SNC analysis showed that j -77,000 gallons of make up water inventory was required for the 13 percent power uprate condition during the four hour SBO coping period. The condensate storage tank is designed to provide 100,000 gallons of make inventory for isolation invents. Therefore, adequate water volume is available for SBO event for 2763 MWt uprate reactor operation. Based on the above evaluation and assurances by the licensee, the SBO coping capabilities are not adversely affected by power uprate and are acceptable to the staff.

1

2.8 Net Positive Suction Head By letter dated July 6,1998 (Reference 4), the licensee responded to the staff's request for additional information (RAI) conceming net positive suction head (NPSH). The RAI addressed the Hatch Unit i NPSH analysis for ECCS pumps and the required use of containment overpressure to ensure adequate NPSH to the ECCS pumps at the extended power uprate with the new ECCS suction strainers installed with the design loads from Bulletin 96-03, " Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling-Water Reactors,"

dated May 6,1996 design loadings. The staff notes that Hatch Unit 2 does not require the use of containment overpressure to ensure adequate NPSH for the ECCS and containment spray pumps. In its RAI response, SNC demonstrated that 2.1 psig of containment overpressure was required to ensure adequate NPSH to the Hatch Unit 1 RHR pumps and 2.0 psig was required for the Hatch Unit 1 core spray pumps during the long term post LOCA. Additionally, SNC

]

requested an additional 2.1 psig (5 feet) of containment overpressure above the required to j address potential future issues. The following review evaluates the use of containment

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i overpressure at the extended power uprate with the new suction strainers installed. I 2.8.1 PM and CS NPSH Calculations 1

The NPSH analyses included the head loss across the new ECCS suction strainers which were installed to meet the requirements of NRC Bulletin 96-03. By .790|letter dated November 5,1997]], j

SNC provided the final dimensions of the strainer, the head loss across the new strainer with 1 l the calculated debris loading (and the basis for the head loss determination), and the resultant l NPSH margin with the new strainers installed for Hatch Unit 1. In its submittal, SNC stated that

, the new strainers were designed to provide adequate NPSH margin with a debris loading

, greater than the debris loading documented in NRC SER dated June 17,1997 (Reference 5).

SNC designed the Hatch Unit 1 strainer with debris loading described below:

l fibrous debris 8 300 ft (700 lb) suppression pool sludge 450 lb dust and dirt 150 lb l epoxy coating 71lb unqualified coatings 120 lb potentially degraded coatings 200 lb inorganic zinc 47 lb top coated inorganic zinc 85 lb The staff notes that changing the debris loading on the strainer changes the calculated head loss across the stramer which affects the NPSH analysis. Therefore, the NPSH analyses evaluated in this safety evaluation incorporate the ECCS strainer debris loading and head loss discussed above.

The licensee provided evaluations of post-LOCA NPSH for RHR and CS pumps. The evaluations were divided into two portions as follows:

Short-Term: 0 to 600 seconds (10 minutes), no operation action credited, vesselinjection phase

Long-Term: 600 seconds to completion of event, operator actions credited, containment cooling phase 2.8.2 Short-Term NPSH Requirements For short term operation, the RHR and CS pumps are assumed to be at runout conditions. No attempt to throttle the pumps is made by the operators, therefore, the RHR and CS pumps run at the highest flow rate that piping friction losses and reactor pressure will physically allow. For RHR, runout flow is assumed to 10,600 gpm, and for CS, runout is assumed to be 5900 gpm.

The reactor is assumed to be at 0 psig. Per GE calculations for the extended power uprate (2763 MWt), the maximum suppression pool temperature at 10 minutes is 161'F. For conservatism, a suppression pool temperature of 165'F was used in the NPSH calculations.

Based on the above assumptions, the licensee evaluated the NPSH Available (NPSHA) using the following equation.

NPSHA = (P,-Pw)144

+Z-(h )-(h _

)

.where: P, = atmospheric pressure, psia P. = saturation pressure at suppression pool temp, psia p = density of suppression pool water, Ib/ft 4 Z = static head, ft hm = piping friction losses, ft hm ,n , = strainer head loss, ft The licensee's calculations demonstrate that at the assumed runout flows and calculated ECCS strainer head loss at 165'F suppression pool temperature, containment overpressure is not required for both the RHR and CS pumps during the short term post LOCA. The staff finds this acceptable at the extended power uprate power level of 2763 MWt.

2.8.3 Long-Term NPSH Requirements For long term operation, greater than 10 minutes post LOCA, the operators can throttle the RHR and the CS pumps to the design flow rates of 7700 gpm and 4725 gpm, respectively. Per GE calculations for the extended power uprate (2763 MWt), the maximum suppression pool temperature during long term operation is approximately 207'F which is used to calculate the

- NPSH available at peak suppression pool temperature. Using the equation described above, the licensee demonstrated that 2.1 psig (5 feet) of containment overpressure was required to ensure adequate NPSH to the Hatch Unit 1 RHR pumps and 2.0 psig (4.88 feet) was required for the Hatch Unit 1 core spray pumps at a peak suppression pool temperature of 207'F. Using the actual suppression pool temperature profile, containment overpressure is needed from approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> post LOCA. l 1

Additionally, SNC requested an additional 2.1 psig (5 feet) of containment overpressure above the required,4.2 psig (10 feet) total at the peak suppression pool temperature, to address potential future issues. This additional containment overpressure margin would be needed from 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to approximately 26.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> post LOCA. The requested and required containment overpressure for the RHR and CS pumps were presented in Figures 60-1 and 60-2 in the

! ' licensee's July 6,1998 submittal. The staff notes that the requested additional containment overpressure is less than half of the calculated minimum containment pressure available.

However, the licensee did not quantify the future issues that could result in needing more containment overpressure than already required.

By letter dated July 31,1998 (Reference 6), the licensee provided Tables 11-1 and 11-2 which presented a time history of the DBA LOCA minimum pressures as illustrated in Figures 60-1 and 60-2 of the July 6,1998 submittal. The column headings defined the applicable pressures.

Containment Overpressure Available (psi) - the containment pressure calculated utilizing the minimum containment pressum analysis presented in response to NRC Question 59, submitted July 6,1998.

Containment Overpressure Calculated Minimum (psi) - The amount of containment overpressure availeble required { sic} to assure adequate NPSH. A negative numberin this column indicates that adequate NPSH is available without containment pressure present.

Containment Overpressure Additional Margin (psi) - The amount of containment overpressure available with the requested overpressure margin.

These tables adequately describe the minimum containment overpressure available, the containment overpressure required to ensure adequate NPSH, and the requested additional containment overpressure margin at the associated time of the LOCA. Therefore, the staff i believes that both Figures 60-1 and 60-2 and the Tables 11-1 and 11-2 should be incorporated l

into the Hatch 1 Final Safety Analysis Report since they describe the current NPSH analysis and containment overpressure requirements and margin at the extended power uprate power level.

Additionally in the July 31,1998 submittal, the licensee made a commitment to notify the NRC if l

future issues, singularly or collectively, require SNC to take credit for i foot (approximately 0.4 psig) of the requested additional containment overpressure margin. As such, the licensee would notify the staff if a change to the RHR NPSH calculation for the long term resulted in an increase of the containment overpressure required from 2.1 psig to 2.5 psig (5 feet to 6 feet) and so forth. This commitment is also applicable to the long term CS NPSH analysis. The staff believes that the proposed notification process would allow the staff an opportunity to evaluate any change that caused a significant increase in the reliance on containment overpressure.

Based on the above analysis, the staff finds that with credit for containment overpressure as specified in Table 11-1 and 11-2, NPSH for the ECCS pumps will be available to meet the long-term worst case scenario. Additionally, the staff concludes that the requested additional containment overpressure margin,4.2 psig (10 feet) total at a peak suppression pool l

1

temperature of 207'F, is acceptable based on the licensee commitment to notify the staff of any individual or collective increase of 1 foot of containment overpressure required in the NPSH analyses. The staff expects that the licensee would submit another license amendment request for any increase in containment overpressure reliance above 4.2 psig at a peak suppression pool temperature of 207'F.

2.9 Containment Response 1

l 2.9.1 Containment System Performance The Edwin 1. Hatch I uc; ear Plant, Units 1 & 2 Final Safety Analysis Report (FSAR) provides the results of analyses of the containment response to various postulated accidents that constitute the design basis for the containment. Operation with 8 percent extended power uprate from 2558 MWt to 2763 MWt would change some of the conditions and assumptions of the containment analyses. Top: cal Report NEDC-32424 " Generic Guidelines For General Electric Boiling Water Reactor Extended Power Uprate," Section 5.10.2 requires the power uprate applicant to show the acceptability of the effect of the uprated power on containment capability. These evaluations will include containment pressures and temperatures, LCCA containment dynamic loads, safry-relief valve containment dynamic loads and subcompartment pressurization. Appendix G of NEDC-32424 prescribes the generic approach for this evaluation and outlines the methods and scope of plant-specific containment analyses to be done in support of extended power uprate. Appendix G states that the applicant will analyze short term containment pressure andemperature response using the GE M3CPT code

. ( current analyses). These analyses will cover the response through the time of peak drywell pressure throughout the range of power / flow operating conditions with extended power uprate.

A more detailed ccmputer model of the NSSS (LAMB or TRACG) may be used to determine more realistic RPV break flow rates for input to the M3CPT code. The use of LAMB code has been reviewed by the NRC for application to LOCA analysis in accordance with 10 CFR 50, Appendix K. The results from these analyses will also be used for input to the LOCA dynamic .;

loads evaluation. 1 Appendix G of NEDC-32424 also requires the applicant to perform long-term containment heatup (suppression pool temperature) analyses for the limiting FSAR events to show that pool temperatures will remain within limits for containment design temperature, ECCS Net positive suction head (NPSH) and equipment qualification temperatures. These analyses can be performed using the GE computer code SHEX. The SHEX computer code for the calculation of suppression pool response to LOCA events can be approved on a plant specific basis, provided that confirmatory calculations for validation of the results were included in the plant specific request. SHEX is partially based on M3CPT and is used to analyze the period from when the break begins until after peak pool heatup (i.e., the long-term response).

2.9.1.1 Containment Pressure and Temperature Response Short term and long-term analyses of the containment pressure and temperature response following a large break inside the drywell are documented in the Edwin l Hatch FSAR. The i short term analysis was performed to determine the peak drywell pressure during the initial I blowdown of the reactor vessel inventory into containment following a large break inside the )

l I

drywell (DBA LOCA), while the long-term analysis was performed to determine the peak pool temperature response considering decay heat addition.

The licensee indicated that the analyses were performed in accordance with Regulatory Guide 1.49 and NEDC-32424 using GE codes and models. The M3CPT code was used to model the short-term containment pressure and temperature response. The more detailed RPV model (LAMB) was used for determining the vessel break flow for input to the M3CPT code in the containment analyses. The use of the LAMB model is justified in " General Electric Company Analytical Model for Loss-of Coolant Accident Analysis in Accordance with10CFR50 Appendix K", NEDE-20566-P-A, September 1986. The staff finds the use of the LAMB model detailed RPV break flow input to the M3CPT code in the containment analysis for extended power uprate acceptable.

, The licensee also indicated that the SHEX code was used to model the long-term containment

! pressure and temperature response. The original FSAR analyses used a predecessor to the HXSIZ code. However, the predecessor code is no longer available for performing i confirmatory calculations. To validate the use of SHEX for Hatch containment analyses, a

[ benchmark analysis was performed with input assumptions and values consistent with the input used in the accepted original FSAR analysis for Hatch Unit 2. Hatch Unit 2 FSAR was chosen because it is quite similar to Unit 1 and contained more detailed information than the Unit 1 FSAR with regard to the geometry inputs, power level, and system operation. Inputs to the benchmark analysis were taken from the extended power uprate analysis if the FSAR did not l l contain thete values. Benchmark analyses were performed using the May-Witt decay heat l model. The analyses predicted the peak suppression pool temperature to be within 1'F f

(210.3*F with SHEX code compared to 209.8'F with the original FSAR analysis). The benchmark analysis also predicted the maximum long-term wetwell pressure by SHEX using FSAR input assumptions within 0.5 psi from the FSAR value at the time of maximum pool

! temperature (12.4 psi verses 12.0 psi). The containment pressure response from the onset of -

sprays (600 sec ) to 10,000 see was 1-3 psi higher than the values reported in the FSAR. This  ;

was mainly due to the assumption used in the FSAR analysis that the drywell and wetwell temperatures are instantaneously equal to the spray temperature from the onset of sprays.

SHEX mechanistically models spray heat transfer, and thus, the results reflect the time required ,

to bring the airspace temperature to spray temperature. The shape of the long-term suppression pool temperature curve and the pressure curve from the SHEX benchmark analyses matches well with the corresponding curves reported in the FSAR. Based on the review of the above, the staff finds the use of the SHEX code for Hatch extended power uprate acceptable.

2.9.1.2 Long-Term Suppression Pool Temperature Response l (1) Bulk Pool Temperature

(

The licensee indicated that the long-term bulk suppression pool temperature response was evaluated for the DBA LOCA. A bounding analysis was performed at 102 percent of 2763 MWt using the SHEX code and the more realistic decay heat model (ANS/ ANSI 5.1). The initial submittal was without the uncertainty adder of 20 to the decay heat model. The staff considers the use of ANS 5.1 without an adder to represent a best estimate of the decay power. This was i

L

deemed to be inappropriate. To be consistent with the conservative nature of the calculations it has been determined than an uncertainty adder of 20 is necessary for the use of the ANS 5.1 1979 nominal decay heat model for the extended uprate in letters dated July 6 and July 31, 1998, the licensee updated the initial containment analysis results with a decay heat model which now includes the 2a uncertainty adder.

The revised long-term containment response analysis at extended uprated powerwas performed separately for Unit 1 and Unit 2 using the SHEX code and ANS 5.1-1979 decay heat model with the 20 uncertainty adder. The analysis also used the same input values as used in the previously accepted analysis. The analysis shows that at uprated power, Unit 1 peak pool temperature will increase to 207'F and Unit 2 peak pool temperature will increase to 206*F i from the current peak pool temperature of 202*F. The revised peak pool temperature for Unit 1 is 1'F higher than Unit 2 mainly because Unit 1 has a slightly smaller pool than Unit 2. These temperatures are below the suppression pool design temperature of 281 *F for Unit 1 and 340 'F for Unit 2.

i l Based on the results of these analyses, the staff concludes that the peak bulk suppression pool temperature response remains acceptable from both NPSH and structural design standpoints for the extended power uprate.

(2) Local Suppression Pool Temperature with SRV Discharge A local pool temperature limit for SRV discharge is specified in NUREG-0783 because of j concems resulting from unstable condensation observed at high pool temperatures in plants without quenchers. Elimination of this limit for plants with quenchers on the SRV discharge lines is justified in GE report NEDO-30832, " Elimination of Limit on Local Suppression Pool Temperature for SRV Discharge with Quenchers". In a safety evaluation report dated August 29.1994, the staff eliminated the maximum local pool temperature limit for plants with quenchers on the SRV discharge lines, provided the ECCS suction strainers are below the quencher elevation. The licensee indicated that since both units of Hatch have quenchers i above the ECCS suction strainers, no evaluation of this limit is necessary. Based on the above review, the staff concludes that no additional analyses are necessary and the extended power uprate analyses are acceptable relative to this issue.

2.9.1.3 Containment Gas Temperature Response l'

The licensee indicated that the containment gas temperature response analyses were performed to cover the blowdown period for DBA-LOCA during which the maximum drywell airspace temperature occurs at 102 percent of extended uprate power, using the Mark I containment LTP methodology. The results show that for Unit 1, the calculated peak drywell gas temperature at extended uprated power increases by 1'F from 292'F to 293'F from the current power level. For Unit 1, the calculated peak drywell gas temperature exceeds the drywell shell design temperature of 281'F by 12*F, but only at the beginning of the accident and for a short period of time. For the worst case the exceedance is less than 20 seconds.

The drywell shellis an extremely massive steel structure. Thickness of the shellis about 1.5 inches. As a result, the shell temperature willlag the gas temperature. This thermallag will cause the shell temperature to not see the exceedance of such a small delta temperature for l

F such a small time period. In other words, the shell design temperature will not be exceeded.

Calculations of the shell temperature transient for a steam line break are also provided below.

For this more severe case, it was shown that the design shell temperature of 281 *F was not exceeded. For Unit 2, the calculated peak drywell temperature at uprated power remains at 292*F and below the drjwell shell design temperature of 340'F.

The licensee also indicated that drywell temperature responses were calculated for a series of small steam line breaks which produced higher drywell gas temperature than the DBA-LOCA. i The peak drywell gas temperature of 324*F was calculated at 102 percent of the extended uprate power level with containment parameters that bound Units 1 and 2. This temperature is l below the drywell shell temperature of 340*F for Unit 2, but exceeds the drywell shell design l temperature of 281*F for Unit 1 for short duration. Therefore, an analysis was performed to determine the shell temperature response. The calculated peak drywell shell temperature 1 determined for the corresponding peak drywell gas temperature of 324*F was 271*F. This I temperature is within the drywell shell design temperature of 281 *F for Unit 1. Therefore, the drywell gas temperature response for the extended power uprate has no adverse effect on the l containment structure.

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The licensee stated that the wetwell gas space peak temperature was calculated assuming thermal equilibrium between the pool and the wetwell gas space. The extended uprate analysis shows that the bulk suppression pool and space temperature will increase slightly after LOCA to 207'F for Unit 1 and 206*F for Unit 2 and would remain below the design value of 281'F for Unit 1 and 340'F for Unit 2. Therefore, the wetwell gas temperature responses at the higher i power level have no adverse effect and remain acceptable.

t Based on the above review, the staff concludes that the containment drywell and wetwell gas temperature response will remain acceptable after the power uprate.

2.9.1.4 Short-Term Containment Pressure Response The licensee indicated that the short-term containment response analyses were performed for the limiting DBA LOCA , which assumes a double ended guillotine break of a recirculation suction line to demonstrate that operation at the proposed power level will not result in exceeding the containment design limits. The short term analysis covers the blowdown period during which the maximum drywell pressure and maximum differential pressure between the drywell and wetwell occur. These analyses were performed at 102 percent of extended power uprate level, using previously accepted methods. These methods were originally accepted during the Mark I containment long term program (LTP). Break flow was calculated using a more detailed RPV model . The extended power uprate analyses calculated a maximum containment pressure of 50.5 psig for Unit 1 and 46.9 psig for Unit 2 from preuprate values of 4g.6 psig for Unit 1 and 45.5 psig for Unit 2. These calculated maximum uprate pressures for Unit 1 and Unit 2 remain below the containment design pressure of 56 psig for both units.

Based on its review, the staff concludes that the containment pressure response following a I postulated LOCA will remain acceptable after the power uprate. I l

2.9.2 Containment Dynamic Loads i

l 1

l

2.9.2.1 LOCA Containment Dynamic Loads '

Generic Guidelines in NEDC-32424 specify that the power uprate applicant determine if the containment pressure, suppression pool temperature, and vent flow conditions calculated with the M3CPT code for the power uprate are bounded by the analytical or experimental conditions on which the previously analyzed LOCA dynamic (cads are based. If the new conditions are

. within the range of conditions used to define the loads, then LOCA dynamic loads are not l affected by the power uprate and thus do not require further analysis.

LOCA containment dynamic loads for the extended power uprate are based on the short-term LOCA analyses, which provide calculated values for the controlling parameters for the dynamic loads throughout the blowdown. The key parameters are the drywell and wetwell pressure, the vent flow rates, and the suppression pool temperature. The dynamic loads considered in the

, power uprate evaluations include pool swell, condensation oscillation (CO), and chugging. For l a Mark i plant like Hatch vent thrust loads are also evaluated.

The licensee stated that the short-term containment response conditions with extended power uprate are within the range of test conditions used to define the pool swell and condensation oscillation loads for the plant. The long-term response conditions with extended power uprate in which chugging would occur are within the conditions used to define the chugging loads.

The vent thrust loads for extended power uprate are calculated to be less than the plant -

specific values determined during the Mark l Containment LTP. Therefore, the LOCA dynamic loads for Hatch are not impacted by the power uprate.

Based on the above review, the staff concludes that the LOCA containment dynamic loads will i remain acceptable after the power uprate.

2.9.2.2 SRV Containment Dynamic Loads The safety-relief valve (SRV) containment dynamic loads include discharge line loads (SRVDL),

suppression pool boundary pressure loads, and drag loads on submerged structures. The loads are influenced by the SRV opening setpoint pressure, the initial water leg height in the

SRVDL, SRVDL geometry, and suppression pool geometry. None of these parameters i

including SRV opening setpoint are changed for extended power uprate for the first SRV actuation for Hatch. Therefore, the extended power uprate will not impact the SRV load definition for first actuations.

For subsequent actuations (second pops), the only additional paran,etric change with extended power uprate is the time between SRV actuations. A higher water level at the time of second pop will result in higher SRV loads. The licensee stated that the effect of power uprate on the SRV discharge line was evaluated. The evaluation showed that with the current SRV low-low set point logic parameters, the SRVDL water level reestablish equilibrium height well before the subsequent SRV actuations. Therefore, there will be no impact of extended power uprate on the SRV subsequent actuation loads.

Based on the above, the staff concludes that the SRV containment dynamic loads will remain acceptable after the extended power uprate.

2.9.2.3 Subcompartment Pressurization Generic Guidelines in NEDC-32424 require that the break flow will be compared with the analytical or experimental basis for the LOCA subcompartment pressurization dynamic loads. If the calculated break flow conditions with extended power uprate are within the range of break flow conditions used to define the loads, subcompartment pressurization dynamic loads are not affected by power uprate.

The licensee indicated that due to changes in operating conditions with extended power uprate, the actual asymmetrical loads on the vessel, attached piping, and biological shield wall ( from a postulated pipe break in the annulus between the reactor vessel and biological shield wall) will increase slightly. The biological shield wall and component designs remain adequate because the original analyzed loads were based on conservative assumptions which provide sufficient margin to accommodate the mass and energy releases at the extended power uprate conditions. Based on the above review, the staff concludes that the subcompartment pressurization effects will remain acceptable after the power uprate.

1 l 2.9.3 Containment isolation i

The licensee indicated that the system designs for containment isolation are not be affected by the extended power uprate. The capability of the actuation devices to perform at extended power uprate conditions has been evaluated and determined to be acceptable. All motor-operated valves (MOVs) used as containment isolation valves will be capable of performing their intended functions at extended uprate conditions as per the requirements of Generic Letter 89-10. Extended power uprate has no adverse effect on containment isolation. Based on its review, the staff finds that the operation of the plant at the extended uprated power level will not impact the containment isolation system.

I 2.9.4 Post-LOCA Combustible Gas Control Under LOCA conditions, combustible gases would be generated in containment from the radiolysis of water (generating oxygen and hydrogen) and the metal-water reaction with the fuel cladding (generating hydrogen). Post-accident hydrogen and oxygen generation rates will increase in proportion to the power level. The function of Combustible Gas Control is that the I

system be used following a LOCA to maintain the containment atmosphere as a non-combustible mixture.

The control of combustible gas concentrations for Unit 1 is attained by the containment atmosphere dilution (CAD) method. This method adds nitrogen to the containment to dilute the oxygen concentration below the flammability limit. The licensee indicated that sufficient capacity exists in the Unit 1 CAD system to account for the increase in oxygen generation due to extended power uprate. Under the most conservative assumptions, extended power uprate may require the Unit 1 CAD system to be initiated earlier in the accident. The CAD system will be started when the oxygen concentration reaches 4 voi percent in about 1.55 days inside the torus and in about 2.14 days inside the drywell. These slightly reduced starting times still provide more than adequate time for the operators to take the necessary actions to initiate the CAD system . Oxygen concentration for Unit 1 is required to be controlled within 5 vol percent 1

following a LOCA. Margin has been provided by designing the CAD system to control oxygen within 4 vol percent.

Unit 2 combustible gas control system is provided with hydrogen recombiners which maintain a safe level of hydrogen inside the containment. The initiation of the recombiners is controlled procedurally to maintain gas concentration within 4 vol percent inside containment following a LOCA, and not by time. The licensee indicated that the impact of a power uprate would cause the Unit 2 recombiners to be initiated slightly earlier in about i hour 50 minutes. Margin has been provided by designing the recombiner system to control hydrogen within 3.5 vol percent.

Contain-ment purge capability serves as backup to the Unit 1 CAD system and Unit 2 recombiner system.

Based on its review, the staff concludes that control of post-LOCA combustible gases will remain acceptable after the extended power uprate.

2.10 Engineered Safety Features and Associated Support Systems and Auxiliary Systems 2.10.1 Standby Gas Treatment System The standby gas treatment system (SGTS) is designed to minimize offsite and control room dose rates during venting and purging of both the primary and secondary contair, ment atmosphere under accident or abnormal conditions while containing airbome particulate and halogens that might be present. The capacity of the SGTS was selected to maintain the secondary containment at a slight negative pressure. The licensee stated that the capability of the SGTS and the charcoal filter beds would not be impacted by the extended power uprate conditions. Also, the licensee stated that the total post-LOCA iodine loading at extended power uprate conditions remains within the current capability of the filter and in accordance with Regulatory Guide 1.52, Revision 2.

Based on its review, the staff finds that plant operation at the extended power uprate level has an insignificant impact on the ability of the SGTS to meet its design objectives, and concludes

. that it is acceptable.

2.10.2 Fuel Pool Cooling The spent fuel pool cooling system (SFPCS)is designed to remove the decay heat released from the stored spent fuel assemblies and maintain a pool water temperature at or below y design temperature under normal operating conditions. Supplemental fuel pool cooling is provided by the residual heat removal (RHR) system in the event of a full core off-load.

l As a result of plant operation at the extended pe,wer uprate level, the SFP heat load would increase since the fuel discharged at each r9tueling outage would contain slightly more decay heat. The licensee determined that the expected heat load in the SFP would increase by approximaiety 8 percent for the normal condition, 9 percent for the refueling condition and 7 percent for the maximum (core off-load) condition. Based on these increased heat loads, it was determined that the SFP cooling system and the RHR system in its fuel pool cooling assist mode would be able to maintain the SFP temperature within the maximum acceptable i

- temperature of 150 degrees F for the normal, refueling, and maximum (core off-load) conditions. The licensee concluded that the extended power uprate would not have any negative effect on the capability to keep the SFP temperature at or below the design temperature to maintain adequate SFP cooling. Also, the licensee installed a Decay Heat Removal System that is capable of removing 40 MBtu/hr while keeping the SFP 5125 degrees F. This system would be able to adequately cool the SFP during a refueling outage for extended power uprate operation.

l Based on the results of the licensee's analysis, the staff concludes that the slight increases in the SFP heat load and fuel pool temperatures due to extended power uprate would be within the design limits of the SFPCS, and are acceptable.

2.10.3 Water Systems 2.10.3.1 Service Water Systems 2 10.3.1.1 Plant Service Water System The plant service water (PSW) system is designed to provide cooling water to various systems (both safety-related and nonsafety-related) and to provide makeup to the plant circulating water system. There are two divisions of PSW. Each of the two divisions supplies cooling water to one redundant train of safety-related equipment. The two safety-related headers pass through l isolation valves and eventually merge into one header supplying nonsafety-related equipment.

The licensee evaluated the PSW system and found that the increase in heat loads for the components affected by extended power uprate are within the existing design heat loads, l except for the stator water coolers, the isophase bus duct coolers and the RBCCW heat exchangers. An evaluation of the PSW system capabilities revealed that the design of the PSW system can accommodate the increase in component heat loads for these three coolers and is l adequate for extended power uprate conditions.

Based on its review, the staff finds that plant operation at the extended power uprate level has an insignificant effect on the design function of the PSW systems, and concludes that it is acceptable. _

i 2.10.3.1.2 Safety-Related Loads The safety-related portion of the PSW system piping provides a reliable supply of cooling water to various safety-related equipment. The licensee stated that the diesel generator loads and cooling loads remain virtually the same as for current rated operation since the equipment and system performance remains unchanged. Also, PSW flow to these components would not change. The building cooling heat loads remain the same as for current rated operation because the equipment performance in these areas has remained unchanged for post-LOCA i

conditions. The staff agrees with the licensee that the safety-related loads for the PSW are not affected by extended power uprate and concludes that it is acceptable.

2.10.3.1.3 Nonsafety-Related Loads I

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l The PSW discharge temperature results from the heat rejected via the reactor building closed '

cooling water (RBCCW) system and other auxiliary heat loads. The PSW heat load increase from extended power uprate would reflect an increase in main generator losses rejected to the 1 stator water coolers, hydrogen coolers and exciter coolers. There would also be an increase in heat loads for the Unit 1 and 2 isophase bus duct coolers and the Unit 1 and 2 RBCCW heat exchangers. The licensee determined that the slight increase in discharge temperature {

)

between rated and uprated power in the PSW system was acceptable for extended power j uprate conditions. l Since nonsafety-related loads do not perform any safety function, the staff has not reviewed the impact of the extended power uprate to the designs and performances of these systems.

2.10.3.1.4 RHR Service Water System The RHR Service Water system is designed to provide a reliable supply of cooling water to the RHR system under normal and post-accident conditions. The licensee stated that the containment cooling analysis in this proposed amendment does not increase for extended ,

power uprate. Therefore, extended power uprate would not increase the cooling requirements I on the RHR and its associated service water system significantly. During shutdown cooling with the RHR system, the greater decay heat generation may require a longer time to cool the reactor following extended power uprate conditions, although, the impact is expected to be minimal. l Based on its review, the staff finds that the design cooling capacity of the RHRSW system is I adequate for extended power uprate conditions, and concludes that it is acceptable.

2.10.4 Main Condenser / Circulating Water / Normal Heat Sink Performance 1 The main condenser, circulating and cooling tower systems are designed to provide the main condenser with a continuous supply of cooling water for removing heat rejected to the t condenser by turbine exhaust, turbine bypass steam and other exhausts over the full range of operating load thereby maintaining low condenser pressure. The licensee stated that the performance of the main condenser, circulating water and cooling tower systems was evaluated and found to be adequate for plant operations at the extended power uprate level. ,

I

! Since the main condenser, circulating water system and cooling tower systems do not perform {

any safety-related function, the staff has not reviewed the impact of the extended power uprate  !

on the designs and performances of these systems.

l 2.10.5 Reactor Building Closed Cooling Water System l .

The RBCCW system is designed to remove heat from vanous auxiliary plant equipment housed in the reactor building. The licensee performed evaluations and determined that the increase in heat loads to this system due to extended power uprate would be within the cooling capabilities and RBCCW flow rates.

Since plant operations at the proposed power uprate level do not change the design aspects and operations of the RBCCW system, the staff agrees with the licensee that plant operations at the extended power uprate level would be acceptable.

2.10.6 Heating, Ventilation and Air Conditioning (HVAC)

The HVAC systems consist mainly of cooling supply, exhaust and recirculation units in the turbine building, reactor building and the drywell. The actual heat loads processed by the HVAC systems in these buildings would be impacted by the extended power uprate due to the increased heat losses from the isophase bus ducts and increased horsepower requirements of the condensate pump, condensate booster pump and the Unit i reactor recirculation pump motors. The licensee's review indicated that the actual design capacity of the cooling units in the condenser bay area near the condensate and condensate booster pumps have sufficient margin to accommodate the additional heat loads due to the increased horsepower requirements without any impact on the area temperatures. Also, the increased heat loads due to an increase in isophase bus duct temperature would be within the design capacity of the coolers in the area.

Due to the increased horsepower requirements of the Unit i reactor recirculation pump motors, the localized bulk average temperature in the vicinity of the recirculation pumps would increase by approximately 2 degrees F. The licensee reviewed the actual design capacity of the drywell coolers and found that the additional Unit 1 heat load would be within the design capacity of the drywell cooling system. There would not be an increase in the HVAC load for the Unit 2 reactor

. recirculation pump motor windings since they are water-cooled. Other areas are unaffected by l the proposed power uprate since the process temperatures remain relatively constant.

Based on its review, the staff finds that plant operation at the extended power uprate level has an insignificant impact on the ability of the HVAC to meet its design objectives, and concludes that it is acceptable.

2.10.7 Fire Protection The licensee reviewed the Hatch 10 CFR 50, Appendix R Fire Hazard Analysis Report and the impact of the Safe Shutdown Analysis Report on Appendix R and found that operation at the l extended power uprate level does not affect the ability of the Appendix R systems to perform their safe shutdown function. Fire suppression systems, fire detection systems and operator l actions required to mitigate the consequences of a fire would not be affected. There are no physical plant configuration or combustible load changes as a result of the increase in power. l The safe shutdown systems and equipment used to achieve and maintain cold shutdown i conditions do not change and remain adequate for the extended power uprate conditions.

1 -

In the evaluation of Appendix R events, the licensee determined that the time available for operator action to initiate containment cooling was reduced. The containment cooling was assumed to be initiated three hours after the event occurs instead of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as assumed in the previous Plant Hatch Appendix R analyses. The licensee stated that the revised initiation time remains well within the expected operator response time.

l

Based on its review, the staff agrees with the licensee that the fire suppression and detection systems and their associated analyses are insignificantly impacted by power uprate, and concludes that the fire protection systems are acceptable at the extended power uprate level.

2.10.8 Additional Systems Not Impacted By Power Rerate 2.10.8.1 Additional Systems With No impact in Section 6.8 of Enclosure 6 to Reference 1, the licensee identified and evaluated plant systems that are not affected or are affected in a minor way, by operation of the plant at the uprated power level. Based on its review, the staff agrees that plant operation at the proposed uprate level has no impact, or an insignificant impact, on these systems.

k 2.10.9 Power Conversion Systems The power conversion systems were originally designed to utilize the energy available from the j nuclear steam supply system and were designed to accept the system and equipment flows t resulting from continuous operation at 1105 percent of rated steam flow. The original power l uprate to 2558 MWt involved some turbine modifications. For the extended power uprate, )

additional turbine modifications are required to accommodate the higher steam flow. j i

2.10.9.1 Turbine-Generator l

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In 1995, the Hatch Unit 1 turbine-generator was rerated to 105 percent of its original rating. In order to achieve the extended power uprate, which is 113 percent of the original rating, the high pressure turbine steam path components would require modifications of the first, second and third-stages to increase the steam flow capacity. The moisture separator reheaters (MSRs) would also require modification, which may include reheater tube bundle replacement and new moisture separator chevrons. The licensee plans to perform these modifications to Unit 1 in the Spring 1999 outage. The licensee stated that the high pressure turbine and MSRs should allow Unit 1 to operate at or near the proposed licensed power level with adequate turbine pressure control.

l Hatch Unit 2 was also rerated to 105 percent of its original rating in 1995. In 1997, new steam path hardware was installed in the Unit 2 turbine-generator to achieve the flow capacity corresponding to ~113 percent of its original rating. Tne new hardware consisted of first-stage cold assembled buckets (2 rows), new second, third and fourth-stage diaphragms, and new L redesigned second and third-stage buckets. The licensee plans to modify the Unit 2 MSRs during the Fall 1998 outage. The licensee stated that the modifications to the high pressure

! turbine and planned MSR changes should allow Unit 2 to operate at or near the proposed l licensed power level with adequate turbine pressure control.

The licensee evaluated the Hatch Unit 1 and 2 turbine-generefors to assess the impact of increased steam flow and pressure as a result of extended pt Mr uprate. The evaluations were based on the turbine control valves in the valve wide open (VWO) position for the increased power conditions. The VWO position corresponds to slightly above 108 percent of the current core thermal power of 2558 MWt. The licensee performed an overspeed calculation and compared the entrapped steam energy contained within the turbine and the associated piping 1

)

after the stop valves trip and the sensitivity of the rotor train for the capability of overspending.

It was determined that for the slight increases in the entrapped energy, an adjustment of the overspeed trip setting was not needed. Therefore, the licensee concluded that for the revised steam specifications for extended power uprate, no changes to the current mechanical trip settings would be required.

Based on its review, the staff agrees with the licensee that the modifications to the turbine- l generators and the current mechanical trip settings should allow Units 1 and 2 to operate at or I near the proposed licensed power level. Therefore, the staff concludes that operation of the modified turbine-generator at the extended power uprate level is acceptable. I 2.10.9.2 Miscellaneous Power Conversion Systems j

The licensee evaluated the miscellaneous steam and power conversion systems and their associated components at the uprated power level. The systems include the condenser and steam jet air ejectors, the turbine steam bypass and the feedwater and condensate systems.

The licensee stated that the existing equipment for these systems, with minimal modifications, are acceptable for operation at the extended power uprate level.

Since these systems do not perform any safety function, the staff has not reviewed the impact of plant operations at the power rerate level on the designs and performances of these systems.  !

2.11 High Energy Line Break Outside Containment The licensee evaluated the high energy line breaks (HELBs) against the criteria set forth in the UFSAR for HELBs outside containment. The critical parameter affecting the HELB analysis for power rerate is an increase in reactor vessel dome pressure. Since there would not be an I increase in the analyzed dome pressure, the licensee determined that there would not be an l increase in the' mass and energy release rates following HELBs. The existing mass and energy I release rates for HELBs outside primary containment were based on saturated fluid conditions )

and frictionless critical mass fluxes determined at the local reactor vessel pressure, which j assumed a 1060 psia steam dome pressure. Additional conservatism was incorporated in the )

existing analyses by neglecting all piping losses and by assuming continuous blowdown at the maximum rate. Since a steam dome pressure of 1050 psia was used for the proposed power uprate, the licensee stated that the existing HELB analyses was bounding for the proposed

. power uprate conditions for the main steam system line break, the high pressure ECCS line break, the reactor core isolation cooling system line break, the reactor water cleanup system line break, pipe whips, jet impingements and the temperature, pressure, and humidity profiles.

For flooding considerations, the feedwater system line break would be the most critical case.

l The flooding rate would depend on the hardware in the feedwater system, such as pipes and pumps. The licennae ::taied that since the feedwater system hardware would not be changing substaniialiy, the existing feedwater break flooding analysis would be valid for the extended power uprate conditions.

l l

f l l Based on its rev5w, the staff agrees with the licensee that the mass and energy releases considered for the current power level of 2558 MWt adequately represent the releases for the extended power uprate, and concludes that it is acceptable.

2.12 Integrity of Reactor Vessel and Intervals and Reactor Coolant System Piping l In Section 3.3 of NEDC-32749 and in the response to the staff's Request for Additional Information (RAI), SNC assessed the effects of the Hatch Unit 1 and Unit 2 power rerstes on i each reactor pressure vessel (RPV) and each set of reactor intemals. Regarding the RPV, the licensee provided an assessment of: (1) the impact of the uprate on the adjusted reference temperature (ART) of the limiting RPV materials; (2) the need to revise the Hatch Unit 1 and Unit 2 pressure-temperature (P-T). limit curves; (3) the changes in the predicted upper shelf I energy (USE) drop for the RPV materials and the validity of previously approved equivalent i

margins analyses; and (4) whether changes in the RPV surveillance program (as required by 10 CFR 50, Appendix H) are necessary. Regarding the reactor intemals, the licensee provided an assessment of: (1) changes in pressure differential loadings caused by the uprate; (2) changes in the assessment of flow-induced vibration caused t'y the uprate; and (3) changes in the potential for erosion damage due to the power uprate.

In analyzing the RPV, SNC examined the effect on the RPV fluence of operating Hatch Unit 1 and Unit 2 at a power of 2763 MW until end-of-license (EOL). SNC's analysis therefore addressed the expected RPV material embrittlement since it is directly related to the RPV neutron fluence, which is in tum related to the reactor operating power. In its March 9,1998, letter, SNC provided the information contained in Tables 1 and 2 on the projected EOL neutron fluence at the clad-to-base metal interface (" surface fluence"), the 1/4 T location (i.e., at a point one-quarter of the way through the RPV wall from the RPV inside diameter) and the 3/4 T location (i.e., at a point three-quarters of the way through the RPV wall from the RPV inside diameter) for each Hatch unit.

in its August 8,1997, submittal, SNC concluded that "[A] comprehensive review...[of) the reactor vessel and intemals....show continued compliance with the original design and licensing criteria for the reactor vessel." SNC went on to explain that with regard to the application of the requirements of Title 10 of the Code of Federal Regulations Part 50, Appendix G," Fracture Toughness Requirements" (10 CFR 50, Appendix G) to the Hatch Unit 1 and Unit 2 RPV materials:

"(a) The BWR Owner's Group Equivalent Margin Analyses are applicable and demonstrate that the upper shelf energy (USE) maintains the margin requirements in 10 CFR 50 Appendix G for the design life of the vessel.

(b) The 32 effective full power years (EFPY) shift is s!!ghtly increased and, consequently requires a change in the adjusted reference temperature (ART), which is the initial RT, plus the shift [ reviewers' note: plus the margin term). The beltline material adjusted reference temperature (ART) will remain well within the 200*F regulatory requirement

[ staff note: This is no longer included in 10 CFR 50 as a regulatory requirement).

f (c) The current P-T curves have been revised considering the slight increase in shift affecting the beltline portion of the curves. This increase in beltline shift affected the P-T curves for Unit 1 beyond 20 EFPY to the end of life and the P-T curves for Unit 2 beyond 28 EFPY to the end oflife."

To address these points, SNC submitted an analysis intended to bound the USE drops for the limiting base and weld metal for each Hatch unit. For this evaluation, SNC chose to conservatively assess the limiting base and weld metal (the ones with the highest copper content) for each unit by assigning them the peak vessel clad-to-base metal fluence. This was considered to be conservative since the evaluation of USE drop for each material would permit i SNC to use the 1/4 T fluence for each material in their evaluations. Based on this approach, SNC demonstrated that the predicted percentage USE drops did not exceed the amount permitted under General Electric Topical Report, NEDO-32205-A, "10CFR50 Appendix G, Equivalent Margin Analysis for Low Upper Shelf Energy in BWR/2 Through BWR/6 Vessels," as it was approved by the NRC staff. For the pressure-temperature limits, SNC submitted new pressure-temperature limits for heatup/cooldown, core criticality, and hydrostatic testing at Hatch Unit i for 20,24,28, and 32 EFPY. Similar curves were submitted for Unit 2 for 32 EFPY only.

Finally, in its March 9,1998, letter, SNC stated that when considering the possibility of a change to the RPV surveillance capsule withdrawal schedule for Unit 2 (the only unit to have a capsule yet to be pulled before EOL), "...it will not be necessary to change the removal interval due to the increased fluences associated with extended power uprate conditions."

For the RPV internals, SNC stated that the proposed power uprate will have no adverse effect on the flaw evaluations for existing flaws in the core shroud or in the core spray header. SNC also concluded that the uprate would not affect the operation of sny other reactor intemals.

SNC's evaluation of the reactor coolant system piping confirmed that changes in the flow parameter associated with the power uprate would have no significant effects on the potential for flow-induced erosion / corrosion in those systems which might be susceptible to the phenomenon (e.g., the feedwater or main steam systems).

The staff has reviewed the RPV assessment provided by SNC and determined that the changes to the P-T limit curves and the changes to the upper shelf energy analyses for each unit is acceptable and addrecs the changes in RPV material embrittlement due to the power uprate conditions. The staff has also concluded that the power uprate does not necessitate any change in the Hatch Unit 1 or Unit 210 CFR 50, Appendix H RPV surveillance program.

l In accordance with in CFR 50, Appendix G, RPV materials must maintain a USE of 50 ft-lbs throughout the life of the vessel or demonstrate that lower values provide margins of safety equivalent to those required by Appendix G to Section XI of the American Society for Mechanical Engineers (ASME) Code. Based upon the 2763 MW 1/4T fluence values submitted by SNC, the staff concluded that the (percentage) upper shelf energy drop for the limiting Hatch Unit 1 RPV weld and base metal materials at EOL submitted by SNC was consistent with or more conservative than the results achieved by the staff using the Regulatory Guide 1.99, Revision 2 methodology. However, in the analysis for the limiting weld of Hatch Unit 1, there was a significant difference between SNC's and the staff's evaluation. SNC used a copper f

1 weight percent value of 0.28 for the limiting heat 1P2815 lower-intermediate shell axial weld and the peak vessel clad-to-base metal fluence of 1.94 x 10 n/cm2 (at 32 EFPY) to arrive at a USE drop of 29 percent. The staff, based on their examination of the Combustion Engineering Owners Group report, CEOG NPSD-1039, Revision 2, "Best-Estimate Copper and Nickel Values in CE Fabricated Reactor Vessel Welds," noted that a best-estimate copper value for this weld wire heat based on all available information was given as 0.316 weight percent. Using the 0.316 weight percent copper value and the 1/4 T fluence for the 1P2815 weld at EOL of 1.4 x 10 n/cm', the staff also concluded that the USE drop would be 29 percent. By either methodology, this was less than the allowable drop of 34 percent documented in NEDO-22205-A as acceptable for BWR/4 RPV weld materials. The NRC staff, as part of a separate action to resolve issues related to Generic Letter 92-01, " Reactor Vessel Integrity," has issued RAls to SNC and other licensees which address issues regarding best-estimate chemistries. Since the specific chemistry for the 1P2815 weld does not adversely affect its USE evaluation when the other conservatism in the SNC approach is eccounted for, the staff has chosen to not pursue resolt, tion of the weld chemistry issue in the process of the extended power uprate review, but I will revisit the issue in the Generic Letter 92-01 RAls. Therefore, SNC has demonstrated that the Hatch Unit 1 and Unit 2 RPV materials retain margins of safety equivalent to those required by ASME Code Section XI, Appendix G.

In evaluating the effect of the power uprete on the shift in limiting materials adjusted reference -

temperature and the need for new P-T limit curves, the staff applied the methodology found in Regulatory Guide 1.99, Revision 2 for evaluation radiation embrittlement. This methodology specifies that a material's ART can be determined from the following equations:

i ART = lnitial RTuor + ARTuor + Margin j where, ARTuor = CF x FF i I

with, CF = the Chemistry Factor, a function of copper and nickel content

]

FF = the Fluence Factor, a function of the RPV material's neutron fluence l and, Margin = a value added to account for analytical uncertainties.

For Hatch Unit 1, the limiting material was found to be plate G-4803-7. This plate has an assigned CF of 334 'F based upon the application of the credible Hatch Unit 1 plate I

surveillance data to its CF determination. The methodology used by SNC to establish this value was reviewed and approved in a staff SER dated August 19,1997, and since the extended power uprate conditions do not affect the CF determination, it was not re-reviewed in this analysis. However, the staff has asked for additional information regarding the licensee's methodology for establishing these RPV capsule fluences and will revisit this issue if significant concems are discovered. Given the margins and factors of safety which are explicitly l incorporated into the determination of P-T limits curves (Km fracture toughness curve, factors of l

1.5 to 2 on pressure stresses,1/4 T flaw postulation, etc.) and the conservatism in the licensee's analysis, the staff has determined that the application of a CF of 334 'F is sufficient pending additienal staff review. Note, the difference in chemistry assigned the 1P2815 wold by the licensee and the NRC (as mentioned in the USE analysis) did not affect the P-T limits l

1 evaluation since Plate G-4303-7 continued to be the limiting material even when the higher copper content was evaluated by the NRC staff.

Also, given that the credible surveillance data was still being used, the margin term assigned in the analysis did not change from that in the August 19,1997, SER. However, the fluences (and fluence factors) associated with the beltline materials at 20,24,28, and 32 EFPY of operation did change due to the extended power uprate. Based upon the fluences provided in the March 9,1998 SNC letter, the staff checked the heatup/cooldown, core criticality, and hydrostatic test curves provided by SNC in Enclosure 4 to the original extended power uprate submittal. The staff found that the curves submitted by the licensee were consistent with or conservative to those determined by the staff using the methodology of the 1989 Edition of the ASME Code,Section XI, Appendix G. Those portions of the curve which were determined by consideration of the non-beltline regions of the RPV (bottom head, flange, etc.) were checked against those previously approved by the staff and also found to be acceptable. The curves approved by the staff for Unit 1 have been included as Figures 1,2, and 3.

For Unit 2, the CFs for all materials were determined by using the Table CFs in Regulatory Guide 1.99, Revision 2 since no credible surveillance data exists for either weld or plate materials. In the staff's most recent SER on updating the Hatch Unit 2 P-T curves (dated April 4,1997), the staff noted that the limiting material for the Hatch Unit 2 RPV was lower shell course axial weld 101-842 fabricated using weld wire heat number 10137. In that analysis, SNC had assigned the peak RPV 1/4 T fluence value to all of the beltline axial welds. In the extended power uprate submittal, SNC differentiated between the peak fluences for the axial welds in the lower-intermediate shell course (0.157 x 10 n/cm2 at the 1/4 T location, ff=0.513) and the axial welds in the lower shell course (0.0947 x 10 n/cm2 at the 1/4 T location, ff=0.406). Because of this differentiation, the lower-intermediate shell course axial welds manufactured with weld wire heat 51874 became the limiting material for the Hatch Unit 2 vessel. SNC reported a chemistry for the 10137 weld of (0.23 wt percent Cu,0.50 wt percent Ni, CF=155) and a chemistry for the 51874 weld of (0.18 wt percent Cu,0.50 wt percent Ni, CF=138).

Based upon the fuences provided in the March 9,1998, SNC letter, the staff checked the heatup/cooldown, core criticality, and hydrostatic test curves provided by SNC in Enclosure 4 to the original extended power uprate submittal. The staff found that the curves submitted by the licensee were consistent with or more conservative than those determined by the staff using the l methodology of the 1989 Edition of the ASME Code,Section XI, Appendix G. Those portions of the curve which were determined by consideration of the non-beltline regions of the RPV (bottom head, flange, etc.) were checked against those previously approved by the staff and also found to be acceptable. The curves approved by the staff for Unit 2 have been included as Figures 4,5, and 6.

The staff is reviewing information from SNC on its RPV fluence methodology. Pending the completion of the review of this methodology, the staff accepts the application of the fluences proposed by SNC in their March 9,1998, submittal for each Hatch unit. Given the margins and factors of safety which are explicitly incorporated into the determination of P-T limits curves (Km fracture toughness curve, factors of 1.5 to 2 on pressure stresses,1/4 T flaw postulation, etc.)

and the conservatism in the licensee's analysis, the staff has determined that these fluences

are sufficient at this time. In addition, in the case of Unit 2, the staff has noted that the chemistry values proposed by SNC for the two weld wire heats noted above (51874 and 10137) are both significantly higher than the best-estimate chemistries reported in the 1997 Combustion Engineering Owners Group report NPSD-1039, Revision 2, "Best-Estimate Copper and Nickel Values in CE Fabricated Reactor Vessel Welds." This may provide additional conservatism in the case of the curves proposed for Unit 2. An RAI has been issued to Plant Hatch (April 24,1998) as a follow-up to Generic Letter 92-01, Revision 1, Supplement 1 to resolve these chemistry issues. The staff will also revisit the issue of the RPV fluences if significant concerns are discovered in the course of the staff's review of the SNC fluence methodology.

Finally, based on the information cited above regarding the change in RPV fluence, the staff concurs with SNC's conclusion that no modification of the Hatch Unit 1 or Unit 2 RPV surveillance program is necessary due to the power uprate. However, the staff would note that some concems have been raised regarding BWR RPV surveillance programs in general with the Boiling Water Reactor Vessels and Internals Project (BWRVIP). These issues question whether certain BWRs possess unirradiated baseline surveillance data from which to measure changes in RPV material embrittlement and, if the data is not available, what actions can or should be taken to address the issue. Hatch Unit 1 has been one facility identified by the staff as potentially lacking baseline data for some surveillance program materials. While this topic does not directly affect the status of the faci!ity's power rerate review, the staff expects that

. SNC will participate in BWRVIP to addresc this outstanding issue.

The staff has reviewed the licensee's evaluations regarding the effect of the power uprate on core shroud and core spray piping and concludes that the licensee has bounded the effects of power rerate on the existing flaws. The staff concludes that the proposed power uprate will not affect the operation of core shroud, core spray header, or any other RPV intemals. The proposed power uprate will slightly increase the susceptibility of the RPV piping to erosion / corrosion (E/C), but it should not cause an adverse increase in E/C orovided that SNC reexamines its E/C inspection programs in light of plant-specific uprate concems (i.e.,

increased flow-induced E/C in systems associated with the turbine cycle). Special attention should be paid to the plant specific basis for selecting the locations for E/C inspections to determine whether additional locations need to be included in the E/C inspection program.

Based on the information presented above, the staff has concluded that RPV integrity, RPV internals, and RCS erosion / corrosion issues have been adequately addressed in the SNC submittal and that the power rerate license amendment (to 2763 MWth) should be approved for l Hatch Units 1 and 2.

l

I I

I I

Table 1 - Peak Fluences for Plant Hatch Unit 1 Beltline Materials at 32 EFPY l

Component Heat or Surface Fluence 1/4 T Fluence 3/4 T Fluence l 2 2 Heat / Lot (n/cm ) (n/cm )

2 (n/cm )

Plates, Lower Course:

C4112-1, C4112-2, 1.32 x 10 9.00 x 10" 4.18 x 10" C4149-1 Plates, Lower-int.

Course:

C4337-1, C3985-2 1.94 x 10 1.40 x 10 7.37 x 10" C4114-2 Welds, Lower, Longitudinal:

13253,1092 1.32 x 10 9.00 x 10" 4.18 x 10" Welds, Lower-Int.,

Longitudinal:

1P2809 1.94 x 10 1.40 x 10'8 7.37 x 10" 1P2815 1.94 x 10 1.40 x 101s 7.37 x 10"

Welds, Circumferential:

90099 1.32 x 10 9.00 x 10" 4.18 x 10" 33A277,0091 1.32 x 10 9.00 x 10" 4.18 x 10 7 i.

I I

J

Table 2 - Peak Fluences for Plant Hatch Unit 2 Beltline Materials at 32 EFPY Component Heat or Surface Fluence 1/4 T Fluence 3/4 T Fluence 2 2 Heat / Lot (n/cm ) (n/cm )

2 (n/cm )

Plates, Lower Course:

C8553-2, C8553-1, 1.39 x 10 9.47 x 10" 4.41 x 10" C8571-1 Plates, Lower-Int.

Course:

C8554-1, C8554-2 2.17 x 10 1.57 x 10 8.25 x 10" C8579-2 j Welds, Lower, Longitudinal:

10137 1.39 x 10 9.47 x 10" 4.41 x 10" Welds, Lower-Int.,

Longitudinal:

51874 2.17 x 10'8 1.57 x 10 8.25 x 10"

Welds, Circumferential:

4P6052 1.39 x 10 9.47 x 10" 4.41 x 10" I

1 l

l l

l

.j

l Figuro 1 Res P/r uurrS 3.4.9 ,

1400 , l A- SYSTEM j l '

HYDROTESTUMIT f! INITIAL RTndt VALUES ARE 1300 -

WITH FUELIN THE * . [j

.- ,, 20 207 FOR BELTUNE.

VESSEL FOR j ' 24 407 FOR UPPER VESSEL

$ AND HATCH 1 f 2E 1200 ,

.L_ n 107 FOR BOTTOM HEAD l

1100

! I II I HEATUP/COOLDOWN l l r f

RATE 207/HR goog a

l

]

I BELTINE CURVES ff ADJUSTED AS SHOWN:

'i g 800

!l ff EFPY 20 SHIFT (T) 142 goo I!

• l' I

l f//

fff

,f BELT 1NE CURVES f ADJUSTED AS SHOWN:

E 700 / / f f EFPY SHIFT (T) g *  : f 24 157 l

g

,g -

i BELTINE CURVES l i )[(f ADJUSTED AS SHOWN:

EFPY 500 .  ! // SHIFT (T) 28 167 -

• 400 7i SELTINE CURVES i ADJUSTED AS SHOWN:

EFPY SHIFT (T) 300 - a !sia rsio! 32 180

,og i j FLANGE eELTUNE-  : REWON - BELTINE UMiT3 AND < ny 100 80770M - = BOTTOM HEAD HEAD say .

UPPER VESSEL 0 )

0 50 100 150 200 250 300 350 400 MINIMUM REACTOR VESSEL METAL TEMPERATURE (T) tue r rueii i Figure 3.4.9-1 Pope 1 of 1)

Pressure /rempera(ture UmHs for i

Inservice Hydrostatic ond inservice Lookoge Tests  ;

i i

Hotch UnN 1 3.4-25 Proposed 8/97 l

Figura 2 RCs e/r uurrs 3.4.9 1400 e

j I 1300 -

B -CORE NOT l  !

{ CRITICAL UMIT FOR HATCH 1 j INITIAL RTndt VALUES ARE l l 2tfF FOR BELTUNE.

1200 , 8 4(PF FOR UPPER VE8SEL, AND l

e 1 10TPOR BOTTOM HEAD 1100  ?

l l HEATUP/COOLDOWN j

g' I

! 1 RATE 100*FMR E '

i J h b i

• l 800 I I j

. *  : BELT 1NE CURVES g g / i ADJUSTED AS SHOWN g , -

f EFPY SHIFT (V) 32 180 g

E 600

/

i /

E

) l 5 soo -

\

4%

/

ll I l I / -5ELTINE UMITS 200 aETUNE

/

,. - - BOTTOM HEAD Ale .

LBMTS BOTTOM M /

100 -'

. . . . . . UPPER VESSEL

' LBMTS

.* PLmas masson i NT 0 '

O SO 100 180 200 250 300 350 400 INN! MUM REACTOR VESSEL METAL TEMPERATURE (T)

] IatAD1 F3421 1 Figure 3.4.9-2 (Pops 1 of 1)

Pressure / Temperature Umtts for Non-Nuclear Hootup.

I Low Power Physics Tests, and Cooldown Following a Shutdown Hotch Unit 1 3.4-26 Proposed 8/97 l

Figura 3 ,es ,fr uurrs 3.4.9 1400 C. CORE 1300 '-

CRITICAL UMrT FOR HATCH 1 INITIAL RTnot VALUES ARE I

-20*F FOR BELTUNE, 1200 40*F FOR UPPER VESSEL, AND 10*F FOR BOTTOM HEAD 1100 I 3g HEATUP/COOLDOWN RATE 100*F/HR

' .00 /

l

~

l- ,

h 700 SELTINE CURVES U

ADJUSTED AS SHOWN:

EFPY SHIFT (*F) 600  !

' 32 180 500 /

400 i

300

-8ELTUNE AND 200 NON SELTUNE UMtTS yg - idWmum Crlboekty Temperature 78*F )

f I 3 \/

0 60 100 150 200 250 300 350 400 miNimuu REACTOR vE8 set METAL TEMPERATURE m r35577 min F1gure 3.4.9-3 (Pope 1 of 1)

Pressure / Temperature UmNs for CrtHoolNy i Hatch Unit 1 3.4-27 Proposed 8/97 l l

\

Figura 4 RCS P/T UWf73 1400 3.4.9 A' A I

INITIAL RTnot VALUES ARE 1300 60*F FOR BELTUNE 26*F FOR UPPER VESSEL, AND 1200 60*F FOR SOTTOM HEAD SELTINE CURVES 1100 ADJUSTED AS SHOWN EFPY SHIFT (*F) 32 127 I1000 i #00 /

NEATUP/C001.DOWN RATE 2FF/HR 800 FOR OURVE A 700 /

800 A*- CORE DELTUNE E

A - NON-BELTUNE l 600 A - PRESSURE TEST WITH FUEL M THE VESSEL E 400 (

-NON4ELTUNE 300 pta pso! -- ..BELTUNE AT 32 200 13VAUh 32 EFPY 0F OPEi ATION.

N oot CURVE A ts VAUD UP 70 32 EFPY

! F0fBb ND 0 EOL FOR NON-BELTUNE.

0 50 100 150 200 280 300 350 400 MINIMutt REACTOR VESSEL BETAL TE3PERATURE ("P)

L ce.mc i.

Figure 3.4.9-1 (Pese 1 of 1)

Pressure / Temperature UmNo for l '

Inservloe Hydrostotle end inservloe Lookope Teste Heteh Unit 2 3.4-2s Propeoed S/s7 c

Figura 5

=Cs */t Lju" ,

1400 S B'

! INITLAL RTndt VALUES ARE 1300 50*F FOR BELTUNE 26*F FOR UPPER VESSEL, AND 1200 ,

50"F POR 90TTOM HEAD i SELTINE CURVES 1100 ,

ADJUSTED AS SHCM1t EPPY SHIFT (*F) 32 127 1000 s 800 -

E NEATUP/C00LDOWN y_ RATE 10(FF/NR FOR CURVE 9

,00 l

i lsoo E

j 8'- CORE DELTUNE 3 - NON-BELTUNE B - NON-NUCLEAR I

5 500 j NEATUP/COOLDOWN

)

I CORE NOT CRITICAL 400 ' I

- NON-8ELTUNE zoo (st:Psrs! '

/ . . . . . .

N

,m,. AT ,

CURVE B'

!

• 18 YAUD UP 70 32 EFPY OF OPERATION.

too

" 2 CURVE B IS VAUD UP 70 32 EFPY

' 0F OPERATION FOR SELTUNE AND EOL FOR NON-SELTUNE.

0 50 100 150 200 280 300 350 400 RENIMUM REACTOR VESSEL METAL TEMPERATURE ("F) l Figure 3.4.9-2 Pope 1 of 1)

Pressure / Temperature umHs for Non-Nuclear Hootup.

Low Power Physles Tests, and Cooldown Following a Shuhlown Motoh Unit 2 3.4-24 Proposed 8/97

)

)

Figura 6 -

RCS P/T UMITS 3.4.9 1400 C C' INITLAL RTnot VALUES ARE 1300 50*F FOR SELTUNE 26*F FOR UPPER VESSEL,

, MD 1200 50*F FOR BOTTOM NEAD SELTINE CURVES ADJUSTED AS BHOWN 1100 W SHIFT m j 32 127 5 1000 m

i e, 900 E NEATUP/COOLDOWN I RATE 10FF/NR r0R curve C I*** 1 700 g

E s00 j C'- CORE DELTUNE E C - NON-BELTUNE C - NON-NUCt. EAR I 500 NEATUP/C00LDOWN CORE NOT CRITICAL goo l

l )

--NON 8ELTUNE

- .. 8ELTUNE AT32 300 dia,gg f EPPY CURVE C' 200 is VAUD UP TO 32 EtW OF OPERATION.

1. p 100 I CURVE C t$ VAUD UP TO 32 EFPY

/ OF OPERATION FOR DELTUNE AND 0 f EOL FOR NON-BELTUNE, 0 50 100 150 200 250 3C0 350 400 anNimum REAcrom VESSEL METAL TEMPERATURE (*P) f3EiBT"F5W 1 Figure 3.4.9-3 (Pope 1 of 1)

Ptwesure/ Temperature Umits for Crtfloolity Hotch UnM 2 3.4-27 Proposed 8/97

~

I i

2.13 instrumentation and Control The setpoint changes for the identified instrumentation for the new power level are predicated  !

on tt'e assumption that analytical limits used by the licensee are based on the application of apprcved design codes.

The folicwing TS changes have been proposed by the licensee:

1. TS Section 3.3.4.1, End-of-cycle recirculation pump trip Applicability for Limiting Condition of Operation 3.3.4.1, Required Action C.2 and SR 3.3.4.1.2, the operability requirements for end-of-cycle recirculation pump trip has been changed from 30 percent to 28 percent. ,

2. TS Section 3.3.1.1, RPS Instrumentation, Required Action E.1, Surveillance Requirement 3.3.1.1.11, and Functions 8 & 9 of TS Table 3.3.1.1-1 The power level at which the direct scram, for Turbine Stop Valve closure and Turbine Control Valve fast closure, is bypassed has been reduced from 30 percent to 28 percent.

3. TS Table 3.31.1-1, Function 2.b, APRM Simulated Thermal Power Scram, Flow Bias -

For two-loop operation, the allowable value has been changed from 0.58w+62 percent to 0.58w+58 percent.

For single loop operation, the allowable value has been changed from 0.58w+62 percent-  ;

0.584w to 0.58w+58 percent-0.58aw.

4. APRM Rod Block, Flow Bias-Trip setting has been changed from 0.58w+50 percent-0.584w to 0.58w+51 percent-0.584w.

i In addition to the above changes, the licensee will implement new setpoints for the j instrumentation which is listed in the TS as percentage of flow or pressure, while the l percentage will not be changed. The licensee has identified this instrumentation as follows:

i (a) APRM Scram (b) Main Steam Line High Flow The licensee has also revised the associated TS Bases io be consistent with the changes to the TS. Reference 1 identified that the instrument setpoint methodology is the same as that used for the previous 5 percent power uprate. The staff has previously reviewed this instrument setpoint methodology and found it acceptable for establishing new setpoints in power uprate ,

applications.

{

The proposed setpoint changes resulting from the power uprate are intended to maintain existing margins between operating conditions and the reactor trip setpoints and do not {

l

significantly increase the likelihood of a false trip nor failure to trip upon demand. Therefore, the existing licensing basis is not affected by the setpoint changes to accommodate the power uprate.

Based on the above review and justifications, the staff concludes that the licensee's instrument setpoint methodology and the resulting setpoint changes incorporated in the TS for the power uprate are consistent with the Hatch licensing basis and are, therefore, acceptable.

3.0 STRUCTURAL AND PRESSURE BOUNDARY INTEGRITY The staff's review of the safety analysis report provided by the licensee, focused on the effects of power uprate on the structural and pressure boundary integrity of the piping systems and components, their supports, and reactor vessel and internal components and the Control Rod Drive Mechanism (CRDM), certain pumps and valves, and the balance-of-plant (BOP) piping systems.

3.1 Reactor Pressure Vessel (RPV) and intemals The licensee evaluated the reactor vessel and intemal components in accordance with the current licensing basis. Load combinations include reactor internal pressure difference (RIPD),

LOCA, and seismic loads. The seismic loads are unaffected by the power uprate. The licensee recalculated RIPDs for the proposed extended power uprate shown in Tables 3-2,3-3 and 3-4 of NEDC-32749P (Enclosure 6 to Reference 1), for normal, upset and faulted conditions, respectively.

The stresses and cumulative fatigue usage factors (CUFs) for the reactor internal and vessel components were evaluated by the licensee in accordance with code of record at Hatch, the ASME Boiler and Pressure Vessel Code, Section ill,1965 Edition with Winter 1966 addenda for Hatch Unit 1 and 1968 Edition with 1970 addenda for Hatch Unit 2. The load combinations for normal, upset and faulted conditiorls were considered in the evaluation. The maximum stresses for critical components of the reactor internals were summarized in Table 3-1 of NEDC-32749P and Table 19-1 of Reference 2 for the current operating and the power uprate conditions. The calculated stresses are less than the allowable code limits shown in the table.

In Reference 2, the licensee indicated that the proposed extended power uprate evaluation was performed for the current reactor configuration incorporating recent shroud repair modifications based on the original repair modification analysis which was previously approved by the staff.

In Reference 2, the licensee also indicated that the Unit 1 feedwater nozzis, control rod drive l nozzle, and vessel shell, and the Unit 2 feedwater nozzle, closure vessel shell, closure region l bolts, and basin seal skirt were reanalyzed for the proposed extended power uprate. For these j limiting components, the licensee provided the calculated CUFs in Table 3-5 of NEDC-32749P

! and the calculated stresses in Tables 24-1 and 24-2 of Reference 2. The staff finds that the calculated CUFs and stresses provided by the licensee are within the code allowable limits. In Reference 2, the licensee indicated that the feedwater nozzle evaluation uses the 1974 ASME Code edition with addenda to and including Summer of 1976 for Unit 1, and 1971 ASME Code edition with addenda to and including Summer 1973 for Unit 2. The licensee also provided a description of the methodology for evaluating the structuralintegrity of the reactor vessel and

components for the requested power uprate. The staff finds that the methodology used by the licensee is consistent with the NRC approved methodology in Appendix i of Reference 6, and is therefore acceptable.

In Reference 2, the licensee stated that the CUF for the Unit 2 feedwater nozzle was initially calculated to be greater than 1.0 using the design basis approach, and was recalculated to be 0.93 for 40 years of operation by combining CUFs based on the actual cycles counting record during plant operation and based on the design basis cycles for the proposed power uprate condition. The staff finds that the method of counting actual cycles has been used previously by Hatch and other nuclear plant facilities to compute CUF, and the CUFs so calculated are realistic and acceptable.

The licensee assessed the potential for flow-induced vibration based on the GE prototype plant vibration data for the reactor intemal components recorded during startup testing and on operating experience from similar plants. The vibration levels were calculated by extrapolating the recorded vibration data to power uprate conditions and compared to the plant allowable limits for acceptance. The licensee found the maximum flow induced vibration at the jet pump j riser braces to be within the acceptance limit for the Hatch proposed power uprate condition.

Based on its review of the information provided by the licensee, the staff finds that the maximum stresses and fatigue usage factors are within the code-allowable limits, and concludes that the reactor vessel and intemal components will continue to maintain their structural integrity for the power uprate condition.

3.2 Control Rod Drive System The licensee indicated that the CRDMs have been designed in accordance with the code of record, the ASME Boiler and Pressure Vessel Code Section ill,1965 Edition with addenda to and including Summer 1966 for Unit 1, and 1968 Edition with addenda to and including Summer 1970 for Unit 2. The components of the CRDM which form part of the primary pressure boundary, have been designed for a dome pressure of 1250 psig which is higher than the reactor bottom head pressure of 1075 psi for normal and uprated power conditions.

In Reference 2, the licensee indicated that the maximum calculated stress for the CRDM indicator tube is 20,790 psi which is less than the allowable stress limit of 26,060 psi. The maximum stress on these component results from a maximum control rod drive (CRD) intemal hydraulic pressure of 1750 psig with no other event having a significant impact on the total load.

The analysis of cyclic operation of the CRDM resulted in a maximum CUF of 0.15 for the l limiting CRD main flange for the power uprate. This is less than the code-allowable CUF limit of 1.0.

On the basis of its review, the staff concludes that the CRDM will continue to meet its design basis and to maintain its structural and pressure integrity at the uprated power conditions.

3.3 Reactor Coolant System Piping and Components The licensee evaluated the effects of the power uprate condition, including higher flow rate, temperature, pressure, fluid transients and vibration effects on the reactor coolant pressure boundary (RCPB) and the BOP piping systems and components. The components evaluated included equipment nozzles, anchors, guides, penetrations, pumps, valves, flange connections, and pipe supports. The evaluation was performed using the original code of record specified in the Hatch FSARs, the code allowables, and analytical techniques. No new assumptions were introduced that were not in the original analyses.

The RCPB piping systems evaluated include main steam piping, reactor recirculation piping, feedwater piping, RPV bottom head drain line, reactor water cleanup (RWCU), reactor vessel head vent line, reactor core isolation cooling (RCIC), core spray piping, high pressure coolant injection piping (HPCI), residual heat removal (RHR), safety / relief valve (SRV) discharge piping and CRD piping. The evaluation included appropriate components, connections and supports.

The licensee's evaluation of the RCPB piping systems consisted of comparing the increase in pressure, temperature and flow rate against the same parameters in the original design basis analyses. The percentage increases in pressure, temperature, and flow for affected limiting piping systems were identified in Tables 3-6 and 3-7 of the uprate license amendment request of NEDC-32749P. l As summarized in Tables 3-6 and 3-7, a majority of the RCPB systems were originally designed to maximum temperatures and pressures that bound the increased operating temperature and pressure due to the power uprate. For those systems whose design temperature and pressure did not envelop the uprate power conditions, the licensee performed stress analyses in  ;

accordance with the requirements of the code and the code addenda of record for the power  !

uprate conditions. The licenses found that the original design analyses have a sufficient margin between calculated stresses and ASME allowable limits to justify operation at the higher operating flow, pressure and temperature for the proposed power uprate. The licensee indicated that all' safety-related piping was analyzed using the licensing basis computer codes.

The licensee concluded that the evaluation showed compliance with all appropriate Code requirements for the piping systems evaluated and that power uprate will not have an adverse effect on the reactor coolant piping system design. The staff reviewed selected portions of the licensee's evaluation and finds that the licensee's conclusions are acceptable.

The licensee evaluated the stress levels for BOP piping and appropriate components, connections and supports in a manner similar to the evaluation of the RCPB piping and

- supports based on increases in temperature and pressure from the design basis analysis input.

The evaluated BOP systems include lines which are affected by the power uprate, but not evaluated in Section 3.5 of Reference 1, such as feedwater heater piping, main steam bypass lines, and portions of main steam, recirculation, feedwater, RCIC, HPCI, and RHR systems outside the primary containment. The limiting stress ratios of maximum calculated stresses to the allowable, resulting from the BOP piping evaluations for the power uprate is shown in Table 29-1 of Reference 2. The licensee concluded that all piping is below the code-allowable limits. The staff finds that the stress ratios provided by the licensee are within the code-allowable limits and are, therefore, acceptable.

l

)

The licensee evaluated pipe supports such as snubbers, hangers, struts, anchorages, equipment nozzles, guides, and penetrations by evaluating the piping interface loads due to the increases in pressure, temperature, and flow for affected limiting piping systems. The licensee indicated that there is an adequate margin between the on@al design stresses and code limits of the supports to accommodate the load increase and as such, all evaluated pipe supports were within the code-allowable limits. The licensee reviewed the original postulated pipe break analysis and concluded that the existing pipe break locations were not affected by the power uprate, and no new pipe break locations were identified. The staff finds the licensee's evaluation to be accetable.

Regarding the assessment of the main steam flow restrictor, the licensee stated that there is no impact on the structuralintegrity of the restrictor for the power uprate. In Section 3.2 of the power uprate license amendment request, the licensee indicated that a higher peak RPV ,

transient pressure of 1325 psig results from the Hatch plant operation at 2763 MWt conditions, but this value remains below the ASME code limit of 1375 psig. Therefore, the main steam line j flow restrictor will maintain its structural integrity following the power uprate since the restrictor was designed for a differential pressure of 1375 psig which envelops the evaluated power uprate conditions.

Based on the above review, the staff concludes that the design of piping, components and their supports will be adequate to maintain the structural and pressure boundary integrity of the BOP and reactor coolant piping, components and supports in the proposed power uprate.

3.4 Equipment Seismic and Dynamic Qualification The licensee evaluated equipment qualification for the powar uprate condition. The dynamic loads such as SRV discharge and LOCA loads (including pool swell, condensation oscillation, j and chugging loads) that were used in the equipment design will remain unchanged as discussed in Section 4.1.2 of NEDC-32749P because the plant-specific hydrodynamic loads defined during the Mark l Containment Long Term Program (LTP) for the design-basis analysis at Hatch are bounding for the power uprate.

Based on its review of the proposed power uprate amendment, the staff finds that the original seismic and dynamic qualification of the safety-related mechanical and electrical equipment is not affected by the power uprate conditions for the following reasons:

1. Seismic loads are unchanged for the power uprate; 2.- No new pipe break locations or pipe whip and jet impingement targets are postulated as a result of the uprated conditions;

3. Pipe whip and jet impingement loads do not increase for the power uprate; and

4. SRV and LOCA dynamic loads used in the original design basis analyses are bounding for the power uprate.

3.5 Safety-Related SRV and Power-Operated Valves In Reference 2, the licensee indicated that the current approved SRV setpoint tolerance (+/ 3 percent) was incorporated in the abnormal transient and accident analyses at the uprate

(

conditions. The licensee determined that peak RPV steam pressure remains below the ASME allowable of 110 percent of design pressure and that safety-related SRV operability is not affected by the proposed changes. The licensee stated that the plant-specific analyses for the power uprate condition conservatively assume one SRV out of service. This additional margin in the plant-specific analyses provides reasonable assurance that the postulated SRV setpoint drift would not result in the maximum allowable system pressure being exceeded. Furthermore, the maximum operation reactor dome pressure remains unchanged for the Hatch extenced power uprate. Consequently, the licensee concluded that the SRV setpoints and analytical limits are not affecter l 5y the proposed power uprate, and that the SRV loads for the SRV l discharge line piping will remain unchanged.

Based on its review, the staff concludes that the SRVs and the SRV discharge piping will I continue to maintain the structural integrity and to provide sufficient overpressure protection to f accommodate the proposed extended power uprate.

In Reference 2, the licensee indicated that the extended power uprate will not increase any  !

system operating pressure, reactor pressure, or safety relief valve setpoints. The licensee also stated that the valve differential pressures and line pressures were not affected by the extended pc.ver uprate. The licensee provided a table indicating the impact of the extended power uprate on plant systems and components. Baced on its review, the licensee concluded that revision of the motor-operated valve (MOV) and air-operated valve (AOV) programs at Hatch were not necessary. The licensee provided follow up information in Reference 4.

In 1995, the NRC steff evaluated the Hatch MOV program developed in response to Generic Letter (GL) 89-10, " Safety-Related Motor-Operated Valve Testing and Surveillance" during inspections in February 1995 (documented in inspection Report 50-321,366/95-02) and December 1995 (documented in inspection Report 50-321,366/95-25). Because the staffc inspections on the Hatch MOV program under GL 89-10 were conducted prior to full implementation of the initial power, the licensee described in Reference 4 changes to the MOV .

j program at Hatch resulting from the increased reactor pressure associated with the initial power J l uprate which was approved by the NRC on August 31,1995 (Reference 13).

The licensee reviewed the plant-specific information on Hatch systems and components for the i extended power uprate to determine its potential effect on the performance of mechanical l components, in References 2 and 4, the licensee concluded that there will be no significant l effect on pumps and valves at Hatch from the extended power uprate. Further, the licensee evaluated changes in environmental temperatures and MOV electric power supplies and found that the proposed power uprate has no impact ~on the licensee's GL 95-07 (" Pressure Locking and Thermal Binding of Safety Related Power Operated Gate Valves," dated August 17,1995) evaluation regarding valve pressure locking or thermal binding. The licensee also indicated that it will incorporate the proposed power uprate condition in the evaluation in response to GL 96-06 (" Assurance of Equipment Operability and Containment Integrity During Design Basis Accident Conditions," dated September 30,1996) on potential overpressurization of isolated piping segments at Hatch. The NRC staff will complete the review of the licensee's response to GL 95-07 and GL 96-06 separate from this power uprate request.

Based on its review and the information provided by the licensee, the staff concludes that the proposed power uprate will not have an adverse effect on the performance of mechanical components of safety-related pumps and valves at Hatch.

Based on its review, the staff concludes that the licensee's proposed power uprate amendment has no adverse effects on the structural and pressure boundary integrity of piping systems, components, their supports, reactor intemals, core support structure, and the CRDS, and is therefore acceptable.

4.0 DESIGN BASIS ACCIDENT RADIOLOGICAL CONSEQUENCES The licensee re-evaluated the radiological consequences of the following three postulated design basis accidents (DBAs) at an uprated reactor power level of 2818 MWt (102 percent of uprated reactor power of 2763 MWt) in Section ').3 of the license amendment request (Reference 1) and in a separate submittal dated April 17,1997 (Reference 6). The analyzed DBAs are (1) Loss-of-Coolant Accident (LOCA), (2) Fuel Handling Accident, (3) Control Rod Drop Accident. The licensee provided an additional information on radiological consequence analyses (Reference 3) in response to the staff's request for additional information. The licensee stated in the amendmcnt request, and the staff agrees, that the main steam line break accident outside containment was not reanalyzed because the mass flow rate from the postulated main ateamline break is unchanged from the original power uprate. The licensee conciudes that the radiological consequences of an accident subsequent to iraplementation of Hatch power uprate remain well below the dose criteria specified in 10 CFR Part 100 and GDC 19 of Appendix A to 10 CFR Part 50.

The staff reviewed the radiological consequence analyses performed by the licensee and finds that the calculational methods used for the radiological consequence assessments are acceptable. With the following comments on the use of the computer code ARCON95 to determine the control room relative concentration (X/Q) values. The licensee has calculated the control room X/Q values using calendar year 1995 hourly meteorological data and the ARCON95 methodology described in NUREG/CR-6331, " Atmospheric Relative Concentrations in Building Wakes." The licensee has calculated X/Q values for various postulated ground level release point and intake pairs. Elevated release calculations were also made for a postulated release from the 120 meter plant stack.

The ARCON95 methodology calculates plume centerline X/Q values for the 0-2 hour time period following the beginning of the postulated accident and sector average X/Q values for the remaining time of the accident. The centerline concentration should be calculated for the 0-8 time period following initiation of the accident. Therefore, the staff made calculations of the l centerline X/Q for the 0-8 hour time period using the ARCON96 methodology and compared the results with the licensee's calculations. The staff has concluded that, for this specific accident scenario, the impact on the total resultant dose in using the highest X/Q centerline concentration only for the 0-2 hour time period is not significant.

The licensee has used calendar year 1995 hourly meteorological data in its assessment of the control room X/Q values. Use of a single year of data could result in uncertainties due to year to ) ser variabilities in meteorological conditions. However, the licensee performed a

i 44 comparison and provided summaries of historic plant data to demonstrate that the data used in its calculations of the X/Q values are adequately representative of long term conditions. Winds at the 10 meter level at the Hatch site appear to be lighter than expected when compared with expectations based on winds at the 60 meter and 100 meter measurement levels. However, the staff has concluded that for this specific accident scenario, the impact on the total resultant dose is not significant.

Therefore, the staff finds the use of the control room X/Q values as listed in Table 2 proposed by the licensee to be acceptable. The licensee should, however, use a methodology that calculates the centerline relative concentrations for the 0-8 hour time period when making any additional calculations of control room X/Q values in the future.

l To verify the licensee's conclusion, the staff performed an independent radiological i consequence analysis using that performed by the staff for the LOCA in License Amendment No.132 (Reference 14) which was ani .ced at a reactor power level of 2537 MWt. The staff believes that the radiological conseque,nas of an accident subsequent to implementation of Hatch power uprate will be increased approximately proportional to the increase in reactor power. For the potential radiological consequence to the main control room operator, the staff used new control room X/Q values proposed by the licensee.

Based on its evaluation and the licensee's analyses, the staff concludes that the radiological consequences with the requested power uprate of 2818 MWt at Hatch Plant Unit Nos.1 and 2 still remain within the relevant dose criteria and will provide reasonable assurance that the radiological consequences of bounding DBAs will not exceed dose acceptance criteria specified in the SRP,10 CFR Part 100, and GDC 19 of Appendix A to 10 CFR Part 50. Therefore, the staff finds that the proposed power uprate to be acceptable. The resulting radiological consequence analyses are provided in Table 1. The control room and site boundary X/Q values used by the staff are provided in Tables 2 and 3 respectively .

TABLE 1

)

Radiological Consequences of Design-Basis Accidents ,

(rem) {

Postulated Accidents EAR LP_Z Control Room Thyroid WBm Thyroid WB Thyroid WB Loss of Coolant 67 2 295 2 24 <1 l

Control Rod Drop Accident 1 <1 3 <1 3 <1 Fuel Handling Accident 32 <1 32 <1 12 <1 (1) Whole Body

Table 2 Control Room Relative Concentration (X/Q) Values Ground Release Stack Release O to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 1.26E-3 4.85E-6 2 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 3.87E-4 1.17E-6 8 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 4.17E-4 9.69E-7 1 to 4 days 3.56E-4 8.27E-7 4 to 30 days 2.37E-4 5.49E-7 Table 3 Site Boundary Relative Concentration (X/Q) Values ")

Ground Release Stack Release O to 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 1.4E-4 3.7E-5 0.5 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 1.4E-4 1.1E-5 2 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 7.0E-5 5.6E-6 8 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 5.0E-5 3.8E-6 1 to 4 days 2.3E-5 1.9E-6 4 to 30 days 8.0E-6 6.4E-7 I

(1) From Reference 13 (minimum EAB and LPZ both equal to 1250 meter) l

5.0 HUMAN PERFORMANCE The staff reviewed the licensee's submittal dated August 8,1997 (Reference 1) and the licensee's March 9 (Reference 2) and July 6,1998 (Reference 4), responses to staff Requests for Additional Information (RAI). The staff's evaluation of the licensee's responses to the RAls which were composed of five review topics is provided below..

Topic 1 - Discuss whether the power uprate will change the type and scope of plant emergency and abnormal operating procedures. Will the power uprate change the type, scope, and nature of operator actions needed for accident mitigation and will it require any new operator actions?

By Encl|letter dated August 8,1997]], the licensee stated that the extended power uprate would not change the type or scope of plant emergency and abnormal operating procedures. The licensee also stated that the extended power uprate would not change the type, scope, or nature of operator actions needed for accident mitigation and that it would not require any new operator actions. The staff finds that the licensee's responses are satisfactory.

Topic 2- Provide examples of operator actions potentially sensitive to power uprate and address whether the power uprate will have any effect on operator reliability or performance. Identify operator actions that would necessitate reduced response times associated with a power uprate. Please specify the expected response times before the power uprate and the reduced response times. What have simulator observations shown relative to operator response times

. for operator actions that are potentially sensitive to power uprate? Please state why reduced operator response times are needed. Please state whether reduced time available to the operator due to the power uprate will significantly affect the operator's ability to complete manual actions in the times required.

By letter dated March 9,1998, the licensee stated that operator action will remain unchanged as a result of implementing the extended power uprate and that simulator observations have shown no noticeable reduction in effectiveness of operator response. In its letter dated July 6, 1998, the licensee provided simulator performance results for a scenario on depressurization with inadequate high-pressure injection (non-anticipated transient without scram) that was conducted at both the present uprate power level and at the proposed extended power uprate level. This scenario was performed without the simulation models having been revalidated to the proposed extended power uprate heat balance design data. The licensee had previously committed by letter dated March 9,1998, in response to NRC question 46.b, to implementing  !

and testing expected system response utilizing currently evaluated steady- state / transient {

performance criteria. This task should be completed before simulator performance results may i be considered to be indicative of expected reference plant characteristics. Absent revalidation in accordance with performance data, the staff finds insufficient basis for confidence in simulated performance to draw adequate conclusions regarding expected effects on plant operations.

The licensee is expected to submit to the NRC the results of the previously discussed simulator scenario after completion of the first phase of the simulator revalidation effort (that is, the simulator performance will be validated against the extended power uprate expected system response).

i i

Topic 3 - Discuss any changes the power uprate will have on control room instruments, alarms, and displays. Are zone markings on meters changed (e.g., normal range, marginal range, and out-of-tolerance range)?

By letter dated March 9,1998, the licensee stated that the extended power uprate will have minimal impact on control room instruments and controls. The licensee noted that no changes to front panel indicators or controls are required. The licensee indicated that the following changes would be implemented: new programmable controls for the recirculation pump runback and the ranges for the main steamline flow transmitters which send signals to the control panel indicators. The staff finds that the licensee's responses are satisfactory since the subject changes are enhancements to the control room instruments and controls.

Topic 4 - Discuss any changes the power uprate will have on the Safety Parameter Display System (SPDS).

By letter dated March 9,1998, the licensee stated that digital signal input and output lists for the SPDS would not be affected. The licensee also stated that extended power uprate. changes (i.e., setpoints and calibration) to field devices that provide a signal to the computer will be automatically reflected in the SPDS. The staff finds that the licensee's responses are satisfactory.

Topic 5 - Describe any changes the power uprate will have on the operator training program and the plant simulator. Provide a copy of the post-modification test report (or test abstracts) to document and support the effectiveness of simulator changes as required by ANSI /ANS 3.5-1985, Section 5.4.1.

(a) Provide classroom and simulator training on the power uprate modification.

The licensee stated in its letter of March 9,1998, that an operator training lesson plan will be prepared to teach plant changes as a result of the extended power uprate and that existing lesson plans will be flagged for revision during the next regular revision cycle. The extended power uprate lesson plan will be presented to all eligible licensed / certified shift personnel before

, plant startup for extended power uprate operation and to all licensed / certified personnel during the following segment of requalification training. Additional training regarding the extended power uprate will be incorporated in continuing training lesson plans for other training sections, as applicable.

l (b) Complete simulator changes that are consistent with ANSI /ANS 3.5-1985. Simulator fidelity will be re-validated in accordance with ANS!/ANS 3.5-1985, Section 5.4.1, " Simulator Performance Testing." Simulator re-validation will include comparison of individual simulated i systems and components and integrated plant steady state and transient performance with reference plant responses using similar startup test procedures.

The licensee stated in its letter of March 9,1998, that simulator changes will be implemented before plant startup for extended power uprate operation. Simulator revalidation will be accomplished in two stages. First, the simulator performance will be validated against the extended power uprate expected system response. Second, post-startup data will be collected 4

k_ _ __ _ _ _ _ , _ - , . - . - ..-,..________.____________________m- _ _ _ __,__ ___-_____a

I and compared with simulator performance data, allowing any necessary adjustments to simulator model performance. This simulator performance validation will be performed in accordance with ANSI /ANS 3.5-1985, Section 5.4.1.

l (c) Complete control room and plant process computer system changes as a result of the power uprate.

See evaluation of Topics 3 and 4, above.

(d) Modify training and plant simulator relative to issues and discrepancies identified during the

startup testing program.

The licensee stated that the simulator performance discrepancies will be identified during the extended power uprate power ascension testing through comparison of plant data with simulator performance data.

On the basis of the information discussed, the staff finds that the licensee has proposed satisfactory changes to the operator training program and the plant simulator as a result of the extended power uprate.

6.0 ELECTRICAL AUXILIARY DISTRifUlTION SYSTEM The staff has reviewed the following enclosures submitted by the licensee of the balance-of-plant licensing report to determine if the power uprate would have an adverse impact on the station's electrical auxiliary distribution system and to see if TS revision is necessary.

6.1 Summary of Plant Modifications The licensee has reviewed the potential impact of a power uprate on the main generator stator and isophase bus cooling, temperature-monitoring system in main transformers, adjustment to the main generator, and switchyard main protective devices. In response to the staff's RAI, the licensee submitted the following details.

Since the power uprate will increase generator rating from 1000 MVA to 1050 MVA at 0.85 and 0.88 power factor respectively, the generator will require an upgrade of the stator water cooling system. The plant service water flow rate to the stator water cooling system will be increased from 1750 gpm to 1880 gpm at 95'F to remove the additional heat from the stators due to increase in the generator rating, and the stator bar flow rate will increase to 550 gpm. The stator bar flow rate will be increased by replacing the main flow orifice and main filter. Also, the flow meter will be replaced with one having a calibration span compatible with the new flow element. Set points for the alarm and interlocks in the stator water cooling system will be changed to accommodate the new system's operating parameters (flow, pressure, and temperature).

The licensee also assessed the impact of an increase in steam flow corresponding to a 113 percent extended flow uprate from the original design on the non-safety-related, isophase bus duct and its cooling equipment. The licensee determined by field testing that no major changes

need be made to the Unit 1 isophase bus duct cooling system to support extended power uprate, because the changes in Unit 1 are very minor.

However, the Unit 2 generator isophase bus duct cooling system will require an upgrade to accommodate the increased power uprate. The plant service water flow rate to the isophase bus duct cooling system will be increased from 156 gpm to 160 gpm at 95'F to remove the additional heat from the isophase bus duct. The cooling coils, the fans, and the fan motors will be upgraded. The duct work will be modified to accommodate the larger fans and cooling coils.

Instrumentation in the duct will be replaced. To accommodate the increased plant service water flow, the plant service inlet and outlet piping to the cooling coils will be increased from 21/2-in. to 3-in. diameter, and an orifice in the discharge piping will be removed or resized. The inlet and outlet carbon steel piping will be upgraded to a more corrosion-resistant material.

Also, the aluminum bars used as connectors at the generator will be replaced WP.h flexible copper braided connectors to improve reliability and reduce maintenance.

The transformers are adequately rated to support power uprate operation. The Unit 1 main transformer rating is 1008 MVA. The maximum load on the transformer at maximum power levels is 954 MVA, which is well within the rating of the transformer. Therefore, no supplemental temperature monitoring is needed. However, the Unit 2 transformer rating is 997.8 MVA. The maximum load on the transformers at the maximum power level is 991 MVA, which is close to the rating of the transformer. A new temperature-monitoring system will be installed in the Unit 2 main transformer to provide accurate data for winding and oil temperature during the power ascension program. Plant operation personnel can also use the temperature-monitoring system to provide more accurate data for determining transformer performance during various degrees of electrical loading against operating conditions such as ambient temperature or loss of cooling fans.

During the power uprate program, the main generator controls and switchyard devices will require adjustment or replacement of some components for proper operation of the equipment.

The licensee's review concluded that the following controls and devices at Hatch will be impacted and would require adjustment :

(1) Generators are capable of meeting the proposed uprate without undergoing physical modifications to the generator, coolers, or excitation system hardware. However, the licensee proposed resetting the underexcited reactive ampere limit (URAL) and annunciator / control for excitation system of generators. A new set of generator performance curves, including excitation V-curves, reactive capability curves, and saturation curves, were provided as plant-specific instruction book updates. The information contained in these curves will be programmed into the turbine generator and excitation control systems during the refueling outage. These programming changes will allow operation at i the new level of reactive ampere limits, annunciator set points, and various other settings resulting from the extended power uprate generator re-rating.

(2) The set points and control associated with the stator water cooling runback logic will be changed as a result of extended power uprate.

I

(3) The 3000/5 amp current transformers (cts) for the Offerman line are currently tapped at 1200/5 amp. During extended power uprate operations, these cts could see current in excess of 1200 amp if the 230 kV switchyard breaker 510 (between the Unit i generator and 230 kV Bus 1) is out for maintenance or is tripped. Therefore, the CT ratio taps will be changed from 1200/5 amp to 2000/5 amp.

(4) As a result of CT ratio tap changes for extended power uprate,12 protection relays for the 230 kV Offerman Line and 2 ground detectors associated with 230 kV switchyard breaker 510 and breaker 490 will be reset.

(5) As a result of CT ratio tap changes, the existing IRQ-9 directional ground relay will be replaced with a new relay. The existing relay has a setting of 12 amp with an instantaneous range of 10 amp to 40 amp. The replacement relay will have the setting of 7 amp with an instantaneous range of 4 amp to 16 amp.

On the basis of the information presented by the licensee, the staff reviewed a summary of plant modifications to be implemented by the licensee preceding the proposed power uprate.

None of these modifications are safety related and no TS changes are required; therefore, they are acceptable to the staff.

6.2.0 Lessons Learned from Maine Yankee ,

I in addition, as a result of lessons leamed from the Maine Yankee independent Safety j Assessment inspection, all licensees are required to review and evaluate whether the power uprate would alter the original licensing basis for General Design Criterion (GDC)-17 and the station blackout (SBO) requirements, which are discussed next.

6.2.1 Electrical Power and Auxiliary System

~ The licensee evaluated onsite and offsite electrical supply and distribution systerhs for safety-related components in conformance to General Design Criterion 17 (10 CFR 50, Appendix A).

The significant results of the evaluation follow:

6.2.2 Generation and Offsite Power System (1) The cooling system for the main electrical generator stator has been enhanced to increase l the MVA rating of the main generator for the extended uprate power level of 2763 MWt.

l (2) With cooling system improvements to the Unit 2 isophase phase bus duct, it will have  !

adequate capacity to carry the maximum generator full load current at the nominal voltage of 24 kV and at the minimum voltage of 22.8 kV under postulated worst case loading conditions.

(3) The main transformers and the associated switchyard components are adequate for uprated transformer output.

(4) The plant stability scenarios outlined in final safety analysis reports (FSARs) were evaluated at the extended uprate power level. The licensee concluded that there are no adverse affects on grid stability or plant reliabliity.

(5) System grid load flow studies were performed using projected 1998 peak and valley load conditions with the Hatch unit at extended uprate power level for scenarios outlined in FSARs. The licensee concluded that resultant switchyard voltages were adequate to perform safe shutdown from the offsite power network.

In response to the staff's RAI, the licensee presented details about how the analysis was performed and the assumptions that were used. In response to a question about system grid load flow studies, the licensee elaborated that under the worst-case condition (i.e., the loss of the 500-kV line with a subsequent LOCA in either unit, assuming a maximum 1-hour demand peak load during the summer season and the grid postulated to deliver the maximum guaranteed demand of 3600 MWe of power to Florida, which results in the lowest voltage in the Plant Hatch switchyard), either unit will remain within the design capability curve of the main generator and can sustain the integrity of the offsite power system network for LOCA mitigation.

During postulated grid upset conditions, system dispatchers will take compensatory measures to restore the grid voltages by tuming on capacitor banks and other appropriate equipment within minutes of the event to maintain long-term required grid voltage. This will be in accordance with their prescribed voltage schedule, which includes guaranteed minimum switchyard voltages for the Plant Hatch units. The licensee concluded that the resultant i switchyard voltages after the power uprate will be adequate to safely shut the units down from the offsite network.

6.2.3 Onsite Power Distribution System Station loads under normal operation / distribution conditions are computed on the basis of equipment nameplate data. Since extended power uprate does not require equipment operation above nameplate rating, the electrical supply and distribution components (switchgear, MCCs, cables, etc.) are adequate.

Station loads under emergency operation / distribution conditions (diesel generators) are based on equipment nameplate data. The extended power uprate will not change the power requirements of any safety-related load; therefore, under emergency conditions, the electrical supply and distribution components are adequate.

The de power distribution system provides control and motive power for various systems and components within the plant. System loads are computed on the basis of equipment nameplate data. Operation at the extended uprate power level wiil not increase any loads beyond the nameplate rating or revise any control logic; therefore, the de power distribution system is adequate.

Even though for power uprate no equipment replacement was necessary for power uprate that would increase electricalloads beyond the design ratings or above levels previously analyzed, the licensee has re-assessed the adequacy of the offsite and onsite power distribution system analysis to ensure that with the increase in Plant Hatch generation output, it would remain in l

t conformance with GDC-17. The licensee finds that the safety functions of the offsite and onsite electric power systems are not affected by the uprated conditions; therefore, power uprate has no effect on the plant's conformance with GDC-17 requirements.

On the basis of the licensee's evaluation above, the staff finds that the plant-shutdown

equipment will continue to perform its intended safety-related functions for the power uprate.

l The staff concludes that the station auxiliary electrical distribution system is not adversely

l. impacted by the proposed power uprate at Plant Hatch.

l 6.2.4 Station Blackout (SBO) q i

The licensee reviewed the SBO analysis and observed that plant response and coping l capabilities for the SBO event are affected slightly by operation at the uprated power level J because of the increase in the decay heat. There are no changes to the systems and {

equipment used to respond to an SBO event, nor is required coping time changed. The Plant )

Hatch coping duration for SBO is 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. However, onsite power (one diesel) which is used as  !

an attemate ac power source (AAC) is available in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The licensee also observed that "As part of the extended power uprate, the Station Blackout (SBO) scenario was reanalyzed assuming that the suppression pool cooling (SPC) was initiated in one hour when the AAC power source is assumed available. The peak pool temperature is 167'F. Even if SPC is not initiated until four hours, the resultant peak pool temperature of 194*F is acceptable for containment and ECCS (emergency core cooling system) pump operation." In response to this observation, the staff, in an RAI, asked the licensee to clarify whether credit is being taken for suppression pool cooling availability within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The preceding information appears to indicate that the AAC power source (Emergency Diesel Generator 1B), will be available to provide SPC one hour after SBO and to limit the pool )

temperature to 167'F. However, in a May 3,1991, response to a staff concem that EDG 1B would be overloaded unless operators shed loads during an SBO, the licensee told the staff that the completed analyses, demonstrated that SPC was not required during 4-hour SBO coping duration. In response to the RAI, the licensee also added the following: " The fact that SBO analysis shows SPC is not required for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> does not preclude using the AAC power source to power SPC within one hour if the diesel loading margins are met and the operator so chooses. There is no change to the safety related loads that would be powered by AAC power source (EDG 18) due to extended power uprate. Therefore, the existing assumptions related to q

1-hour initiation of SPC and the acceptability of the 4-hour coping period are no different than i those documented in the original SBO submittal which was approved by the NRC in the SER {

dated November 1,1991." '

The staff reviewed the original SBO submittal and SER dated November 1,1991, and concluded that the assumptions used in the extended power uprate analysis did not differ from assumptions made in the SBO analysis that the staff reviewed and accepted.

7.0 EQUIPMENT QUALIFICATION The licensee reviewed the impact on safety-related electrical equipment qualification for power uprate for normal and accident conditions inside and outside of containment. Applicable i

i conservatism in accordance with IEEE Standard 323-1974, "lEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations," was applied to the environmental parameters as required. j l

The licensee observed that, during an accident at extended power uprate conditions, the maximum humidity will remain at 100 percent. The maximum pressure will increcse to less .

l than 51 psig but will not affect qualification. The accident temperature profile at the sxtended l

power uprate condition exceeds the current accident profile by up to 7'F during the time period

• from 35,000 seconds to 70,000 seconds. This will have no effect on qualification of any equipment. The extended power uprate accident radiation dose has beer; adjusted for the original power uprate of 5 percent already implemented and the proposed extended power uprate of 8 percent. In response to the staff's RAI concerning whether, for each component on i the equipment qualification (EQ) Master List, the existing qualification test data envelope the q accident temperature profile at extended power uprate conditions with the required margin, the licensee furnished curves showing Unit 1 and 2 drywell temperature EQ profiles. The profiles showed that the peak drywell temperature under worst-case accident conditions is below

' 330'F, which is the peak temperature presently assumed in evaluating the adequacy of environmental qualification tests for drywell equipment. The licensee also stated in the

]

response that degraded equivalency analysis, documented in SCS calculation SINH 97-004, '

shows that the present worst-case design-basis event profile envelopes the new accident profile at extended power uprate conditions. The staff reviewed the calculation and concludes that the present profile has enough conservatism to envelope the new accident profile at extended power uprate conditions. However, the degraded equivalency analysis is based on the Arrhenius Methodology and, as a separate issue outside the scope of power uprate reviews, the staff will evaluate the acceptability of the Arrhenius Methodology for environmental qualification under LOCA and Post-LOCA conditions.-

The licensee also stated that a review of equipment qualification at the extended power uprate conditions identified some equipment located inside of containment that is potentially affected by the higher than normal radiation level. The qualification of this equipment has been reevaluated on the basis of location-specific dose calculations. This equipment has been found acceptable for extended power uprate conditions, although it will be necessary to decrease the qualified life of specific components because of increased radiation levels during extended _

power uprate conditions. In an RAI, the staff asked the licensee to provide a detailed discussion of the equipment potentially affected and to quantify the decrease in qualified life for potentially affected equipment. Also, the licensee was asked to submit a detailed discussion of the review process and denote the actual EQ analysis performed for a few of the potentially affected equipment to include the EQ analysis performed for the component.that has the greatest decrease in qualified life.

In response to the RAI the licensee fumished the following details:

The environmental qualification review for extended power uprate (EPU) consists of. (1) an initial screening of all components on the EQ Master List for the effect on qualification parameters such as temperature, pressure, and radiation; (2) a location-specific dose

calculation for the equipment identified in the initial screening as potentially impacted; and (3) a re-evaluation of all equipment on the EQ Master List based on the results of the location-specific dose calculation.

Radiation was determined to have the greatest potential impact on equipment qualification.

The initial screening assumed an 8 percent increase in the specified 40-year total integrated dose (TID) inside the drywell. From the initial screening, Target Rock solenoid valves (model 1/2 SMS-S-02-4) and NAMCO limit switches (model EA180 and EA740) located inside the drywell were identified as being potentially impacted. A location-specific calculation was then prepared for these devices.

The calculation demonstrated that the Target Rock solenoid valves inside the drywell are qualified for 40-year TID at extended power uprate conditions. The calculation also identified five NAMCO limit switches with 40-year, location-specific doses that will exceed the tested dose of 5.0E+07 rads. Therefore, the calculation included a determination of revised qualified life based on radiation.

Temperature is currently the most limiting factor in determining the qualified life of the NAMCO limit switches. The thermally qualified life remains the most limiting for three of the limit switches; however, the radiation-qualified life will be most limiting for two of the limit switches for extended uprate. The license summarized these results in a tabular form.

The calculation also determined a revised bounding maximum dose for any equipment in the drywell. The qualified life of all EQ components in the drywell was reviewed with respect to a revised maximum bounding dose. No additional equipment was affected. The replacement intervals for affected equipment will be revised upon implementation of extended power uprate.

On the basis of the information submitted by the licensee, the staff concludes that the qualification of safety-related electrical equipment has been adequately addressed and the equipment will continue to be qualified for the extended power uprate.

7.1 EQ OF MECHANICAL EQUIPMENT WITH NON-METALLIC COMPONENTS The licensee evaluated the effect of extended power uprate on the non-metallic parts of equipment and components, such as pumps and heat exchangers. The Quality Assurance l Program at SNC was reviewed for all structures, systems and components (SSCs) that could

, be impacted by changes associated with power uprate. The licensee evaluated the changes in system pressures, temperatures and flow rates, and determined that most of the SSCs were within their original design capabilities with no additional actions needed. The licensee stated that if a design change to any SSC was necessary to assure the compatibility with normal or accident conditions, then the changes would be performed under the Quality Assurance Program at SNC. Therefore, the licensee concluded that the design and qualification requirements of non-metallic parts of equipment and components would continue to be met at power uprate conditions.

Based on its review, the staff finds that the environmental qualification of the non-metallic components at the extended power uprate conditions is acceptable under the administrative controls of SNC's Quality Assurance Program.

8.0 INDIVIDUAL PLANT EXAMINATION (IPE)

The licensee addressed the impact of the proposed Hatch extended power uprate on plant risk.

The proposed extended power level of 2763 MWt represents an 8 percent increase in reactor thermal power from the current power level of 2558MWt. The licensee had received its first power uprate approval of 5 percent increase (2436MWt to 2558MWt) from the staff on August 31,1995. The Hatch IPE was performed prior to this first power uprate approval. The licensee stated that the first power uprate was judged to have had a negligible impact on the calculated CDF. The PRA performed for the proposed extended power uprate accounts for the combination of both the first power increase and the proposed extended increase. In essence, this analysis considered a 13 percent difference in the power level with the baseline PRA representing the plant at 2436MWt and the extended power uprate PRA at 2763MWt.

8.1 Evaluation The staff reviewed Section 10.5 " Individual Plant Evaluation" of the licensee's submittal (Reference 1). The staff's evaluation addressed the licensee's discussion on risk pertaining to internal events (Level 1), containment analysis (Level 2), and external events (fire and seismic).

8.1.2 Internal Events The licensee addressed PRA attributes that could potentially be affected by the proposed extended power increase. These included: initiating event frequencies, success criteria, and operator actions. In addition, the licensee also addressed the effect of extended power uprate on component failure rates in the March 27,1998 letter.

The licensee's analysis considered the impact of 13 percent power increase on various accident initiating events. These intemalinitiating events included: (1) loss of coolant accident (LOCA)-

- small, medium, large and LOCAs outside the containment, (2) anticipated transients - reactor scram, turbine trip, loss of feedwater, loss of condenser vacuum, MSIV closure, inadvertent open relief valve, loss of drywell cooling, loss of control room cooling, loss of plant service water, loss of various AC and DC buses, loss of grid during various inidators, (3) loss of offsite power (including station blackout), and (4) anticipated transients without scram (ATWS) - MSIV closure, loss of feedwater, and turbine trips. The licensee performed a qualitative review of the underlying contributors to these initiating events to determine the potential effects of the power uprate on the initiating event frequencies. The licensee concluded that extended power uprate l l

would have no readily discernible adverse effect on initiator frequency. The staff finds it reasonable to assume that initiating event frequencies would not be changed as long as operating band of equipment are not exceeded. The staff expects that any potential deviations in initiating event frequencies in the future may be identified under the plant's Maintenance Rute program.

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The licensee determined that the critical functions in maintaining plant conditions to prevent core damage are: reactivity control, pressure control, high pressure inventory control, vessel depressurization, low pressure inventory control, and long-term containment heat removal. To evaluate the success criteria for these functions, the licensee performed a series of MAAP l

calculations which re-computed the plant's thermal-hydraulic performance and timing of events at the proposed higher power levels. The results of these calculations were used to obtain certain plant parameters during transients or plant accidents. The information was then compared to the specific success criteria of the baseline PRA. The licensee determined that

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the success criteria for the extended power uprate PRA did not change from the success criteria for the baseline PRA and that they remain adequate for the extended power uprate level.

l With respect to the potential impact on equipment reliability by the proposed extended power uprate, the licensee reported that the component failure rate will not change significantly with extended power uprate because the component monitoring programs that are in place, e.g.,

environmental qualification, and erosion / corrosion, will be modified to account for the wear as a result of extended power uprate. The licensee stated that extended power uprate may rescit in l

- components being refurbished or replaced at more frequent intervals; however, the functionality and reliability of components will be maintained to the current standard. Similar to the above discussion on the effect of extended power uprate on initiating event frequency, the staff finds it reasonable to assume that component failure rate would not be changed as long as operating

. band / limits of component are not exceeded. The staff expects that any potential deviations in component failure rates in the future may be identified under the plant's Maintenance Rule program.

The licensee conducted an evaluation to determine how the extended power uprate would

impact operator response capabilities during accidents. When shorter time is available for an operator to diagnose and execute an action in response to an accident situation, a higher human error probability would be estimated for that action. The licensee identified operator actions for which the reduction in time available to complete the action would result in significant change in risk. These operator actions included

failure to depressurize given inadequate high pressure injection (non-ATWS), failure to depressurize given inadequate high pressure injection (ATWS), failure to initiate Standby Liquid Control with Turbine Bypass Valve capacity unavailable (ATWS), failure to control low pressure injection after depressurization (ATWS), and grid recovery probability for station blackout without high pressure injection.

Sensitivity studies of these operator actions were performed to evaluate their impact on risk.

The results of the sensitivity studies showed that operator actions involved in AMS sequences did not have a significant impact on CDF. The result of calculating grid recovery probability for station blackout on the basis of new shorter available time showed that the probability did not change significantly and the resulting impact on the CDF was determined to be negligible.

However, the operator action to depressurize the reactor (non-AMS) was shown to have a significant impact on the increase in CDF from the extended power uprate. In fact, the licensee estimated that the entire CDF increase due to the extended power uprate (for both Hatch units) was attributed to this operator action. This operator action is not the only operator depressurization action in the PRA models. It is specific only to those non-ATWS events L___________________ .- - - - - -

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1 requiring depressurization and situations in which the operators have to resort to estimating the  !

vessel water level due to potential incorrect level indications caused by elevated drywell }

temperatures or overheated main control room instrumentation. This is the reason that most of 1 the sequences impacted by this operator action involve medium-LOCA and loss of main control room cooling initiating events.

The licensee estimated that the CDF from intemally initiated events is about 2.3E-5/ year for the proposed extended power level for Hatch Unit 1 and 2.4E-5/ year for Hatch Unit 2. This represents an increase of about 1E-6/ Year from the baseline CDF of 2.2E-5/ year for Unit 1 and an increase of about 1E-S/ year from the baseline CDF of about 2.3E-5/ year for Unit 2. As noted above, this increase in CDF is dominated by the decrease in time available for the operator to respond to accident scenarios.

Based on the reported analysis and results, the staff agrees that the resulting change in CDF (internal events) is small and that this increase is mainly due to an increase in one human error rate. Therefore, the staff considers the change in risk for internal events from the requested power increase by 8 percent to be acceptable.

8.1.3 Level 2 Intemal Events PRA The licensee's evaluation showed that there were no new PRA sequences in the Level 1 re-analysis which required specific evaluation to determine the impact on containment performance. That is, the extended power uprate did not modify the PRA model sequence database to an extent which would alter the baseline PRA results. The licensee found that, in general, the operator actions and success paths fy Level 2 associated with this analysis were of a sufficiently long term in nature that they would nu 5 significantly affected by the proposed uprate.

In response to a staff RAI, dated March 27,1998, which requested that the licensee provide any quantitative results for Level 2 analysis, the licensee reported that an approximate 1 percent change in CDF was noted for those sequences which were part of the Large Early Release Frequency (LERF) for each unit when evaluated for extended power uprate. This was considered a negligible change. The revised probability for operator failing to depressurize the reactor (non-ATWS) introduced no new sequences to be addressed in the Level 2 analysis.

Thus, the licensee maintained that the containment analysis performed for the baseline PRA was still valid for the extended power uprate case. The staff considers this negligible change in LERF due to the proposed extended power uprate to be acceptable.

J 8.1.4 Intemal Fire, Seismic and Other External Events PRA l The licensee estimated that the CDF associated with fire increased by less than 1 percent from the baseline of 5.6E-6/ year for Hatch Unit 1 and approximately 2.2 percent from the baseline of 3.4E-6/ year for Unit 2. These increases, less than 1E-7/ year for Unit 1 and about 1E-6/ year for Unit 2, were attributed primarily to the operator action of failing to depressurize given inadequate high pressure injection (non-AW/S).

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With respect to seismic events, the licensee reported that the proposed extended power uprate has no effect on the seismic margins analysis (SMA) performed for the Hatch plant. The increase in the power level is not expected to affect equipment survivability nor equipment response during an earthquake, nor does it modify the safe shutdown pathway assumed in the SMA. The staff considers the risk increase from internal fire and seismic events due to the proposed extended power uprate to be small.

8.1.5 Quality of PRA The licensee's original IPE was submitted to the NRC in 1992 and the Staff Evaluation Report (SER) accepting the submittal was issued by the staff in 1995. As stated in the SER, the staff 3

found that (1) the Hatch IPE was complete with respect to the information requested in Generic  !

Letter 88-20 and associated supplement 1, (2) the analytic approach was technically sound and capable of identifying plant-specific vulnerabilities, including those associated with internal flooding, (3) the licensee employed a viable means to verify that the IPE models reflect the current plant design and operation at time of submittal to the NRC, (4) the IPE had been peer reviewed, (5) the licensee participated in the IPE process, (6) the IPE specifically evaluated the decay heat removal function for vulnerabilities, and (7) the licensee responded appropriately to the Containment Performance improvement program recommendations. Based on these findings, the staff concluded that the licensee met the intent of Generic Letter 88-20. Although ,

this information alone does not necessarily ensure that the PRA performed for the proposed extended power uprate is of sufficient quality, the staff considers that several of the elements, e.g., peer review, serve as some indication of quality in the licensee's PRA. The licensee indicated that they plan to provide additional information to address the quality of their PRA 8.2 Conclusion Based on the reported analysis and results, the staff agrees that the resulting change in CDF (internal events, and fire) and LERF is mainly from an increase in one human error rate, namely operator failure to emergency depressurize given a loss of high pressure injection (non-ATWS).

The staff agrees that based on the current analysis, no significant change can be predicted for initiating event frequencies, success criteria and component failure rates.

The staff considers the increase in CDF (internal and external events) and LERF due to the proposed extended power uprate to be small and is, thus, acceptable. The licensee has l indicated that additional information will be provided to address the uncertainty associated with the PRA as well as the quality and scope of their PRA. Pending staff's review of this additional information, the staff agrees that operating the plant at the requested extended power level does not pose undue risk at the plant and considers the change in risk due to the extended power uprate.to 2763 MWt acceptable.

Principal Contributors: (List SE Contributors)

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Date:

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1 REFERENCES

1. Letter from Southern Nuclear Operating Company to the NRC, "Edwin 1. Hatch Nuclear )

' Plant, Request for License Amendment, Extended Power Uprate Operation," dated I August 8,1997, and attachments

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2. Letter from Southern Nuclear Operating Company to the NRC, "Edwin 1. Hatch Nuclear l Plant, Request for Additional Information on Extended Power Uprate License l . Amendment Request," dated March 9,1998 l

3. Letter from Southem Nuclear Operating Company to the NRC, "Edwin 1. Hatch Nuclear i Plant, Request for Additional Information on Extended Power Uprate License Amendment Request," dated May 6,1996

4. Letter from Southern Nuclear Operating Company to the NRC, "Edwin I. Hatch Nuclear Plant, Request for Additional Information on Extended Power Uprate Licensse Amendment Request," dated July 6,1998

5. Letter from Southern Nuclear Operating Company to the NRC, "Edwin 1. Hatch Nuclear l

Plant, Request for Additional Information on Extended Power Uprate License Amendment," dated July 31,1998

6. Letter from Southern Nuclear Operrating Company to the NRC, "Edwin 1. Hatch Nuclear Plant, Revised Post-LOCA Doses," dated April 17,1997

7. General Electric Licensing Topical Report NEDC-32424P, " Generic Guidelines of General Electric Boiling Water Reactor Extended Power Uprate" (ELTR1), dated February 1995 (Proprietary information, not publicly available)

8. NRC letter from D.M. Crutchfield to G.L. Sozzi (GE), " Staff Position Conceming GE BWR

j. Extended Power Uprate Program," dated February 8,-1996

9. General Electric Licensing Topical Report NEDC=32523P, " Generic Evaluation of

, . General Electric Boiling Water Reactor Extended Power Uprate" (ELTR2), dated March l 18996 (Proprietary information, not publicly available) and Supplement 1, Volumes 1

!- and 2, dated June 1996 (Proprietary information, not publicly available)

10. (MONTICELLO SER, TO BE PUBLISHED)

11. ' SECY-97-042, " Response to OlG Event inquiry 96-04S Regarding Maine Yankee,"

dated February 18,1997

12. NRC letterfrom Ngoc B. Le," Safety Evaluation Related to NRC Bulletin 96-02, '

Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors'- Edwin 1. Hatch Nuclear Plant, Units 1 and 2 (TAC NOS. M95148 and M95149)," dated June 17,1997

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13. NRC letter from K.N. Jabbour to Southem Nuclear Operating Company, " Issuance of l

Amendments - Edwin I. Hatch Nuclear Plant, Units 1 and 2 (TAC NOS. M91077 and M91078)," dated August 31,1995

14. NRC letter from K.N. Jabbour to Georgia Power Company, " Issuance of Amendment -

Edwin I. Hatch Nuclear Plant, Unit 2 (TAC NO. M87850), dated March 17,1994 I

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