ML062900306

Extended Power Uprate Attachment 8 to EPU NRC Submittal, Startup Testing

ML062900306
Person / Time
Site:	Susquehanna
Issue date:	10/11/2006
From:	Susquehanna
To:	Office of Nuclear Reactor Regulation
References
PLA-6076
Download: ML062900306 (149)

Text

9 Attachment 8 to PLA-6076 Startup Testing Susquehanna Steam Electric Station Extended Power Uprate Attachment 8 to EPU NRC Submittal Startup Testing Page 1 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAI,--STARTUP TESTING Table of Contents 1.0 Introduction

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4 2.0 Purpose ............................................................................................................................................................

4 2.1 B ackground

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4 2.2 Objective

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5 3.0 Summary of Conclusions

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5 4.0 Testing Evaluations

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7 4.1 Comparison to SSES Startup Test Program [SRP 14.2.1; III.A] ..............................

7 Power ascension startup tests performed at 2 80% of OLTP ...................................................

7 Power ascension transient tests performed at Z 80% of OLTP ..................................................

7 Tests at lower power invalidated by EPU ...................................................................................

7 Attachments 1 and 2 of the SRP 14.2. 1 .......................................

7 4.2 Post Modification Testing Requirements

[SRP 14.2.1, Ill.B] ...............................

8 Modification Aggregate Impact .....................................................

8 Multiple Structure Systems and Components

("SSC') .............................................................

9 4.3 Justifications for Elimination of Power Ascension Tests [SRP 14.2.1, 1IJ.C] .....................

9 Guidelines of SRP 14.2.1, Paragraph Ill. C.2 ...............................................................................

9 Feedwater

/Condensate Pump Trip ..........................................................................................

10 Loss of Feedwater Heating .......................................................................................................

12 M SIV C losure E vent ......................................................................................................................

14 Turbine Trip/Generator Load Rejection...................................................................................

17 Recirculation Pump Trip ...........................................................................................................

20 R elief Valve Testing .......................................................................................................................

22 RCIC Functional Testing ...........................

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24 HPCI Functional Testing.........................................................................................................

25 5.0 Operator Training/Large Transient Simulations

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27 6.0 Large Transient Testing Risk Assessment...............................................................................................

27 7.0 Post EPU Industry Experience

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28-.-.-.Post EPU Steam D ry er Issues .................................................................

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28__Industry Post EPU Transient Events ...............................................

29 2 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Table of Contents (Continued)

Table I Startup Testing Comparison Page 31 Table 2 EPU Implementation Modifications Page 42 Table 3 Planned EPU Power Ascension Testing Page 48 3 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING 1.0 Introduction The following information supplements the Susquehanna Steam Electric Station ("SSES") Power Uprate Safety Analysis Report ("PUSAR")

and provides additional information about startup testing as is re-quired by SRP 14.2.1 -Generic Guidelines for Extended Power Uprate Testing Programs.2.0 Purpose 2.1 Background This attachment provides detailed information on the testing PPL intends to perform following the EPU implementation outages. The first implementation outage will be on Unit 2 in 2007 followed by Unit I in 2008. The first implementation outage on each unit will upgrade plant equipment and load fuel sufficient to support operation at 3733 MWt. The next implementation outage will be on Unit 2 in 2009 followed by Unit I in 2010. These outages will upgrade plant equipment and load fuel sufficient to support opera-tion at 3952 MWt. During the startup following each of these implementation outages, PPL will conduct a comprehensive startup test program to ensure the safe operation of the plant. The tests that PPL intends to perform are described herein.The Nuclear Regulatory Commission

("NRC") decides whether Large Transient Testing is necessary dur-ing power ascension to ExtendedPower Uprate ("EPU") on a plant by plant basis. SSES plans to perform a Constant Pressure Power Uprate ("CPPU") to 3,952 MWt. The planned CPPU is approximately four-teen percent (14%) above current licensed thermal power (3,489 MWt) and twenty percent (20%) above original licensed thermal power (3,293 MWt). The purpose of this report is to describe the startup testing SSES intends to perform in support of EPU and to supplement the SSES CPPU application to assist the NRC in making a final determination relative to Large Transient Testing at SSES.The NRC endorsed the Licensing Topical Report (NEDC 32424P-A called ELTRI) for Extended Power Uprates. The NRC also accepted the test program of the CPPU Licensing Topical report (NEDC 33004P-A called CLTR) for CPPUs, but reserved the right to consider on a plant by plant basis the CLTR recom-mendation against Large Transient Testing. The CLTR is the controlling document for the SSES planned CPPU. SSES will comply with the startup test requirements of the CLTR and will take exception to per-forming Large Transient Tests.ELTRI stated MSIV Closure Events would be tested for EPU if the power uprate was more than 10%above any previously recorded MSIV closure transient.

Similarly, ELTRI stated a generator load rejec-tion test would be performed if the uprate was more than 15% above any previously recorded generator load rejection transient.

ELTR1 applies to extended power uprates whether constant pressure or other-wise. The CLTR on the other hand, applies directly to constant pressure power uprates.With regard to these specific ELTRI requirements, SSES recorded a MSIV closure event in Unit I on July 1, 1999 and a generator load reject event in Unit 2 on June 6, 2005 and. Based on these two events, the ELTRI criteria apply to SSES as follows: CPPU Power Required by Event Date Power Level % Increase Ri Level ELTRI MSIV Closure 7-1-1999 3441 MWt 3952 MWt 14.9% Yes-greater Event than 10%Generator Load 6-6-2005 3489 MWt 3952 MWt 13.3% No-less than Reject 3 15%4 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING The CLTR states: "The same performance criteria (for CPPU) will be used as in the original power ascen-sion tests, unless they have been replaced by updated criteria since the initial test program. Because nei-* ther steam pressure nor core flow has been changed and because recirculation flows only slightly increase for CPPU, testing of system performance affected by these parameters is not necessary with the exception of the test listed above." No performance criteria have been replaced by updated criteria since initial test-ing at SSES.2.2 Objective This supplement is submitted to support the request to the NRC that Large Transient Testing not be re-quired before CPPU at SSES. The supplement addresses all guidelines of SRP 14.2.1, even though the only ELTRI event that would require testing is the MSIV closure event and in spite of the fact that the CLTR applies to SSES and the CLTR states testing is not required where core flow and steam pressure remain essentially unchanged.

3.0 Summary

of Conclusions PPL has determined per SRP 14.2.1 which of the original startup tests described in the FSAR need to be performed for EPU. The startup tests PPL intends to perform for EPU are described in Table 3. This in-cludes a commitment to perform a condensate pump trip on one unit to verify continued feedwater capa-bility.PPL has also determined the post EPU modification tests that impact plant safety that will be performed.

The post EPU modification tests are described in Table 2. Table 2 includes tests on modifications that do not impact plant safety, but are included for completeness.

As further detailed below, Large Transient Testing at SSES is not required for CPPU because: (A) SSES has already tested large transient events and has documented the results; (B) potential gains from further Large Transient Testing are minimal and are outweighed by the potential harm testing can cause; and (C)advanced analytical methods and advanced training facilities accurately and adequately simulate large transient events without the need to impose actual events. In view of previous test results and plant re-sponses to prior documented events, the CPPU startup testing program as proposed in this document is considered sufficient to validate the continued ability of the plant to safely operate within required pa-rameters and analytical limits.A. SSES has tested large transient events and has documented results.Large Transient Testing performed during plant startup testing determined integrated plant re-sponse after reaching full power. Startup tests were required to baseline plant responses and to in-dividualize system performances.

Startup test results indicate Structures Systems and Compo-nents ("SSCs") perform their intended functions.

SSES satisfied all Acceptance Criteria necessary at startup testing. During startup testing SSES uncovered potential equipment defects for DBA mitigation by deliberately placing the plant in transient events. Further Large Transient Testing.for CPPU is not required because events have been baselined by startup testing, actual events, post modification testing, and by analytical techniques.

Testing to gain information that is minimal to plant operation and that SSES has already estab-lished is cumulative and disruptive, and subjects the plant to unnecessary increased risk. Large Transient Testing challenges a limited number of systems and components, all of which have a history of safe performance at SSES. SSES has accumulated twenty (20) years of experience dealing with plant transient response.

Therefore, the need to perform additional testing to demon-strate plant response at CPPU is not justified.

5 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING B. Gains from Large Transient Testing are minimal, and outweighed by the potential harm Large Transient Testing can cause.No new transients occur as a result of CPPU. Transient analyses at CPPU resemble analyses at current plant conditions.

Changes in plant conditions for CPPU are not expected to result in a significant change to current plant conditions and response.

Therefore, SSES has already per-formed sufficient testing and any gains from further testing are minimal and would be outweighed by the potential harm Large Transient testing can cause.No new thermalhydraulic phenomena or system interactions have occurred following actual tur-bine trip and load reject events at SSES. Plants responded as expected in accordance with their design features.

No unexpected conditions were experienced and no latent defects were uncov-ered during these events, beyond the specific failures that initiated the events.The proposed EPO test program tests the aggregate impact of plant modifications.

Plant modifica-tions to support CPPU have minimal safety significance.

Modifications are implemented as needed in advance of CPPU implementation.

Benefits derived from Large Transient Testing may be achieved by safer means. CPPU has minimal affect on plant modifications.

Correct and timely operator responses to plant transients and abnormal events (as well as DBAs) are assured and documented by simulator training.The risk associated with a planned transient is on the same order of magnitude as the risk of an unplanned transient event. From a PRA perspective, Large Transient Testing should not be per-formed unless clear benefits are achievable and cannot be obtained through other methods. Large Transient Testing without significant need and well defined goals is unwarranted.

C. Advanced Analytical Methods and training facilities accurately and adequately simulate large transient events and system performance.

Advances in analytical techniques, methods, models, and simulators have created a high level of confidence in determining plant responses and are cost effective alternatives to actual testing.Analyses and simulator training demonstrate that plant shutdown is safely achieved under CPPU conditions.

The benefits from Large Transient Testing are outweighed by the potential affects Large Tran-sient Testing has on plant equipment.

Large Transient Testing has a negative impact on the sta-tion and power grid, for which the station supplies a significant base load. Large Transient Test-ing provides information on a limited number of plant systems. The scram and subsequent rapid reduction in power is controlled by normal operator actions. Therefore, the need to perform Large Transient Testing at SSES to demonstrate safe operation of the plant is unwarranted.

D. SSES plant simulator models BOP transients.

The SSES plant simulator provides accurate BOP modeling of transients such that operators will be well trained and experienced in potential EPU transients or events. Prior to EPU implementa-tion, the simulator will be updated to model the EPU transient analyses.

SSES operators will be trained on various plant upset conditions from postulated accident conditions to anticipated tran-sients. In this way, plant operators will be prepared for the nature, timeline, and extent of the plant response to simulated transients.

Initiating actual plant transient events for purposes of op-erator training will not be necessary.

Simulator training has the advantage of exposing all operat-ing shifts to the transients whereas only the on duty shift has the hands on experience of in-plant transients.

6 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING 4.0 Testing Evaluations

4.1 Comparison

to SSES Startup Test Program ISRP 14.2.1; IJI.A]Power ascension startup tests Performed at >_ 80% of OLTP Table I provides comparisons of initial startup tests and startup tests for the 4.5% uprate to 3441 MWt to planned testing for CPPU startup. As seen in Table 1, the following tests were performed at 80% of OLTP or greater: ST-I, ST-2, ST-5, ST-8, ST-9, ST-I1, ST-12, ST-16, ST-17, ST-18, ST-19, ST-20, ST-21, ST-24, ST-29, ST-32, ST-33, ST-35, ST-36, and ST-37. Planned testing for CPPU is indicated in Ta-ble 1, with additional details provided in Table 3. Justifications for exemption from certain transient test-ing are provided in paragraph 4.3 below. A listing of transient tests performed at 80% or greater during initial startup testing is provided in the following paragraph.

Power ascension transient tests performed atl> 80% of OLTP Table I to this supplement provides a complete comparison of initial startup tests to the startup tests per-formed for the uprate to CLTP (3,489 MWt) and the tests planned for CPPU (3,952 MWt). As seen in Table I, the following table shows those startup transient tests performed at 80% of OLTP or greater.This table is provided in accordance with SRP 14.2.1, paragraph III.A.1 and III.A.2. Initial startup tests, along with test power levels, are also provided in Table I to this Attachment.

Initial Transient Test Test Num- Power Level UFSAR Attachment 2 ber U1 U2 Page No. to SRP 14.2.1 Pressure Regulator ST-22 97.5% 99% 14.2-81 Yes Feedwater Pump Trip ST-23.5 97% 97% 14.2-33 Yes Loss of Feedwater Heating ST-23.4 85% 82% 14.2-33 Yes Turbine Valve Surveillance ST-24 100% 100% 14.2-241 No Closure of All MSIVs ST-25 100% 100% 14.2-241 Yes Turbine Trip/Generator Load Rejection ST-27 98%/100% 97% 14.2-244 Yes Recirculation Flow Control ST-29 98% 96% 14.2-247 No Recirculation Pump Trip (One Pump) ST-30 70%/98% 72%/98% 14.2-248 Yes Tests at lower power invalidated by EPU In accordance with SRP 14.2.1, paragraph III.A.2, the startup tests of Table I were reviewed for potential tests that would be invalidated by EPU. No such testing was identified for the SSES CPPU.Attachments I and 2 of the SRP 14.2.1 In accordance with SRP 14.2.1, paragraph IlI.A.2, Attachments 1 and 2 of SRP 14.2.1 were reviewed for consistency with the SSES startup testing program. The following tests, shown in Attachment 2 of SRP 14.2.1, were not performed during SSES startup at power levels greater than 80%. They are included here for completeness and are also discussed in the justifications of paragraph

4.3 Initial

Transient Test Test Power Level Applicable Reference Number UlI U2 to SSES RCIC Functional Testing ST-14 <75% <75% No Startup Report HPCI Functional Testing' ST-I5 <75% <75% No Startup Report Relief Valve Testing ST-26 45% 41% No Startup Report Recirculation Pump Trip (Two Pumps) ST-30 75% 72% No Startup Report 1 HPCI testing is not listed in Appendix 2 to SRP 14.2.1 but is included here due to its similarity to RCIC testing, 7 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING 4.2 Post Modification Testing Requirements JSRP 14.2.1, JII.B]Table 2 provides a listing of EPU implementation modifications that are currently anticipated and that are being prepared for implementation between 2006 and 2010. The SSES Units plan to implement EPU over two fuel cycles, as shown below. In view of this two step process, implementation of the DCPs of Table 2 will occur throughout the period.SSES Unit Uprate Step Increase Date Unit 2 1V -7% to 3733 MWt Spring 2007 Unit 1 lst ~ 7% to 3733 MWt Spring 2008 Unit 2 2n Up to 1300 MW'e Spring 2009 Unit I 2~ Up to 1300 MWe Spring 2010 Modification Aggregate Impact As can be seen from inspection of the modifications list of Table 2, the aggregate impact of most of these modifications on plant operations is minimal. The majority of the modifications are minor changes. The modifications that are more significant (e.g. HP turbine replacement, SLCS boron enrichment, and UHS modifications) are largely unrelated to each other, and therefore the aggregate impact of the changes is relatively insignificant.

With some of the changes that are more interrelated (e.g. piping changes in main steam, feedwater, and extraction steam), the extent of the changes themselves are minor (drain piping changes or pipe support modifications).

An overall aggregate impact of these changes is not anticipated.

Condensate system and feedwater system upgrades do represent significant plant modifications, such as replacement of condensate pump impellers, upgrade of RFP turbines and steam path, installation of an additional condensate filter and condensate demineralizer, and changes to RFP low suction pressure trips.These modifications will have an aggregate impact on BOP systems. However, these changes will be adequately addressed during post modification testing and the aggregate impact will be addressed by feed water system power ascension testing. Feed water system testing is described in Table 3 (ST-23). Also, the impact of EPU flow rates and condensate pump head (impeller changes) on RFP low suction trip set-points will be tested during power ascension on the first unit in order to demonstrate that sufficient mar-gins are assured to preclude loss of all feedwater on loss of a condensate pump. The current sequential trip of RFPs on low suction pressure will be retained post EPU. The sequential trip feature assures that loss of a condensate pump can not credibly result in a loss of all reactor feedwater at SSES.Aggregate impact of EPU plant modifications, setpoint adjustments, and parameter changes will be dem-onstrated by a test program established for BWR EPU in accordance with startup test specifications as described in PUSAR Section 10.4. The startup test specifications are based upon analyses and GE BWR experience with uprated plants to establish a standard set of tests for initial power ascension for CPPU.These tests, which supplement the normal Technical Specification testing requirements, are summarized below: Testing will be performed in accordance with the Technical Specifications Surveillance Require-ments on instrumentation that is recalibrated for CPPU conditions.

Overlap between the IRM and APRM will be assured.Data will be taken at points from 90% up to 100% of the CLTP RTP. so that system performance pa-ramneters can be projected for CPPU power before the CLTP RTP is exceeded.2 Full power during initial startup (Test Condition

6) was defined as 95% to 100% of rated thermal power and 100%+0 and minus 5% of rated core flow. The plant is expected to be generator limited to 1300 MWe on startup after EPU implementation, which falls within the TC 6 definition.

8 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING" CPPU power increases will be made in predetermined increments of <5% power. Operating data, including fuel thermal margin, will be taken and evaluated at each step. Routine measurements of reactor and system pressures, flows, and vibration will be evaluated from each measurement point, prior to the next power increment.

Radiation measurements will be made at selected power levels to ensure the protection of personnel.

• Control system tests will be performed for the reactor feedwater/reactor water level controls, and pressure controls, as applicable.

These operational tests will be made at the appropriate plant condi-tions for that test at each of the power increments, to show acceptable adjustments and operational capability.

• Steam dryer/separator performance will be confirmed within limits by determination of steam moisture content as required during power ascension testing.* Testing will be done to confirm the power level near the turbine first stage scram bypass set point.The same performance criteria will be used as in the original power ascension tests, eXcept where they have been replaced by updated criteria since the initial test program. Because steam pressure and core flow have not changed and recirculation flow may only slightly increase for CPPU, testing of system per-formance affected by these parameters is not necessary with the exception of the tests listed above.The CPPU testing program at SSES, which is based on the SSES specific initial CPPU power ascension and Technical Specifications, has been reviewed and is confirmed to be consistent with the generic de-scription provided in the CLTR.Multiple Structure Systems and Components

("SSC")Functions important to safety and that rely on integrated operation of multiple SSCs following plant events (such as plant load swings and loss of feedwater heating) are adequately addressed for SSES, as further described in Section 4.3 below.4.3 Justifications for Elimination of Power Ascension Tests [SRP 14.2.1, 1i'. C]Guidelines of SRP 14.2.1, Paragraph IIJ.C.2 Paragraph III.C.2 of SRP 14.2.1 provides specific guidance to be considered in order to justify elimina-tion of large transient testing. The following table provides a cross reference between the guidance of paragraph III.C.2 and this Attachment to the SSES CPPU application.

The table is provided to assist Staff reviewers in locating or identifying the appropriate information.

Paragraph Guidance/Criteria Discussion/Location in This Document 111.C.2 Contained in paragraph

4.3 where

applicable (a) Previous operating experience to specific tests and in paragraph 7.0 for post EPU industry experience.

No new thermalhydraulic phenomena or new New thermalhydraulic phenomena or system interactions were identified as a result system interactions of SSES CPPU. No further discussion is pro-vided.a wSSES has no unique limitations associated (c) analytical methods with conformance to analytical methods. No further discussion of this subject is provided.9 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING (d) Plant staff familiarization with Provided in paragraph

5.0 facility

operation and EOPs P Margin reduction in safety analysis Provided in paragraph 4.3 for specific tests, (e) Marg A00where applicable.

Discussed in the section on for AOOs EPU analyses results.j j Guidance in Vendor topical reports Discussed in paragraph

2.1 above

(g) Risk implications Provided in paragraph

6.0 Based

upon paragraph 4.1 above, the following large transient tests are discussed below along with justi-fications for why further Large Transient Testing is not required before CPPU. These tests include Pump Trip, Loss of Feedwater Heating, Closure of MSIV, Turbine Trip/Generator Load Reject, Recirculation Pump Trip, Relief Valves, RCIC Functional Testing, and HPCI Functional Testing.Feedwater

/Condensate Pump Trip The Feedwater Pump Trip startup test checks the recirculation system's ability to prevent a low water level scram from occurring following the trip of one Feedwater Pump operating at EPU. The startup test Feedwater Pump Trip at SSES established this occurrence and therefore further testing for Feedwater Pump Trip is not necessary.

Startup Test Objectives The objective for the startup Feedwater Pump Trip test was to test the capability of the automatic core flow runback feature to prevent low water level scram following the trip of one feedwater pump. The Ac-ceptance Criteria and testing methods for Feedwater Pump Trip are described in FSAR 14.2.Startup Test Results All Acceptance Criteria for startup Feedwater Pump Trip testing was satisfied for Unit I and Unit 2.Demonstrate the Capability of the Automatic Core Flow Runback Feature to Prevent Low Water Level Scram Following the Trip of One Feedwater Pump.Unit. 1: Startup testing was conducted at Test Condition 6 and with reactor power level at 97%. The "B" Feedwater Pump was tripped. The recirculation pump speeds ran back to the number 2 Limiter (approximately 46% speed) and this prevented a reactor scram from low water level." Unit 2: Startup testing was conducted at Test Condition 6 and with reactor power at 97%.The "B" Feedwater Pump was tripped to determine the resulting margin to scram. A scram did not occur and the resulting margin to the low reactor water level scram, ex-trapolated to 100% reactor power, was sixteen inches. Sixteen inches meets the Accep-tance Criteria of greater than or equal to three inches.Operational Experience Since Startup On September 24, 2003, a feed pump trip occurred in Unit 1. As demonstrated in the following graph, a reactor trip occurred when reactor vessel level dropped below the trip set point. While the trip was sub-sequently attributed to inappropriate recirculation control system gain settings which inhibited the run-back capability of the recirculation system (and was later corrected), the event does show that a feedwater pump trip could result in a reactor scram at current licensed thermal power (CLTP). EPU transient analy-ses (described below) shows that a reactor SCRAM will occur at EPU power levels on a feedwater pump 10 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING trip. While this is not a desirable result from a power generation standpoint, there are no safety implica-tions associated with this condition.

Feed Pump Trip -- 9-24-03 2.00 1.50 1.00 0.50 o 0.00 0 u-0.50 Lt.-1.00-1.50-2.00 Rx Power-x.- NR Pressure;WR Level Time in Seconds EPU Transient Analysis Results/CPPU Margins Several single feed water pump trip (SFWPT) events were evaluated, originating from 3952 MWt and 3733 MWt with core flows ranging from 108% to 85%. The trips were simulated using GE transient code analyses.

The analyses were performed at BOC conditions as GE states that this is the worst condition.

Specifically, for the limiting case, water level results reached the Level 3 SCRAM setpoint In view of the Level 3 SCRAM, SSES is changing its licensing basis for SFWPT to indicate that a reactor SCRAM on low water level may occur during this event, in which case there would be no need to test this result because a reactor SCRAM places the plant in a safe condition.

SRP 15.2.7 discusses loss of normal feedwater flow. The SRP states that main steam system pressure should remain below 110% of the design value. As shown in the plot of the 9-24-03 event (above), an increase in reactor or main steam pressure during this event is not an issue. Also, system design pressure margins are not affected by CPPU since, even though main steam and feedwater flows increase at CPPU, the numbers and setpoints of the SRVs are unchanged and therefore pressure peaks will be limited exactly in accordance with current design conditions.

11 of 51 Suisquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING EPU Power Ascension Testing Planned EPU power ascension testing of the feedwater control system is described in Table 3 (Test #23).For example, feedwater control system responses to reactor water level set point changes (for level set point change tests) are evaluated in various control modes (i.e. three element, single element).

However, power ascension testing of a feedwater pump trip is not planned since a reactor scram on low level is an-ticipated and therefore such a test is not meaningful.

At the same time, while not part of the initial feedwater trip startup test (ST-23) nor part of Appendix I or 2 of SRP 14.2.1 (which incorporates by reference RG 1.68, Section 5), SSES intends to conduct conden-sate pump testing to confirm that a condensate pump trip does not result in a loss of all feedwater, as fur-ther detailed below.1. SSES will perform hydraulic analyses to demonstrate that a single condensate pump trip will not result in a loss of all feedwater.

[Note: The SSES design incorporates time delays into the feed-water pump low pressure suction trips such that trip of the first feedwater pump on low suction pressure should restore the suction pressure to the other two pumps. These analyses will consider both steps of power uprate, namely the 7% increase to 3733 MWt and the remaining increase to 3952 MWt.2. SSES will conduct a condensate pump trip at full power during the 7% increase to 3733 MWt on the first unit to attain this power level to confirm the capability of feedwater to supply water to the RPV after the condensate pump trip.3. Assuming both the 3733 MWt analysis and the 3952 MWt analysis demonstrate that loss of a condensate pump does not result in a loss of all feedwater, and assuming that the results of the full power test at the 3733 MWt step are comparable to the 3733 MWt analysis, testing of this matter will be considered to be satisfactorily resolved and repeat testing of 3952 MWt will not be conducted.

4. If the results of the 3733 MWt test are not sufficient to reasonably confirm the analysis model used for the 3733 MWt step, the condensate pump trip test will be repeated at 3952 MWt on the first unit to attain this power level.Conclusion Power ascension testing does not anticipate actual testing of a feedwater pump trip, because a reactor scram on low level is anticipated and therefore such a test is not meaningful.

However, condensate pump trip testing, as detailed above, will be conducted as part of the SSES power ascension testing. This testing will confirm that a condensate pump trip will not result in a loss of all feedwater flow.Loss of Feedwater Heating The loss of feedwater heating portion of the Feedwater System startup tests verifies that the maximum decrease due to a single failure case is less than or equal to 100 'F. The resultant MCPR must be greater than the fuel safety limit. The startup test for Loss of Feedwater Heating at SSES established this occur-rence and therefore further testing is not necessary.

Startup Test Oboectives The objective for startup test Loss of Feedwater Heating is to determine stable reactor response to sub-cooling changes (i.e. Loss of Feedwater Heating) and to show that the actual change in final feedwater.

temperature is less than that assumed in the analysis.

The Acceptance Criteria and testing methods for Loss of Feedwater Heating are described in FSAR 14.2.12 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Startup Test Results All Acceptance Criteria for startup Loss of Feedwater Heating testing was satisfied for Unit I and Unit 2.Determine Stable Reactor Response to Subcooling Changes (i.e. Loss of Feedwater Heating)." Unit 1: Startup testing at 85% power, a simulated turbine trip signal to the extraction steam valves were initiated which would result in the most severe restriction of extraction steam to one feedwater heater string. Recordings of the transient were analyzed and com-pared to the predicted response and Acceptance Criteria.

The decrease in final feedwater temperature was 44°F and all other acceptance criteria were met.* Unit 2: Startup testing at 82% power, a simulated turbine trip signal to the extraction steam valves was initiated which resulted in the most severe restriction of extraction steam to one feedwater heater string. Recordings of the transient were analyzed and com-pared to the predicted response and Acceptance Criteria.

The decrease in final feedwater temperature was 34 °F and all other acceptance criteria were met.Based on plant historical data and EPU analytical results, the decrease in final feedwater temperature and the response of the feedwater" system and the reactor to a loss of feedwater heating are well within the analysis, therefore a loss of feedwater heating startup test is not necessary.

EPU Transient Analysis Results/CPPU Margins A loss of feedwater heating (LFWIH) transient can occur in one of two ways: " A steam extraction line to a feedwater heater is closed.* Inadvertent opening of the turbine bypass valves.The first case produces a gradual drop in the temperature of the feedwater.

In the second case, the re-duced steam flow through the turbine reduces extraction pressures and temperatures, resulting in a tem-perature reduction in the isolated heater string and overall feedwater heating is reduced. Both cases cause a decrease in the temperature of the feedwater entering the reactor vessel. This results in an increase in core inlet subcooling, which collapses voids and increases core average power and shifts the axial power distribution toward the bottom of the core. Because of this axial shift, voids begin to build up at the bot-tom again, acting as negative feedback to the void collapse process. This feedback moderates the core power increase.A LFWH analysis was performed for the EPU equilibrium cycle core design using approved methodolo-gies. An evaluation of the linear heat generation rate (LHGR) during a loss of feedwater heating transient for the EPU equilibrium cycle determined that the protection against power transients are not violated.The LHGR did not exceed 135% of the steady state value in any LFWH calculation.

SRP 15.1.1 provides acceptance criteria for loss of feedwater heating events. Loss of feedwater heating events at SSES, either under CLTP or CPPU conditions, do not challenge the criteria of SRP 15.1.1.EPU Power Ascension Testing Planned EPU power ascension testing of the feedwater control system is described in Table 3 (Test #23).For example, feedwater control system responses to reactor water level set point changes (for level set point change tests) are evaluated in various control modes (i.e. three element, single element).

Level set point changes are tested at each test condition 13 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING EPU Power ascension testing does not anticipate tripping feedwater heaters, because this type of event is relatively common and typically results in mild transients that are well within the capability of the plant systems to handle.Conclusion Testing the loss of feedwater heating is not required because this type of event is relatively common and typically results in mild transients that are well within the capability of the plant systems to handle.MSIV Closure Event The MSIV Closure Event startup test functionally checks the Main Steam Isolation Valves for proper op-eration at selected power levels, determines reactor transient behavior during and following simultaneous full closure of all MSIVs, determines isolation valve closure time and determines the maximum power at which a single valve closure can be made without a scram. The startup test for MSIV Closure Event at SSES established this occurrence and therefore further testing is not necessary.

Startup Test Objectives The objectives of the MSIV Closure Event startup tests are as follows: (1) functionally check MSIVs for proper operation at selected power levels; (2) determine reactor behavior during and following full and simultaneous closure of all MSIVs; (3) determine isolation valve closure time; and (4) determine the maximum power at which a single valve closure can be made without a scram. The Acceptance Criteria and testing methods for MSIV Closure Event are described in FSAR 14.2.Startup Test Results All Acceptance Criteria for MSIV Closure Event startup testing was satisfied for Unit I and Unit 2.Proper MSIV operation was demonstrated and proper closure times, during testing, at selected power lev-els for Unit I and Unit 2. The highest power level at which a single MSIV could be tested and still yield acceptable margins to scram and isolation was extrapolated and demonstrated to be 88.5% for Unit 1 and 88% for Unit 2. A full MSIV isolation was initiated from 100% power and the parameters of heat flux and reactor pressure were recorded and compared to predicted values for Unit I and Unit 2. Finally, valve clo-sure time was adjusted to within acceptable limits for Unit I and proper operation was demonstrated and closure times were within limits for Unit 2.Functionallv check MSIVs for Proper Operation at Selected Power Levels Unit 1: During startup testing MSIVs were closed and tested individually during initial heatup at rated pressure, and during TC-l at approximately 19% power. Proper operation was demonstrated and closure times were within limits. Neutron flux, reactor pressure, heat flux, and steam flow margins to scram or isolation were calculated and results were within limits.* Unit 2: Each MSIV was individually closed and tested during initial heatup at rated pres-sure, TC-5 at approximately 64% power, and TC-6 at approximately 89% power. Neu-tron flux, reactor pressure, heat flux, and steam flow margins to scram or isolation were calculated and results were within limits.Determine Reactor Behavior (huring and following Full and Simnulaneous Closure of all MSIVs* Unit I: A full MSIV isolation was initiated from 100%.power and the parameters of heat flux and reactor pressure were recorded and compared to predicted values. The actual 14 of 51 II Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING pressure rise experienced during this test was such that no safety/relief valves lifted.RCIC and HPCI auto started and restored water level to normal. The maximum water level experienced was +65". The results are shown in the table below and all Acceptance Criteria were met during the test..Unit 2: A full MSIV isolation was initiated from 100% power and the parameters of heat flux and reactor pressure were recorded and compared to predicted values. The actual pressure rise experienced during this test was such that no safety/relief valves lifted.RCIC and HPC1 auto started and restored water level to normal. The maximum water level experienced was +76". The results are shown in the table below and all Acceptance Criteria were met during the test.Predicted Actual Predicted Actual Average Maximum Test Heat Flux Heat Flux Pressure Pressure Closure Water Increase Increase Increase Increase Time Level Unit I Test 25.3 1% 0% I16psi 50 psi 3.2 sec 64.6 in.100% RP Unit 2 Test 25.3 <1% 0% 109.3 psi 50 psi 4.0 sec 76.2 in 100% RP Determine Isolation Valve Closure Time* Unit 1: During startup testing MSIVs were closed and tested individually during initial heatup at rated pressure, and during TC-1 at approximately 19% power. Proper operation was demonstrated and closure times were within limits.* Unit 2: Each MSIV was individually closed and tested during initial heatup at rated pres-sure, TC-5 at approximately 64% power, and TC-6 at approximately 89% power. Proper operation was demonstrated and closure times were within limits.Determine the Maximum Power a! which a Single Valve Closure can be made without a Scram" Unit 1: The highest power level at which a single MSIV could be tested and still yield acceptable margins to scram and isolation was extrapolated and demonstrated to be 88.5%." Unit 2: The highest power level at which a single MSIV could be tested and still yield acceptable margins to scram and isolation was extrapolated and demonstrated to be 88%.Operational Experience Since Startup On July 1, 1999, a full MSIV closure event occurred in Unit 1. The event occurred when the inadvertent closure of one MSIV resulted in an indication of high steam flow in the remaining 3 steam lines. The first MSIV closed at time zero, with the remaining 3 closing at time 8 seconds. Reactor pressure remained fairly stable throughout the event, with reactor vessel level varying from slightly below instrument zero to approximately

+60 inches. Data recorded during the event demonstrated that the plant responded as ex-pected and that resulting parameters were well within guidelines and requirements.

The July 1999 event is not exactly the same as the startup tests (test #25.3), since there was an 8 second difference between closure of the first MSIV and closure of the other three. Nevertheless, a comparison of the July 1999 data with the startup testing data shows that the results are comparable.

15 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL---STARTUP TESTING Unit I Startup Test Unit 2 Startup Test July 1999 Event Actual Pressure Increase 50 psi 50 psi 20 psi Maximum Level 64.6 inches 76.2 inches 59.6 inches EPU Transient Analhsis Results/CPPIJ Margins The analysis of the closure of all MSIVs ("MSIVALL")

was performed at EPU rated power and core flow conditions covering the full range of core flows at rated power. Comparing the limiting Delta CPRs for the MSIVALL transient with the results from other transients shows that the MSIVALL transient is not limiting with respect to Delta CPR at EPU rated power.The following table lists the limiting Delta CPRs for the MSIVALL transient for the conditions analyzed.Limiting Delta CPR Results for Closure of All MSIVs Event ATRPUM-1 0 Delta CPR Exposure (MWdIMTU)

MELLLA BOC to EOC 0.11 MSIV closure margins are discussed in SRP 15.2.4. Similar to the generator load reject event (GLR), the SRP states that reactor steam pressures should remain below 110% of the design value. As in the case of the GLR event, this is not an issue at SSES since the safety relief valves (SRVs) will easily maintain pres-sure below the design value. This was vividly demonstrated at SSES during a GLR event on June 6, 2005. This event is discussed (including a plot of RV pressure) in the GLR discussion below. As shown below, the RV pressure transient was limited to approximately 1100 psia by operation of two SRVs. Two SRVs operated during the 06-06-05 event. Even if a 3 d SRV were to operate at CPPU, there would be no change in pressure and no change in design margin.EPU Power Ascension Testing / CPPU Modifications EPU plant response during power ascension is tested and documented as described in the CTLR/ELTR.

MSIV full closure testing at 100% core power during EPU power ascension testing is not required at SSES because the plant response at CPPU conditions is expected to be similar to the documented re-sponse during initial startup testing. The transient analysis performed for the SSES CPPU demonstrates that all safety criteria are met and that CPPU does not cause any previous non-limiting events to become limiting.

However, deliberately closing all MSIVs from 100% power will result in an undesirable transient cycle on the primary system that can reduce equipment service life? The transient loading provides no addi-tional plant response information beyond that documented during startup testing and provides no benefit to safety equipment Conclusion Based on plant historical data and EPU analytical results, actual test results were well within expected limits. Actual pressure increase, in both Unit I and Unit 2 startup tests, were less than 50% of the ex-pected values and further plant testing of MSIV Closure Event is not necessary.

• As demonstrated during startup and confirmed by analysis, all equipment responses to the transient are within component and system design capabilities.

However, placing accident mitigation equipment into service, tinder maximum loading conditions, uses available service life. Equipment service life should be retained for actual events rather than for demonstration purposes.16 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Turbine Trip/Generator Load Rejection The startup testing for Turbine Trip/Generator Load Rejection demonstrates the response of the reactor and its control systems to protective trips in the turbine and generator.

The startup test for Turbine Trip/Generator Load Rejection at SSES adequately demonstrated this response and further testing is not con-sidered necessary.

Startup Test Objectives The objectives of the Generator Load Rejection startup tests are as follow: (1) demonstrate the response of the reactor and its control systems to protective trips in the turbine and generator; (2) demonstrate the capacity of the turbine bypass valves. The Acceptance Criteria and testing methods for Turbine Trip/Generator Load Rejection are described in FSAR 14.2.Startup Test Results All Acceptance Criteria for Turbine Trip/Generator Load Rejection startup testing were satisfied for Unit 1 and Unit 2 as further detailed below.Demonstrate the Response of the Reactor and its Control Systems to Protective Trips in the Turbine and Generator* Unit 1: This subtest was performed twice because the first test was invalidated when the transfer of the plant electrical loads did not occur. Test results follow.A generator load rejection was initiated by opening the Main Generator Breaker 230 KV OCB IRI01. This action initiates a fast closure of the Main Turbine Control Valves to limit the turbine overspeed.

The load rejection was performed at 100% power. Fast trans-fer of the auxiliary bus from the unit auxiliary transformer to the startup transformer oc-curred. The plant responded as expected.Unit 2: All Acceptance Criteria were verified satisfactorily with exception of the two pump drive flow coastdown constants.

The reactor operated at 97% power and the gen-erator output breakers were opened causing a fast closure of the main turbine control valves and a subsequent reactor scram.Demonstrate the Capacity of the Turbine Bypass Valves.The objectives of the test were met and all Acceptance Criteria were satisfied for Unit 1 and Unit 2 except with the two pump drive flow coastdown time constant requirement, which was later evaluated and re-solved.Unit 1: With the reactor operating at 25% of rated power level, so that the reactor scram signals on Turbine Control Valve Fast Closure and Turbine Stop Valve Trip were by-passed, the Main Generator Breaker was opened. This resulted in a Turbine Trip and Control Valve Fast Closure without causing a reactor scram. The bypass valves opened to control reactor pressure and the feedwater system maintained water level constant al-though a slight oscillatory response in water level was noted. The overall response was uneventful as anticipated.

A failure of the Level I Criteria which states that the bypass valves should be opened to a point corresponding to greater than or equal to 80% of full open within 0.3 seconds from 17 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING the beginning of control or stop valve closure motion was encountered during this test.This failure resulted because power level at which the test was performed only required the bypass valves to open 73% to maintain pressure after the turbine trip. This response occurred in 0.2 seconds, which was determined to be acceptable.

Overall results confirm that conservative assumptions were made in the analysis of these events in Section 15 of the FSAR. The objectives of the test were met and All Accep-tance Criteria was satisfied.

Unit 2: Within the reactor operating at 20% of rated power level, so that the reactor scram signals on Turbine Control Valve Fast Closure and Turbine Stop Valve Trip were by-passed, the Main Generator Breaker was opened. This resulted in a Turbine Trip and Control Valve Fast Closure without causing a reactor scram. The bypass valves opened to control reactor pressure and the feedwater system maintained water level constant al-though a slight oscillatory response in water level was noted. The overall response was uneventful as anticipated.

The delay time from the start of control or stop valve closure to the start of bypass valve opening was 0.05 seconds, which was less than the maximum al-lowed of 0.1 seconds.Operational Experience Since Startup A turbine trip/full load rejection event occurred in SSES Unit 2 on June 6, 2005. An electrical transient caused a trip of both recirculation pumps. As shown in the graph below, reactor vessel pressure remained fairly stable (after an initial peak to approximately I 100 psia) and level varied as expected.

The feedwa-ter system returned reactor water level to normal. Two SRVs opened and then closed. The bypass valves operated successfully and contributed to maintenance of steady vessel pressures.

A recirculation pump was restarted to reestablish core flow. There were no challenges to the containment during this event.18 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Generator Load Reject'- 06/06105 0 C 0 U_1.20 1.00 0.80 0.60 0.40 0.20............

........ ..is 20 2 fl\ -.iNR Pressurei; WR Level RX Power 0.00 1 I 5-0.20 Time in Seconds EPU Transient Analysis ResultsfCPPLJ Mar2ins The Generator Load Rejection with bypass (LRWB) and the Turbine Trip with bypass (TTWB) events were conservatively combined as one event ("LRWB/1TWB").

The LRWB!TTWB event is identical to the Generator Load Rejection and Turbine Trip without bypass except the turbine bypass valves (TBV)are allowed to operate to help mitigating the pressurization event.The LRWBfTTWB analyses were performed at EPU rated power and core flow conditions covering the full range of core flows at rated power. The following table lists the limiting change in Critical Power Ra-tios ("CPR") for the LRWBITTWB transient for the conditions analyzed.Limiting Delta CPR Results for Load Rejection/Turbine Trip With Bypass Exposure ATRIUM-10 Delta CPR (MWd/MTU)

MELLLA BOC to EOC 0.22 GLR margins requirements are given in SRP 15.2.6 (Loss of Non-Emergency AC Power). The SRP states the steam system should be maintained below 110% of the design value. As shown in the generator load reject event of 06-06-05 (above), RV pressure and steam pressure peak in the 1100 psia range due to operation of the SRVs. Two SRVs operated in the 06-06-05 event. Even if a 3 Yd SRV were to open at EPU conditions, the pressure profile would remain essentially the same. There would be no challenge to system design pressure.

In addition, there would be no changes in pressure margins between CLTP and CPPU conditions.

19 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING EPU Power Ascension Testing Turbine trip/generator load rejection testing at 100% core power during EPU power ascension testing is not required at SSES because plant responses at CPPU conditions are expected to be similar to the docu-mented response seen during initial startup testing and the recent Unit 2 load reject on June of 2005. The transient analysis performed for the SSES CPPU demonstrates that all safety criteria are met and that CPPU does not cause any previous non-limiting events to become limiting.

However, deliberately caus-ing a load reject and subsequent scram from 100% power results in an unnecessary transient cycle on the primary system that can cause undesirable effects on equipment and grid stability.

The transient loading pro-vides no benefit to safety equipment.

Therefore, additional load reject I turbine trip testing causing a scram from high power levels is not expected to result in plant response that has not been previously observed nor provide new insights into SSC performances.

Conclusion In view of the above, transient mitigation capability is demonstrated by post modification testing and by Technical Specification required testing. In addition, the limiting transient analyses are included as part of the reload licensing analysis.

From a safety significance standpoint, turbine trip/load reject testing cannot be justified in that the transient cycle on the primary plant is undesirable and the potential benefits from such a cycle are not safety significant.

The potential for hidden defects or latent problems that might be uncovered (such as potential hanger failures or potential snubber failures) are not justified on the basis of safety significance, compared to the potential negative aspects of the transient.

The response of the reactor and its control systems following trips of the turbine and generator has been demonstrated by numerous plant events and shown by EPU analysis to be acceptable.

Therefore the objective of this test is satisfied without requiring actual plant transient testing.Finally, full load reject testing is not required under the guidelines of ELTRI as shown below: Event Date Power Level Power % Increase Required by Level ELTRI Reject 6-6-2005 3489 MWt 3952 MWt 13.3%Reject 15%Recirculation Pump Trip Information gathered during startup Recirculation Pump trip testing is used to (1) obtain recirculation sys-tem performance data during pump trip, flow coastdown and pump restart; (2) verify that the feedwater control system can satisfactorily control water level without a resulting turbine trip and associated scram;(3) record and verify acceptable performance of the recirculation two pump circuit trip system; (4) verify the adequacy of the recirculation runback to mitigate a scram, and (5) verify that no recirculation system cavitation will occur in the operable region of the power-flow map. The Recirculation Pump Trip startup test satisfied acceptance criteria and therefore further testing is not necessary.

Startup Test Objectives The Recirculation Pump Trip startup test objectives are: (1) obtain recirculation system performance data during pump trip, flow coastdown, and pump restart; (2) verify that the Feedwater Control System can satisfactorily control water level without a resulting turbine trip and associated scram; (3) record and ver-ify acceptable performance of the recirculation two pump circuit trip system; (4) verify the adequacy of the recirculation runback to mitigate a scram: (5) verify that no recirculation system cavitation will occur in the operable region of the power-flow map. The Acceptance Criteria and testing methods for Recircula-tion Pump Trip are described in FSAR 14.2.20 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Startup Test Results The overall Acceptance Criteria and objectives for the Recirculation Pump Trip test were satisfied for Unit 1 and Unit 2.Obtain Recirculation Sstem Performnance Data during Pump Trip, Flow Coastdown, and Pump Restart and VerifX that the Feedwater Control System can Satisfactorily Control Water Level without a Resulting Turbine Trip and Associated Scram and R ecord and Verify Acceptable Performance of the Recirculation Two Pump Circuit Trip Sjstem* Unit 1: RPT breakers were simultaneously tripped using a temporary test switch while the power was at 75% and core flow was at 100%. Flow coast down times were accept-able.MG Set breakers were tripped from the control room at 70% power and 100% core flow and an unexpected MG Set breaker trip occurred due to a circuit board failure at 98%power and 98% core flow. For each trip, recordings of reactor parameters were made dur-ing the ensuing transient and these recordings were analyzed to verify non-divergence of oscillatory responses, adequate margins to RPS set points and capability of the feedwater system to prevent a high water level trip. The restart capability of the recirculation pump at high power level was also demonstrated.

The margins to scram that were measured during the pump trip and pump restart were found to be acceptable.

• Unit 2: RPT breakers were simultaneously tripped using a temporary test switch while the power was at 72% and core flow was at 99%. Flow coast down times were accept-able.Breakers were tripped from the control room at 72% power and 96% core flow and again at 98% power and 99% core flow. During each trip recordings of reactor parameters were made during the ensuing transient and these recordings were analyzed to verify non-divergence of oscillatory responses, adequate margins to RPS set points and capability of the feedwater system to prevent a high water level trip. The restart capability of the recir-culation pump at high power level was also demonstrated.

The margins to scram that were measured during the pump trip and pump restart met acceptance criteria.Veeýi' the Adequacy of the Recirculation Runback to Mitigate a Scram* Unit 1: Runback occurred producing a smooth transient for all parameters measured.

A circulating water pump trip was simulated while running at 75% power and 100% core flow causing a runback to the number two Limiter setting of 45%..* Unit 2: Runback occurred producing a smooth transient for all parameters measured.

A feedwater pump was tripped and reactor water level allowed to drop below level 4 caus-ing a runback of both recirculation pumps to the number two Limiter setting of 45% of rated speed. The feedwater pump was tripped while running at 71% power and 98% core flow.Verif, that no Recirculation System Cavitation Occurs in the Operable Region of[the Power-Flow Map.* Unit 1: This test demonstrates that the Feedwater Flow interlocks with the Recirculation Pump Number I Limiter are set such that cavitation will not occur in the Recirculation Pumps or Jet Pumps. The absence of pump cavitation is verified by observation of nor-'21 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING mally installed instrumentation to monitor the differential pressure across each recircula-tion pump, loop flow elbow tap and double tap jet pumps.With reactor power at 57% and core flow at 100% of rated, the No. I Limiter was by-passed so the actual runback would not take place and control rods were inserted until the No. I Limiter actuated.

This occurred at 20% of Total Feedwater Flow for each limiter.Cavitation was not observed.Unit 2: This test demonstrates that the Feedwater Flow interlocks with the Recirculation Pump No. I Limiter are set such that cavitation will not occur in the Recirculation Pumps or Jet Pumps. The absence of pump cavitation is verified by observation of normally in-stalled instrumentation to monitor the differential pressure across each recirculation pump, loop flow elbow tap and double pumps.With reactor power at 51% and core flow at 95% of rated, the No. 1 Limiter was by-passed so the actual runback would not take place and control rods were inserted until the No. I Limiter actuated.

This occurred at 20% of Total Feedwater Flow for each limiter.Cavitation was not observed.

Acceptance Criteria 7 was verified in this subtest.EPU Transient Analysis Results Recirculation pump trip events were not analyzed since they have been dispositioned as non-limiting events. In addition, in a CPPU, core flow remains essentially unchanged.

Therefore recirculation pump testing is not necessary.

EPU Power Ascension Testing/CPPU Margins Core flow does not appreciably change in a CPPU. The results from startup testing and also from the events that have occurred during plant operations indicate recirculation pump trip testing is not necessary.

Because The feedwater flow value used to initiate the recirculation runback to the #1 limiter is unchanged for EPU, protection against cavitation is assured., SRP 15.3:1 provides criteria for loss of forced RCS flow events. None of these criteria are challenged at SSES either under CLTP conditions or at CPPU.Conclu sion Based on plant historical data and EPU analytical results, (1) recirculation system performance data was collected, (2) the feedwater control system satisfactorily controls water level without a resulting turbine trip and scram, (3) the recirculation two pump circuit trip system performed acceptably, (4) the recircula-tion runback mitigated scrams, and (5) no recirculation system cavitation occurred in the operable region of the power-flow map and therefore further plant testing of Recirculation Pump Trip is not necessary.

Relief Valve Testing This startup test Relief Valve Testing verifies that the relief valves function properly, reseat properly after operation, and contain no major blockages in the relief valve discharge piping. Startup testing showed that all relief valves functioned properly and reseated properly after operations.

Testing demonstrated plant pressure control system stability during relief valve operation and showed that no blockages existed in relief valve discharge piping. Therefore further testing is not necessary.

22 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Startup Test Objectives The objectives for Relief Valve startup testing are: (1) verifythat the relief valves function properly and can be manually opened and closed; (2) verify that the relief valves reseat properly after operation; (3)verify that there are no major blockages in the relief valve discharge piping; and (4) verify the proper op-eration of the relief valve actuation logic system. The Acceptance Criteria and testing methods for Relief Valve are described in FSAR 14.2.Startup Test Results Acceptance Criteria for Relief Valve startup testing was satisfied overall for Unit I and Unit 2.Verify that the Relief Valves Function Properly, Can be Manually Opened and Closed, and Reseat Prop-erlX after Operation* Unit 1: Relief Valve Rated Pressure Testing was implemented at 45% rated thermal power with a dome pressure of 944 psig. Each relief valve was manually cycled to verify proper operation at rated pressure.

Pressure control system related variables were again observed for stability during relief valve actuation and the relief valve tail pipe tempera-tures were monitored after actuation to verify that each relief valve had properly reseated.All Acceptance Criteria were met during the test." Unit 2: Relief Valve Rated Pressure Testing was implemented at 41% rated thermal power with a dome pressure of 930 psig. Each relief valve was manually cycled to verify proper operation at rated pressure.

Pressure control system related variables were again observed for stability during relief valve actuation and the relief valve tail pipe tempera-tures were monitored after actuation to verify that each relief valve had properly reseated.All Acceptance Criteria were met during the test.that there are No Ma or Blockages in the Relief Valve Discharge Pi ing Unit 1: Each relief valve was manually cycled to verify proper operation at rated pres-sure. The decrease in main generator electric output during each relief valve actuation was compared to the generator electric output average change, calculated after all relief valves had been actuated, to verify that no major blockages in valves or tailpipes existed.Relief Valve Rated Pressure Test was implemented at 45% rated reactor thermal power with reactor dome pressure at 944 psig during. All Acceptance Criteria were met during the test.Unit 2: Each relief valve was manually cycled to verify proper operation at rated pres-sure. The decrease in main generator electric output during each relief valve actuation was compared to the generator electric output average change, calculated after all relief valves had been actuated, to verify that no major blockages in valves or tailpipes existed.Relief Valve Rated Pressure Test was implemented at 41% rated reactor thermal power with reactor dome pressure at 930 psig. All Acceptance Criteria were met during the test.Operational Experience Since Startup Relief valves are inspected and tested in accordance with Technical Specification requirements.

EPlI Transient Analysis Results Relief valve operations were not analyzed.

Inadvertent relief valve openings have been determined to be non-limiting events.23 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL--STARTUP TESTING EPU Power Ascension Testing Relief valves will continue to be tested in accordance with Technical Specifications.

Since relief valve setpoints are not changed and relief valve operations are not impacted by CPPU, there is no need for any additional testing beyond the testing already required by Technical Specifications.

Conclusion Technical specification testing demonstrates that relief valves function properly.

Plant pressure control system stability has been consistently demonstrated during relief valve operation showing no blockages existed in relief valve discharge piping. Further in-plant testing of relief valves is not necessary.

RCIC Functional Testing The RCIC Functional Testing startup test verifies the proper operation of the RCIC system at the mini-mum and rated operating pressures and flow ranges and demonstrates reliability in automatic mode start-ing with cold standby when reactor is at power conditions.

The test is demonstrated by two methods: (1)by flow injection into a test line that leads to the Condensate Storage Tank (CST) and (2) by flow injec-tion directly into the reactor vessel. Acceptance Criteria was satisfied for the RCIC Functional Test dur-ing startup testing and therefore further testing is not necessary.

Startup Test Objectives The objectives for RCIC functional testing startup tests are: (1) demonstrate the proper operation of the Reactor Core Isolation Cooling (RCIC) System over its expected operating pressure and flow ranges; and (2) demonstrate RCIC reliability in automatic starting from cold standby when the reactor is at power conditions.

The Acceptance Criteria and testing methods for RCIC Functional Testing are described in FSAR 14.2.Startup Test Results All Acceptance Criteria for startup RCIC Functional testing was satisfied for Unit I and Unit 2.Demonstrate the Proper Operation of the Reactor Core Isolation Cooling (RCIC) System over its Ex-pected Operating Pressure and Flow Ranges" Unit 1: All Acceptance Criteria was satisfied.

The RCIC system demonstrated its reliabil-ity by never tripping or isolating during testing and by always achieving rated flow within the allowed 30 seconds. The few minor problems that did occur were Level 2 Acceptance Criteria failures and were adequately dispositioned." Unit 2: All Acceptance Criteria was satisfied.

The RCIC system demonstrated its reliabil-ity by always achieving rated flow within the allowed 30 seconds, and by never tripping during auto start tests. The turbine did trip once during a manual start, which was attrib-uted to air in the servo control valve following maintenance to the control valve. The other minor problems that did occur were all Level 2 Acceptance Criteria failures and were adequately dispositioned.

Demonstrate RCIC Reliability in Automatic Starting from Cold Standby when the Reactor is at Power Conditions

• Unit .: All Acceptance Criteria was satisfied.

The RCIC system demonstrated its reliabil-ity by never tripping or isolating during testing and by always achieving rated flow within 24 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL--STARTUP TESTING the allowed 30 seconds. The few minor problems that did occur were all Level 2 Accep-tance Criteria failures and adequately dispositioned.

Unit 2: All Acceptance Criteria was satisfied.

The RCIC system demonstrated its reliabil-ity by always achieving rated flow within the allowed 30 seconds, and by never tripping during auto start tests. The turbine did trip once during a manual start, which was attrib-uted to air in the servo control valve following maintenance to the control valve. The other minor problems that did occur were all Level 2 Acceptance Criteria failures and were adequately dispositioned.

Conclusion Based on plant historical data and EPU analytical results, proper operation of the RCIC system at the minimum and rated operating pressures was achieved and flow ranges demonstrated reliability in auto-matic mode starting with cold standby when reactor is at power conditions and therefore further plant test-ing of RCIC Functional Testing is not necessary.

EPU Reactor Core Isolation Cooling System Evaluation The RCIC system does not change for CPPU. Pressures, flow rates, and response times are virtually identical.

Consequently, the RCIC system is not evaluated other than as it contributes to mitigation of other anticipated transients and events..Operational Experience Since Startup During operational events since startup, RCIC has provided acceptable performance when required to function by operational events.EPTJ Power Ascension Testing RCIC testing during EPU power ascension testing is not required because the CPPU changes do not have a significant impact on the RCIC system.* Specifically, system pressures, temperatures, flow rates, and timing requirements remain unchanged from CLTP requirements.

Therefore, RCIC testing would not provide any new data, particularly with regard to overall plant safety significance.

RCIC testing in accor-dance with Technical Specification requirements remains a sufficient demonstration of RCIC capability.

HPCI Functional Testing The High Pressure Coolant Injection

("HPCI") Functional Testing startup test verifies the proper opera-tion of the HPCI system at the minimum and rated operating pressures and flow ranges and demonstrates reliability in automatic mode starting with cold standby when reactor is at power conditions.

The test is demonstrated by two methods: (1) by flow injection into a test line that leads to the Condensate Storage Tank (CST) and (2) by flow injection directly into the reactor vessel. Acceptance Criteria was satisfied for the HPCI Functional Test during startup testing and therefore further testing is not necessary.

Startup Test Obiectives The objectives for HPCI functional testing startup tests are: (i) demonstrate the proper operation of the HPCI system over its expected operating pressure and flow ranges: and (2) demonstrate HPCJ reliability in automatic starting from cold standby when the reactor is at power conditions.

The Acceptance Criteria and testing methods for HPCI Functional Testing are described in FSAR 14.2.25 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Startup Test Results All Acceptance Criteria for startup HPCI Functional testing was satisfied for Unit I and Unit 2.Demonstrate the Proper Operation of the High Pressure Coolant hniection (HPCII System over its Ex-pected Operating Pressure and Flow Ranges.* Unit 1: The HPCI system demonstrated its reliability by never tripping or isolating during testing and by achieving rated flow within the allowed 25 seconds in nine out often tests.In the tenth test, ST 15.1 on 1-1-83, the system started in 25.1 seconds with flow exceed-ing the 4900 gpm during the interval between 17 and 25 seconds. Evaluation by General Electric determined that the results were acceptable.

Some problems were experienced in tuning the HPCI flow controller.

Difficulty was ex-perienced in trying to find the optimum controller settings so that the system would start in 25 seconds but not trip, yet would still be stable for step changes in flow demand. As a result, ST 15.1 and 15.2 had to be repeated.Unit 2: Testing of the HPCI system can be divided into two phases, before and after pre-commercial outage. Prior to the pre-commercial outage the HPCI system demonstrated its reliability by never tripping or isolating during testing and by achieving rated flow within the allowed 25 seconds in five out of six tests. In the sixth test, ST 15.3 on 9-25-84, the system required 26.3 seconds to achieve rated flow. The Tech Spec limit of 30 seconds was not violated.

Investigation into the problem resulted in an Environmental Upgrade Modification and a replacement of the mechanical overspeed trip mechanism.

The Envi-ronmental Upgrade Modification involved replacing the EGR, the servo on the control valves, the temperature control valve on the lube oil cooler and the turbine trip solenoid valve and was done during the Pre-commercial Operations Outage.The two other problems that did occur were both Level 2 Acceptance Criteria failures.The initial run of ST 15.1 yielded a subsequent speed peak of 4440 rpm, which was above the limit of 4336 rpm. The HPCI flow controller was tuned, and since ST 15.1 at 150# had already been run, ST 15.1 was repeated at both 150# and rated pressure.

The other problem which also surfaced during the initial test concerned a low NPSH value caused by the startup strainer never being removed from the suction line. Upon removal, the NPSH value was acceptable.

All acceptance criteria were satisfied except for the time to rated flow failure mentioned previously.

Conclusion Based on plant historical data and EPU analytical results, proper operation of the HPCI system at the minimum and rated operating pressures was achieved and flow ranges demonstrated reliability in auto-matic mode starting with cold standby when reactor is at power conditions and therefore further plant test'ing of HPCI Functional Testing is not necessary.

EPU Hiuh Pressure Coolant Injection System Evaluation The HPCI system does not change for CPPU. Pressures, flow rates, and response times are virtually iden-tical. Consequently.

the HPCI system is not evaluated other than as it contributes to mitigation of other anticipated transients and events.26 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL--STARTUP TESTING Operational Experience Since Startup During operational events since startup, HPCI has provided acceptable performance when required to function by operational events.EPU Power Ascension Testing HPCI testing during EPU power ascension testing is not required because the CPPU changes do not have a significant impact on the HPCI system. Specifically, system pressures, temperatures, flow rates, and timing requirements remain unchanged from CLTP requirements.

Therefore, HPCI testing would not provide any new data, particularly with regard to overall plant safety significance.

HPCI testing in accor-dance with Technical Specification requirements remains a sufficient demonstration of HPCI capability.

5.0 Operator

Training/Large Transient Simulations For EPU, SSES plans to benchmark its simulator to conform to EPU transient analysis results and to sub-sequently perform certification tests to confirm the adequacy of simulation of the various transients.

Once the simulator is benchmarked and certified, SSES operators will be trained on various plant upset conditions, from postulated accident conditions to anticipated transients.

In this way, plant operators will be prepared for the nature, timeline, and extent of the plant response to simulated transients.

6.0 Large

Transient Testing Risk Assessment SSES conducted a risk assessment for performing two plant transient tests upon EPU implementation.

The evaluated tests were a generator full load reject and an MSIV isolation event. The risk assessment indicated the proposed tests represented an increase in the risk of core damage and large early release.This assessment does not include the potential for equipment damage or challenges to the operators, which should be avoided.Method The calculations were performed with the FEB05RA version of the SSES PRA. The Conditional Core Damage Probabilities (CCDPs) were calculated by multiplying the random maintenance model Core Damage Frequency (CDF) from the pre-EPU model by the Fussell-Vesely of the initiator and dividing that product by the frequency of the initiator.

The Fussell-Vesely represents the fractional contribution to the damage state from the event occurring.

PRA Results Below are the data extracted from the cut set file. The LOOP frequency is from the Initiating Event Note Book.27 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL,-STARTUP TESTING I CDF I LERF Base 2.95E-06 1.18E-06 Fussell-Vesely

• Fussell-Vesely

• Initiating Event CDF (FV) LERF (FV) Frequency

/ year Non-isolation event 1.88E-01 8.64E-02 8.90E-0 I Isolation event (MSIVC) 2.80E-02 4.47E-02 1.36E-01 Recirc Suction side LOCA 5.90E1-02 1.33E-02 3.8 1E-04 LOOP 5.56E-0I 6.28E-01 2.98E-02 CCDPa = CDFbase

• FVa / Fa (similar formula for CLERPa)Initiator CCDP CLERP Non-isolation event 6.24E-07 1.15E-07 Isolation event (MSIVC) 6.08E-07 3.88E-07 Recirc Suction side LOCA 4.57E-04 4.13E-05 LOOP 5.51E-05 2.49E-05* FV is the fraction of core damage attributable to the specific event.Conclusion The Conditional Core Damage Probabilities (CCDP) and Conditional Large Early Release Probabilities (CLERP) for a turbine trip (%INONISO) and for a MSIV closure event (%IISO) are relatively small compared to events such as the LOOP or a suction side LOCA. However, they do have some risk signifi-cance.The calculated CCDPs are 6.24E-7 and 6.08E-7 for the non-isolation (turbine trip) and isolation (MSIV closure), respectively.

Also, the calculated CLERPs are 1.15E-7 and 3.88E-7 for the non-isolation (tur-bine trip) and isolation (MSIV closure), respectively.

These CCDPs and CLERPs represent the additional probabilities of core damage and large early release, caused by performing the proposed tests (i.e., the initiating events occur). If both tests are performed, the total additional probabilities would, thus, be 1.23E-6 (CCDP) and 5.03E-7 (CLERP). [Note: The analyses do not credit compensatory measures that may reduce the risk of core damage given that extra operators may be staged for the proposed tests.]In view of the foregoing and from a PRA perspective, Large Transient Testing should not be performed unless clear benefits can be achieved that cannot otherwise be obtained through an unplanned event.7.0 Post EPU Industry Experience Post EPU Steam Dryer Issues Steam dryer failures have occurred at post EPU conditions.

These failures have been attributed to high cycle fatigue stresses that result from acoustic and pressure pulses caused by the higher EPU main steam velocities.

Problems that have occurred are the result of long term cyclic pulses that fatigue areas of high stress intensities.

They do not result from transient events except to the extent that the lifting of safety 28 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING relief valves can add to main steam velocities.

In the case of Large Transient Testing; however, safety relief valves typically lift because the MSIVs have closed with the result being that steam velocities are actually lower and not higher. Also, with fatigue as the failure mechanism, even increased velocities are not significant in that they do not last for extended periods of time.Stresses imposed on steam dryers by the higher steam flows are being addressed in Attachment 10 of the SSES EPU application, and therefore will not be repeated here. At the same time, it should be noted that steam dryer performance is not demonstrated by Large Transient Testing. Steam dryer stresses can be determined by finite element analyses using pressure and acoustic data developed from strain gauge and acoustic measurements in the main steam lines. Should dryer failures occur, they can be observed by changes in main steam flows, steam line pressure drops, and high moisture carryover content. Dryer fail-ures would not be indicated in Large Transient Testing because even if abnormal measurements were to occur during a transient test, they would be masked by the transient and would not stand out as an indica-tion of dryer problems.Industrv Post EPU Transient Events A review of industry transient events that occurred at greater than original power levels at BWR-4 units that are similar in design to SSES resulted in the following examples of plant response to MSIV closure and load reject events. As indicated in the examples below, the plants responded as expected in accor-dance with their design features.

No unexpected conditions were experienced nor were any latent defects uncovered in these events beyond the specific failures that actually initiated the events. These events pro-vide further evidence that Large Transient Testing is unnecessary.

Edwin I. Hatch Nuclear Plant -13% Approved Power Uprate LER 99-05 On May 5, 1999, Hatch Unit 2 was at 98.3% of rated power (2,716 CMWT). At that time, the turbine tripped when the main generator tripped on a ground fault. The reactor scrammed and the reactor recircu-lation pumps tripped automatically on turbine control valve fast closure caused by the turbine trip. The reactor feed water pumps maintained water level higher than eight inches above instrument zero. No safety system actuations on low level were received nor were any required.

Pressure reached a maximum value of 1,124 psig. Plant and system responses were as expected.LER 2000-004 On July 10,2000, Hatch Unit I was at 99.7% rated thermal power (2,754 CMWT). At that time, the main turbine tripped when the vibration instrument on the main generator exciter outboard bearing failed and produced a false high bearing vibration signal. The reactor automatically scrammed and the reactor recir-culation pumps automatically tripped on turbine stop valve fast closure caused by the main turbine trip.All systems functioned as expected and given the water level and pressure transients caused by the turbine trip and reactor scram. Vessel water level never decreased to the Level 3 actuation setpoint.

No safety system actuations were received nor were any required.LER 2001-02 On March 28, 2001, Plant Hatch Unit I was at 100 percent rated thermal power (2.763 CMWT). At that time, the reactor automatically scrammed on turbine control valve fast closure caused by a main turbine trip. The main turbine tripped when actuation of phase two and phase three differential relays monitoring a unit auxiliary transformer resulted in actuation of a lockout relay. Actuation of this lockout relay gener-ated a direct turbine trip signal and the main turbine tripped per design.29 of 51 Susquelhanna Steant Electric Station, Extended Power Uprate Project ATTACHMENT TO EPU NRC SUBMITTAL-STARTUP TESTING Reactor Feedwater Pumps recovered reactor vessel water level within 30 seconds of the scram. As a re-sult, the HPCI and RCIC system low water level initiation signals cleared before either system could in-ject makeup water to the reactor vessel. Vessel pressure reached a maximum value of 1,127 psig after receipt of the scram. All systems functioned as expected and per their design given the water level and pressure transients caused by the turbine trip and reactor scram. Vessel water level was maintained well above the top of the active fuel throughout the transient.

Brunswick Steam Electric Plant -20% Approved Power Uprate LER 2003-01 On January 12, 2003, Brunswick Steam Electric Plant Unit I was operating at 94% rated thermal power.Decreasing reactor coolant level due to a reactor feed water pump turbine trip resulted in the actuation of the reactor protection system, and a Group 2 and Group 6 primary containment isolation valves closures.After the plant trip, the (4) emergency diesel generators started due to an invalid signal generated by switchyard equipment.

In addition, the Reactor Core Isolation Cooling system was manually operated to maintain coolant level in the reactor vessel. The loss of the reactor feed water pump. was attributed to insufficient lube oil pressure margin in the bearing oil header.The required equipment responded as designed and the Group 2 and 6 valves isolated.

All control rods fully inserted into the core. However, a power circuit breaker in the 230 kV electrical power system did not open initially as designed to separate the main transformer and generator from the grid. This caused an invalid signal that resulted in the start of the emergency diesel generators after the turbine generator trip.LER 2003-04 On November 4, 2003, Brunswick Steam Electric Plant Unit 2 was operating at approximately 96% of rated thermal power when a generator/turbine trip occurred due to loss of generator excitation.

Ap-proximately three seconds into the voltage transient, the Unit 2 generator/turbine tripped, resulting in RPS actuation.

The voltage decrease also resulted in PCIS Valve Group I (Main Steam Isolation valves (MSIVs), Main Steam Line Drain valves, and Reactor Recirculation Sample valves), Group 3 (Reactor Water Cleanup isolation valves), and Group 6 (Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post Accident Sampling System isolation valves) isolations.

All control rods fully inserted into the core. Plant response to the transient also resulted in High Pres-sure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) System actuations on low reactor pressure vessel (RPV) coolant level, with injection into the RPV. All four Emergency Diesel Generators (EDGs) automatically started but did not load because electrical power was not lost to the emergency buses.30 of 51 Suisquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent of Test Unit' Uprate Testing Planned JustificatlontNotes 3489 MWt (CLTP)Tesitti Original Test _(UFSAR 14.31 for CPPU Te't .Description E (UFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P 2 2___ U 19%Chemical & Radiochemical:

This 27%test secures information on the 27%cheisryandraioheiisryof 54% Secured information YeNo.chemistry and radiochemistry of 69% y y on chemistry and ra- EPU task Test will be performed.

See X X X X Sampling equipment.

procedures, 9"% diochemistry in the T1005 Table 3 for details.sapln euimnt poedre, TCI-3 uprate condition.

and techniques meet specifications TC c and requirements.

TC6 Radiation Measurements:

This test At the uprate power determines background radiation 17% level, gamma dose and levels in plant environs prior to op- 47% neutron dose rate Yes None.ST-2 cration for base data on activity 100% V y measurements were EPU task Test will be performed.

See X X X X X buildup and monitors radiation at TC I made at pre-designated T1005 Table 3 for details.selected power levels to assure the TC 3 locations to identify protection of personnel during plant TC 6 and assess the impact operation.

.of the SSES uprate.Fuel Loading: The objective of this test is to achieve the full and proper Fuel loading was per- Yes None.ST-3 core complement of nuclear fuel -Y V formed in accordance.

EPU task Test will be performed.

See X assemblies through a safe and effi- with plant procedures.

T1005 Table 3 for details.cicnt fuel loading evolution.

Full Core Shutdown Margin: The purpose of this test is to demonstrate Yes None.ST-4 Ihat the reactor will be subcritical

-y Shutdown margin EPU task Test will be performed.

See X througherat the first fuel cycle with checks were performed TI005 Table 3 for details.any single control rod fully with-drawn.4 See the Notes at the end of Table I for definitions of Test Conditions 31 of 51 Sisquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing r r -..Original Teot No.Startup Test Uniti 3441 MWt Uprate Testing IIFSAR 14.31 Testing Planned for CPPU Evaluation/

Justlflcation/Notes CPPU Test Conditions Percent of 3489 MWt (CLTP)Original Test Description IUFSAR Section 14.21 i I RTP U I U 2 Control Rod Drive System: The objectives of this test are (I) demon-strate the system operates properly CRD dynamic friction CRD dynamic friction to be ST-5 over the full range of primary cool- TC Y determined within STSTC 3 Y V Yes determined within limits and ant temperatures and pressures front TC 6 limits and acceptable acceptable scram times verified.ambient to operating and (2) deter- scram times verified.mine the initial operating character-istics of the entire CRD system.SRM Performance and Control Rod Sequenc : This test demonstrates operational sources, SRM instru- As in FSAR 14.2.12.6, mentation, and rod withdrawal se- This startup test was merged ST-6 qttences provide adequate informa- -Y N" testing originally con- None into Test #10 tion to achieve criticality and merged into test wa.increase power in a safe, efficient m i e manner for each specific rod with-drawal sequence.

_dra'al equece.- -Not necessary to retest.Reactor Water Cleanup System: Modifications were This test is to demonstrate specific M ade ST-7 aspects of the mechanical operabil-TC 3 Y V made to this system None Not necessary to retest.ity of the Reactor Water Cleanup prior to power uprate.Post modification test-System. ing was successful.

Residual Heat Removal System: Not necessary to retest.This test shows the ability of the Satisfied by verifying Residual tHcat Removal System to the RHR HX capacity ST-8 ( I ) remove heat from the reactor 96% Y y was greater than or None. Not necessary to retest.system for refueling and nuclear TC 6 equal to design. Steam system servicing and condense condensing mode of steam while the reactor is isolated the RHR system has from the main condenser.

been eliminated.

5 By the time of Unit 2 startup testing, ST-6 had been merged into ST-10. Hence the test was accomplished with ST-10.32 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing i r Startup Test Unit'3441 MWt Uprate Testing Testing Planned fnr CPPU Evaluation/

Justification/Notes CPPU Test Conditions Percent of 3489 MWt (CLTP)Original Test No.Original Test Description (UFSAR Section 14.21 IUFSAR 14.31 for CPPU U 1 RTP U 2<90 90 100 107 103 E P 110 IU-----4 4 4-.---~-------1

-+-------------------- ST-9 Water Level Measurement:

This test determines actual reference leg tem-perature and recalibrates instruments if necessary and to verify consistent response of the upset range, narrow range and wide range level instru-mentation.

TCI-6 21%40%44%*73%*69%V Y Not necessary to retest.The small, correction for the small increase in drywel temperature was negligible.

None.Not necessary to retest.IRM Performance:

The objective of this test is to adjust the Intermediate ST-10 Range Monitor System to obtain the desired overlap with the SRM and APRM systems.Y Y I Not necessary to retest.Operational sources have been removed from the core. Several startups have been Yes None.successfully corn- EPU task Test will be performed.

See X pleted. IRM overlap T1005 Table 3 for details.with SRMs and APRMs are routinely performed per proce-dures..ST-1 I Local power Range Monitorine System Calibration:

The objective of this test is to calibrate the LPRM System.TC 2 TC3 TC 6 Y Y LPRMs were cali-brated Yes EPU M515 None.Test will be performed.

See Table 3 for details.x 1- 1 Averave Power Rane Monitoring ST-12 System: The objective of this test is to calibrate th-i APRM system_ .....18.2%39%71.4%69%97%99.9%TC F TC 2 TC 3 TC 5 TC 6 Y Y APRMs were cali-brated per the weekly schedule Yes EPU task T1005 None.Test will be performed.

x 33 of 51 Suisquehanna Steam Electric Station, Extended Power Uprate Project TABLE 1 -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent or Test Unit" Uprate Testing Planned Justification/Notes 3489 MWt (CLTP)Original Test IUFSAR 14.31 for CPPU Originl ,N.Description E Orlt na.IIJFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P 1 2 NSSS Process Computer:

The objec- Further testing unnec-tive of this test is to verify the NSSS TC 2 essary since computer ST- 13 performance of'the process con- TC 3 Y Y functions were not None. Not necessary to retest.puter under plant operating condi- changed.lion.Reactor Core Isolation Cooling Sys- Test is not required.

CPPU does tern: This test verifies the proper Testing not cause any changes to RCIC operation of the RCIC system at the RC1C manual start at beyond rninimunm and rated operating pres- TC 2 normal system. Pressures, tempera-ST-14 surcs and flow ranges and demon- TC-3 Y Y 150 psig reactor pres- surveil- tures, flow rates, and timing strates reliability in automatic mode sure lance not requirements are unchanged.

starting with cold standby when required See PUSAR Supplement Section reactor is at power conditions.

4.3 for furtherjustification.

Iligh Pressure Coolant Iniection:

Test is not required.

CPPU does This test verifies the proper opera- Testing not cause any changes to HPCI tion of HPCI system at the minimum TC 2 HPCI slow manual beyond not ca u res tempCa wand rated operating pressures and TC3 Y Y start followed by an normal system. Pressures, tempera-low ranges and demonstrates reli TC 4 auto quick start at 150 surveil- tures, flow rates, and timing abilityiu t o tnpie r srequirements are unchanged.

psig reactor pressure quired See PUSAR Supplement Section from cold standby when the reactor required 4.3 for further justification.

is at rated pressure conditions.

_ I III ST-16 Selected Process Temperatures:

This test establishes the proper setting of the low speed limiter for recircula-tion pumps to avoid coolant tem-perature stratification in the reactor pressure vessel bottom head region.TC 3 TC 4 TC 6 Not necessary to retest.The low speed limiter is not being changed,.No recirculation pump trips planned, Reactor pressure vessel bottom head regions tempera-ture data during recir-V Y None Not necessary to retest. The low speed limiter is not being changed,.

No recirculation pump trips planned. Reactor pressure vessel bottom head regions tem-perature data during recircula-tion pump trips are routinely collected and analyzed per exist-ing plant procedures.

culation pump trips are routinely collected and analyzed per existing Dlant procedurcs.

34 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 1 -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation!

CPPU Test Conditions Percent of Test Unit 4 Uprate Testing Planned Justification/Notes 3489 MWt (CLTP)Original Original Test IUFSAR 14.31 for CPPU -Tcr No. Description E IUFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P!_ _ _ _U Not necessary to retest. Not necessary to retest. Power Power uprate increases uprate temperature increases of System Expansion:

This test demon- the temperature of primary system piping is negli-strates that reactor recirculation, TC-2 primary system piping gible with respect to the thermal ST-17 md TC-3 [Y by 57F. The increase is None expansion of piping that ranges the piping systems in Table 3.9-33 TCnegligible with respect from 700 to 550'F .(there are no respond to thermal expansion con- to the thermal expan- changes in primary system tem-sistent with stress analysis results. sion of piping that perature except for a FW temp ranges from 70' to increase of 10'F).550"F.TIP Uncertainty:

This test deter- TC 3 This test is performed This test is normally performed ST-l8 mines the uncertainty otthe TIP TC 6 Y Y after each refueling Yes after each refueling outage after X system readings.

97.4% outage at 100% power attaining 100% power.Core Performance:

This test (1) TC 1 Steady state core ther-evaluates the core thermal power thru mal power measure-and (2) evaluates the following core TC 6 mnts at 90% and Yes None.S'. 1-l performance parameters:

0) maxi- 65.5% y y 0%oforiginal EPU task Test will be performed.

See X X X X X X mum linear heat general rate, (ii) 46% power and then at 3% T1005 Table 3 for details.minimum critical power ratio, and 69% power antenvat 3% tT (iii) maximum average planar linear 95% power intervals up to heat general rate. 99% new rating Not necessary to retest.There are no warran-Steam Production Verification:

This ties associated with Not required.

Power uprate ST-20 test demonstrates that NSSS is pro- 99.7% Y N steam production for None warranties will be tested else-riding steam sufficient to Satisfy all power uprate. Power where appropriate warranties.

uprate warranties are tested in Test 50.Not necessary to retest.Operation in regions of Core Power-Void Mode Response:

high core power-void Operation in the instability re-ST-21 This test verifies the stability of the TC4 Y Y dynamic response is None gion is governed by the plant core power-void dynamic response.

governed by the plant technical specifications.

technical specifica-tions.35 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 1 -Comparison of SSES initial startup testing and planned EPU testing Startup Test Unit 4 3441 MWt Uprate Testing IUFSAR 14.31 Testing Planned for CPPU Evaluation/

Justification/Notes CPPU Test Conditions Percent of 3489 MWt (CLTP)I Original Test No.Original Test Description IUFSAR Section 14.21 RTP'I Ii 2 Pressure Regulator:

This test demn-onstrates the takeover capability of 43%the backup pressure regulator upon 60%failure of the controlling pressure 63% Step changes and Yes None.regulator and to demonstrate smooth simulated regulator EPU task Test will be performed.

See pressure control transition between 7% failures were demon-the control valves and bypass valves 100% strated when reactor steam generation ex- TCI-6 ceeds steam flow used by the tur-binc.Feedwater System: The objectives of this test are: (I) demonstrate ac-ceptable response to the fecdwater control system for reactor water Test will be performed.

See le'el control, (2) to demonstrate Feedwater testing w as Table 3 for details. However, stable reactor response to subcooling 45% performed but not loss Yes feedwater pump trip and loss of ST-23 changes, (3) to demonstrate the ca- 75% V Y of feedwater heating, EPU task reedwater heating will not be pability of the automatic core flow 97% feed pump trip, or feed TI005 performed.

See PUSAR Sup-runback feature to prevent low water TCI-6 runout testing plement, Section 4.3, Justifica-level scram following the trip of the tion for Elimination of Power one feedwater pump, and (4) to Ascension Tests demonstrate the maximum feed-pump runout capability is compati-ble with licensing assumptions.

x X X X X X ST-24 Turbine Valve Surveillance:

This test shows acceptable procedures and maximum power levels for pe-riodic surveillance testing of the main turbine control, stop, intercept and bypass valves without produc-inp a reactor scram.TC 3 TC 5 TC 6 56%69%100%V Y Turbine control valve testing was performed Yes EPU task T1005 None.Test will be performed.

See Table 3 for testing details.36 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent of Test Unit 4 Uprate Testing Planned Justification/Notes 3489 MWt (CLTP)Original Test _ IUFSAR 14.31 for CPPU"re~l No. Description E JUFSAR Section 14.21 RTP U U <90 90 100 103 107 110 p 1 2 Main Steam Isolation Valves: This See PUSAR Supplement, Sec-test functionally checks the main tion 4.3, Justification for Elimi-steam isolation valves for proper nation of Power Ascension Tests operation at selected power levels, 56% MSIV surveillance All MSIV determines reactor transient behav- 69% testing was performed.

closure [Note: MSIV surveillance test-ST-25 ior during and following simultane-86% Y Y Closure of all MSIV event will ing (functionality and closure ous full closure of all MSIVs, de- ST-5 transient event was not not be times of individual valves) will'tcrmines isolation valve closure time ST-6 tested tested be performed.

MSIV testing is and determines the maximum power performed during shutdown for at which a single valve closure can a refueling outage or during an be madc without a scram e outage after MSIV mainte-nance.1 Relief Valves: This test verifies that New safety valve set Normal Safety relief valve set points will the relief valves function properly, points set and tested at surveil- be tested in accordance with ST-26 reseat properly after operation, and TC 2 Y Y an approved lance test- normal surveillance require-contain no major blockages in the safety/relief valve test relief valve discharge piping. facility.

ing ments Turbine Trip and Generator Load TC 3- Test results proved that Rejection:

The objective of this test TC 6 the analysis tools were SAR Supplement, See-ST-27 is to demonstrate the response of the 75% conservative.

Since the Testing Not See PU4.3 Supplement , Sec-reactor and its control systems to 75% increase in power level Required nation of Power Ascension Tests protective trips in the turbine and 98% is small, a repeat of the generator.

100% .test is not warranted..Shutdown from Outside the Main Power uprate does not hControl Room: This test is to dem- change the capability Power uprate does not change Constrol R th is th e s isatoran besh- of the plant to shut the capability of the plant to shut onstrate that the reactor can be shut- down from outside the down from outside the main ST-28 down, maintained in a hot shutdown TC I Y V main control room, nor None con rom orsde t ale condition, and cooled down from 19% .does it alter the func- control room, nor does it alter outside the main control room. The tion or intent of the the function or intent of the adequacy of the Emergency Operat- emergency operating emergency operating procedures ing Procedures will be verified also. proceduresnc.

opera 37 of 51 Suisquehanna Steam Electric Station, Extended Power Uprate Project TABLE 1 -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent of Test Unit' Uprate Testing Planned Justification/Notes 3489 MWt (CLTP)Original Test (UFSAR 14.31 for CPPU Oriia Description E IUFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P 1 2 Recirculation Flow Control System: The tests objectives are: (I) demon. TC 2 Recirculation flow control sys-strate the flow control capability of TC tecrn chatng tow amnals the plant over the entire pump speed TC 5 tem was changed to a manual ST-29 range including individual local TC 6 Recirculation flow system. eb ere is no special manual and combined master man- 40% control was tested not nee ssary. Coop te ual operation and (2) determine that 70% positioner HSS will be reset and all electrical compensators and con- 74% teswce trollers are set for desired system 98% tested performance and stability.

.Recirculation System: The tests objectives are: (I) obtain recircula-tion system performance data during pump trip, flow coastdown and pump restart; (2) verify that the feedwater control system can satis-factorily control water level without TC 3 Power uprate has no a resulting turbine trip and associ- effect that will alter the See PUSAR Supplement, Sec.ST-30 ated scram, (3) record and verify TC 6 V Y ability of the recircula-Testing Not tion 4.3, Justification for Elimi-acceptable performance of the recir- 75% tion system to satisfy Required nation of Power Ascension Tests culation two pump circuit trip sys- these objectives.

temn. (4) verify the adequacy of the recirculation runback to mitigate a scram, and (5) verify that no recircu-lation system cavitation will occur in the operable region of the power-flow map. ._ IIIIIIIIIIII_1__

38 of 51 Sutsquehanna Steam Electric Station, Extended Power Uprate Project TABLE 1 -Comparison of SSES initial startup testing and planned EPU testing Startup Test Unit'3441 MWt Uprate Testing IIFSAR 14.31 Testing Planned for CPPU Evaluation/

Justification/Notes CPPU Test Conditions Percent of 3489 MWt (CLTP)Orig1,al Test No.Original Test Description JUFSAR Section 14.21__________

--h I RTP U I U 2 Loss of Turbine Generator and Off- Not necessary to retest.site Power: This test determines that Power uprate does not Not necessary to retest. Power the required safety system will initi- change the ability or uprate does not change the abil-atc and function properly without the safety systems to ity of the safety systems to initi-manual assistance, the electrical TC 2 initiate and function it ate afety systers nor ST-31 distribution and diesel generator 45% V Y properly nor change TcstingrNot ate and function properly nor systems will function properly, and the ability of the elec- Required change the ability ofthe electri-cal distribution antd diesel gen-the IIPCI and/or RCIC systems will trical distribution and erator systems to function prop-maintain water level if necessary diesel generator sys- erly.during a simultaneous loss of main tems to function prop-turbine generator and offsite power. erly.Containment Atmos here and Main Steam Tunnel Cooling: This test verifies the ability of the drywell coolers/recirculation fans and the reactor building portion of the main 97M ue% Measurements will be taken to steam tunnel coolers to maintain Measurementsassure temperatures remain be-ST-32 design conditions in the drywell and TC3 Y y taken to assure tem- Yes low TS limits. No EPU changes reactor building portion of the main- TC 5 peratures remained are being made that would affect steam tunnel, respectively, during TC 6 drywell air distribution.

operating conditions and post scram conditions.

This test also demon-strates that containment main steam-line penetrations do not overheat adjacent concrete.Piping Steady State Vibration:

The test demonstrates that steady state vibration levels on reactor recircula-50% Not necessary to retest.tion and main steam inside contain- 75% The increase in flow Piping vibration measurements ST-33 ment are within acceptable limits. 100% y y for power uprate does Yes will be taken as appropriate to (Note: This test includes piping TC2 not significantly demonstrate piping adequacy.previously contained in ST-40. Dy- TC3 change vibration levels namic transient vibration testing TC6 of this piping.previously contained in this test have been merged into ST-39).x x x I 39 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent of Test Unit' Uprate Testing Planned Justification/Notes 3489 MWt (CLTP)Original Test IUIFSAR 14.31 for CPPU Teht No. Description E IUFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P 1 2 I_ _ U Control Rod Sequence Exchange: The objective of this test is to per- Not necessary to retest.form a representative sequence ex- Plant personnel and Not necessary to retest. Plant change of control rod patterns at the 70% procedures have dem- personnel and procedures have ST-34 power level at which such cx- TC-3 Y N onstrated the capability None demonstrated the capability of changecs will be done during plant of rod sequence ex- rod sequence exchange without operation and demonstrate that core change without ex- exceeding limits.limits and PCIOMR threshold limits ceeding limits.will not be exceeded.Recirculation System Flow Calibra- TC3 tion: The objective of this test is to 610 Recirculation flow data Recirculation flow data will be ST-35 perform a complete calibration of 75% Y y taken and flow instru- Yes taken and flow instruments will X X X the installed recirculation system 98% ments recalibrated be recalibrated as needed flow instrumentation.

100%Cooling Water Systems: This test is Not necessary to retest.to verify that the performance of the TC1 Heat loads do not Reactor Building Closed Cooling TC2 change significantly Temperature measurements will ST-36 Water, the Turbine Building Closed TC Y N for power uprate. The Yes be taken as necessary to confirm X X X X X Cooling Water, and Service Water TC6 systems operate within EPU analyses Systems are adequate with the reac-thi de gn tor at rated temperature.

their design.Gaseous Radwaste System: This test TO demonstrates that ihe Gaseous Rad- TCO Secured information waste System operates within the TC3 on offgas system efflu-Technical Specification and design TC6 ents and demonstrated Data will be recorded to confirm sr-37 limits during a full range of plant 20T Y Y that gaseous and par- Yes acceptance criteria X X X X X power operation and to demonstrate 60% ticulate effluents satis-the proper operation of the contain- 69% fled acceptance crite-ment nitrogen inerting system dur- 97% ria.ing plant operation.

--I 40 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE I -Comparison of SSES initial startup testing and planned EPU testing Startup 3441 MWt Testing Evaluation/

CPPU Test Conditions Percent of Test Unit 4 Uprate Testing Planned JustificationlNotes 3489 MWt (CLTP)rOriginal Test UFSAR 14.31 for CPPU Original OrgnlTs Test No. Description E IUFSAR Section 14.21 RTP U U <90 90 100 103 107 110 P 1 2 U Test merged into ST- 17. ST- 17 isnot necessary since. Power BOP Piping System Expansion:

The uprate temperature increase is system expansion testing previously

-N N Test merged into negligible with respect to the ST-38 contained in this test has been NiN A None thermal expansion of piping that merged into ST- 17. ranges from 700 to 550'F .(there are no changes in primary sys-tem temperature except for a FW temp increase of I01F).i TC2 Not necessary to retest.P Vibration During TCO The small increase in Transients:

This test demonstrates TC6 initial power level ST-39 that vibration levels on main steam 25% V y from power uprate No Dynamic transients are not be-inside containment and reactor meet 38% does not significantly ing performed acceptable limits during selected change the response of dnaic transients.

75%this piping to dynamic dynami transents.100%

ti iigt yai transients.

13OP Piping Steady State Vibration:

ST-40 The steady state vibration testing V N N/A. Test merged into Yes Merged into test ST-33 previously contained in this test has ST-33 been merged into ST-33.Notes for Table I TC 1 Core thermal power between approximately 5% and 20% rated. Recirculation pump speed within +10% of minimum pump speed. Before and after main generator synchronization.

TC 2 Core thermal power between 45% power rod line and 75% power rod line. Recirculation pump speed between minimum and lowest pump speed corresponding to Master Manual Mode. Lower power corner is within Bypass valve capacity.TC 3 Core thermal power between 45% power rod line and 75% power rod line. Total core flow between 80% and 100% rated.TC 4 On the natural circulation core flow line within +0, -5% of the intersection with the 100% power rod line.TC 5 Core thermal power within +0, -5% of the 100% power rod line. Recirculation pump speed within +5% of the minimum recirculation pump speed corresponding to Master Manual Mode.TC 6 Core thermal power between 95% and 100% rated. Total Core flow +0, -5% rated core flow.41 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List Title Uit I ~'~i~ni ~ -fitkilated .os 0oilcto Dileesciption', Common- Tetn 2005 -2008 INSTALLATIONS I & C MODIFICATIONS Install accelerometers on Main Steam, Reactor Recirculation, Vibration/Acoustic Monitoring RHR and RWCU Lines for vibration monitoring 2006 2005 V Install instrumentation on main steam lines for steam dryer U114RIO U212R1O Instrument functional checks acoustic wave monitoring

-APRM Flow-biased SCRAM Neutron Monitoring System

• APRM Flow-biased Rod Block 2008 2007 Instrument functional checks and Settings

• APRM Upscale Setdown SCRAM U115RIO U213RIO surveillance tests I RBM Power-based Rod Blocks-Replace existing GE analog system with GE digital NUMAC Power Range Neutron Monitor system 2006 2007 System [Provided for completeness only. NRC approval has been U114RIO U213RIO Logic system functional checks requested in a separate, prior submittal]

-Revise the APRM flow-biased scram and rod block trip setpoints 2006 ARTS/MELLLA (Provided for completeness only. NRC approval has been Post 200713R requested in a separate, prior submittal]

Outage U213R eo* Install accumulators on Turbine Control Valve EHC FAS lines-Install Steam Line Resonance Cards on pressure transmitter EHC System loops to dampen 3rd harmonic frequency 2008 2007 EHC functional checks and" Modify Turbine Control Valve Digital Positioning Cards Ul15RIO U213R1O Pressure Regulator Testing" Recalibrate the Power Load Unbalance circuit MSIV High Flow Isolation

-Revise setpoint for EPU conditions (this will require new 2008 2007 Setpoint switches)

U115RIO U213R1O Calibration and functional checks 42 of 51 Suisquehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List Tile-.ec -pto Unit. * ": "1, Unit 2:. Ahticipated Post.ModfiCation Title ueS~cription

• ... Iu m o .:-=:.-:...l

..CInstl I'nstali Testing Reactor Recirculation 2008 2007 Runback Limiter #2 *Logic change U115RIO U213RIO Calibration and functional checks-RPS Scram Bypass HP Turbine Instrument

-RWM Setpoints 2008 2007 Change

• RSCS Setpoints U115RIO U213RIO Calibration and functional checks C Power Dependent Condenser High Pressure Alarm Power Signal Reactor Feedpump Low 2008 2007 R Revise setpoints for EPU conditions Calibration and functional checks Suction Pressure U115RIO U213RIO Instrument Calibration and 2008 2007 C Recalibrate instruments and revise software for EPU conditions Calibration and functional checks Computer Software Changes U115RIO U213R0CaIbrtoOn ucinlcek 43 of 51 Susqutehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List* .-..... ......UnitI' I Title~~~~t 1 -Cmhio i Uit 2' ;'Anticipted PostMdfcio Description"Isal{Istl etn MECHANICAL MODIFICATIONS Reactor Feedpump Seal

• Revise Temperature Control Valve settings per vendor 2006 2007 recommendation Calibration and functional checks W Revise drain line vent piping for increased drain flow-Revise setpoint for EPU conditions Cross Around Relief Valve Set

• Revise design pressure of associated piping for EPU conditions 2006 2007 Point Change

• Replace relief line expansion joints for EPU steam flow U114RIO U213RIO conditions 125% rotor speed factory test High Pressure Turbine Replace the High Pressure Turbine for increased steam flow at 2008 2007 1 rotospeed fato te HgPrsueTrie EPU conditions U115RIO U213RIO Transient/steady state data____conditionsU115R_______

recording Over-speed trip testing-Replace Condensate Pump Impellers for increased flow at EPU conditions

• Replace minimum flow valve internals to allow a larger minimum 2008 2007 Pump performance testing Condensate Pump Impellers flow valve U213RaO Head versus flow measurements, flow U1 15RI0 U213RIOSse rnsetTsig* Replace MOVs on pump discharge valves System Transient Testing.* Revise relief valve settings .,_# Increase design pressure and increase shell relief valve 2008 2007#5 Feed Water Heaters setpoints U115RI 213RI Standby Liquid Control Boron -Replace existing sodium pentaborate solution 2008 2007 Pressure/flow rate testing Enrichment

-Modify system logic to allow for single pump initiation U115RIO U213RIO TS surveillance testing Circ Water Box Vents

• Add automatic Circulating Water Box vent valves to prevent air 2008 2007 CLrc Water______ents

_binding of condenser tubes U115RIO U213RI0 Performance tests 44 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List , ..... __-Uniti I Comnt , Unit2: AntiCipated Post-Modification Title Description Common: Install :: esting Install-Install a second isolation valve, manually operated, in each of two Spray pond Spray Header Bypass Lines to reduce the effects 2006 Performance tests Ultimate Heat Sink of a single bypass line isolation failure-to-close under accident Post NA Piping pressure tests/leak tests conditions Outage Valve performance tests-Reduce number of large array nozzles to improve efficiency Hydrogen Water Chemistry

• Increase hydrogen, oxygen and zinc injection flows due to 2008 2007 Flow rate measurements Flow increased feedwater flow rate under EPU conditions.

U115RIO U213RIO EPUI Implementation Configuration modification for EPU implementation.

No physical 2008 2007 work involved.

U115RIO U213RIO As per EPU startup testing Acid Injection

• Provide additional acid injection capability for the Cooling Tower 2008 2007 Flow rate measurements basin. U115RIO U213RIO#3 FWH Emergency Dump

• Replace valves for EPU conditions 2008 2007 Performance testing Valves U115RIO U213RIO-Replace all three Reactor Feed Pump Turbines due to higher Functional performance tests Reactor Feed Pump Turbines turbine speeds required at EPU conditions 2010 2009 Overspeed/trip testing-Upgrade turbine speed controls and overspeed trip to digital U116RIO U214RIO Piping leakage and integrity testing, controls System Transient Testing.-Install an 8th Condensate Demineralizer to maintain Condensate 2010 2009 Flow rate testing; Hydrostatic Condnsat DemneraizerTesting; Piping leakage and Condensate Demineralizer water quality under increased EPU flow conditions U116RIO U214RIO integrity testing-Install a 7th Condensate Filter to maintain Condensate water 2010 2009 Flow rate testing; Hydrostatic Condnsat Fiter InsallTesting; Piping leakage and Condensate Filter quality under increased EPU flow conditions U116RIO U214RIO integrity testing ESW to Fuel Pool Check

• Valve change to reduce mission dose for post-LOCA manual 2006 Flow rate testing; Hydrostatic Valve action Post N/A Testing; Piping leakage and Valveaction

_Outage integrity testing 45 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List Unit 11! .. .: Unite CUnit 2 Anticipated Post-Modification Title Description Common Install Testing Install.*Changes to manage velocity and tube vibration issues at EPU 2010 2009 System flush and flow rate testing Feedwater Heaters conditions 0U116RI0 U214RI* Hydrostatic Testing Piping leakage and integrity testing 200_88 2007 Potential EQ Changes

• As required for EPU environmental conditions U115RIO U213RIO As Required Au Logic Logic change and raceway protection to eliminate fire-induced Appendix R RHR Pump failure mechanisms 2008 2007 Logic functionaltest Change

• Provide cross-divisional cooling to RHR pump motor coolers U115RIO U213R Lo CIVIL I PIPING MODIFICATIONS RFP Suction Piping

• Replace suction flanges, revise piping design pressure, revise 2008 2007 Non-Destructive Examination Modification relief valve setpoints U115RIO U213RIO required Main Steam, Feedwater and 2008 2007 Non-Destructive Examination Extraction Steam Piping -Revise piping supports as necessary for EPU conditions U115RIO U230R08 Piping integrity/pressure tests ast Supports required Gaseous Radwaste

• Revise drain piping configuration for increased EPU flow 2008 2007 Non-Destructive Examination Recombiner Drain Piping conditions U115RIO U213RIO Piping integrity/pressure tests 46 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 2 -Modification List unit.U'Anit IIticpated P'stModification Title Description ommon I 2 A Install Install: Testing ELECTRICAL MODIFICATIONS

_* Install new switchyard capacitor banks to meet PJM reactive power requirements for generators Power Distribution[Switchyard "Replace Unit 1 Sync breaker and associated controls with a 2008 2007" breaker having a higher amperage rating U115RIO U213RIO Performance testing as required* Uprate Unit 2 main transformers and change tap settings to meet EPU conditions 47 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 3 -Planned Tests Title Test Number Test Description Samples are taken and measured at EPU power levels to determine the chemical and radiochemical quality of Chemistry

& Radiochemistry Test No. I reactor water, thermodynamic steam quality (moisture carryover) feed water, and gaseous effluent.Gamma dose rate and neutron dose rate measurements are taken at specific limiting locations (where appropri-Radiation Measurements Test No. 2 ate) at various EPU levels. These measurements assess the effect uprate has on actual plant area dose rates.FSAR radiation zones are monitored for required changes.Fuel loading shall be performed per plant procedures and the FACCTAS. The FACCTAS is prepared according Fuel Load Test No. 3 to RE-081-042, FACCTAS Preparation Guidelines for Refueling Outages. Core Verification is performed ac-cording to RE-081-036, Core Post-Alteration Verification.

Full core shutdown margin demonstration shall be performed per reactor engineering surveillance procedures Full Core Shutdown Margin Test No. 4 SR-100-008 (SR-200-008), In-Sequence Critical and Shutdown Margin Demonstration.

CRD dynamic friction determined to be within limits prior to startup and acceptable scram times verified at Control Rod Drive System Test No. 5 normal TS surveillance intervals.

After the APRM calibration for EPU, the IRM gains are adjusted as necessary to assure the IRM overlap with IRM Performance Test No. 10 the APRMs.The LPRM channels are calibrated to make the LPRM readings proportional to the neutron flux in the LPRM LPRM Calibration Test No. II water gap at the chamber elevation.

Calibration factors are obtained through an offline or a process computer calculation that relates the LPRM reading to the average fuel assembly power at chamber height.APRM: Confirms the calibration of APRMs consistent with the rated thermal power, referenced to CLTP, as determined from the heat balance. Assures that the APRM flow-biased scram and rod block setpoints in the power range neutron monitors are consistent with MELLLA operation by confirmingladjusting the drive flow gain in neutron monitors during power ascension and at rated power, so that the drive flow normalization con-APRM / RBM Test No. 12A ditions (i.e. 100% drive flow is equal to 100% core flow at 100% power) is satisfied.

Confirms all APRM trips Test No. 12B and alarms prior to entering the MELLLA region.RBM: Confirms that the power range neutron monitor RBM power based setpoints have been changed to the ARTS values and the RBM has been calibrated consistent with Technical Specifications.

Verifies that the RBM adjustments have been properly set for the RBM TIP Uncertainty Test No. 18 This test is normally performed at 100% power after each refueling outage upon reaching 100% power.Routine measurements of reactor parameters are taken near 90% and 100% of CLTP and extrapolated to the next power step up to maximum EPU power. Core thermal power and core performance parameters are calcu-lated using accepted methods to ensure current licensed and operational practices are maintained.

Power is in-Core Performance Test No. 19 creased using control rods and core flow in incremental steps of 5% or less to ensure a careful, monitored ap-proach to maximum EPU power. Measured reactor parameters and calculated core performance parameters are utilized to project those values at the next power level step. Each step's actual values are satisfactorily con-firmed with the projected values for that step before advancing to the next step and the final confirmation is at Page 48 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 3 -Planned Tests Title Test Number Test Description the maximum EPU power level.The pressure regulator requires only the following changes for EPU: (1) Those settings identified in Task T0700, Turbine Generator Performance Evaluations (2) Task T0502, Pressure Control System, (i.e. Pressure Regulator Setpoint), (3) The EHC modification of Table 2, and (4) Confirming the dynamic tuning parameters.

Before EPU, while the plant is shutdown, the pressure regulator system will tested and dynamically calibrated.

Pressure Regulator Test No. 22 GE Service Information Letter (SIL) No. 589 (Ref. 4.1) discusses the tuning of the dynamic parameters for the pressure regulator.

Pressure control system response to pressure set point change is tested at various test conditions.

Testing the system requires a 10 psi down set point change followed by a 10 psi up setpoint change when conditions stabi-lize. Pressure regulators are tested individually and sequentially.

Feedwater control system response to reactor water level set point changes (for level set point change tests) are evaluated in the indicated control mode (i.e. three element, single element)..

Changes are made only after con-ditions stabilize in accordance with the following set point change sequence.(I) + 2 inches (3) + 3 inches (5) + 4(+ or-l") inches (2) -2 inches (4) -3 inches (6) -4(+ or -1") inches The 2 and 3 inch level set point steps are informational and recommended to demonstrate the level control re-sponse prior to performing the formal level set point steps (i.e. 4(+ or-l) inch). The results from the informa-tional level set point steps are utilized to anticipate the responses to the formal demonstration test steps, so that effects on the reactor may be anticipated (i.e. power increases, level alarms). The tolerance of the formal level step (i.e. 4(+ or-I) inch) permits adjustment to take into consideration the limit cycles of the control mode being tested. If the limit cycles are small enough to permit the formal steps to be at the lower end of the toler-ance (i.e. 3 inches), then the informational 3 inch steps need not be performed.

Feedwater System Test No. 23 The normal feed water control system mode is three-element control, with single element control only being used for temporary backup situations.

The feed water control system in three-element control mode should be adjusted, not only for stable operational transient level control (i.e. decay ratio), but also for stable steady state level control (i.e. minimize reactor water limit cycles). In single element control mode, the system adjustments must achieve the operational transient level control criteria, but for steady state level control the temporary backup nature of this mode should be considered.

For tests calling for manual flow step changes, at each test condition the feed water control system is placed in a manual/auto configuration (i.e. one feed water pump in manual and the other in automatic).

Flow step changes are made by inserting the step demand change into the feed water pump controller in manual or by changing the set point of that controller in accordance with the following set point change sequence (expressed in percent of rated EPU feed water flow). After completion of testing on one controller, the manual/auto con-figuration is switched and the sequence is repeated on the other controller.

49 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 3 -Planned Tests Title Test Number Test Description (1) Increase 5%(2) Decrease 5%(3) Increase 10%(4) Decrease 10%The 5% flow step changes are informational and recommended to demonstrate the feed water turbine response prior to performing the formal test flow step changes (i.e. + or -10%). The results from the smaller informa-tional flow steps are used to anticipate the responses to the formal demonstration tests and any effects on the reactor (i.e. level changes, power increases).

Initial tests are performed (using the original STS methodology) near and at two points below the power level at which each valve's surveillance has been performed in pre-EPU uprate tests. Maximum power test condition is determined by projecting the initial test's scram/trip set point margins to the highest power level where all Turbine Valve Surveillance Test No. 24 the margins are acceptable.

Final tests are performed at this maximum power test condition (within fuel pre-conditioning limits) to confirm acceptable test performance.

Proximity to vessel pressure is closely monitored in neutron and heat flux scrams and also main steam line high flow isolation trip. Each test is manually initi-ated, valve stroked, and reset in accordance with the current valve surveillance procedure.

MSIV Surveillance Test No. 25 Surveillance test performed during outage.Recirculation Flow Control Test No. 29 Scoop tube positioner high speed stops will be reset because more recirc pump flow will be needed to produce 108 Mlb/hr core flow. The new HSS will be tested.Containment Atmosphere and Alain Test No. 32 Measurements will be taken to assure temperatures remain below TS limits.Steam Tunnel Cooling Piping Steady State Vibration Test No. 33 Piping vibration measurements will be taken as appropriate to demonstrate piping and support adequacy.Reeirculation Flow Control Calibra-tion Test No. 35 Recirculation system data will be recorded to calibrate core flow at EPU conditions Cooling Water Svtems Test No. 36 Temperature measurements will be taken as necessary to confirm EPU analyses Gaseous Radwaste System Test No. 37 Data will be recorded to confirm acceptance criteria.During EPU power ascension, designated main steam and feedwater piping points (i.e. location and direction) are monitored for vibration.

Vibration monitoring points are designated based on EPU piping vibration analysis and engineering judgment.

Monitoring points may be coincidental with those in the initial startup piping vibra-MS & Feed Piping Vibrations Test No. 100 tion test or selected as those points with the highest predicted vibration.

Vibrations monitoring points can be coincidental, with exposed piping attachments, provided that acceptance criteria is established for those points based on piping system vibration analysis.

Vibration measurements taken above CLTP will permit a thorough assessment of the effect of the EPU in comparison to any previous piping vibration analysis or evaluation.

50 of 51 Susquehanna Steam Electric Station, Extended Power Uprate Project TABLE 3 -Planned Tests Routine measurements of the power dependant parameters from systems and components affected by the EPU are taken near 90% and 100% of CLTP and extrapolated to the next power step up to maximum EPU power.Power is increased using control rods and core flow in incremental steps of 5% or less to ensure a careful and monitored approach to maximum EPU power. Power dependant parameters are calculated to ensure current Plant Parameter Monitoring Test No. 101 licensed and operational practice is maintained by using accepted methods. Measured and calculated power dependant parameters are utilized to project those values at the next power level step prior to increasing to the next EPU test condition.

Each step's projected values will be evaluated to have satisfactorily confirmed the actual values before advancing to the next step and the final increase to maximum EPU power.One condensate pump will be tripped from a power level of 3733 MWt (+0, -5%) during the startup test pro-gram for the first uprate step on the first unit. If the results of that trip deviate significantly from the predicted Condensate Pump Trip Test No. 102 results, a condensate pump trip will be repeated from the 3952 MWt (+0, -5%) power level during the startup test program for the second uprate step on the first unit.51 of 51 lb Attachment 9 to PLA-6076 Flow Induced Vibration Piping / Components Evaluation Table of Contents 1. Purpose 2. Background

3. Extent of Condition Review (EOC)4. SSES Plant Personnel Vibration Inputs 5. Review of CPPU System Changes as They Affect FIV 6. Vibration Acceptance Criteria 7. Type of Vibration Monitoring

8. Vibration Monitoring Results To Date 9. Inspection and Walkdowns 10. Modifications

11. Valves 12. Sample Probes 13. Pipe Mechanical Snubbers 14. Conclusion

15. References Appendix Al -Vibration accelerometers on Main Steam Piping (Unit 1)Appendix A2 -Vibration accelerometers on Main Steam Piping (Unit 2)Appendix B1 -Vibration accelerometers on Feedwater Piping (Unit 1)Appendix B2 -Vibration accelerometers on Feedwater Piping (Unit 2)Appendix CI -Vibration accelerometers on Reactor Recirculation/RHR Loop A Piping (Ukit 1)Appendix C2 -Vibration accelerometers on Reactor Recirculation/RHR Loop B Piping (Unit 1)Appendix C3 -Vibration accelerometers on Reactor Recirculation/RHR Loop A Piping (Ujit 2)Appendix C4 -Vibration accelerometers on Reactor Recirculation/RHR Loop B Piping (Unit 2)Appendix D -Vibration accelerometers on RHR Piping, Outside Containment (Unit 1)Appendix D2 -Vibration accelerometers on RHR Piping, Outside Containment (Unit 2)Appendix El -Vibration accelerometers on Extraction Steam Piping, Outside Containment (Unit 1)2 OF 24

1. Purpose The purpose of this attachment is to provide information in addition to that presented in the Power Uprate Safety Analysis Report (PUSAR) section 3.4, regarding the susceptibility review of plant system piping and components that might be affected adversely by Flow Induced Vibration (FIV) under Constant Pressure Power Uprate (CPPU) conditions.

Reactor Internal Components are not addressed in this attachment.

PUSAR, section 3.4.2 provides a discussion of the FIV effects on Reactor Internal Components.

2. Background

PPL Susquehanna, LLC (PPL) intends to implement a 14% of Original License Thermal Power (OLTP) CPPU above the Current License Thermal Power (CLTP) of 1.06*OLTP.

The implementation is planned in two increments that extend over two refueling outages for each unit. This conservative implementation plan minimizes the potential for significant changes in flow induced vibration (FIV) to cause degradation of plant components.

This approach permits plant walkdowns and inspections of CPPU affected systems before and after each power increase.In November 2004 the BWR Owners' Group (BWROG) issued NEDO 33159, "CPPU Lessons Learned and Recommendations," (Reference

1) to provide assistance to plants that are in the evaluation and implementation phases of a CPPU. As part of the CPPU implementation strategy, Susquehanna Steam Electric Station (SSES) is following the recommendations of the BWROG in order to minimize CPPU impacts on plant reliability.

PPL intends to continue its involvement in industry efforts and consideration of on-going issues associated with FIV. Lessons learned will be evaluated and incorporated into the SSES implementation strategy as applicable.

The increase in flow resulting from CPPU is expected to result in higher vibration accelerations in some piping and piping components.

The types of vibration that are of concern are structural resonance, acoustic standing waves, vortex shedding, rotating equipment excitation at the pump vane passing frequency, and fluid-elastic stability in heat exchangers.

This attachment identifies those systems & components where CPPU is expected to increase the susceptibility to FIV, describes the methods to determine the CPPU effects and the actions to address potential problem areas.3 OF 24 I

3. Extent of Condition (EOC) Review SSES has performed both an internal and external EOC review for vibration related issues to confirm that planned CPPU actions are adequate to address those issues already identified by either SSES maintenance or industry experience.

The internal review involved a document review of SSES piping and attached components vibration history, including calculations.

The external review concentrated on a review of industry databases relating to piping and component vibration, and the BWROG generic recommendations for implementing CPPU with respect to increased FIV.The following is the process that was used to identify systems affected by FIV: A. Identified those SSES systems that are expected to see a flow change due to CPPU or as determined in the correlated review in paragraph E.B. Determined expected maximum increase in flow rate due to CPPU. See Section 5 for more detailed discussion.

C. Identified those SSES systems, components, and documents with previous or existing vibration issues.D. Reviewed the following external databases for systems and components with previous vibrations issues: a. INPO Significant Event Reports (SER's) and Operating Experience (OE's);b. NRC Information Notices;E. Correlated SSES maintenance history documents to the BWROG recommended actions. Estimated the susceptibility of the SSES piping and components to FIV at CPPU conditions.

4 OF 24 I Table 1 -EOC Estimation of Susceptibility to FIV Using Plant Maintenance History, Industry Reviews, and BWROG Recommendations A B C D E SYSTEM FLOW EXISTING INDUSTRY SUSCEPTIBILITY CHANGE VIBRATION VIBRATION TO FIV AT CPPU Circulating Water 0 % X X X Condensate 15% X X X EHC (2) X X X Extraction Steam 16 % X X X Feedwater (IC) 15 % None None X Feedwater (OC) 15 % X X X HPCI Steam (2) X X X Main Steam (IC) 14% None X X Main Steam (OC) 14% X X X RCIC Steam (2) None X X Recirculation/R[IR 3 % X X X Turbine Piping 14% X X X Sample Probes (1) 15 % None X X Snubbers (1) 15% X X X (1) These components were found to be sensitive to FIV in numerous plant systems. See.sections 12 and 13 of this attachment for an additional discussion.

(2) Flow change is 0 % but their attachment to the main steam line piping warranted investigating their susceptibility to FIV at CPPU conditions.

(3) X indicates the system has one, or more, piping/components susceptible to FIV.(4) (IC) Inside Containment, (OC) Outside Containment

4. SSES Plant Personnel Vibration Inputs PPL has placed an emphasis on involving plant and office personnel who are knowledgeable with FIV issues. In the fall of 2004, General Electric interviewed a number of SSES personnel.

The discussions focused on system existing conditions, likely CPPU effects, and recommendations to improve both. PPL has evaluated these results.In the fall 2005 key plant operations support groups listed areas where SSES might be vulnerable to FIV. In addition to the known issues, the following are representative of new topics identified:

• Main Turbine steam admission valve limit switches,* Main Steam line vibration (broken support mounting bolts), and* Rack Mounted Instruments (e.g. Reactor Protection System).Both the known and the new topics are included in the CPPU FIV evaluation plan.I I 5 OF 24

5. Review of CPPU System Changes as They Affect FIV The Reactor Coolant Pressure Boundary (RCPB) and Balance of Plant (BOP) piping systems were reviewed, and the systems that have significant changes in flow as a result of CPPU are: Main Steam, Feedwater, Condensate, Feedwater Heater Drains, and Extraction Steam. CPPU maximum flows increase and thepotential increases in FIV, which can increase by the square of the flow increase, are summarized as follows: Table 2- SSES Piping Systems with Large Flow Changes Item Piping System CLTP CPPU CPPU-CLTP Increase In Vibration Flow Flow. CLTP Levels (MIlb/hr) (Mlbihr) (%) [(CPPU/CLTP) 2-1](%)I Main Steam 14.84 16.98 14 30%2 Feedwater/Condensate 14.85 17.03 15 32%3 Extraction Steam 1.23 1.42 16 34%4 FW Heater Drains 6.00 6.86 15 31%6. Vibration Acceptance Criteria ASME Codes associated with safety related nuclear power plant piping require vibration testing and monitoring of this important plant piping during initial operation at new and higher flow rates. The steady state level of piping FIV is expected to increase from current levels in proportion to the change in fluid density (p) and fluid flow velocity (V)squared or (pV 2). The large diameter piping (>2 in) in the affected systems is reviewed for the impact of this increase on stresses.

Small diameter branch piping also is susceptible to cracking at socket welded connections and is reviewed for changes in header flow velocity and the resulting vibration frequency change.Vibration acceptance criteria are included in the CPPU power ascension program. The methodology of ASME O/M-S/G Part 3, "Requirements for Preoperational and Initial Start-Up Vibration Testing of Nuclear Power Plant Piping Systems," is used. The criteria in this industry standard are based on the material endurance limit, which assumes an unlimited number of load cycles. The piping systems expected to be impacted the most significantly by CPPU implementation are identified.

For the portions of these systems inside the drywell, which will not be accessible during plant operation, detailed piping computer models were created. Response spectrum modal superposition analyses were run, which identified the natural frequencies, mode shapes, and resulting pipe displacements and accelerations.

Locations and directions for the accelerometers were selected based on the locations of maximum vibration acceleration and displacement.

Baseline vibration data was collected prior to CPPU implementation.

Acceleration vs.-frequency curves were developed from this data and extrapolated to expected CPPU 6 OF 24 levels. The piping analyses were then re-run using these curves, and the results scaled up until the endurance limit is reached. A number of conservatisms were incorporated in the process to allow for uncertainty and provide extra margin. The resulting vibration spectra are used as initial acceptance criteria.For accessible systems outside containment, systems less affected by CPPU, and small bore piping; generic vibration screening allowables are used. Most of the piping outside containment will be screened for vibration by walkdown and measurement with portable equipment.

Vibration monitoring will be performed during startup at plateaus beginning with 75% of the CLTP and proceeding at varying increments to CPPU. This will allow trending of the data and will identify whether a condition other than final CPPU data results in the highest vibration levels. Direction is provided in the test program for plant personnel in the event that vibration limits are exceeded.

If required, power will be reduced to the previous levels until further evaluation can be performed.

7. Types of Vibration Monitoring The piping systems located inside containment are being monitored for vibration using accelerometers, and the data is collected on dedicated data acquisition computers.

The piping systems located outside containment generally will be monitored using portable vibration instrumentation, with data collected during walkdowns of the piping, and with remote vibration monitoring sensors in inaccessible areas. Remote operated cameras are an alternative to pipe mounted vibration instrumentation to provide plant and engineering personnel with qualitative feedback on flow induced vibration of piping and associated components.

Ongoing evaluations to determine whether additional monitoring is needed are in progress.

Additional monitoring instrumentation will be installed if initial measurements indicate that screening criteria could be exceeded.The following systems arc monitored with remote vibration instrumentation:

1) Main Steam 2) Feedwater 3) Recirculation (for non-CPPU vibration issues)4) RHR 5) Extraction Steam Other Systems are monitored with localized, or portable vibration instrumentation:

1) Condensate

2) HPCI (outside containment)

3) Electro Hydraulic Control (EHC)4) Feedwater Heater Drains 7 OF 24 I As previously described in section 6, the locations and directions of accelerometers are selected based on maximum analysis stress results at CLTP conditions and at known FIV susceptible locations such as the Safety Relief Valves (SRVs) that are discussed in section 11. Since the FIV monitoring is performed at CLTP conditions, CPPU flow simulated (during Main Steam Isolation Valve (MSIV) slow-closure testing) conditions, and CPPU conditions, any increase in FIV results will be clearly identified and evaluated.

The following table summarizes the instrumentation installed, or planned to be installed, to monitor FIV. See the Appendices of this attachment for additional details regarding sensor locations.

Table 3 -Monitoring Currently Installed

& Planned For Installation System Unit 1 Unit 2 (2)# Locations I # Accelerometers

1. Locations

/ #Accelerometers Main Steam 6/18 6/16 Feedwater 51/11 5/11 Recirculation/RHR 18 / 27 12 + 6 / 16 + 11 (Inside Containment)

RHR (Outside 4/20 4/20 Containment)

Extraction Steam 4 3 / 8 (3) Under Review Stage Notes: 1. Bold items are currently installed 2. Accelerometers not currently installed in Unit 2 will be installed by April, 2007.3. These accelerometers were installed to address the expected increases in vibration due to the Turbine Replacement Project during 2002. They will be active through the CPPU startup program.I I I I I 8 OF 24

8. Vibration Monitoring Results to Date Vibration data has been collected from the accelerometers installed in Unit I since Spring 2006 and in Unit 2 since Spring 2005. The data has been compared to the screening values for those lines and the results summarized in the table below.The vibration data from the Unit I Extraction Steam accelerometers was also collected and evaluated prior to 2005 and the results summarized in the table below.Table 4 -Measured Vibration Accelerations

-% of Calculated Screening Criteria System Unit I Unit 2 Main Steam 40% 30 %Feedwater 45% (1)Recirculation/RHR 60% 60%Extraction Steam 40 % (2)Notes: 1. Accelerometers to be installed March, 2007. Data to be available later in 2007 2. System is being evaluated to determine if accelerometers are needed The recirculation/RHR results are higher than those associated with the main steam &feedwater systems. These vibration levels reflect the system response to recirculation pump vane passing frequencies.

Since the recirculation flow increases less than 3%, operation at CPPU is not expected to cause vibration levels to increase above screening criteria.

Based on the existing system behavior, including the above measured accelerations, and experience at other plants, it is expected that the feedwater system vibration levels at CPPU will not exceed screening criteria.In April, 2006 PPL performed MSIV slow closure tests for each of the A, B, C, D Outboard MSIVs at the 80% Power Level. During these tests, the main steam flow through each of the open MSIVs was equal to a flow that will exist at about the first implementation step of the CPPU (- 1.13 OLTP). The Root Mean Square (RMS) and Peak accelerations were recorded.

The maximum RMS value is listed below and compared to the maximum CLTP values and the increase is slightly smaller than the predicted ratio of 1.14 determined from the square of the velocity increase discussed in Section 6. For simplicity the velocity change is assumed proportional to the square of the Power Ratio, [(1.13/1.06)2].

9 OF 24 I Table 4A -Measured Vibration Maximum Accelerations (G's) -Unit 1 Main Steam Lines Comparison of CLTP to Simulated Y2 of CPPU (MSIV Slow Closure Tests)RMS at CLTP RMS at Test Measured Predicted CONDITIONS CONDITIONS

= Increase Increase 1.06 OLTP 1.13 OLTP.074 .081 1.10 1.14 The above results are considered relatively low for the main steam system, and the vibration levels after implementation of CPPU arc not expected to exceed screening criteria.9. Inspections and Walkdowns Since vibration instrumentation is neither practical nor desirable for all systems, visual inspections are a key part of PPL's CPPU FIV evaluation strategy.

Walkdowns are planned in 4 major CPPU phases; pre-CPPU, CPPU first step (7%), CPPU second step (7%), and, CPPU post implementation.

The following systems will have walkdowns scheduled:

main steam, feedwater, condensate, extraction steam, feedwater heater drains, main turbine EHC, and HPCI steam (outside containment).

The reactor recirculation system is currently remotely monitored for FIV and inspected every outage. Since the increase in CPPU flow for the recirc system is small (2% to 3%), the inspections routinely performed on the system are adequate for CPPU implementation.

Each planned walkdown inspection criteria includes the following:

• Condition of insulation on subject and adjacent pipes,* Condition of pipe supports," Piping," Attached components and branch lines,* Condition of structures and components adjacent and below, and" Other specific criteria for particular systems.10. Modifications Programs are in place, and in some instances implemented, to reduce the susceptibility of piping to FIV. These programs include the following: " Socket welds on small pipe attached to the recirculation lines are inspected to more stringent criteria than was used during original construction.

If the existing welds do not meet the upgraded criteria, the welds are repaired or replaced with an improved socket weld design,* Capped piping small pipe attached to the recirculation lines has been removed and the connection plugged, 10 OF 24 I

• Modifications of the RHR 050A/B check valves that attach to recirculation piping,* Supports have been added to feedwater heater drain lines,* Mechanical snubbers have been replaced on the steam seal evaporator lines by Wire Energy Absorbing Restraints, and* Mechanical snubbers to be replaced with more vibration resistant hydraulic snubbers on the RWCU and steam seal piping.Modifications are needed to address the increased effects of FIV at CPPU conditions.

One example is the EHC system, which is being modified to add accumulators in accordance with existing GE recommendations to reduce susceptibility to fatigue. Other.modifications may be identified as additional vibration data becomes available.

Vibration monitoring and walkdown programs will identify those areas susceptible to FIVand trend their data to determine whether CPPU could lead to the exceedence of screening criteria.Engineering evaluations of the data will determine whether additional physical modifications will be needed.Of special concern for FIV susceptibility tracking and trending is the identification of piping/components that already have frequent replacement rates, and whose CPPU response could require replacement in less than the current 2 year operating cycle schedule.

Table 5 lists examples of components with frequent replacement rates and the expected change due to CPPU.Table 5 -Piping/Components with Frequent Replacement Rates A B C D E F COMPONENT ITEM SYSTEM FLOW EXISTING EXPECTED CHANGE REPLACEMENT REPLACEMENT Due to RATE RATE WITH CPPU CPPU 1. Check valves Soft Seats Feedwater 15 % Every 2 years Every 2 years 2. Butterfly Entire Service Water 0 % Every Outage Every Outage Valve valve to Stator Cooling 3. Valves Torque on HIPCI and 0 % Re-torque every Re-torque every Valve RCIC Drains Outage Outage Packing 4. Air Operated Valve Feedwater 16 % 2 yr diagnostic/

6 yr Rebuild frequency Valves Bodies & Hleater Drains rebuild may increase Controller

& Extraction Linkages Steam 11. Valves Industry reviews have shown that valves can be sensitive to FIV. Information Notice 2005-23 (Reference 2), documenting the sensitivity of butterfly valve taper pins to FIV, is the latest in a series of notices involving valve component failures due to FIV. PPL evaluates IE Notices and salient industry events under the SSES corrective action program, and is aware of the potential for vibration loosening of valve parts. Affected components are part of maintenance inspections.

11 OF 24 I The Safety Relief Valves (SRV) on the main steam lines are a primary FIV concern for CPPU implementation.

Vibration accelerometers are located on selected SRV bodies and adjacent discharge piping. Accelerometer vibration results to date, calculations using that data and extending it to CPPU conditions, and the results of scale model testing indicate thai the SSES SRVs will not experience problems due to CPPU. However, PPL will monitor the results of inspections and industry activities regarding SRVs to determine if and how they may apply at SSES.The SRVs, and other valves (that have shown a sensitivity to FIV), will be inspected for FIV degradation at each of the four planned CPPU phases discussed in section 9 of this attachment.

12. Sample Probes There are a number of sample probes and thermowells that extend into the flow stream on the piping systems affected by CPPU (Reference 3). The probes are susceptible to vibration from vortex shedding.

As the flow velocity increases, not only does the vibration magnitude increase, but also the vortex shedding frequency increases.

If the new vortex shedding frequency coincides with the structural natural frequency of the probe, overstress can result.The sample probes have been reviewed for sensitivity to CPPU flow. In most cases, the design of the probes has considerable margin. The probes will be modified during CPPU implementation if the frequencies induced by the flow approach the natural frequencies of the probes.13. Mechanical Snubbers on Pipes There are a number of mechanical snubbers installed as restraints on piping systems that are affected by CPPU. Some snubbers are showing signs of degradation due to FIV and the wear is expected to become more severe with the implementation of CPPU. Several mechanical snubbers have already been replaced by WEAR (Wire Energy Absorbing Rope) pipe restraint and vibration isolators.

Several other mechanical snubbers are being replaced with hydraulic snubbers.

The existing snubber testing plan ensures that mechanical snubber degradation is checked and corrected.

If testing results deem necessary, PPL will increase the frequency of mechanical snubber inspections for those located on piping that has high FIV responses now, and those which are expected to become more severe with CPPU.12 OF 24 I

14. Conclusion PPL has identified piping and components that are expected to be most affected by CPPU by performing a review of both industry and plant specific experience using the BWROG CPPU Extent of Condition matrix as guidance.

The BWROG CPPU Extent of Condition matrix is Appendix C of NEDO 33159, "CPPU Lessons Learned and Recommendations," November 2004 (Reference 15.1).Piping and components are being monitored with either remote vibration acceleration instrumentation, hand held vibration instrumentation, or observation programs during operation.

Vibration Acceptance criteria have been defined and accelerometer data, to date, indicates that no screening criteria will be exceeded due to CPPU conditions.

Walkdowns and inspections are planned for the areas of interest during accessible times.The analyses conclude that no actions, beyond those previously discussed in section 10, are needed at this time. However, the results of the planned data collections and walkdowns/

inspections will be reviewed to determine whether changes are needed.The PPL FIV program for CPPU is dynamic through continuous involvement in the BWROG, monitoring industry and plant developments, collecting and evaluating vibration data, and performing modifications, if required, to stay within acceptable FIV acceptance criteria.15. References

1. BWR Owners' Group (BWROG), "CPPU Lessons Learned and Recommendations," NEDO 33159, November 2004.2. NRC INFORMATION NOTICE 2005-23, "Vibration Induced Degradation of Butterfly Valves," February 10, 2005.3. NRC INFORMATION NOTICE 2004-06, "Loss of Feedwater Isokinetic Sampling Probes at Dresden Units 2 and 3, March 26, 2004.13 OF 24 I Appendix Al -Vibration Accelerometers on Main Steam Piping (Unit 1)Accelerometer Pipe Location Node Direction No. Line OD No.VE -16708 B 10.75 HPCI 426 Y VE -16709 B 10.75 HPCI 426 X VE-16710 B 10.75 HPCI 426 Z VE -16711 B 12.75 SRV M 33G Y VE -16712 B 12.75 SRV M 33G X VE -16713 B 12.75 SRV M 33G Z VE -16714 B 26 B 266 Y VE -16715 B 26 B 266 X VE -16716 B 26 B 266 Z VE -16717 C 4.5 RCIC Z003 Y VE -16718 C 4.5 RCIC Z003 X VE -16719 C 4.5 RCIC Z003 Z VE -16720 C 12.75 SRV B 53Z Y VE -16721 C 12.75 SRV B 53Z X VE -16722 C 12.75 SRV B 53Z Z VE -16723 C 26 C 509 Y VE -16724 C 26 C 509 X VE -16725 C 26 C 509 Z Totals: 6 locations on 2 lines with 18 accelerometcrs X -Horizontal, East/West Y -Vertical Z -Horizontal, North/South 14 OF 24 I Appendix A2 -Vibration Accelerometers on Main Steam Piping (Unit 2)Accelerometer Pipe Location Node Direction No. Line OD No.VE -26707 B 10.75 HPCI NA X VE -26708 B 10.75 HPCI NA Y VE -26709 B 10.75 HPCI NA Z VE -26710 B 12.75 SRV J NA X VE -26711 B 12.75 SRV J NA Z VE-26712 B 26 B NA Y VE -26713 B 26 B NA X VE -26714 B 26 B NA Z VE -26715 C 4.5 RCIC NA X VE -26716 C 4.5 RCIC NA Y VE -26717 C 4.5 RCIC NA Z VE -26718 C 12.75 SRV B NA X VE -26719 C .12.75 SRV B NA Y VE -26720 C 12.75 SRV B NA Z VE -26721 C 26 C NA X VE -26722 C 26 C NA Z Totals: 6 locations on 2 lines with 16 accelerometers X -Horizontal, East/West Y -Vertical Z -Horizontal, North/South 15 OF 24 I Appendix BI -Vibration Accelerometers on Feedwater Piping (Unit 1)Accelerometer Pipe Location Node Direction No. Line OD No.VE- 16753 DLA- 24 DLA101- 18 Y 101 H2 VE -16754 DLA- 12 Near N4F & 50 HP 102 PR-53 VE -16755 DLA- 12 Near N4F & 50 HO 102 PR-53 VE -16756 DLA- 12 Near N4E & 84 A 102 PR-40 VE -16757 DLA- 12 Near N4E & 84 HP 102 PR-40 VE- 16758 DLA- .12 NearN4E & 84 HO 102 PR-40 VE- 16759 DLA- 12 PR-251 99 Y 102 VE- 16760 DLA- 12 PR-251 99 A 102 VE- 16761 DLA- 12 PR-251 99 HP 102 VE -16762 DLA- 12 Near N4D 118 HP 102 & PR-45 VE -16763 DLA- 12 Near N4D 118 HO 102 & PR-45 Totals: 5 locations on I line with 11 accelerometers A -Axial, along pipe Y -Vertical HP -Horizontal and perpendicular to pipe HO -Horizontal, perpendicular to pipe and to HP 16 OF 24 I Appendix B2 -Vibration Accelerometers on Feedwater Piping (Unit 2)Accelerometer Pipe Location Node Direction No. Line OD No.VE-26769 DLA- 24 On NA Y 201 HV241 F011A VE-26770 DLA- 12 Near N4F & NA HP 202 PR-53 VE-26771 DLA- 12 Near N4F & NA HO 202 PR-53 VE-26772 DLA- 12 Near N4E & NA A 202 PR-40 VE-26773 DLA- 12 Near N4E & NA HP 202 PR-40 VE-26774 DLA- 12 Near N4E & NA HO 202 PR-40 VE-26775 DLA- 12 Near PR-251 NA Y 202 VE-26776 DLA- 12 Near PR-251 NA A 202 VE-26777 DLA- 12 Near PR-251 NA HP 202 VE-26778 DLA- 12 Near N4D & NA HP 202 PR-45 VE-26779 DLA- 12 Near N4D & NA HO 202 PR-45 Totals: 5 locations on I line with 11 accelerometers A -Axial, along pipe Y -Vertical HP -Horizontal and perpendicular to pipe.HO -Horizontal, perpendicular to pipe and to HP 17 OF 24 I Appendix CI -Vibration Accelerometers on Reactor Recirculation/RHR Piping (Unit 1)[LOOP A]Accelerometer Pipe Location Node Direction No. Line OD No.VE -16726 A 12 Below N2K nozzle 8014 HP VE -16727 A 4 Riser of Discharge Valve Z001 X_ Bypass Line VE -16728 A 4 Bypass Line 8018 Y VE -16729 A 4 Bypass Line Blind Flange 252 Z VE -16730 A. 4 Decontamination 405 HP Connection at Blind Flange VE -16731 A 4 RWCU 8028 Y VE -16732 A 2 RWCU 344 X VE -16733 A 2 RWCU 340 Z VE -16734 A NA Body of Discharge Valve 233 X VE-16735 A 24 RHR 172 Y VE -16736 A 24 RHR 172 HA VE -16737 A 24 RHR 172 HP VE -16738 A 24 RHR 186 .HP VE -16739 A 24 RHR 186 HA VE -16740 A NA Body of Check Valve 146 Y F050A VE -16741 A NA Body of Check Valve 146 X F050A VE -16742 A NA Body of Check Valve 146 Z F050A VE -16743 A NA Body of Check Valve 146 ATS F050A Totals: 12 locations on 1 line with 18 accelerometers ATS -Acoustic Tapping Sensor HA -Horizontal axial HP -Horizontal and perpendicular to pipe HO -Horizontal, perpendicular to pipe and to HP X -Horizontal, East/West Y -Vertical Z -Horizontal, North/South 18 OF 24 I Appendix C2 -Vibration Accelerometers on Reactor Recirculation/RHR Piping (Unit 1)[LOOP B]Accelerometer Pipe Location Node Direction No. Line OD No.VE -16744 B 12 Below N2E Nozzle 8014 HP VE -16745 B 4 Riser of Discharge Valve Z001 X I _Bypass Line VE -16746 B 4 Bypass Line 794 Y VE -16747 B 2 RWCU 808 X VE -16748 B 2 RWCU 810 Z VE -16749 B NA Body of Check Valve 700 Y F050B VE -16750 B NA Body of Check Valve 700 X F050B VE -16751 B NA Body of Check Valve 700 Z F050B VE -16752 B NA Body of Check Valve 700 ATS I__ IF050B Totals: 6 locations on I line with 9 accelerometers ATS -Acoustic Tapping Sensor HP -Horizontal and perpendicular to pipe X -East -West Y -Vertical Z -North -South 19 OF 24 I Appendix C3 -Vibration Accelerometers on Reactor Recirculation/RHR Piping (Unit 2)ILOOP Al Accelerometer Pipe Location Node Direction No. Line OD No.VE -26723 A 12 Below N2K nozzle 145 HP VE -26724 A 4 Riser of Discharge Valve 580 X*_Bypass Line VE -26725 A 4 Bypass Line 615/620 Y VE -26726 A 4 Bypass Line Blind Flange 595 Z VE -26727 A 4 Decontamination Blind 355 HP Flange VE -26728 A 4 RWCU 540 Y VE -26729 A 2 RWCU 441 X VE -26730 A 2 RWCU 441 Z VE -26731 A 28 Pump Discharge Piping 280 X VE -26732 A 24 Body of Check Valve 690 Y F050A VE -26733 A 24 Body of Check Valve 146 X F050A VE -26734 A 24 Body of Check Valve 146 Z F050A VE -26735 A 24 RHR 760 Y VE -26736 A 24 RHR 760 HA VE -26737 A 24 RHR 760 HP VE -26738 A 24 RHR 784 HP VE- 26780 A 24 RHR 784 HA VE -26759 A NA Body of Check Valve 146 ATS I I_ F050A I Totals: 12 locations on I line with 18 accelerometers ATS -Acoustic Tapping Sensor HA -Horizontal axial HP -Horizontal and perpendicular to pipe X -East -West Y -Vertical Z -North -South 20 OF 24 Appendix C4 -Vibration Accelerometers on Reactor Recirculation/RHR Piping (Unit 2)[LOOP B]Accelerometer Pipe Location Node Direction No. Line OD No.VE-26760 B 12 Below N2E Nozzle NA HP VE-26761 B 4 Riser of Discharge Valve NA X Bypass Line VE-26762 B 4 Bypass Line NA Y VE-26763 B 2 RWCU NA X VE-26764 B 2 RWCU NA Z VE-26765 B NA Body of Check Valve NA Y F050B VE-26766 B NA Body of Check Valve NA X F050B VE-26767 B NA Body of Check Valve NA Z F050B VE-26768 B NA Body of Check Valve NA ATS F050B Totals: 6 locations on I line with 9 accelerometers ATS -Acoustic Tapping Sensor HP -Horizontal and perpendicular to pipe X -East -West Y -Vertical Z -North -South 21 OF 24 Appendix D1 -Vibration accelerometers on RIIR piping, Outside Containment (Unit 1)Accelerometer Pipe Location Node Direction No. Line OD No.VE-16769 RHR A 24 Valve NA HP to Shutdown HV151FO15A stem VE-16770 RHR A 24 Valve NA Y to stem Shutdown HV151FO15A VE-16771 RHR A 24 Valve NA A to stem Shutdown HV151FO15A VE-16772 RHR A 24 Valve NA A to pipe Shutdown HV151FO15A VE-16773 RHR A 24 Valve NA Y to pipe Shutdown HV151FO15A VE- 16774 RHR A 24 Valve NA HP to Shutdown HV151FO17A stem VE-16775 RHR A 24 Valve NA Y to stem Shutdown HVI51FO17A VE-16776 RHR A 24 Valve NA A to stem Shutdown HVI51FO17A VE-16777 RHR A 24 Valve NA A to pipe Shutdown HVI51FO17A VE-16778 RHR A 24 Valve NA Y to pipe Shutdown HVI51FO17A VE-16779 RHR B 24 Valve NA HP to Shutdown HVI51FO15B stem VE-16780 RHR B 24 Valve NA Y to stem Shutdown HVI51FO15B VE-16781 RHR B 24 Valve NA A to stem Shutdown HVI51FO15B VE-16782 RHR B 24 Valve NA A to pipe Shutdown HV151FO15B VE-16783 RHR B 24 Valve NA Y to pipe Shutdown HV 151 FO15A VE-16784 RHR B 24 Valve NA HP to Shutdown HV151 FO17B stem VE-16785 RHR B 24 Valve NA Y to stem Shutdown HV151FO17B VE-16786 RHR B 24 Valve NA A to stem Shutdown HVI51FO17B VE-16787 RHR B 24 Valve NA A to pipe Shutdown HV151FO17B VE-A-Axial 16788 RHR B Shutdown 24 Valve HV151FO17B NA Y to pipe Totals: 4 locations on 2 lines with 20 accelerometers HP -Horizontal and perpendicular Y -Vertical 22 OF 24 I Appendix D2 -Vibration accelerometers on RIHR piping, Outside Containment (Unit 2)Accelerometer Pipe Location Node Direction No. Line OD No.VE-26739 RHR A 24 Valve NA HP to Shutdown HV251 F015A stem VE-26740 RHR A 24 Valve NA Y to stem Shutdown HV251 F015A VE-26741 RHR A 24 Valve NA A to stem Shutdown HV251 F015A VE-26742 RHR A 24 Valve NA A to pipe Shutdown HV25IF015A VE-26743 RHR A 24 Valve NA Y to pipe Shutdown HV251 F015A A VE-26744 RHR A 24 Valve NA HP to Shutdown HV251 F017A stem VE-26745 RHR A 24 Valve NA Y to stem Shutdown HV251 F017A VE-26746 RHR A 24 Valve NA A to stem Shutdown HV251 F017A VE-26747 RHR A 24 Valve NA A to pipe Shutdown HV251 F017A VE-26748 RHR A 24 Valve NA Y to pipe Shutdown HV251 FO 1 7A VE-26749 RHR B 24 Valve NA HP to Shutdown HV251F015B stem VE-26750 RHR B 24 Valve NA Y to stem Shutdown HV25I FOI5B VE-26751 RHR B 24 Valve NA A to stem Shutdown HV251 F015B VE-26752 RHR B 24 Valve NA A to pipe Shutdown HV251F015B VE-26753

• RHR B 24 Valve NA Y to pipe Shutdown HV25I F015B VE-26754 RHR B 24 Valve NA HP to Shutdown HV25 I FO I 7B stem VE-26755 RHR B 24 Valve NA Y to stem Shutdown HV251 F017B VE-26756 RHR B 24 Valve NA A to stem Shutdown HV251F017B VE-26757 RHR B 24 Valve NA A to pipe Shutdown HV251 F017B VE-26758 RHR B 24 Valve NA Y to pipe Shutdown I HV25I FO17B I A-Axial Totals: 4 locations on 2 lines with 20 accelerometers HP -Horizontal and perpendicular Y -Vertical 23 OF 24 I Appendix El -Vibration accelerometers on Fourth Stage Extraction Steam Piping (Unit 1)Accelerometer Pipe Location Node Direction No. Line OD No.VE-10201A HGD- 16 Between NA HP 101-1 BTV10210A and PP 10241 A VE-10202A HGD- 16 Between NA A 101-1 BTV10210A and PP 10241 A VE-10201B HGD- 16 Between NA HP 101-2 BTV1021OB and PP10241B VE-10202B HGD- 16 Between NA A 101-2 BTV10210B and PP 10241 B VE-10203C HGD- 16 Between NA HP 101-2 BTV 1021OC and PP10241C VE-10201C HGD- 16 1 ft. from NA HP 101-3 Thermowell TWI0205C VE-10202C HGD- 16 1 ft. from NA A 101-3 Thermowell TWI0205C VE-10204C HGD- 16 Between NA A 101-3 BTV 1021OC and PP 10241C Totals: 4 locations on 3 lines with 8 accelerometers A -Axial, along pipe HP -Horizontal and perpendicular 24 OF 24 I l7*00 Attachment 11 to PLA-6076 Grid Stability Evaluation PPL Susquehanna LLC Susquehanna Steam Electric Station Units 1&2 Extended Power Up-rate Attachment 11 SSES Grid Stability Evaluation Page 1 3/24/2006 TRANSMISSION SYSTEM STABILITY Studies were performed to evaluate the impact of Susquehanna Steam Electric Station (SSES) EPU operation on the transmission system stability.

The proposed SSES EPU electrical generator power output is 1300 MW, for each unit. The estimated power increases expected to be obtained from EPU and high pressure turbine replacements are 100 MW, per unit.ELECTRICAL SYSTEM GENERAL DESCRIPTION The PPL Susquehanna LLC SSES, as described in this document, is composed of: two nuclear units that are connected to the PJM 230kV and 500 kV transmission systems.The units Susquehanna Unit 1 1354 MVA and Susquehanna Unit 2 1354 MVA, produce power, which is distributed through the 230kV and 500 kV system, respectively, through two (2) 500 kV transmission lines, seven (7) 230 kV transmission lines and one 500/230kv transformer.

The lines are:* 500 kV Susquehanna

-Wescosville

• 500 kV Sunbury -Susquehanna

• 230 kV Susquehanna

-Sunbury* 230 kV Susquehanna

-Montour* 230 kV Susquehanna

-E Palmerton* 230 kV Susquehanna

-Harwood* 230 kV Susquehanna

-Jenkins* 230 kV Susquehanna

-Stanton #1* 230 kV Susquehanna

-Stanton #2 The transformer is the 500/230kv Transformer 21 located at the Susquehanna 500kv switchyard and electrically connected between the 500kv and 230kv switchyards.

Susquehanna Transmission System The design basis for the electric power system is described in Section 8.0 "Electric Power" of the Final Safety Analysis Report (FSAR)."The two independent offsite electric connections to Susquehanna SES are designed to provide reliable power sources for plant auxiliary loads and the engineered safety features loads of both units such that any single failure can affect only one power supply and cannot propagate to the alternate source." (FSAR Section 8.1. 1)Page 2 3/24/2006 "Unit I and 2 generators are connected by separate isophase buses to their respective main step-up transformer banks. Unit 1 main step-up transformer bank, with two three-phase, half capacity power transformers, steps up the 24 kV generator voltage to 230 kV; the Unit 2 bank, with three single phase power transformers, steps up the 24 kV generator voltage to 500 kV. The step-up transformer for Unit 1 connects to the Susquehanna 230 kV switchyard and for Unit 2 to the Susquehanna 500 kV switchyard.

The Susquehanna 230 kV switchyard is designed for six (6) 230 kV breaker and a half bays, and two (2)230 kV bus." (FSAR Section 8.1.2)"The Susquehanna 500 kV switchyard consists of three bays with double breakers, two 500 kV buses, two 500 kV lines, a 500 kV generator lead, and a 500-230 kV transformer tapped off the south bus. The Susquehanna 230 kV switchyard and 500 kV switchyard are approximately

1.9 miles

apart and are interconnected by a 500-230 kV bus tie transformer and transmission line. Aerial transmission connects the Susquehanna 230 kV switchyard with Sunbury and Montour switchyards, and with Stanton, East Palmerton, Harwood, and Jenkins Substations.

Aerial transmission lines integrate the Susquehanna 500 kV switchyard into the 500 kV system with connections at Wescosville, Alburtis and Sunbury.Both the Susquehanna 500 kV switchyard and the 230 kV switchyard are tied into the PJM interconnection." (FSAR Section 8.1.2)"The plant startup and preferred power for the engineered safety features systems is provided from two independent offsite power sources shown in Dwg. D159760, Sh. 1.a) A 230 kV line from the Susquehanna TI0 230 kV switching station feeds the start-up transformer No. 10.b) A 230 kV tap from the 500-230 kV tie line feeds the startup transformer No. 20." (FSAR Section 8.1.2)"The bulk power transmission system of PPL operates at 230 kV and 500 kV. Unit 1 of the Susquehanna Steam Electric Station supplies power to the 230 kV system through a 230 kV switchyard and Unit 2 supplies power to the 500 kV system through a separate 500 kV switchyard.

The offsite power system for the plant is supplied through the 230 kV portion of the bulk power system. "(FSAR Section 8.2.1.1)"Two independent offsite power sources are supplied to the Susquehanna plant via Transformer TlO and second source T20, and are shared by both units. One source is supplied from the Susquehanna TI0 230 kV Switchyard located to the west of the plant by constructing 4530 feet of 230 kV line on painted steel poles structures to startup transformer

1. 10. The Switchyard consists of two breaker-and-one-half bays. A total of three 230 kV circuit breakers are electrically configured in a ring buss connecting the Montour-Susquehanna TI0 230 kV line and Mountain-Susquehanna TI0 230 kV line to the Unit I Start-up Transformer

1. 10. "(FSAR Section 8.2.1.1)"The two switchyards are physically separate but are tied together by a 230 kV yard tie line with a 230-500 kV transformer in the 500 kV yard.(Section 8.2.1.1)""Two independent offsite power sources are supplied to the Susquehanna plant via Transformers T10 and second source T20, shared by both units. One source is supplied from the Susquehanna TI0 230 kV Switchyard located to the west of the plant by 4530 Page 3 P3/24/2006 feet of 230 kV line on painted steel poles to startup transformer

1. 10. The Switchyard consists of two breaker-and-one-half bays. A total of three 230 kV circuit breakers are electrically configured in a ring buss connecting the Montour-Susquehanna TIO 230 kV and Mountain-Susquehanna TI 0 230 kV lines and the Susquehanna Transformer

1. 10.(Section 8.2.1.1)""The Susquehanna T10 230 kV Switchyard is supplied by two 230 kV transmission lines, the Mountain-Susquehanna TIO and Montour-Susquehanna TI0 lines. The Mountain-Susquehanna TI0 line and the Montour-Susquehanna Tl0 230 kV line share double circuit structures from Susquehanna from the Susquehanna T1O 230kV Switchyard northeast to a point where the Mountain -Susquehanna T10 230kV line branches off to the east lines share a common right of way into the Susquehanna TIO 230 kV switchyard.(Section 8.2.1 .1)""The second offsite power supply is furnished by the multiple sources throughout the bulk power grid system through the 230 kV and 500 kV lines emanating from the Susquehanna 230 kV and 500 kV switchyards.

All transmission lines meet or exceed design requirements set forth by the National Electric Safety Code. One or two overhead ground wires are employed on the transmission lines above the phase conductors to provide adequate lightning flashover protection.

All lines meet the Army Corps of Engineers requirements for clearance over flood levels. All bulk power transmission lines are designed to withstand 100 mph hurricane wind loads on bare conductors." (FSAR Section 8.2.1.1)"No single disturbance in the bulk power grid system will cause complete loss of offsite power to the Susquehanna SES. This is a basic system design criteria." (FSAR Section 8.2.1.1)Transmission Interconnection PPL is a member of PJM, which permits exchanges of power with neighboring utilities and provides emergency assistance under Independent System Operator (ISO) direction.

Direct bulk power ties are between PPL and PECO Energy (formerly Philadelphia Electric), Luzerne Electric Division of UGI, Metropolitan Edison, Pennsylvania Electric, Jersey Central Power and Light, Public Service Electric and Gas, and Baltimore Gas and Electric Companies. (FSAR Section 8.2.1.2)ANALYSIS The PJM bulk power system is planned in accordance with Mid-Atlantic Area Council (MAAC) Reliability Principles and Standards.

MAAC is one often regional reliability councils of the North American Electric Reliability Council (NERC). The studies performed for Susquehanna, by PJM, tested the compliance of the system with the MAAC Reliability Principles and Standards.

The power flow portion of the analysis consisted of testing the system under normal and emergency operation conditions.

The transmission system was tested under normal conditions in order to assess the transmission network element loading with the addition Page 4 3/24/2006 of the proposed upgrades.

Testing included simulations of heavy power transfer conditions followed by single and multiple transmission facility outages.Under all power flow conditions tested, the stations and the transmission system satisfy the MAAC Reliability Principles and Standards.

There are some cases when the system becomes unstable during certain line or transformer outages. Case 2 below results from the impact of the Unit 2 generation increase.

The other cases are base line problems irrespective of the CPPU generation increases.

An Operating Guide (PPL Electric Utilities NEPA memorandum) is in place to reduce power during these specific transmission outages. The mitigating action provided by the existing Operating Guide for the Susquehanna to Wescosville line out of service addresses the newly identified Case 2 line outage condition.

Unstable cases due to line outages are: 1. Susquehanna to Sunbury line out of service 3 phase fault at Susquehanna (500kV) on line between Susquehanna and Wescosville

2. Susquehanna to Wescosville line out of service 3 phase fault at Sunbury on line between Sunbury and Juniata 3. Susquehanna 500/230 KV transformer out of service 3 phase fault at Sunbury on line between Sunbury and Juniata 4. Susquehanna to Wescosville line out of service 3 phase fault at Susquehanna (500kV) on line between Susquehanna and Sunbury The stability analysis was conducted using the PSS/E Load Flow and Dynamic Stability software provided by Power Technologies Incorporated (done by PJM and finalized in the impact studies for queue positions M 11 & M12). A key part of this regional planning protocol is the evaluation of both generation interconnection and merchant transmission interconnection requests, in this case queue position M I1 and M12 were requested and approved by PJM for the additional power output.The types of faults tested in accordance with the MAAC Criteria,Section IV, were: 1. Three (3) phase faults with normal clearing time 2. Single phase to ground faults with Breaker Failure (delayed clearing).

From a system stability point of view, faults on transmission lines around Susquehanna are more critical than a trip of either nuclear unit. Therefore, the system study considered the most critical line faults consistent with MAAC criteria.Maximum gross MVARS limitation on the generators will cause both real time and post contingency 500 kV voltage criteria deviations when specific 500kV lines are out of service. If this occurs, options will be exhausted to correct the deviation including a Page 5 3/24/2006 generation reduction at Susquehanna, which may be required to allow MVAR reduction to relieve the voltage violation.

To accommodate the loss in reactive capability due to the increase in real power output a 183 MVAR capacitor will be installed on the 230kV substation bus and a 171 MVAR will be installed on the 500kV substation at Susquehanna (see Figure 1 for more details)The PJM impact studies and PPL Electric Utilities NEPA memorandum provide information concerning the maximum gross MWs and MVARs output for each of the units, to maintain a stable grid operation under various system maintenance and outage conditions.

These conditions include operation with one (1) and two (2) units in service and various transmission line outages. The NEPA memorandum is provided and is used by the Transmission and Distribution System Operations Center to direct the Susquehanna Control Rooms to operate the units.Study criteria and assumptions When dispatching power flow and determining stability limits, the following criteria are applied: Steady state voltage: pre-fault voltages at selected 500 kV buses are not above 1.1 pu or below 1.0 pu.In addition, the terminal bus voltages at Susquehanna Units 1 and, 2 shall not be below 0.9 pu at the pre-fault condition.

• Transient stability:

PJM's transient stability criteria are applied: The system must be stable for all faults considered

• Damping: post-fault system damping shall be above 3%. Considering the difficulty in applying this criterion with the tool used, only selective cases are checked, based on the engineering judgment.

Therefore, this criterion was not strictly enforced.0 Transient voltage: post-fault transient voltages at 500 kV buses shall not be below 0.7 pu.CONCLUSION The study described above provides the following conclusions:

1. The power system is stable for all three-phase and single-phase faults studied, when cleared by primary protection in accordance with planned relay settings.2. Power system stability was confirmed for all cases of faults, which were cleared by primary protection.

Page 6 P 3/24/2006

3. The Susquehanna bus stability and continued availability was confirmed.

In summary, PPL concludes that the effects of the proposed Susquehanna EPU on the offsite electrical power system will not affect the ability to meet the requirements of GDC 17. The Susquehanna units remain stable for all normal design configurations and will also remain stable for all maintenance out of service configurations provided that they are operated within the limits allowed by the Electric Utilities memorandum NEPA.Susquehanna 500kV & 230kV Figure 1 Page 7 3/24/2006 1320 Attachment 12 to PLA-6076 RS-001 Standard Review Plan Correlation Matrices MATRIX I SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Materials and Chemical Engineering Areas of Review I Applicable to Primary. y,., Secondary,:

SRP Focus of SR uda Othelr Taetmyvplate I Cross Referec--

t Review Review Section usage Giac-ISafety Eva luation-Bac Brnhe) Number Section Number BWR PWR PUSAR,. CLTR., FSAR Reactor Vessel All EPUs EMCB SRXB 5.3.1 GDC-14 RG 1.190 2.1.1 2.1.1 3.2.1 3.2.1 5.3.1 Material Surveillance Draft Rev. 2 GDC-31 Program April 1996 10 CFR Part 50, App. H 10 CFR 50.60 Pressure-All EPUs EMCB SRXB 5.3.2 GDC-14 RG 1.161 2.1.2 2.1.2 3.2.1 3.2.1 5.3.2 Temperature Limits Draft Rev. 2 GDC-31 RG 1.190 and Upper-Shelf April 1996 10 CFR Part RG 1.99 Energy 50, App. G 10 CFR 50.60 Pressurized Thermal PWR EPUs EMCB SRXB 5.3.2 GDC-14 RG 1.190 2.1.3 N/A for BWRs Shock Draft Rev. 2 GDC-31 RG 1.154 April 1996 10 CFR 50.61 Reactor Internal and All EPUs EMCB SRXB 4.5.2 GDC-1 Note 1" 2.1.3 2.1.4 10.7 10.7 4.5.2 Core Support Draft Rev. 3 10 CFR Materials April 1996 50.55a I-1-MATRIX I OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Secondary SRP Focus of SRPý Other." T-:j:zTempIate---

-Cross Reference to Review Review Section Usage ..G-... G-6ui'dance-, ,Safety Evaluation.'

--Branch Branch(es)

Number Section Number'..... ......... .. .. ..... .... ... .. ..... .". ... ... .....S F S A R Reactor Coolant Pressure Boundary Materials All EPUs EMCB EMEB SRXB 5.2.3 Draft Rev. 3 April 1996 4.5.1 Draft Rev. 3 April 1996 5.2.4 Draft Rev. 2 April 1996 5.3.1 Draft Rev. 2 April 1996 5.3.3 Draft Rev. 2 April 1996 6.1.1 Draft Rev. 2 April 1996 GDC-1 10 CFR 50.55a GDC-4 GDC-14 GDC-31 10 CFR Part 50, App. G GDC-1 10 CFR 50.55a GDC-14 10 CFR 50.55a GDC-1 10 CFR 50.55a GDC-4 GDC-14 GDC-31 10 CFR Part 50, App. G RG 1.190 GL 97-01 IN 00-17sl BL 01-01 BL 02-01 BL 02-02 Note 2*Note 3*2.1.4 2.1.5 2.5.3, 3.2.1, 10.7 2.5.3, 3.2.1, 10.7 4.5.2, 5.2.3 Leak-Before-Break PWR EPUs EMCB 3.6.3 GDC-4 NUREG Draft 1061 Aug. 1987 Vol. 3 Nov. 1984 2.1.6 N/A for BWRs-2-MATRIX I OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003

-V I r r I Areas of Review Applicable to Primary Review Branch Secondary Review Branch(es)

SRP Section Number Focus of SRP Usage, Oth.. Other Guidance--'Temp ate --Safety Evaluation

-.Section Number___Cross Reference to Protective Coating All EPUs EMCB Systems (Paints) -Organic Materials Effect of EPU on All EPUs EMCB Flow-Accelerated Corrosion Steam Generator PWR EPUs EMCB Tube Inservice Inspection Steam Generator PWR EPUs EMCB Blowdown System Chemical and Volume PWR EPUs EMCB Control System (Including Boron Recovery System)Reactor Water BWR EPUs EMCB Cleanup System 6.1.2 Draft Rev. 3 April 1996 10 CFR Part 50, App. B Rr. 1_54 BWR PWR PUSAR CLTR FSAR 2.1.5 2.1.7 4.2.6 4.2.6 6.1.2 Note 4* 1 2.1.6 2.1.8 10.7 10.7 5.4.2.2 Draft Rev. 2 April 1996 10 CFR 50.55a 2.1.9 N/A for BWRs 2.1.10 N/A for BWRs 10.4.8 Draft Rev. 3 April 1996 GDC-14 SPLB SRXB 9.3.4 Draft Rev. 3 April 1996 GDC-14 GDC-29 2.1.11 N/A for BWRs 5.4.8 Draft Rev. 3 April 1996 GDC-14 GDC-60 GDC-61 3.11, 3.11 5.4.8 10.7 Notes: 1. In addition to the SRP, guidance on the neutron irradiation-related threshold for inspection for irradiation-assisted stress-corrosion cracking for BWRs is in BWRVIP-26 and for PWRs in BAW-2248 for E>1 MeV and in WCAP-14577 for E>0.1 MeV. For intergranular stress-corrosion cracking and stress-corrosion cracking in BWRs, review criteria and review guidance is contained in BWRVIP reports and associated staff safety evaluations.

For thermal and neutron embrittlement of cast austenitic stainless steel, stress-corrosion cracking, and void-3-MATRIX I OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 swelling, licensees will need to provide plant-specific degradation management programs or participate in industry programs to investigate degradation effects and determine appropriate management programs.2. For thermal aging of cast austenitic stainless steel, review guidance and criteria is contained in the May 19, 2000, letter from C. Grimes to D. Walters, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components." 3. For intergranular stress corrosion cracking in BWR piping, review criteria and review guidance is contained in BWRVIP reports, NUREG-0313, Revision 2, GL 88-01, Supplement I to GL-88-01, and associated safety evaluations.

4. Criteria and review guidance needed to review EPU applications in the area of flow-accelerated corrosion is contained in Electric Power Research Institute (EPRI) Report NSAC-202L-R2, "Recommendations for Effective an Flow-Accelerated Corrosion Program," dated April 1999. This EPRI document is copyrighted.

EPRI has provided copies of this document to EMCB for use by NRC staff. Copying of this document, however, is not allowed.5. Also see the plant-specific license amendments approving alternate repair criteria and redefining inspection boundaries. MATRIX 1 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 2 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Mechanical and Civil Engineering r T T 7 T 1 Areas of Review I Applicable to Pririmary RevieW, Branch-Sec&n-dair BReview-Bra nch(es)SRP Section-Number--Focus'f SRP 7 usage --Guidance Template--- -:-- Safety -Evaluation.,!, ,Section Number Cross Reference to Pipe Rupture Locations All EPUs EMEB and Associated Dynamic Effects Pressure-Retaining All EPUs EMEB Components and Component Supports 3.6.2 Draft Rev.2 April 1996 3.9.1 Draft Rev.3 April 1996 3.9.2 Draft Rev.3 April 1996 GDC-4 BWR PWR PUSAR ý. CLTR FSAR 2.2.1 10.1, 10.1, 3.6.2 10.2 10.2 GDC-1 GDC-2 GDC-14 GDC-15 2.2.2 2.2.2 2.5.3, 3.1, 3.2.2, 3.4, 3.5, 3.7, 3.8 2.5.3, 3.1, 3.2.2, 3.4, 3.5, 3.7, 3.8 3.9.1, 3.9.2, 3.9.3, 5.2.1.1 GDC-1 GDC-2 GDC-4 GDC-14 GDC-15 IN 95-016 IN 02-026 3.9.3 10 CFR 50.55a IN 96-049 Draft Rev. GDC-1 GL 96-06 2 GDC-2 April 1996 GDC-4 GDC-14 GDC-15 5.2.1.1 Draft Rev.3 April 1996 10 CFR 50.55a GDC-1 RG 1.84 RG 1.147 DG 1.1089 DG 1.1090 DG 1091 5. _____________

.5. ________ .5. ______ £ _____ .L I ________ J.-1-MATRIX 2 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary.Review Branch Secondary Review, Branch (es)ý- SRP -Section Number Focus of SRP Usage Other-Guidance,-,.-Template Safety Evaluation Section Number Cross Reference to-BWR"PWR PUSAR CLTR FSAR Reactor Pressure Vessel Internals and Core Supports All EPUs EMEB 3.9.1 Draft Rev.3 April 1996 3.9.2 Draft Rev.3 April 1996 GDC-1 GDC-2 GDC-1 GDC-2 GDC-4 2.2.3 2.2.3 3.1, 3.3, 3.4.2 3.1, 3.3, 3.4.2 3.9.1, 3.9.2, 3.9.3 3.9.5 IN 95-016 IN 02-026 3.9.3 10 CFR 50.55a IN 96-049 Draft Rev. GDC-1 GL 96-06 2 GDC-2 April 1996 GDC-4 3.9.5 Draft Rev.3 April 1996 10 CFR 50.55a GDC-1 GDC-2 GDC-4 GDC-10 IN 02-026 Note 1" Safety-Related Valves and Pumps All EPUs EMEB 3.9.3 Draft Rev.2 April 1996 GDC-1 10 CFR 50.55a(o IN 96-049 GL 96-06 2.2.4 2.2.4 3.1, 3.8, 4.1.3, 4.1.4, 4.1.6, 4.2 3.1, 3.8, 4.1, 4.2 3.9.6 Draft Rev.3 April 1996 GDC-1 GDC-37 GDC-40 GDC-43 GDC-46 GDC-54 10 CFR 50.55a(f)GL 89-10 GL 95-07 GL 96-05 IN 97-090 IN 96-048sl IN 96-048 IN 96-003 RIS 00-003 RIS01-015 RG 1.147 RG 1.175 DG 1089 DG 1091-i I-a a -i -I ma -I -I --2-MATRIX 2 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review Branch Secondary Review Branch(es)

SRP -'Section Number Focus of SRP Usage_Other Guidance-Template

,-: SafetyýSection Numbler..............

Cross Reference to I -~ --BWR: PWR PUSAR CLTR FSAR Seismic and Dynamic All EPUs EMEB EEIB 3.10 GDC-1 Qualification of Draft Rev. GDC-2 Mechanical and 3 GDC-4 Electrical Equipment April 1996 GDC-14 GDC-30 10 CFR Part 100, App. A 10 CFR Part 50, App. B USI A-46 2.2.5 2.2.5 10.1, 10.1, 3.10 10.3.3, 10.3.3 3.5.1, 3.5.2 Notes: 1. As indicated in IN 2002-26 and Supplement 1 to IN 2002-26, the steam dryers and other plant components recently failed at Quad Cities Units 1 and 2 during operation under extended power uprate (EPU) conditions.

The failures occurred as a result of high-cycle fatigue caused by increased flow-induced vibrations at EPU conditions.

The staffs review of the reactor internals as part of EPU requests will cover detailed analyses of flow-induced vibration and acoustically-induced vibration (where applicable) on reactor internal components such as steam dryers and separators, and the jet pump sensing lines that are affected by the increased steam and feedwater flow for EPU conditions.

In addition, the staff is evaluating the need to address potential adverse effects on other plant components from the increased steam and feedwater flow under EPU conditions. MATRIX 2 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 3 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Electrical Engineering T *.. r T T r T r Areas of Review-Applicable1--o

-ýPrimary Review Branch Secondary Review:- .Branch(es)

Environmental All EPUs EEIB Qualification of Electrical Equipment Offsite Power System All EPUs EEIB.-I SRP Section.'Number--3.11 Draft Rev.3 April 1996 8.1 Draft Rev.3 April 1996 8.2 Draft Rev.4 April 1996 8.2, App.A Draft Rev.4 April 1996 Focus of SRP: Usage 10 CFR 50.49 Other Guidance I.

• I BWR.PWR PUSAR CLTR FSAR Template Safety Evaluation Section Cross Reference to, 2.3.1 2.3.1 10.3.1 10.3.1 3.11 GDC-17 GDC-17 GDC-17 BTP PSB-1 Draft Rev. 3 April 1996 BTP ICSB-1 1 Draft Rev. 3 April 1996 2.3.2 2.3.2 6.1.1 SSES NOTE S-1 6.1.1 8.2 MATRIX 3 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 AC Onsite Power All EPUs EEIB System DC Onsite Power All EPUs EEIB System 8.1 Draft Rev.3 April 1996 8.3.1 Draft Rev.3 April 1996 8.1 Draft Rev.3 April 1996 8.1 Draft Rev.3 April 1996 GDC-17 GDC-17 GDC-17 10 CFR 50.63 10 CFR 50.63 2.3.3 2.3.3 6.1.2 6.1.2 8.3 2.3.4 2.3.4 6.2 6.2 8.3 Station Blackout All EPUs EEIB SPLB SRXB Note 1*2.3.5 2.3.5 9.3.2 9.3.2 15.2.6+8.2, App.B Draft Rev.4 April 1996 10 CFR 50.63 1. The review of station blackout includes the effects of the EPU on systems relied upon for core cooling in the station blackout coping analysis (e.g., condensate storage tank inventory, controls and power supplies for relief valves, residual heat removing system) to ensure that the effects are accounted for in the analysis.Susquehanna Notes: S-1 A grid stability analysis has been performed and is provided in attachment

11. Identifies any additional evaluations or equipment modifications. MATRIX 3 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 4 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Instrumentation and Controls Areas of Review Applicable to iL-=__-Primary Review ,-Branch-.-Secondary-Review Branch(es):

_SRP..Section-Number!Reactor Trip System All EPUs EEIB Engineered Safety All EPUs EEIB Features Systems Safety Shutdown All EPUs EEIB Systems Control Systems All EPUs EEIB Diverse I&C Systems All EPUs EEIB General guidance for All EPUs EEIB use of other SRP Sections related to I&C 7.2 Rev. 4 June 1997 7.3 Rev. 4 June 1997 7.4 Rev. 4 June 1997 7.7 Rev. 4 June 1997 7.8 Rev. 4 June 1997 7.0 Rev. 4 June 1997 Focus of SRP~Usage"'10 CFR 50.55(a)(1) 10 CFR 50.55a(h)GDC-1 GDC-4 GDC-13 GDC-19.GDC-20 GDC-21 GDC-22 GDC-23 GDC-24 10 CFR 50.55(a)(1) 10 CFR 50.55a(h)GDC-1 GDC-4 GDC-13 GDC-19 GDC-24 10 CFR 50.55(a)(1) 10 CFR 50.55a(h)GDC-1 GDC-13 GDC-19 GDC-24 Other:-, -Template Safety Guidance ! rEvaluation:.

-Section Number., BWR[.PWR-I -~ -PUSAR CLTR FSAR 2.4.1 2.4.1 5.3, 5.3 7.2 10.4 SSES Notes S-1 2.4.1 2.4.1 5.3 5.3 7.3.2.4.1 2.4.1 5.3 5.3 7.4 2.4.1 2.4.1 5.1, 5.1, 7.7 5.2, 5.2, 5.3 5.3 Cross Reference to, 2.4.1 2.4.1 5.1, 5.2, 5.3 5.1, 5.2, 5.3-1-MATRIX 4 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Susquehanna Notes: S-1 Reactor Trip System -PPL Susquehanna LLC Letter PLA-5931, "Susquehanna Steam Electric Station Proposed License Amendment Numbers 279 for Unit 1 Operating License No. NPF-14 and 248 for Unit 2 Operating License No. NPF-22 ARTS/MELLLA Implementation," dated November 18, 2005 provides the basis for the Average Power Range Monitor (APRM) flow-biased scram and rod block trip setpoints, and the power dependent RBM setpoints.

This submittal assumes prior approval of the ARTS/MELLLA License Change Request.-2 -MATRIX 4 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 5 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Plant Systems Areas of Review.Applicable to Primary -Secondary-,Review .1'. Review ._Branch-ý

ýBranch(es), Flood Protection EPUs that result in SPLB significant increases in fluid volumes of tanks and vessels Equipment and Floor EPUs that result in SPLB Drainage System increases in fluid volumes or in installation of larger capacity pumps or piping systems Circulating Water EPUs that result in SPLB System increases in fluid volumes associated with the circulating water system or in installation of larger capacity pumps or piping systems! SRP Section Number 3.4.1 Rev. 2 July 1981 9.3.3 Rev. 2 July 1981 10.4.5 Rev. 2 July 1981 3.5.1.1 Rev. 2 July 1981 Focus of SRP-Usage.Other.Guidance, , Template Safety, Evaluation Section, Number -GDC-2 Cross Reference to.GDC-2 GDC-4 GDC-4 GDC-4BWR- PUSAR. .-CLTR ;-FSAR 2.5.1.1. 2.5.1.1. 10.1.2, 10.1, 3.4 1 1 10.2, 10.2 10.5.1 2.5.1.1..

2.5.1.1. 8.1 8.1 9.3.3 2 2 2.5.1.1. 2.5.1.1. 6.4.2 6.4.2 10.4.5-3 3 2.5.1.2. 2.5.1.2. 7.1, 7.1, 3.5.1.1, 1 1 10.1 10.1 3.5.1.3 2.5.1.2. 2.5.1.2. 10.1 10.1 3.5.1.2 1 1 Internally Generated Missiles (Outside Containment)

EPUs that result in substantially higher system pressures or changes in existing system configuration SPLB EMCB EMEB Internally Generated EPUs that result in SPLB EMCB 3.5.1.2 GDC-4 Missiles (Inside substantially higher EMEB Rev. 2 Containment) system pressures or I July 1981 changes in existing system configuration MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review Branch Se Br econdary SRP Review Section anch(es) Number.10.2 Rev. 2 July 1981 Focus of SRP Oth Usage Guida er Template Safety nce Evaluation Section Number Cross Reference to I --I -BWR PWR PUSAR CLTR--FSAR Turbine Generator All EPUs except where SPLB the application demonstrates that previous analysis is bounding Protection Against EPUs that affect SPLB Postulated Piping environmental Failures in Fluid conditions, habitability of Systems Outside the control room, or Containment access to areas*important to safe control of postaccident operations Fire Protection All EPUs except where SPLB Program the application demonstrates that previous analysis is bounding GDC-4 GDC-4 EMCB EMEB 3.6.1 Rev. I July 1981 9.5.1 Rev. 3 July 1981 5.4.11 Rev. 2 July 1981 2.5.1.2. 2.5.1.2. 7.1 7.1 10.2 2 2 2.5.1.3 2.5.1.3 10.1, 10.1, 3.6.1 10.2, 10.2 8.5, 9.2 10 CFR 50.48 10 CFR Part 50, App. R GDC-3 GDC-5 GDC-2 GDC-4 Note 1* 2.5.1.4 2.5.1.4 6.7 SSES Note S-3 6.7 Fire Protection Review Report (FPRR)Pressurizer Relief Tank PWR EPUs that affect pressurizer discharge to the PRT SPLB EMEB 2.5.2 N/A to BWRs.4 1 4 4 4 Fission Product Control Systems and Structures All EPUs except where the application demonstrates that previous analysis is bounding SPLB EMCB 6.5.3 Rev. 2 July 1981 GDC-41 2.5.3.1 4.5 4.5 6.5.3, 6.5.11 Main Condenser EPUs for which the main SPLB Evacuation System condenser evacuation system is modified Turbine Gland Sealing EPUs for which the SPLB System turbine gland sealing system is modified 10.4.2 Rev. 2 July 1981 10.4.3 Rev. 2 July 1981 GDC-60 GDC-64 GDC-60 GDC-64 2.5.2.2 2.5.3.2 7.2 7.2 10.4.2 2.5.2.3 2.5.3.3 7.1 7.1 10.4.3-2-MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary. S *6-dary Review r es)e-Branch. Branch(es).

Main Steam Isolation BWR EPU that affect the SPLB Valve Leakage Control amount of valve leakage System that is assumed and resultant dose consequences.

Spent Fuel Pool All EPUs except where SPLB Cooling and Cleanup the application System demonstrates that previous analysis is bounding Station Service Water All EPUs except where SPLB System the application demonstrates that previous analysis is bounding Reactor Auxiliary All EPUs except where SPLB Cooling Water the application Systems demonstrates that previous analysis is bounding Ultimate Heat Sink All EPUs except where SPLB the application demonstrates that previous analysis is bounding Auxiliary Feedwater PWR EPUs except SPLB System where the application demonstrates that.previous analysis is bounding SRP Number 6.7 Rev. 2 July 1981 9.1.3 Rev. 1 July 1981 Focus of SRP Otherf 2.5.2.4 0USAR_CLTR FSAR.Tep.....

SumbetyCross Reference to Nvaumbinertio GDC-54 GDC-5 GDC-44 GDC-61 4.6 4.6 SSES Note S-1 EMCB 2.5.3.1 Note 2*2.5.4.1 6.3 6.3 9.1.3.9.2.1 GDC-4 GL 89-13 2.5.3.2 2.5.4.2 6.4 6.4.1, 9.2 Rev. 4 GDC-5 and 6.4.5 June 1985 GDC-44 Suppl. 1 GL 96-06 and Suppl. 1 9.2.2 Rev. 3 June 1986 GDC-4 GDC-5 GDC-44 GL 89-13 and Suppl. 1 GL 96-06 and Suppl. 1 2.5.3.3 2.5.4.3 6.4 6.4.3 9.2 I I 1- +9.2.5 Rev. 2 July 1981 10.4.9 Rev. 2 July 1981 GDC-5 GDC-44 2.5.4.4 6.4.5 6.4.5 Section 9.2.7 GDC-4 GDC-5 GDC-19 GDC-34 GDC-44 2.5.4.5 N/A for BWRs-3-MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review, Branch Secondary Review Branch(es)

Main Steam Supply All EPUs except where SPLB System the application demonstrates that previous analysis is bounding Main Condenser All EPUs except where SPLB the application demonstrates that previous analysis is bounding Turbine Bypass All EPUs except where SPLB System the application demonstrates that previous analysis is bounding Condensate and All EPUs except where SPLB Feedwater System the application demonstrates that previous analysis is bounding SRP Section Number 10.3 Rev. 3 April 1984 10.4.1 Rev. 2 July 1981 Focus of SRP-.. Usage ---Other Guidance Template Safety Evaluation Section Number I., BWR PWR-PUSAR CLTR SFSAR Cross Reference to GDC-4 GDC-5 GDC-34 GDCo60 10.4.4 Rev. 2.July 1981 10.4.7 Rev. 3 April 1984 11.3 Draft Rev. 3 April 1996 GDC-4 GDC-34 GDC-4 GDC-5 GDC-44 2.5.4.1 2.5.5.1 3.5.1 3.5.1, 5.4.5 3.7,' 10.3 3.8, 5.3.1 2.5.4.2 2.5.5.2 6.4.2, 7.2 10.4.1 7.2 2.5.4.3 2.5.5.3 7.3 7.3 10.4.4 2.5.4.4 2.5.5.4 7.4 7.4 10.4.7 2.5.5.1 2.5.6.1 8.2 8.2 11.3 2.5.5.2 2.5.6.2 8.1 8.1 11.2 Gaseous Waste Management Systems EPUs that impact the level of fission products in the reactor coolant system, or the amount of gaseous waste SPLB IEPB 10 CFR 20.1302 GDC-3 GDC-60 GDC-61 10 CFR Part 50, App. I Liquid Waste EPUs that impact the SPLB IEPB 11.2 10 CFR Management Systems level of fission products Draft 20.1302 in the reactor coolant Rev. 3 GDC-60 system, or the amount of April 1996 GDC-61 liquid waste 10 CFR Part 50, App. I-4-MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review Branch Secondary Review Branch(es)

SRP Section Number Focus of S Usage RP Other" Guidance Template Safety Evaluation Section-ý Number'Cross Reference to BWR PWR PUSAR CLTR FSAR 4 4 +Solid Waste Management Systems EPUs that impact the level of fission products in the reactor coolant system, or the amount of solid waste SPLB IEPB 11.4 Draft Rev. 3 April 1996 Emergency Diesel EPUs that result in SPLB Engine Fuel Oil higher EDG electrical Storage and Transfer demands System 10 CFR 20.1302 GDC-60 GDC-63 GDC-64 10 CFR Part 71 GDC-4 GDC-5 GDC-17 GDC-61 GDC-62 9.5.4 Rev. 2 July 1981.9.1.4 Rev. 2 July 1981 2.5.5.3 2.5.6.3 8.1 8.1 11.4 2.5.6.1 2.5.7.1 6.1.1 6.1.1 8.3 2.5.6.2 2.5.7.2 6.8 6.8 9.1.4 SSES NOTE S-2 Light Load Handling System (Related to Refueling)

EPUs except where the application demonstrates that previous analysis is bounding SPLB SPSB Notes: 1. Supplemental guidance for review of fire protection is provided in Attachment 1 to this matrix.2. Supplemental guidance for review of spent fuel pool cooling is provided in Attachment 2 to this matrix.Susquehanna Notes: S-1 The Main Steam Isolation Valve Leakage Control System at SSES has been eliminated.

The current MSIV leakage treatment method is described in a separate license amendment request that proposes a full scope implementation of an AST. Refer to PLA-5963 dated October 13, 2005.S-2 The Fuel Handling System is not affected by the SSES CPPU.S-3 PPL is committed to 10CFR50 Appendix R Sections 111G, IIIJ, IIIL, and 1110 as well as Appendix A of BTP APCSB 9.5-1 as demonstrated in the FPPR.-5-MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 ATTACHMENT I TO MATRIX 5 Supplemental Fire Protection Review Criteria Plant Systems This attachment provides guidance for the review of the fire protection information to be provided in an application for a power uprate. Power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown.

In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire. However, the licensee's application should confirm that these elements are not impacted by the extended power uprate. This confirmation should be reflected in the staffs safety evaluation.

If the licensee indicates that there is an impact on these elements, the staff should review the licensee's assessment of the impact using this attachment.

The systems relied upon to achieve and maintain safe shutdown following a fire may be affected by the power uprate due to the increase in decay heat generation following a plant trip. For fire events where the licensee is relying on one full train of the redundant systems normally used for safe shutdown, the analysis of the impact of the power uprate on the important plant process parameters performed for other plant transients (such as a loss of offsite power or a loss of main feedwater) will typically bound the impact of a fire event. In this case, a specific analysis for fire events may not be necessary.

However, where licensees rely on less than full capability systems for fire events (e.g., partial automatic depressurization system capability for reduced capability makeup pump), the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the integrity of the reactor pressure vessel or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability.

The staff should verify that the capability of the alternative/dedicated or backup systems relied upon for post-fire safe shutdown is sufficient to achieve and maintain safe shutdown considering the impact of the power uprate.The plant's post-fire safe shutdown procedures may also be impacted by the power uprate. For example, the allowable time to perform necessary operator actions may decrease as a result of the power uprate. In this case, the flow rates needed for systems required to achieve and maintain safe shutdown may need to be increased.

The licensee should identify the impact of the power uprate on the plant's post-fire safe shutdown procedures.

ATTACHMENT I TO MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 ATTACHMENT 2 TO MATRIX 5 Supplemental Spent Fuel Pool Cooling Review Criteria Plant Systems 1. BACKGROUND All operating nuclear power plants were licensed to certain design criteria regarding the adequacy of spent fuel pool (SFP) cooling capability.

The most common criterion is that contained in General Design Criterion (GDC)-61 of Appendix A to 10 CFR Part 50. This criterion specifies, in part, that the fuel storage system (1) be designed with a residual heat removal capability having reliability and testability that reflects the importance to safety of decay heat and other residual heat removal and (2) be designed to prevent a significant reduction in coolant inventory under accident conditions.

Earlier licensing criteria are generally consistent with GDC-61. However, later guidance contained in Section 9.1.3 of the Standard Review Plan applied GDC-44 to the SFP cooling system. GDC-44 requires, in part, that a licensee provide a cooling system that is capable of accomplishing its safety function with or without offsite sources of power, assuming a single failure. To satisfy these criteria, each licensee should demonstrate that there is adequate SFP cooling capacity and should also demonstrate the ability to supply adequate make-up water in the event of total loss of SFP cooling.A significant design-basis challenge to the SFP cooling system is imposed by a planned evolution (fuel transfer from the reactor vessel). Emergency offloads are not considered credible because fuel transfers may be accomplished only after plant cooldown, reactor disassembly, and refueling cavity flooding, which are time-consuming, manual processes.

As a result, the staff will review factors that increase heat load (e.g., power increases, decay-time reductions, or storage capacity increases) and other operational factors that reduce heat load (e.g., longer decay times or transfer of fewer fuel assemblies to the SFP) or that increase heat removal capability (e.g., scheduling offloads for periods of reduced ultimate heat sink temperature or optimizing cooling system performance) to ensure that the licensee has demonstrated the adequacy of the SFP cooling system.This guidance supercedes the guidance of paragraphs 111.1.d. and 111.1.h. of Standard Review Plan Section 9.1.3.2. ACCEPTANCE CRITERIA The adequacy of cooling may be evaluated against the capability to complete normal, planned activities, including fuel handling, without a degradation in safety and the ability to maintain defense-in-depth against a significant reduction in coolant inventory under accident conditions.

With respect to fuel handling, which is a manual process, SFP temperatures affect safety through operating environment and visibility.

At SFP temperatures below 140 0 F, (1) the fuel handling building ventilation is typically adequate to maintain a suitable operating environment, (2) evaporation from the SFP surface is at a sufficiently low rate to preclude fogging, and (3) the SFP temperature is within the design range of the cleanup system demineralizes to maintain water clarity. Defense-in-depth is provided by: ATTACHMENT 2 TO MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 1- DECEMBER 2003 (1) alarms to notify operators of a loss of cooling;(2) the capability of the SFP cooling system to maintain or reestablish, within a reasonable time, forced cooling following a single failure of an active component; (3) the ability of the cooling system to maintain the SFP temperature below the design temperature of the SFP structure and liner following a single-active failure or a design-basis event (e.g., a seismic event) within the current design basis of the facility;and (4) the availability of two reliable sources of makeup water, one having sufficient capacity to make up for evaporation following a total loss of forced cooling. Only one source need have this capacity because the heat load and boil-off rate decrease rapidly with time from the peak value such that a much lower makeup rate would be effective in extending the recovery time.The reliability of the systems relied upon to meet these guidelines should be maintained consistent with the plant's current design basis.3. REVIEW PROCEDURES

3.1. Adequate

SFP Cooling Capacity The licensee demonstrates adequate SFP cooling capacity by either performing a bounding evaluation or committing to a method of performing outage-specific evaluations.

3.1.1. Bounding

Calculation Two scenarios are analyzed:

(1) full cooling capability and (2) a single failure of an active cooling system component.

3.1.1.1. Full Cooling System Capability Evaluation Analysis conditions:

(1) decay heat load is calculated based on bounding estimates of offload size, decay time, power history, and inventory of previously discharged assemblies (2) heat removal capability is based on bounding estimates of ultimate heat sink temperature, cooling system flow rates, and heat exchanger performance (e.g., fouling and tube plugging margin)(3) alternate heat removal paths (e.g., evaporative cooling) should be appropriately validated and based on bounding input parameter values (e.g., air temperature, relative humidity, and ventilation flow rate)(4) actual bulk SFP temperature should remain below 140 OF -calculated SFP temperatures up to approximately 150 OF are acceptable when justified by conservative methods or assumptions (5) with appropriate administrative controls to verify that analysis inputs bound actual conditions, a set of bounding analyses may be prepared by the licensee to support operational flexibility.

ATTACHMENT 2 TO MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 3.1.1.2. Single-Active Failure Evaluation Analysis conditions:

(1) decay heat load is calculated based on a bounding estimate of offload size, decay time, power history, and inventory of previously discharged assemblies (2) heat removal capability is based on a bounding estimate of ultimate heat sink temperature, heat exchanger performance (e.g., fouling and tube plugging margin), and cooling system flow rates assuming the limiting Single failure with regard to heat removal capability (3) alternate heat removal paths (e.g., evaporative cooling) should be appropriately validated and based on bounding input parameter values (e.g., air temperature, relative humidity, and ventilation flow rate)(4) calculated bulk SFP temperature should remain below the design temperature of the SFP structure and liner, and calculated peak storage cell temperature should remain below the storage rack design temperature (5) for plants where a single failure results in a complete loss of forced cooling, the licensee's analysis should demonstrate that the loss of cooling would be identified and forced cooling would be restored before the bounding decay heat load would cause the SFP temperature to reach its design limit (6) with appropriate administrative controls to verify that analysis inputs bound actual conditions, a set of bounding analyses may be prepared by the licensee to support operational flexibility.

3.1.2. Cycle-Specific Calculation:

The licensee can choose to define a method to calculate operational limits prior to every offload using the anticipated actual conditions at the time of the offload.Cycle-specific analysis conditions:

(1) define the method to calculate decay heat load based on decay time, power history, and inventory of previous fuel discharges (2) define the method to calculate cooling system heat removal capacity based on ultimate heat sink temperature, cooling system flow rates, and heat exchanger performance parameters (3) define the method for calculating alternate heat removal capability (e.g., evaporative cooling) and provide validation of the method (4) using the methods defined to calculate heat load and heat removal capability, define the method to determine the limiting value of the variable operational parameter (typically, decay time) such that bulk SFP temperature will remain below 140 OF with full cooling capability (5) using the methods defined to calculate heat load and heat removal capability, define the method to determine the limiting value of the variable operational parameter (typically, decay time) such that bulk SFP temperature will be maintained below the SFP structure design temperature assuming a single failure affecting the forced cooling system (this may be a heat-balance analysis if cooling is degraded or a heatup-rate analysis if forced cooling is completely lost and subsequently recovered using redundant components)

(6) describe administrative controls that will be implemented each offload to ensure the ATTACHMENT 2 TO MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0-3 DECEMBER 2003 cycle-specific analysis inputs and results bound actual conditions prior to fuel movement 3.2. Adequate Make-Up Supply (1) Following a Ioss-of-SFP cooling event, the licensee should be able to provide two sources of make-up water prior to the occurrence of boiling in the pool. To determine the time to boil, the initial pool temperature is the peak temperature from a planned offload, assuming the worst single-active failure occurred.(2) At least one make-up source should have a capacity that is equal to or greater than the calculated boil-off rate so that the SFP level can be maintained.

Only one source need have this capacity because the heat load and boil-off rate decrease rapidly with time from the peak value such that a much lower makeup rate would be effective in extending the recovery time.ATTACHMENT 2 TO MATRIX 5 OF SECTION 2.1 OF RS-001, REVISION 0-4 DECEMBER 2003 MATRIX 6 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Containment Review Considerations Areas of Review Applicable to Primary Review Branch Secondary-Review-Branch(es),, PWR Dry Containments, EPUs for PWR SPSB Including plants with dry Subatmospheric containments Containments (including subatmospheric containments) except where the application demonstrates that previous analysis is bounding Ice Condenser EPUs for PWR SPSB Containments plants with ice condenser containments except where the application demonstrates that previous analysis is_bounding Pressure-Suppression EPUs for BWR SPSB Type BWR plants with pressure-Containments suppression containments except where the application demonstrates that previous analysis is bounding Subcompartment All EPUs except SPSB Analysis where the application demonstrates that previous analysis is bounding SRP Section Number, 6.2.1 Rev. 2 July 1981 6.2.1.1.A Rev. 2 July 1981 6.2.1 Rev. 2 July 1981 6.2.1.1 .B Rev. 2 July 1981 6.2.1 Rev. 2 July 1981 6.2.1.1.C Rev. 6 Aug. 1984 S6.2.1 Rev. 2 July 1981-Focus of SRP

' TemplatE*Usagei !: Guidance-Evaluatior GDC-13 GDC-16 GDC-38 GDC-50 GDC-64 GDC-13 GDC-16 GDC-38 GDC-50 GDC-64 GDC-4 2.6.1 GDC-13 GDC-16 GDC-50 GDC-64 PUSAR NCLTRB I I FSAR Cross Reference to 2.6.1 N/A for BWRs N/A for BWRs 4.1 4.1 6.2.1 through 4.1.3, 9.3.2, 10.3.1 GDC-4 GDC-50 2.6.2 4.1.2.3 4.1 6.2.1.2 6.2.1.2 Rev. 2 July 1981-1-MATRIX 6 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review.Branch Secondary..Review hs SBranch(es)_

Mass and Energy All EPUs except SPSB Release Analysis for. where the application Postulated Secondary demonstrates that System Pipe Ruptures previous analysis is bounding SPSB Mass and Energy PWR EPUs except SPSB Release Analysis for where the application Postulated Secondary demonstrates that System Pipe Ruptures previous analysis is bounding Combustible Gas EPUs that impact SPSB Control In Containment hydrogen release assumptions Containment Heat SPSB Removal Secondary Containment EPUs that affect the SPSB Functional Design pressure and temperature response, or draw-down time of the secondary containment SRP.Section*Number.6.2.1 Rev. 2 July 1981 6.2.1.3 Rev. 1 July 1981 6.2.1 Rev. 2 July 1981 6.2.1.4 Rev. 1 July 1981 6.2.5 Rev. 2 July 1981 Focus of SRP Usage-Other -Template Safety Guidance Evaluation Section--- Number .BwR PWR 1- *,. I PUSAR CLTR FSAR-Cross Reference to_____ 4. 4. 4.GDC-50 10 CFR Part 50, App. K GDC-50 2.6.3.1 4.1.1 through 4.1.2.2 4.1, 10.1 6.2.1.3 2.6.3.2 N/A for BWRs 10 CFR 50.44 10 CFR 50.46 GDC-5 GDC-41 GDC-42 GDC-43 GDC-38 2.6.4 4.7 4.7 6.2.5_____ 4. I I 6.2.2 Rev. 4 Oct. 1985 6.2.3.Rev. 2 July 1981 DG-1 107 2.6.5 2.6.5 3.10, 4.2.6 3.10, 4.2.6 GDC-4 GDC-16 2.6.6 4.5 4.5 6.2.3-2-MATRIX 6 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 1 1 r 7 , Areas of Review Applicable to Primary BRevie-w Branch Secondary Review, Branch(es)

• SRP Section Number Focus of SR P Other T'empilate SAety:.Usage-, Guidance Evaluation Section.Number>----BWR~ W I Cross Reference to -2.6.6 N/A for BWRs PUSAR , tCLTR I FSAR Minimum Containment PWR EPUs except SPSB SRXB 6.2.1 10 CFR 50.46 Pressure Analysis for where the application Rev. 2 10 CFR Part 50, Emergency Core demonstrates that July 1981 App. K Cooling System previous analysis is Performance Capability bounding Studies 6.2.1.5 Rev. 2___________________

________________

________ _______ I July 1981 _ ______2.6.6 N/A for BWRs-3-MATRIX 6 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 7 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Habitability, Filtration, and Ventilation Areas of Review Applicable to Primary Review Branch Sd66ndary-7-SRP.Review Branch(es)

Number F66us76f SRP-Guidanc~e Evaluationi Section Number"--Cross Reference to r 4 r B..PWR PUSAR CLTR" FSAR______ 4- 4 -4 4 Control Room All EPUs except SPSB Habitability System where the application demonstrates that previous analysis is bounding ESF Atmosphere All EPUs except SPSB Cleanup System where the application demonstrates that previous analysis is bounding Control Room Area All EPUs except SPSB Ventilation System where the application demonstrates that previous analysis is bounding Spent Fuel Pool Area All EPUs except SPSB Ventilation System where the application demonstrates that previous analysis is bounding Auxiliary and Radwaste All EPUs except SPSB Area Ventilation System where the application demonstrates that previous analysis is bounding Turbine Area Ventilation All EPUs except SPSB System where the application demonstrates that previous analysis is bounding 6.4 Draft Rev.3 April 1996 6.5.1 Rev. 2 July 1981 9.4.1 Rev. 2 July 1981 9.4.2 Rev. 2 July 1981*9.4.3 Rev. 2 July 1981 9.4.4 Rev. 2 July 1981 G DC-4 GDC-19 Note 1" Note 2*2.7.1 2.7.1 4.4 4.4 6.4 GDC-19 GDC-41 GDC-61 GDC-64 GDC-4 GDC-19 GDC-60 GDC-60 GDC-61 2.7.2 2.7.2 4.5 4.5 6.5.1 2.7.3 2.7.3 4.4 4.4, 9.4.1 6.6 2.7.4 2.7.4 6.6 6.6 9.4.2, 9.4.6 2.7.5 2.7.5 6.6 6.6 9.4.3 2.7.5 2.7.5 6.6 6.6 9.4.4 GDC-60 GDC-60-1-MATRIX 7 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review Branch Secondary ,BReview*Branch(es)

I SRP Section Number 9.4.5 Rev. 2 July 1981 Focus of SRP Usage Other--- -Template Safety'Guidance Evaluation Section Number Cross Reference to Li I ,. V BWR PWR PUSAR CLTR.FSAR ESF Ventilation System All EPUs except SPSB where the application demonstrates that previous analysis is bounding GDC-4 GDC-17 GDC-60 2.7.6 2.7.6 6.6 6.6 9.4.2, ADD 9.4.5, SSES 9.4.7, NOTE? 9.4.8 Notes: 1. Under SRP Section 6.4,Section II, "Acceptance Criteria," the discussion for Item C related to GDC-19 should be supplemented with "and providing a suitably controlled environment for the control room operators and the equipment located therein." 2. Under SRP Section 6.4,Section II, Item 2, "Ventilation System Criteria," the discussion related to review of the control room area ventilation system under SRP Section 9.4.1 should be retained.-2-MATRIX 7 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 8 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Reactor Systems Areas of Review-Applicable to Primary -Secondary-

'-SRP Review .. RevieW-. '-Section..Branch Branch(es)

Number SRP-Us'a-ge j I Guidance, Section Number__- Cross Reference to, I r F BWR, PWR -'PUSAR'CLTR FSAR Fuel System Design All EPUs SRXB Nuclear Design All EPUs SRXB Thermal and Hydraulic All EPUs SRXB Design 2.1,* 4.2 10 CFR 50.46 Note 1" 2.8.1 2.8.1 2.2, 4.2 Draft Rev. GDC-10 Note 2* 2.3, 3 GDC-27 2.5, April 1996 GDC-35 4.3, 9.1 4.3 GDC-10 RG 1.190 2.8.2 2.8.2 2.1, 43 GDC.1 RG .1902.2, Draft Rev. GDC-11 GSI 170 2.3, 3 GDC-12 IN 97-085 2.4, April 1996 GDC-13 2.5, GDC-20 4.3, GDC-25 Section 5 GDC-26 9.1, GDC-27 9.2, GDC-28 9.3 4.4 Draft Rev.2 April 1996 4.6 Draft Rev.2 April 1996 Functional Design of Control Rod Drive System All EPUs SRXB SPLB GDC-10 GDC-12 GDC-4 GDC-23 GDC-25 GDC-26 GDC-27 GDC-28 GDC-29 10CFR 50.62(c)(3)

Note 3*2.8.4.1 2.8.4.1 2.5 2.5 4.6 2.8.3 2.8.3 2.2, 2.3j 2.4, 5.3, 9.1 4.4-1-MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Secondary., SRP Review .Review -...Section Branch-. Branch(es). Focus of SRPI Usage:ý Other.'Guidance Template Safety Evaluation 2 Section Number.Cross Reference to BWR,!PWR PUSAR CLTR FSAR Overpressure Protection All EPUs SRXB during Power Operation Overpressure Protection PWR EPUs SRXB during Low Temperature Operation Reactor Core Isolation BWR EPUs SRXB Cooling System Residual Heat Removal All EPUs SRXB System Emergency Core Cooling All EPUs SRXB System-t t -t 5.2.2 Draft Rev.3 April 1996 5.2.2 Draft Rev.3 April 1996 5.4.6 Draft Rev.4 April 1996 5.4.7 Draft Rev.4 April 1996 GDC-15 GDC-31 GDC-15 GDC-31 Note 4* 2.8.4.2 2.8.4.2 3.1 5.2.2 2.8.4.3 N/A for BWRs GDC-4 GDC-5 GDC-29 GDC-33 GDC-34 GDC-54 10 CFR 50.63 GDC-4 GDC-5 GDC-19 GDC-34 3.9 9.1.3 3.9 5.4.6 9.3.2 2.8.4.4 Note 5*2.8.4.4 3.10, 4.2.4, 4.2.6, 6.3 3.10 5.4.7+ 4 + + 4 + 4 6.3 Draft Rev.3 April 1996 GDC-4 GDC-27 GDC-35 10 CFR 50.46 10 CFR Part 50, App. K Note 6*2.8.5.6.2 2.8.5.6.3 4.2, 4.3 6.3 Standby Liquid Control System BWR EPUs SRXB EMCB 9.3.5 SPLB Draft Rev..3 April 1996 GDC-26 GDC-27 10 CFR 50.62(c)(4)

Note 10* 12.8.4.5 6.5, 6.5 9.3.5 9.3.1-2-MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Review Branch Secondary Review Branch(es)

SRP Section Number Focus of SRP Other Usage .Guidance Template Safety*Evaluation

.Section Number Cross Reference to BWR PWRPUSARW CLTR SFSAR Decrease in Feedwater All EPUs SRXB Temperature, Increase in Feedwater Flow, Increase in Steam Flow, and Inadvertent Opening of a Steam Generator Relief or Safety Valve Loss of External Load; All EPUs SRXB Turbine Trip, Loss of Condenser Vacuum;Closure of Main Steam Isolation Valve (BWR); and Steam Pressure Regulator Failure (Closed)Loss of Nonemergency AC All EPUs SRXB Power to the Station Auxiliaries 15.1.1-4 GDC-10 Note 7* 2.8.5.1 2.8.5.1. 9.1 15.1.1-4 Draft Rev. GDC-15 1 2 GDC-20 April 1996 GDC-26 15.2.1-5 GDC-10 Note 7* 2.8.5.2. 2.8.5.2. 3.1, 15.2.1-5 Draft Rev. GDC-15 1 1 3.8, 2 GDC-26 9.1 April 1996 15.2.6 GDC-10 Note 7* 2.8.5.2. 2.8.5.2. 6.1, 15.2.6 Draft Rev. GDC-15 2 2 9.1 2 GDC-26 April 1996 Loss of Normal Feedwater Flow All EPUs SRXB EEIB 15.2.7 Draft Rev.2 April 1996 GDC-10 GDC-15 GDC-26 Note 7*2.8.5.2.3 2.8.5.2.3 3.9, 9.1 15.2.7 I -~ ________Feedwater System Pipe Breaks Inside and Outside Containment PWR EPUs SRXB EEIB 15.2.8 Draft Rev.2 April 1996 GDC-27 GDC-28 GDC-31 GDC-35 Note 7" 2.8.5.2.4 N/A for BWRs Loss of Forced Reactor All EPUs SRXB Coolant Flow Including Trip of Pump Motor and Flow Controller Malfunctions 15.3.1-2 Draft Rev.2 April 1996 GDC-10 GDC-15 GDC-26 Note 7* 2.8.5.3.1-3-MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Revie:W ...Applicable to:..Primary Secondary.

Review " : Review',,:Braihch-

", B ranch(es)§L,: SRP Section Number..... -- ------- ......Focus of SRP:*Usagei ::;Other Guidance: Template Safety E v 'IdEval'ati6h_"', Section Number Cross Reference to SBWR PWR, PUSAR CLTR FSAR Reactor Coolant Pump All EPUs SRXB Rotor Seizure and Reactor Coolant Pump Shaft Break Uncontrolled Control Rod All EPUs SRXB Assembly Withdrawal from a Subcritical or Low Power Startup Condition Uncontrolled Control Rod All EPUs SRXB Assembly Withdrawal at Power Control Rod Misoperation PWR EPUs SRXB (System Malfunction or Operator Error)Startup of an Inactive Loop All EPUs SRXB or Recirculation Loop at an Incorrect Temperature, and Flow Controller Malfunction Causing an Increase in BWR Core Flow Rate Chemical and Volume PWR EPUs SRXB Control System Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant 15.3.3-4 15.3.3-4 GDC-27 Note 7* 2.8.5.3. 2.8.5.3. 9.1. SSES Draft Rev. GDC-28 2 2 9.2 NOTE 3 GDC-31 April 1996 15.4.1 15.4.1 GDC-10 Note 7* 2.8.5.4. 2.8.5.4. 5.1.2, SSES Draft Rev. GDC-20 1 1 5.3.4 NOTE 3 GDC-25 N-2 April 1996 1 1 1 1 1 1 S-2 15.4.2 Draft Rev.3 April 1996 GDC-10 GDC-20 GDC-25 Note 7*2.8.5.4.2 2.8.5.4.2 5.3.5, 9.1 15.4.2 15.4.3 GDC-10 Note 7*Draft Rev. GDC-20 3 GDC-25 April 1996 15.4.4-5 GDC-10 Note 7*Draft Rev. GDC-15 2 GDC-20 April 1996 GDC-26 GDC-28 15.4.6 GDC-10 Note 7*Draft Rev. GDC-15 2 April GDC-26 1996 2.8.5.4.3 2.8.5.4. N/A for BWRs 3 2.8.5.4. 9.1 15.4.4-5 4 2.8.5.4. N/A for BWRs 5-4-MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to : Primary Review Branch -Secondary-SRP-Review- -Section Branch(es)-

Number Focus of SRP Usage---,: Other--.:Guidance:

itempl ,ate Safety7-Evaluation-Section Number -Cross Reference to PWR PUSAR I*CLT R FSAR Spectrum of Rod Ejection PWR EPUs SRXB Accidents Spectrum of Rod Drop BWR EPUs SRXB Accidents Inadvertent Operation of All EPUs SRXB ECCS and Chemical and Volume Control System Malfunction that Increases Reactor Coolant Inventory Inadvertent Opening of a All EPUs SRXB PWR Pressurizer Pressure Relief Valve or a BWR Pressure Relief Valve Steam Generator Tube PWR EPUs SRXB Rupture Loss-of Coolant Accidents All EPUs SRXB Resulting from Spectrum of Postulated Piping Breaks within the Reactor Coolant Pressure Boundary Anticipated Transient All EPUs SRXB Without Scram 15.4.8 GDC-28 Note 7*Draft Rev.3 t April 1996 2.8.5.4.6 N/A for BWRs 15.4.9 Draft Rev.3 April 1996 GDC-28 Note 7*2.8.5.4.4 5.3, 15.4.9 9.2 15.5.1-2 Draft Rev.2 April 1996 GDC-10 GDC-15 GDC-26 Note 7*Note 8*2.8.5.5 2.8.5.5 9.1 15.5.1-2 15.6.1 Draft Rev.2 April 1996 GDC-10 GDC-15 GDC-26 Note 7*2.8.5.6.1 2.8.5.6.1 9.1 15.6.1, 15.1.4 SSES NOTE S-3 15.6.3 Note 7* Note 7*Draft Rev.3 April 1996 2.8.5.6. N/A for BWRs 2 15.6.5 Draft Rev.3 April 1996 GDC-35 10 CFR 50.46 Note 7*Note 9*2.8.5.6.2 2.8.5.6.3 4.3 15.6.5 Note 7* 2.8.5.7 2.8.5.7 6.5, 9.3 15.8 Note 10* 9.3.1, 9.3.3-5-MATRIX 8 OF SECTION 2.1 OF RS-o001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to-7 Primary, Review Secondary I~- SRP- -

-6ertion Branth(6s)_

TN urnmbe Ir .--Focus ofSRPK :0ther Template Safety-.-----Usage,-7,Guidance

-Evaluation~-.

---

----Secti66'dfi6umbe Cross Reference to New Fuel Storage EPU applications SRXB that request approval for new fuel design.Spent Fuel Storage EPU applications SRXB that request approval for new fuel design.9.1.1 Draft Rev.3 April 1996 9.1.2 Draft Rev.GDC-62I .PWR.. .PUSAR,, CLTR %: FSAR 2.8.6.1 2.8.6.1 NIA for SSES SSES NOTE S-4 2.8.6.2 2.8.6.2 N/A for SSES SSES NOTE S-4 GDC-4 GDC-62 4 April 1996-6-MATRIX 8 OF SECTION 2.1 OF RSo001, REVISION 0 DECEMBER 2003 Notes: 1. When mixed cores (i.e., fuels of different designs) are used, the review covers the licensee's evaluation of the effects of mixed cores on design-basis accident and transient analyses.2. The current acceptance criteria for fuel damage for reactivity insertion accidents (RIAs) need revision per Research Information Letter No. 174, "Interim Assessment of Criteria for Analyzing Reactivity Accidents at High Bumup." The Office of Nuclear Regulatory Research is conducting confirmatory research on RIAs and the Office of Nuclear Reactor Regulation is discussing the issue of fuel damage criteria with the nuclear power industry as part of the industry's proposal to increase future fuel burnup limits. In the interim, current methods for assessing fuel damage in RIAs are considered acceptable based on the NRC staffs understanding of actual fuel performance, as shown in three-dimensional kinetic calculations which indicate acceptably low fuel cladding enthalpy.3. The review also covers core design changes and any effects on radial and bundle power distribution, including any changes in critical heat flux ratio and critical power ratio. The review will also confirm the adequacy of the flow-based average power range monitor flux trip and safety limit minimum critical power ratio at the uprated conditions.

4. The review also covers the determination of allowable power levels with inoperable main steam safety valves.5. The review also covers the total time necessary to reach the shutdown cooling initiation temperature.

6. The review for BWRs will cover the justification for changes in calculated peak cladding temperature (PCT) for the design-basis case and the upper-bound case and any impact of the changes in PCTs on the use of the design methods for the power uprate.7. The review: confirms that the licensee used NRC-approved codes and methods for the plant-specific application and the licensee's use of the codes and methods complies with any limitations, restrictions, and conditions specified in the approving safety evaluation.

confirms that all changes of reactor protection system trip delays are correctly addressed and accounted for in the analyses.(for PWRs) confirms that steam generator plugging and asymmetry limits are accounted for in the analyses.(for PWRs) covers the licensee's evaluation of the effects of Westinghouse Nuclear Service Advisory Letters (NSALs), NSAL 02-3 and Revision 1, NSAL 02-4, and NSAL 02-5.These NSALs document problems with water level setpoint uncertainties in Westinghouse-designed steam generators.

The review is conducted to ensure that the effects of the identified problems have been accounted for in steam generator water level setpoints used in LOCA, non-LOCA, and ATWS analyses.8. For the inadvertent operation of emergency core cooling system and chemical and volume control system malfunctions that increase reactor coolant inventory events: (a) non-safety-grade pressure-operated relief valves should not be credited for event mitigation and (b) pressurizer level should not be allowed to reach a pressurizer water-solid condition.

9. The review also verifies that: Licensee and vendor processes ensure LOCA analysis input values for PCT-sensitive parameters bound the as-operated plant values for those parameters (For PWRs) The models and procedures continue to comply with 10 CFR 50.46 during the switchover from the refueling water storage tank to the containment sump (i.e., the core remains adequately cool during any flow reduction or interruption that may occur during switchover).(For PWRs) Large-break LOCA analyses account for boric acid buildup during long-term core cooling and that the predicted time to initiate hot leg injection is consistent with the times in the operating procedures.(For BWRs) The licensee's comparison of parameters used in the LOCA analysis with actual core design parameters provide the needed justification to confirm the applicability of the generic LOCA methodology.

10. The ATWS review is conducted to ensure that the plant meets the 10 CFR 50.62 requirements:

For PWR plants with both a diverse scram system (DSS) and ATWS mitigation system actuation circuitry (AMSAC), the staff will not review ATWS for EPUs.MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 For PWR plants where a DSS is not specifically required by 10 CFR 50.62, a review is conducted to verify that the consequences of an ATWS are acceptable.

The acceptance criteria is that the peak primary system pressure should not exceed the ASME Service Level C limit of 3200 psig. The peak ATWS pressure is primarily a function of the moderator temperature coefficient and the primary system relief capacity.For BWR plants, the review is conducted to ensure that the licensee has appropdately accounted for changes in analyses due to the uprated power level and confirm that required equipment, such as the standby liquid control system (SLCS) pumps, can deliver required flowrates.

The review will also cover the SLCS relief valve margin. In addition, a review is conducted to ensure that SLCS flow can be injected at the assumed time without lifting bypass relief valves during the limiting ATWS.Susquehanna Notes: S-1 Pump Seizure / Shaft Break: FSAR Section 15.3.4 concludes that the pump seizure accident is more limiting than the pump shaft break. Section 15.3.3 of the FSAR (Pump Seizure) will be updated to be consistent with the conclusions in the PUSAR.S-2 Uncontrolled Control Rod Assembly Withdrawal from a Subcdtical or Low Power Startup Condition:

Continuous rod withdrawal during a reactor startup from a subcritical or low power startup condition is described in SSES FSAR Section 15.4.1.2.

As described in the FSAR, the low power rod withdrawal error events are considered as non-limiting events, and are not reanalyzed as part of the reload analysis unless the event disposition changes.The original FSAR analysis of the transient caused by continuous control rod withdrawal in the startup range demonstrates considerable margin for the peak fuel enthalpy to the licensing basis criterion of 170 cal/gm.S-3 Inadvertent Openinq of a BWR Pressure Relief Valve: Section 15.1.4 of the SSES FSAR identifies this event as non-limiting based on a qualitative analysis.

Since dome pressure is unchanged at EPU conditions the SRV capacity per valve remains the same which means there is a minimal effect on the depressurization for this event at EPU conditions.

Therefore, the original qualitative analysis conclusions remain valid for the transition to EPU conditions.

S-4 The SSES EPU submittal does not request approval for a new fuel design.-8 -MATRIX 8 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 9 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Source Terms and Radiological Consequences Analyses Areas of Review Applicable to Primary Review Branch Secondary ,_ Review SBranch(es)" Othier Guidainc'e

]:=Template Safety-Evaluation Section--Number I Cross Reference to Source Terms for Input All EPUs SPSB into Radwaste Management Systems Analyses 11.1 10 CFR Part 20 Draft Rev. 3 10 CFR Part April 1996 50, App. I GDC-60 BWR PWR' PUSAR -':CLTR FSAR 2.9.1 2.9.1 8.4, 8.4, 11.1, 8.6 8.6 11.2, 11.3, 11.4 Radiological Consequence Analyses Using Alternative Source Terms EPUs that utilize alternative source term SPSB EEIB EMCB EMEB IEPB SPLB SRXB 15.0.1 Rev. 0 July 2000 10 CFR 50.67 GDC-19 10 CFR 50.49 10 CFR Part 51 10 CFR Part 50, App. E NUREG-0737 2.9.2 2.9.2 8.5 9.2 SSES NOTE S-1 8.5, 9.2 2.3.6.4, 15.2, 15.3, 15.4, 15.6, 15.7, 18.1 Appendix 15B, 15C, 15D Radiological Consequences of Main Steamline Failures Outside Containment for a PWR PWR EPUs that do not utilize alternative source term whose main steamline break analyses result in fuel failure SPSB SRXB 15.1.5, App.A Draft Rev. 3 April 1996 10 CFR Part 100 Notes 4, 5,6,7, 27*4 4.6.4 Draft Rev. 3 April 1996 GDC-19 Notes 1, 2,3,28, 29*Radiological EPUs that do not SPSB SRXB 15.3.3-4 10 CFR Part Notes 5, Consequences of utilize alternative Draft Rev. 3 100 8, 9, 27*Reactor Coolant Pump source term whose April 1996 Rotor Seizure and reactor coolant Reactor Coolant Pump pump rotor seizure Shaft Break or reactor coolant pump shaft break results in fuel failure 2.9.2 N/A for BWRs 2.9.3 N/A for SSES-1-MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary- Secondary SRP Section Focus of SRP -Template Safety- .7 Cross Reference to.Review Review Number Usage Guidance Evaluation Section.----- Branch Branch(es)

Number--SWR PWR* PUSAR CLTR: FSAR Radiological PWR EPUs that do SPSB SRXB 15.4.8, App. 10 CFR Part Notes 4, 2.9.4 N/A for BWRs Consequences of a not utilize A 100 21,22, Control Rod Ejection alternative source Draft Rev. 2 27*Accident term whose rod April 1996 ejection accident results in fuel failure 6.4 GDC-19 Notes 1, or melting Draft Rev. 3 2, 3, 28, April 1996 29*6.4 GDC-19 Notes 1, Draft Rev. 3 2, 3, 28, April 1996 29*Radiological BWR EPUs that do SPSB SRXB 15.4.9, App. A 10 CFR Part Notes 9, Notes N/A for SSES Consequences of not utilize Draft Rev. 3 100 10, 27* 1, 2, 3, Control Rod Drop alternative source Aprl 1996 28,29*Accident term whose control rod drop accident 6.4 GDC-19 results in fuel failure Draft Rev. 3 or melting April 1996 Radiological EPUs that do not SPSB 15.6.2 GDC-55 2.9.3 2.9.5 N/A for SSES Consequences of the utilize alternative Draft Rev. 3 10 CFR Part Failure of Small Lines source term whose April 1996 100 Carrying Primary failure of small lines Coolant Outside carrying primary Containment coolant outside 6.4 GDC-19 Notes 1, containment result Draft Rev. 3 2, 3, 28, in fuel failure April 1996 29*Radiological PWR EPUs that do SPSB SRXB 15.6.3 10 CFR Part Notes 4, 2.9.6 NIA for BWRs Consequences of not utilize Draft Rev. 3 100 13, 14, Steam Generator Tube alternative source April 1996 .15, 27*Failure term whose steam generator tube 6.4 GDC-19 Notes 1, failure results in fuel Draft Rev. 3 2, 3, 28, failure April 1996 29*-2-MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary :Secondary SRP Section Focus of SRP 'Other':.'

ýTemplate Safety Cross Refdeence to Review Review Number Usage Guidance' Evaluation Section Branch 'Brafnch(es)-

7- ~fbr--BWR PWR'I ~P0AR CLTR PA Radiological BWR EPUs that do SPSB SRXB 15.6.4 10 CFR Part Note 27* 2.9.4 N/A for SSES Consequences of Main not utilize Draft Rev. 3 100 Steamline Failure alternative source April 1996 Outside Containment for term whose main a BWR steam line failure 6.4 GDC-19 Notes 1, outside containment Draft Rev. 3 2, 3, 28, results in fuel failure April 1996 29*Radiological EPUs that do not SPSB SPLB 15.6.5, App. 10 CFR Part Notes 41 2.9.5 2.9.7 N/A for SSES Consequences of a utilize alternative A 100 23,24, Design Basis Loss-Of- source term Draft Rev. 2 25, 26, Coolant-Accident April 1996 27*Including Containment Leakage Contribution 6.4 GDC-19 Notes 1, Draft Rev. 3 2, 3, 28, April 1996 29 Radiological EPUs that do not SPSB SPLB 15.6.5, App. 10 CFR Part Notes 11, 2.9.5 2.9.7 N/A for SSES Consequences of a utilize alternative B 100 27*Design Basis Loss-Of- source term Draft Rev. 2 Coolant-Accident:

April 1996 Leakage from ESF Components Outside 6.4 GDC-19 Notes 1, Containment Draft Rev. 3 2,3,28, April 1996 29*Radiological BWR EPUs that do SPSB 15.6.5, App. 10 CFR Part Notes 9, 2.9.5 N/A for SSES Consequences of a not utilize D 100 12, 27*Design Basis Loss-Of- alternative source Draft Rev. 2 Coolant-Accident:

term April 1996 Leakage from Main Steam Isolation Valves 6.4 GDC-19 Notes 1, Draft Rev. 3 2, 3, 28, April 1996 29*-3-MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Areas of Review Applicable to Primary Secondary SRP Section Focus of SRP Other Template Safety Cross Reference to Review Review Number Usage Guidance Evaluation Section Branch Branch(es)

Number BWR PWR, USAR CLTR FSAR Radiological EPUs that do not SPSB SPLB 15.7.4 10 CFR Part Notes 4, 2.9.6 2.9.8 N/A for SSES Consequences of Fuel utilize altemative Draft Rev. 2 100 5, 18, 19, Handling Accidents source term April 1996 GDC-61 20, 27-6.4 GDC-19 Notes 1, Draft Rev. 3 2, 3, 28, April 1996 29*Radiological EPUs that do not SPSB EMEB 15.7.5 10 CFR Part Notes, 5, 2.9.7 2.9.9 N/A for SSES Consequences of Spent utilize alternative SPLB Draft Rev. 3 100 16, 17, 8, Fuel Cask Drop source term April 1996 GDC-61 18, 27*Accidents 6.4 GDC-19 Notes 1, Draft Rev. 3 2, 3, 28, April 1996 29*-4-MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 Notes: 1. In addition to SRP Section 15.6.5, Appendices A, B, and D, dose consequences in the control room are determined from design-basis accidents as part of the review for SRP Sections 15.0.1; 15.1.5, Appendix A; 15.3.3-4, 15.4.8, Appendix A; 15.4.9, Appendix A; 15.6.2, 15.6.3, 15.6.4, 15.7.4, and 15.7.5.2. Regulatory Guide 1.95 was canceled.

Relevant guidance from Regulatory Guide 1.95 was incorporated into Regulatory Guide 1.78, Revision 1 in January 2002. Therefore, Regulatory Guide 1.95 should not be used.3. Table 6.4-1, attached to SRP Section 6.4 and referred to in Item 7, 'Independent Analyses," of the "Review Procedures" Section of SRP Section 6.4 may not be used.4. Acceptable dose conversion factors may be taken from Table 2.1 of Federal Guidance Report 11, *Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion," Environmental Protection Agency, 1988; and Table 111.1 of Federal Guidance Report 12, =Extemal Exposure to Radionuclides in Air, Water, and Soil," Environmental Protection Agency, 1993.5. NUREG-1465 should not be used.6. For the review of the main steamline failure accident, review of facilities licensed with, or applying for, alternative repair criteria (ARC) should use SRP Section 15.1.5, Appendix A, in conjunction with the guidance in Draft Regulatory Guide DG-1 074, "Steam Generator Tube Integrity," December 1998, for acceptable assumptions and methodologies for performing radiological analyses.7. For facilities that implement ARC, the primary-to-secondary leak rate in the faulted generator should be assumed to be the maximum accident-induced leakage derived from the repair criteria and burst correlations.

The leak rate limiting condition for operation specified in the technical specifications is equally apportioned among the unaffected steam generators.

8. Guidance for the radiological consequences analyses review with respect to acceptable modeling of the radioactivity transport is given in SRP Section 15.6.3, "Radiological Consequences of Steam Generator Tube Failure (PWR)," for applicants that use the traditional source term, based on TID-14844.

9. References to specific computer codes (e.g., SARA, TACT, Pipe Model) are not necessary since other computer codes/methods may be used.10. In the second paragraph of Section III, "Review Procedure," it is stated that the control rod drop accident is expected to result in radiological consequences less than 10 percent of the 10 CFR Part 100 guideline values, even with conservative assumptions.

The value of 10 percent should be replaced with 25 percent.11. In Section Ill, 'Review Procedures,*

the guidance in the fourth paragraph, which deals with passive failures, should not be used.12. The last paragraph on page 15.6.5-4 refers to a "code" developed by J. E. Cline and Associates, Inc. This is identified as Reference 5 in the paragraph.

The word "code" should be changed to "model" because the staff does not have the computer code. In addition, the correct reference to the work by J. E. Cline and Associates, Inc., is 4.13. Item 4 of the "Review Interfaces" section should be deleted. SPSB review of the steam generator.tube rupture accidents for their contribution to plant risk is not currently used in the design-basis accident review for radiological consequences.

14. The reference to Figure3.4-1 of the Nuclear Steam Supply System vendor Standard Technical Specification in Item 6.(a) of Section Il1, "Review Procedures," does not apply. In addition, the primary coolant iodine concentration discussed in this Item is the 48-hour maximum value.15. In Item 6.(b) of Section III, "Review Procedures," the multiplier of 500 used for estimating the increase in iodine release rate is reduced to 335 as a result of the staffs review of iodine release rate data collected by Adams and Atwood.MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003

16. The reference to SRP Section 9.1.4 in Item 2.c of the "Review Interfaces" section should be changed to SRP Section 9.1.5.17. The reference to Regulatory Guide 1.25, which was deleted in 1996, should be retained, with exceptions as noted below in Note 18.18. The following exceptions to Regulatory Guide 1.25 are provided.

These exceptions are based on the staffs review of NUREGICR-6703.

The fraction of the core inventory assumed to be in the gap for the various nuclides are given in the table below. The release fractions from the table are used in conjunction with the calculated fission product inventory and the maximum core radial peaking factor. These release fractions have been determined to be acceptable for use with currently approved LWR fuel with a peak burnup up to 62,000 MWD/MTU, provided that the maximum linear heat generation rate will not exceed 6.3 kW/ft peak rod average power for rods with burnups that exceed 54 GWD/MTU. As an alternative, fission gas release calculations using NRC-approved methodologies may be considered on a case-by-case basis.NON-.OCA FRACTION OF FISSION PRODUCT INVENTORY IN GAP I GROUP FRACTION 1-131 0.08 Kr-85 0.10 Other Noble Gases 0.05 Other lodines 0.05 19. References to the Standard Technical Specifications should be replaced with references to the plant-specific technical specifications or technical requirements manual (TRM).20. Technical Specification Task Force (TSTF) Traveler TSTF-51 proposed to add the term "recently," as it applies to irradiated fuel, to the applicability section of certain technical specifications.

The proposed change is intended to remove certain technical specifications requirements for operability of ESF systems (e.g., secondary containment isolation and filtration systems) during refueling.

The associated technical specifications bases define "recently," as it applies to irradiated fuel, as the minimum decay time used in supporting radiological consequences analyses of fuel handling accidents.

Radiological consequences analyses for these applicants should generally assume a 2-hour release directly to the environment, without holdup or mitigation by ESF systems and no credit for containment closure. Additionally, licensees adding the term "recently" must make a commitment for a single normal or contingency method to promptly close primary or secondary containment penetrations.

Such prompt methods need not completely block the penetration or be capable of resisting pressure.

The review of this commitment and the prompt methods should be coordinated with IORB, SPLB, and IEPB.21. In the last sentence of Item 2 of the "Review Interfaces" section, the reference to the number of fuel pins experiencing departure from nucleate boiling (DNB) should.be deleted. The reference to fuel clad melting should be used and is therefore retained.22. In Item 2 of the "Review Procedures" section, the references to the "number of fuel pins reaching DNB" should be deleted and replaced with "the number of fuel pins with cladding failure." In addition, the use of a conservative value of 10 percent for fuel cladding failure in the calculation of the radiological consequences of the rod ejection accident is acceptable.

23. In Item 1 of the "Areas of Review" section, the use of the word "established" is incorrect.

The word "established" should be replaced with the word "assessed.".24. In Item 1 of the "Acceptance Criteria" section, the following text in the last line should be deleted: "3.0 Sv (300 rem) to the thyroid and 0.25 Sv (25 rem) to the whole body." MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003

25. In Item 1 of the "Review Procedures" section, the following should be added after the first sentence: Appendix K to 10 CFR Part 50 defines conservative analysis assumptions for evaluation of ECCS performance during design-basis LOCAs. Appendix K requires the licensees to assume that the reactor has been operating continuously at a power level at least 1.02 times the licensed power level to allow for instrumentation error. Appendix K allows for an assumed power level less than 1.02 times the licensed power level but not less than the licensed power level, provided the alternative value has been demonstrated to account for uncertainties due to power level instrumentation error.26. In Item 2 of the "Review Procedures" section, the following statements should be deleted: "A check is made of the LOCA [loss-of-coolant accident]

assumptions listed in Chapter 15 of the SAR to verify that the primary containment leakage rate has been assumed to remain constant over the course of the accident for a BWR and to remain constant at one half of the initial leak rate after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for a PWR.""The leakage rate used should correspond to that given in the technical specification." The above statements should be replaced with the following: "A check is made of the LOCA assumptions listed in Chapter 15 of the SAR to verify acceptable primary containment leakage assumptions.

The primary containment should be assumed to leak at the peak pressure technical specification leak rate for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. For PWRs, the leakage'rate may be reduced after the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 50 percent of the TS leak rate. For BWRs, leakage may be reduced after the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, if supported by plant configuration and analyses, to a value not less than 50 percent of the TS leak rate. Leakage from subatmospheric containments is assumed to terminate when the containment is brought to and maintained at a subatmospheric condition, as defined by the TSs." 27. The staff has drafted updated guidance on performing design-basis radiological analyses in draft Regulatory Guide DG-1 113, "Methods and Assumptions for Evaluating Radiological Consequences of Design Basis Accidents at Light-Water Nuclear Power Reactors," issued for public comment January 2002. The resulting final regulatory guide may be used for guidance on review of design-basis accident non-alternative source term radiological analyses after the date of issuance of the final regulatory guide.28. In Section II, "Acceptance Criteria," the discussion for Item C related to GDC-19 should be supplemented with"and providing a suitably controlled environment for the control room operators and the equipment located therein." 29. In Section II, Item 2, "Ventilation System Criteria," the discussion related to review of the control room area ventilation system under SRP Section 9.4.1 should be retained.Susquehanna Notes -Matrix 9: S-1 The radiological consequence analyses using the Alternate Source Term (AST) have been previously evaluated for SSES EPU conditions in a separate License Amendment Request PLA-5963 dated October 13, 2005. This submittal proposed a full-scope implementation of an AST, which complies with the guidance given in R.G. 1.183 and SRP 15.01.-7" -MATRIX 9 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 10 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Health Physics Areas of Review Applicable to Primary Review Branch Secondarf y Review Branch(es Radiation Sources All EPUs IEPB Radiation Protection All EPUs IEPB Design Features Operational Radiation All EPUs IEPB Protection Program SSRP-Section Number 12.2 Draft Rev.3 April 1996 12.3-4 Draft Rev.3 April 1996 Focus of SRP Oý.other&-

Template Usage Guidance 'Evaluatioh-Section" Number, 10 CFR Part 20 10 CFR Part 20 GDC-19 BW PR PIUSAR', CLTRý FSAR 2.10.1 2.10.1 8.3, 8.3, 12.2 8.4 8.4 Cross Reference to Note 1*2.10.1 2.10.1 8.5, 8.6 8.5, 8.6 12.3, 12.4 12.5 10 CFR Part 20 Note 2* 2.10.1 2.10.1 8.5 8.5 12.5 Draft Rev. Note 3*3 April 1996 Notes: 1. Regulatory Guide 8.12, "Criticality Accident Alarm Systems" has been withdrawn and should not be used.2. Regulatory Guide 8.3, "Film Badge Performance Criteria" has been withdrawn and should not be used.3. Regulatory Guide 8.14, "Personnel Neutron Dosimeters" has been withdrawn and should not be used.-1-MATRIX 10 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 11 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Human Performance Areas of Review Applicable to Primary Review..Branch.Secondary Review Branch(es)

Reactor Operator All EPUs IROB Training Training for Non- All EPUs IROB Licensed Plant Staff Operating and All EPUs IROB Emergency Operating Procedures Human Factors All EPUs IROB Engineering I SRP Section Number 13.2.1" Draft Rev.2 Dec. 2002 ft13.2.2 Draft Rev.2 Dec. 2002 13.5.2.1*Draft Rev.1 Dec. 2002 18.0"*Draft Rev.0 April 1996 Fous bf SRP-7 7 thri Temip ate Safety: Usage,,-,"., Guidance. .EvaluationSection.

--Number: ,-.,:Cross Reference to-77 Specific review questions are provided in the template safety evaluations.

Specific review questions are provided in the template safety evaluations.

Specific review questions are provided in the template safety evaluations.

Specific review questions are provided in the template safety evaluations.

BWR .PWRý::- PUSAR -CLTR-- FSAR 2.11 2.11 10.6 10.6 13.2.1 2.11 2.11 10.6 10.6 13.2.1 2.11 2.11 10.9 10.9 13.5.2.1 2.11 2.11 10.6 10.9 7.5 SPLB SPSB SRXB*The staff is currently finalizing SRP Sections 13.2.1, 13.2.2, and 13.5.2.1.

While these SRP Sections are being finalized, the staff will continue to use the versions issued in December 2002 for interim use and public comment. Once finalized, the staff will use the new versions of these SRP Sections.**The staff received significant comment on draft SRP Chapter 18.0 that was issued in December 2002 for interim use and public comment. The staff is working on finalizing this SRP.However, due to the significance of the comments received, the staff will use Draft SRP Chapter 18.0, Revision 0, dated April 1996.-1-MATRIX 11 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 12 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Power Ascension and Testing Plan Areas of Review Applicable to Primary* Review Branch Secondary Review=Branch(es)

ýSRP Section":".

Number.-Focus of SRP-ý:; -Other-:.asge -Gdidafic&

I Template Safety-EValuation Section--Number'Cross Reference to Power Ascension and All EPUs IEPB EEIB 14.2.1" Entire Section Testing EMCB Draft Rev.EMEB 0 IROB Dec. 2002 SPLB SPSB SRXB-BWR -PWR PUSAR: -CLTR FSAR 2.12 2.12 10.4 10.4 14.3, 14.4*The staff is currently finalizing SRP Section 14.2.1. While this SRP Section is being finalized, the staff will continue to use the version issued for interim use and public comment in December 2002. Once finalized, the staff will use the new version.-1-MATRIX 12 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 MATRIX 13 SCOPE AND ASSOCIATED TECHNICAL REVIEW GUIDANCE Risk Evaluation I I Areas of Review Applicable to Primary Review Branch Secondary-

-'-'SRP -Review -Section Branch(es)

Number.Focus of SRP- Other!,--Usage Guidance-Template Safety-:: Evaluation Section Number Cross Reference to.SBWR: PWR: PUSAR CLTR, FSAR Risk Evaluation All EPUs SPSB Note 1" 2.13 2.13 10.5 10.5 RG 1.174 RIS 2001-02 Notes: 1. The staffs review is based on Attachmentl ito this matrix. Attachment 1 invokes SRP Chapter 19, Appendix D, if special circumstances are identified during the review.-1-MATRIX 13 OF SECTION 2.1 OF RS-001, REVISION 0 DECEMBER 2003 IL?

Attachment 13 to PLA-6076 RS-001 Safety Evaluation Template

2.1 Materials

and Chemical Engineering

2.1.1 Reactor

Vessel Material Surveillance Propram Regulatory Evaluation The reactor vessel material surveillance program provides a means for determining and monitoring the fracture toughness of the reactor vessel beltline materials to support analyses for ensuring the structural integrity of the ferritic components of the reactor vessel. The NRC staff's review primarily focused on the effects of the proposed EPU on the licensee's reactor vessel surveillance capsule withdrawal schedule.

The NRC's acceptance criteria are based on (1) General Design Criterion (GDC)-l 4, insofar as it requires that the reactor coolant pressure boundary (RCPB) be designed, fabricated, erected, and tested so as to have an extremely low probability of rapidly propagating fracture; (2) GDC-3 1, insofar as it requires that the RCPB be designed with margin sufficient to assure that, under specified conditions, it will behave in a nonbrittle manner and the probability of a rapidly propagating fracture is minimized; (3) 10 CFR Part 50, Appendix H, which provides for monitoring changes in the fracture toughness properties of materials in the reactor vessel beltline region; and (4) 10 CFR 50.60, which requires compliance with the requirements of 10 CFR Part 50, Appendix H.Specific review criteria are contained in Standard Review Plan (SRP) Section 5.3.1 and other guidance provided in Matrix I of RS-001.NOTE: In accordance with the provisions of 10CFR50.90, PPL Susquehanna, LLC submitted a request for amendment to Technical Specification 3.5.10 "RCS Pressure And Temperature (P/T) Limits" for the Susquehanna SES Units 1 & 2 in October of 2005 (reference)

PLA-5933, PPL Letter to NRC. "Proposed Amendment No. 280 To Unit I Facility Operating License NPF-14 And Proposed Amendment No. 249 To Unit 2 Facility Operating License NPF-22: Revise Technical Specification 3.4.10 "RCS Pressure And Temperature (P/T) Limits", McKinny, Britt T. To U.S. Nuclear Regulatory Commission, 10/5/2005.

The Pressure/Temperature curves presented in that submittal account for the CPPU operating conditions up to 3952 MWth.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's evaluation of the effects of the proposed EPU on the reactor vessel surveillance withdrawal schedule and concludes that the licensee has adequately addressed changes.in neutron fluence and their effects on the schedule.

The NRC staff further concludes that the reactor vessel capsule withdrawal schedule is appropriate to ensure that the material surveillance program will continue to meet the requirements of 10 CFR Part 50, Appendix H, and 10 CFR 50.60, and will provide the licensee with information to ensure continued compliance with GDC-14 and GDC-31 in this respect following implementation of the proposed EPU. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the reactor vessel material surveillance program.INSERT 1 FOR SECTION 3.2 : BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003 2.1.2 Pressure-Temperature Limits and Upper-Shelf Enere, Regulatory Evaluation Pressure-temperature (P-T) limits are established to ensure the structural iniegrity of the ferritic components of the RCPB during any condition of normal operation, including anticipated operational occurrences and hydrostatic tests. The NRC staff's review of P-T limits covered the P-T limits methodology and the calculations for the number of effective full power years specified for the proposed EPU, considering neutron embrittlement effects and using linear elastic fracture mechanics.

The NRC's acceptance criteria for P-T limits are based on (1) GDC-14, insofar as it requires that the RCPB be designed, fabricated, erected, and tested so as to have an extremely low probability of rapidly propagating fracture; (2) GDC-3 1, insofar as it requires that the RCPB be designed with margin sufficient to assure that, under specified conditions, it will behave in a nonbrittle manner and the probability of a rapidly propagating fracture is minimized; (3) 10 CFR Part 50, Appendix G, which specifies fracture toughness requirements for ferritic components of the RCPB; and (4) 10 CFR 50.60, which requires compliance with the requirements of 10 CFR Part 50, Appendix G. Specific review criteria are contained in SRP Section 5.3.2 and other guidance provided in Matrix I of RS-001.NOTE: In accordance with the provisions of I OCFR50.90, PPL Susquehanna, LLC submitted a request for amendment to Technical Specification 3.5.10 "RCS Pressure And Temperature (P/T) Limits" for the Susquehanna SES Units I & 2 in October of 2005 (reference)

PLA-5933, PPL Letter to NRC, "Proposed Amendment No. 280 To Unit I Facility Operating License NPF-14 And Proposed Amendment No. 249 To Unit 2 Facility Operating License NPF-22: Revise Technical Specification 3.4.10 "RCS Pressure And Temperature (P/T) Limits", McKinnv, Britt T. To U.S. Nuclear Regulatory Commission, 10/5/2005.

The Pressure/Temperature curves presented in that submittal account for the CPPU operating conditions up to 3952 MWth.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's evaluation of the effects of the proposed EPU on the P-T limits for the plant and concludes that the licensee has adequately addressed changes in neutron fluence and their effects on the P-T limits. The NRC staff further concludes that the licensee has demonstrated the validity of the proposed P-T limits for operation under the proposed EPU conditions.

Based on this, the NRC staff concludes that the proposed P-T limits will continue to meet the requirements of 10 CFR Part 50, Appendix G, and 10 CFR 50.60 and will enable the licensee to comply with GDC-14 and GDC-31 in this respect following implementation of the proposed EPU. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the proposed P-T limits.INSERT I FOR SECTION 3.2- BWR TEM PLATE SAFETY EVALUATION DECEMBER 2003

2.1.5 Protective

Coating Systems (Paints) -Organic Materials Regulatory Evaluation Protective coating systems (paints) provide a means for protecting the surfaces of facilities and equipment from corrosion and contamination from radionuclides and also provide wear protection during plant operation and maintenance activities.

The NRC staff's review covered protective coating systems used inside the containment for their suitability for and stability under design-basis loss-of-coolant accident (DBLOCA) conditions, considering radiation and chemical effects. The NRC's acceptance criteria for protective coating systems are based on (1) 10 CFR Part 50, Appendix B, which states quality assurance requirements for the design, fabrication, and construction of safety-related SSCs and (2) Regulatory Guide 1.54, Revision 1, for guidance on application and performance monitoring of coatings in nuclear power plants. Specific review criteria are contained in SRP Section 6.1.2.Note that, as described in Section 3.13 of the SSES Final Safety Analysis Renort (FSAR), for NSSS Systems. the provisions of Reg. Guide 1.54 are not imposed due to the relatively small amount of exposed surface area.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's evaluation of the effects of the proposed EPU on protective coating systems and concludes that the licensee has appropriately addressed the impact of changes in conditions following a DBLOCA and their effects on the protective coatings.

The NRC staff further concludes that the licensee has demonstrated that the protective coatings will continue to be acceptable following implementation of the proposed EPU and will continue to meet the requirements of 10 CFR Part 50, Appendix B. Therefore, the NRC staff finds the proposed EPU acceptable with respect to protective coatings systems.INSERT I FOR SECTION 3.2- BWR TEMPLATE SAFETY EVALUATION

.DECEMBER2003 2.5.1.1.3 Circulating Water System Regulatory Evaluation The circulating water system (CWS) provides a continuous supply of cooling water to the main condenser to remove the heat rejected by the turbine cycle and auxiliary systems. The NRC staff's review of the CWS focused on changes in flooding analyses that are necessary due to increases in fluid volumes or installation of larger capacity pumps or piping needed to accommodate the proposed EPU. The NRC's acceptance criteria for the CWS are based on GDC-4 for the effects of flooding of safety-related areas due to leakage from the CWS and the effects of malfunction or failure of a component or piping of the CWS on the functional performance capabilities of safety-related SSCs. Specific review criteria are contained in SRP Section 10.4.5. Since neither the CWS fluid volume nor flow rate increases at SSES due to the proposed EPU, the proposed EPU is acceptable with respect to the CWS. The licensee's floodine analysis is considered in SE sections 2.5.1.1.1 and 2.5.1.3.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's assessment of the modificaticns to the CWS and concludes that the licensee has adequately evaluated the systemthesc mediflcations. NRC staffn ...ludz th;t,..n.i.tent with t!b requirements ePGDG the inefeased

.lumes , ..... fid leakage that .ould p1tcntially result from these fnedifieaiiens would fle; r-esul ini ;be failtife of safeiy rolaloed 88G fellewintg implementation of !be prop,,ed EPU.. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the CWS.INSERT 5 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEM BER 2003 2.5.2.4 Main Steam Isolation Valve Leakage Control System Regulatory Evaluation Redundant quick-acting isolation valves are provided on each main steamline.

The leakage control system is designed to reduce the amount of direct, untreated leakage from the main steam isolation valves (MSIVs) when isolation of the primary system and containment is required.

The NRC staff's review of the MSIV leakage control system focused on the effects of the proposed EPU on the amount of leakage assumed to occur. The NRC's acceptance criteria for the MSIV leakage control system are based on GDC-54, insofar as it requires that piping systems penetrating containment be provided with leakage detection and isolation capabilities.

Specific review criteria are contained in SRP Section 6.7.NOTE: The MSIV Leakage Control System has been deleted from the SSES Design Bases.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's assessment related to the MSIV leakage control system and finds that the licensee has adequately accounted for the effects of the proposed EPU on the assumed leakage through the MSIVs. The NRC staff further concludes that the leakage control system will continue to reliably detect and isolate the leakage, as required by GDC-54. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the MSIV leakage control system.INSERTS FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003 2.5.4.2 Main Condenser Regulatory Evaluation The main condenser (MC) system is designed to condense and deaerate the exhaust steam from the main turbine and provide a heat sink for the turbine bypass system (TBS). For BWRs without an MSIV leakage control system, the MC system may also serve an accident mitigation function to act as a holdup volume for the plateout of fission products leaking through the MSIVs following core damage (the MSIV leakage control system at SSES has been eliminated).

The NRC staff's review focused on the effects of the proposed EPU on the steam bypass capability with respect to load rejection assumptions, and on the ability of the MC system to withstand the blowdown effects of steam from the TBS. The NRC's acceptance criteria for the MC system are based on GDC-60, insofar as it requires that the plant design include means to control the release of radioactive effluents.

Specific review criteria are contained in SRP Section 10.4.1.Technical Evaluation lInsert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's assessment of the effects of the proposed EPU on the MC system and concludes that the licensee has adequately accounted for the effects of changes in plant conditions on the design of the MC system. The NRC staff concludes that the MC system will continue to maintain its ability to withstand the blowdown effects of the steam from the TBS and thereby continue to meet GDC-60 with respect to controlling releases of radioactive effluents.

Therefore, the NRC staff finds the proposed EPU acceptable with respect to the MC system.INSERT 5 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003

2.6.5 Containment

Heat Removal Regulatory Evaluation Fan cooler systems, spray systems, and residual heat removal (RHR) systems are provided to remove heat from the containment atmosphere and from the water in the containment wetwell. The NRC staff's review in this area focused on (1) the effects of the proposed EPU on the analyses of the available net positive suction head (NPSH) to the containment heat removal system pumps and (2) the analyses of the heat removal capabilities of the spray water system and the fan cooler heat exchangers.

The NRC's acceptance criteria for containment heat removal are based on GDC-38, insofar as it requires that a containment heat removal system be provided, and that its function shall be to rapidly reduce the containment pressure and temperature following a LOCA and maintain them at acceptably low levels.Specific review criteria are contained in SRP Section 6.2.2, as supplemented by Draft Guide (DG) 1107.NOTE: SSES does not have safety-related containment for cooling systems, and the spray systems are not safety-related as described in the Section 6.2 of the Final Safety Analysis Report (FSAR).Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the containment heat removal systems assessment provided by the licensee and concludes that the licensee has adequately addressed the effects of the proposed EPU. The NRC staff finds that the systems will continue to meet GDC-38 with respect to rapidly reducing the containment pressure and temperature following a LOCA and maintaining them at acceptably low levels. Therefore, the NRC staff finds the proposed EPU acceptable with respect to containment heat removal systems.INSERT 6 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003

2.6.6 Secondary

Containment Functional Design Regulatory Evaluation The secondary containment structure and supporting systems of dual containment plants are provided to collect and process radioactive material that may leak from the primary containment following an accident.

The supporting systems maintain a negative pressure within the secondary containment and process this leakage. The NRC staff's review covered (1) analyses of the pressure and temperature response of the secondary containment following accidents within the primary and secondary containments; (2) analyses of the effects of openings in the secondary containment on the capability of the depressurization and filtration system to establish a negative pressure in a prescribed time; (3) analyses of any primary containment leakage paths that bypass the secondary containment; h przzzurz r-espense of the seeendary eentainment resulting fromF inadvzretznt deprzzzurizatien of the primar ... n..inment when !here is vacuum relief fr.m the scc.ndarY centainmznt (not applicable to SSES because the SSES design does not include secondary to primary containment vacuum breakers);

and (5) the acceptability of the mass and energy release data used in the analysis.

The NRC staff's review primarily focused on the effects that the proposed EPU may have on the pressure and temperature response and drawdown time of the secondary containment, and the impact this may have on offsite dose.The NRC's acceptance criteria for secondary containment functional design are based on (1) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate the effects of environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, and be protected from dynamic effects (e.g., the effects of missiles, pipe whipping, and discharging fluids) that may result from equipment failures; and (2) GDC-I 6, insofar as it requires that reactor containment and associated systems be provided to establish an essentially leak-tight barrier against the uncontrolled release of radioactivity to the environment.

Specific review criteria are contained in SRP Section 6.2.3.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.)Conclusion The NRC staff has reviewed the licensee's assessment related to the secondary containment pressure and temperature transient and the ability of the secondary containment to provide an essentially leak-tight barrier against uncontrolled release of radioactivity to the environment.

The NRC staff concludes that the licensee has adequately accounted for the increase of mass and energy that would result from the proposed EPU and further concludes that the secondary containment and associated systemswill continue to provide an essentially leak-tight barrier against the uncontrolled release of radioactivity to the environment following implementation of the proposed EPU. Based on this, the NRC staff also concludes that the secondary containment and associated systems will continue to meet the requirements of GDCs 4 and 16. Therefore, the NRC staff finds the proposed EPU acceptable with respect to secondary containment functional design.INSERT 6 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003 2.7 Habitability, Filtration, and Ventilation

2.7.1 Control

Room Habitability System Regulatory Evaluation The NRC staff reviewed the control room habitability system and control building layout and structures to ensure that plant operators are adequately protected from the effects of accidental releases of toxic and radioactive gases. A further objective of the NRC staff's review was to ensure that the control room can be maintained as the backup center from which technical support center personnel can safely operate in the case of an accident.

The NRC staff's review focused on the effects of the proposed EPU on radiation doses, toxic gas concentrations, and estimates of dispersion of airborne contamination.

The NRC's acceptance criteria for the control room habitability system are based on (1) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate the effects of and to be compatible with the environmental conditions associated with postulated accidents, including the effects of the release of toxic gases; and (2) GDC- 19, insofar as it requires that adequate radiation protection be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem TEDEw..l.

bedy, or quiveent, t, an), part .f .th, d , for the duration of the accident.

Specific review criteria are contained in SRP Section 6.4 and other guidance provided in Matrix 7 ofRS-001.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.1 Conclusion The NRC staff has reviewed the licensee's assessment related to the effects of the proposed EPU on the ability of the control room habitability system to protect plant operators against the effects of accidental releases of toxic and radioactive gases. The NRC staff concludes that the licensee has adequately accounted for the increase of toxic and radioactive gases that would result from the proposed EPU. The NRC staff further concludes that the control room habitability system will continue to provide the required protection following implementation of the proposed EPU. Based on this, the NRC staff concludes that the control room habitability system will continue to meet the requirements of GDCs 4 and 19. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the control room habitability system.INSERT 7 FOR SECTION 3.2 -BVR TEMPLATE SAFETY EVALUATION DECEM BER 2003

2.7.2 Engineered

Safety Feature Atmosphere Cleanup Repulatory Evaluation ESF atmosphere cleanup systems are designed for fission product removal in postaccident environments.

These systems generally include primary systems (e.g., in-containment recirculation) and secondary systems (e.g., standby gas treatment systems and emergency or postaccident air-cleaning systems) for the fuel-handling building, control room, shield building, and areas containing ESF components.

For each ESF atmosphere cleanup system, the NRC staff's review focused on the effects of the proposed EPU on system functional design, environmental design, and provisions to preclude temperatures in the adsorber section from exceeding design limits. The NRC's acceptance criteria for ESF atmosphere cleanup systems are based on (1) GDC-19, insofar as it requires that adequate radiation protection be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem TEDEwhol e b.dy, or its equiv'alent, to any part of the b.dy, for the duration of the accident; (2) GDC-41, insofar as it requires that systems to control fission products released into the reactor containment be provided to reduce the concentration and quality of fission products released to the environment following postulated accidents; (3) GDC-61, insofar as it requires that systems that may contain radioactivity be designed to assure adequate safety under normal and postulated accident conditions; and (4) GDC-64, insofar as it requires that means be provided for monitoring effluent discharge paths and the plant environs for radioactivity that may be released from normal operations, including anticipated operational occurrences (AOOs), and postulated accidents.

Specific review criteria are contained in SRP Section 6.5.1.Technical Evaluation

[Insert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's assessment of the effects of the proposed EPU on the ESF atmosphere cleanup systems. The NRC staff concludes that the licensee has adequately accounted for the increase of fission products and changes in expected environmental conditions that would result from the proposed EPU, and the NRC staff further concludes that the ESF atmosphere cleanup systems will continue to provide adequate fission product removal in postaccident environments following implementation of the proposed EPU. Based on this, the NRC staff concludes that the ESF atmosphere cleanup systems will continue to meet the requirements of GDCs 19, 41, 61, and 64. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the ESF atmosphere cleanup systems.INSERT 7 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003

2.7.3 Control

Room Area Ventilation System Regulatory Evaluation The function of the control room area ventilation system (CRAVS) is to provide a controlled environment for the comfort and safety of control room personnel and to support the operability of control room components during normal operation, AOOs, and DBA conditions.

The NRC's review of the CRAVS focused on the effects that the proposed EPU will have on the functional performance of safety-related portions of the system. The review included the effects of radiation, combustion, and other toxic products; and the expected environmental conditions in areas served by the CRAVS. The NRC's acceptance criteria for the CRAVS are based on (i) GDC-4, insofar as it requires that SSCs important to safety be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents; (2) GDC-I 9, insofar as it requires that adequate radiation protection be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures in excess of 5 rem TEDE vhelc bedy, or- its equiv"lent

t. an.y, pai , f 'he bad), for the duration of the accident; and (3)GDC-60, insofar as it requires that the plant design include means to control the release of radioactive effluents.

Specific review criteria are contained in SRP Section 9.4.1.Technical Evaluation llnsert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's assessment of the effects of the proposed EPU on the ability of the CRAVS to provide a controlled environment for the comfort and safety of control room personnel and to support the operability of control room components.

The NRC staff concludes that the licensee has adequately accounted for the increase of toxic and radioactive gases that would result from a DBA under the conditions of the proposed EPU, and associated changes to parameters affecting environmental conditions for control room personnel and equipment.

Accordingly, the NRC staff concludes that the CRAVS will continue to provide an acceptable control room environment for safe operation of the plant following implementation of the proposed EPU. The NRC staff also concludes that the system will continue to suitably control the release of gaseous radioactive effluents to the environment.

Based on this, the NRC staff concludes that the CRAVS will continue to meet the requirements of GDCs 4, 19, and 60. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the CRAVS.INSERT 7 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECENI BER 2003 2.8.4.5 Standby Liquid Control System Regulatory Evaluation The standby liquid control system (SLCS) provides backup capability for reactivity control independent of the control rod system. The SLCS functions by injecting a boron solution into the reactor to effect shutdown.

The NRC staff's review covered the effect of the proposed EPU on the functional capability of the system to deliver the required amount of boron solution into the reactor. The NRC's acceptance criteria are based on (1) GDC-26, insofar as it requires that two independent reactivity control systems of different design principles be provided, and that one of the systems be capable of holding the reactor subcritical in the cold condition; (2) GDC-27, insofar as it requires that the reactivity control systems have a combined capability, in conjunction with poison addition by the ECCS, to reliably control reactivity changes under postulated accident conditions; and (3) 10 CFR 50.62(c)(4), insofar as it requires that the SLCS be capable of reliably injecting a borated water solution into the reactor pressure vessel at a boron concentration, boron enrichment, and flow rate that provides a set level of reactivity control, and IDEPENDING ON CONSTRUCTION PERMIT DATE OR ORIGINAL DESIGNi that the system initiate automatically.

Specific review criteria are contained in SRP Section 9.3.5 and other guidance provided in Matrix 8 of RS-001.Note that the SSES SLCS System is manually initiated.

Technical Evaluation lInsert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]Conclusion The NRC staff has reviewed the licensee's analyses related to the effects of the proposed EPU on the SLCS and concludes that the licensee has adequately accounted for the effects of the proposed EPU on the system and demonstrated that the system will continue to provide the function of reactivity control independent of the control rod system following implementation of the proposed EPU. Based on this, the NRC staff concludes that the SLCS will continue to meet the requirements of GDCs 26 and 27, and 10 CFR 50.62(c)(4) following implementation of the proposed EPU. Therefore, the NRC staff finds the proposed EPU acceptable with respect to the SLCS.INSERT8 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION

.DECEMBER2003 2.8.5.7 Anticipated Transients Without Scrams Regulatory Evaluation ATWS is defined as an AOO followed by the failure of the reactor portion of the protection system specified in GDC-20. The regulation at 10 CFR 50.62 requires that:* each BWR have an ARI system that is designed to perform its function in a reliable manner and be independent (from the existing reactor trip system) from sensor output to the final actuation device.* each BWR have a standby liquid control system (SLCS) with the capability of injecting into the reactor vessel a borated water solution with reactivity control at least equivalent to the control obtained by injecting 86 gpm of a 13 weight-percent sodium pentaborate decahydrate solution at the natural boron- 10 isotope abundance into a 25 1-inch inside diameter reactor vessel. The system initiation must be automatic.

each BWR have equipment to trip the reactor coolant recirculation pumps automatically under conditions indicative of an ATWS.The NRC staff's review was conducted to ensure that (1) the above requirements are met, (2) sufficient margin is available in the setpoint for the SLCS pump discharge relief valve such that SLCS operability is not affected by the proposed EPU, and (3) operator actions specified in the plant's Emergency Operating Procedures are consistent with the generic emergency procedure guidelines/severe accident guidelines (EPGs/SAGs), insofar as they apply to the plant design. In addition, the NRC staff reviewed the licensee's ATWS analysis to ensure that (1) the peak vessel bottom pressure is less than the ASME Service Level C limit of 1500 psig; (2) the peak clad temperature is within the 10 CFR 50.46 limit of 2200 *F; (3) the peak suppression pool temperature is less than the design limit; and (4) the peak containment pressure is less than the containment design pressure.

The NRC staff also evaluated the potential for thermal-hydraulic instability in conjunction with ATWS events using the methods and criteria approved by the NRC staff. For this analysis, the NRC staff reviewed the limiting event determination, the sequence of events, the analytical model and its applicability, the values of parameters used in the analytical model, and the results of the analyses.

Insert the following sentence if the licensee relied upon generic vendor analyses IThe NRC staff reviewed the licensee's justification of the applicability of generic vendor analyses to its plant and the operating conditions for the proposed EPU.J Review guidance is provided in Matrix 8 ofRS-001.Note that the SSES SLCS System is manually initiated.

Technical Evaluation lInsert technical evaluation.

The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]INSERT 8 FOR SECTION 3.2 -BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003