ML081080034

Transcript of ACRS Power Uprates Subcommittee Meeting on March 20, 2008, Pages 1-199

ML081080034
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Site:	Hope Creek
Issue date:	03/20/2008
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NRC-2076
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. 1.A cF?,5 ~-z +43 Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION

Title:

Advisory Committee on Reactor Safeguards Subcommittee on Power Uprates OPEN SESSION Docket Number: (n/a) Process Using ADAMS Template ACRS/ACNW-005 SUNSI Review Complete Location: Rockville, Maryland MAR 3 12008 Date: Thursday, March 20, 2008 Work Order No.: NRC-2076 Pages 1-199 NEAL R. GROSS AND CO., INC.

Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.

Washington, D.C. 20005 (202) 234-4433 t1-oV M OFCEW

DISCLAIMER UNITED STATES NUCLEAR REGULATORY COMMISSION'S ADVISORY COMMITTEE ON REACTOR SAFEGUARDS March 20, 2008  : .

The contents of this transcript of the proceeding of the United "tesNucklear Regulatory Commission Advisory Committee on Reactor Safeguards, taken on March 20, 2008, as reported herein, is a record of the discussions recorded at the meeting held on the above date.

This transcript has not been reviewed, corrected and edited and it may contain inaccuracies.

1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 +++++

4 ADVISORY COMMITTEE ON REACTOR SAFEGUARD 5 (ACRS) 6 7 SUBCOMMITTEE ON POWER UPRATES 8

9 THURSDAY 10 MARCH 20, 2008 11 12 ROCKVILLE, MARYLAND 13 +++++

14 OPEN SESSION 15 +++++

16 The Subcommittee met in Open Session at 17 the Nuclear Regulatory Commission, Two White Flint 18 North, Room T2B3, 11545 Rockville Pike, at 8:30 a.m.,

19 Dr. Said Abdel-Khalik, Chairman, presiding.

20 SUBCOMMITTEE MEMBERS PRESENT:

21 SAID ABDEL-KHALIK, Chair 22 MARIO V. BONACA 23 SANJOY BANERJEE 24 J. SAM ARMIJO 25 OTTO L. MAYNARD NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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2 1 NRC STAFF PRESENT:

2 ZENA ABDULLAHI, Designated Federal Official 3 CATHERINE HANEY 4 JOHN G. LAMB 5 KAMISHAN MARTIN 6 TONY NAKANISHI 7 PETER YARSKY 8 MUHAMMAD RAZZAQUE 9 RICHARD LOBEL 10 ALSO PRESENT:

11 TOM JOYCE 12 PAUL DAVISON 13 BILL KOPCHICK 14 DON NOTIGAN 15 ED BURNS 16 PAUL LINDSAY 17 PAUL DUKE 18 FRAN BOLGER 19 TED DelGAIZO 20 SKIP DENNY 21 VINCENT ZABIELSKI 22 BRIAN MOORE 23 FRANCIS SAFIN 24 SHELLY KUGLER 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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3 1 TABLE OF CONTENTS 2 AGENDA ITEM/TOPIC: PAGE 3 Opening Remarks 4 4 Introduction 5 Catherine Haney 6 6 John Lamb 7 7 Hore Creek EPU - Overview 8 Tom Joyce, PSEG, Nuclear Senior 9 Vice President of Operations, 10 Salem and Hope Creek 13 11 Paul Davison, PSEG, Hope Creek Site 12 Engineering Director 16 13 Operations Training, Emergency Operating 14 Procedures, Operator Actions 41 15 Bill Kopchick, PSEG, Shift Operatiol 'IS 16 Superintendent, Hope Creek 17 Power Ascension and Testing 78 18 Bill Kopchick, PSEG, Shift Operatioi 'is 19 Superintendent, Hope Creek 20 Human Performance Timelines /

21 Kamishan Martin, NRR 96 22 Reactor Systems 106 23 Muhammad Razzaque, NRR 24 Tony Nakanishi, NRR 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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4 1 Containment Analysis Methodology 160 2 Paul Davison, Hope Creek Site 3 Engineering Director 4 Ted DelGaizo, Mainline Engineering 5 Mr. Skip Denny, GE-Hitachi 6 Containment Q and A by members 186 7 Flow Accelerated Corrosion and 8 Pressure Temperature Limit Curves 193 9 Paul Davison, PSEG, Hope Creek Site 10 Engineering Director 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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5 1 P-R-O-C-E-E-D-N-G-S 2 (8:30 a.m.)

3 CHAIR ABDEL-KHALIK: The meeting will now 4 come to order. This is the first day of a two-day 5 meeting of the Advisory Committee on Reactor 6 Safeguards Power Uprates Subcommittee. I'm Said 7 Abdel-Kahlik, Chairman of the Power Uprates 8 Subcommittee's review of the Oak Creek Generating 9 Station Extended Power Uprate Application.

10 Subcommittee members in attendance are 11 Mario Bonaca, Sam Armijo, Sanjoy Banerjee, Otto 12 Maynard. We also expect Michael Coradini to join us 13 later today. Also in attendance are ACRS consultants, 14 Graham Wallis and tom Kress. ACRS members Jack Sieber 15 and John Stetkar and ACRS consultant Alan Pierce are 16 expected to join us tomorrow.

17 The purpose of this two-day meeting is to 18 hear presentations by and hold discussions with the 19 Hope Creek licensee, PSEG, the NRC staff, their 20 consultants and other interested persons regarding the 21 proposed EPU. The subcommittee will gather 22 information, analyze relevant issues and facts and 23 formulate proposed positions and actions as 24 appropriate for deliberations by the ful committee.

25 Zena Abdullahai is the designated federal official for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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6 1 this meeting.

2 Parts of this meeting will be closed, 3 because the material to be presented is considered 4 proprietary by the Applicant, PSEG and/or its 5 contractors, General Electric-Hitachi and Continuum 6 Dynamics, Incorporated. The proposed times for the 7 closed sessions are identified in the agenda.

8 Attendees who are required to leave during the closed 9 sessions can call 301-415-7360 to obtain a status 10 report as to when they can rejoin the meeting.

11 1 We received a request for a teleconference 12 from Mr. Jerry Humphreys who represents the State of 13 New Jersey. A bridge telephone number was made 14 available. I understand that Mr. Humphreys has not 15 signed a proprietary agreement for General Electric-16 Hitachi and, therefore, cannot participate in today's 17 closed sessions involving GEH proprietary information.

18 However, having signed the relevant propriety 19 agreement with Continuum Dynamics, Incorporated, Mr.

20 Humphreys should be able to participate in tomorrow's 21 closed session, discussions of the steam dryer based 22 on CDT's analyses and methodologies. Please note that 23 the bridge connection is only for listening in.

24 A transcript of the meeting is being kept 25 and will be made available as stated in the Federal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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7 1 Register Notice. It is requested that speakers first 2 identify themselves and speak with sufficient clarity 3 and volume so that they can be readily heard. We will 4 now proceed with the meeting, and I call on Ms.

5 Catherine Haney of NRR to start the meeting.

6 MS. HANEY: Thank you. Good morning. I'm 7 the Director of the Division of Operator Reactor 8 Licensing in the office of Nuclear Reactor Regulation.

9 Over the next two days, you will hear the results of 10 a very thorough review by our staff of the application 11 submitted by Public Service Enterprise Group Nuclear, 12 Limited Liability Corporation, PSEG.

13 We had frequent communications with the 14 licensee over the last several months including calls, 15 conference calls, meetings, letters, etcetera. We 16 believe that this helped with our thorough review of 17 the application. In addition, there were several 18 rounds of requests for additional information that 19 were issued to the licensee. The RA~s were submitted 20 as they were developed allowing the licensee as much 21 time as possible to review and respond to our RAIs.

22 The input from the licensee was then reviewed by our 23 technical staff.

24 Some of the more challenging review areas 25 that you will hear about over the next two days are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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L8 1 the steam dryer stress analysis and the fuel and core 2 design analysis. As presented in the draft safety 3 evaluation without the steam dryer which was provided 4 to the ACRS on February 14th, 2008, and the steam 5 dryer safety evaluation input which was provided on 6 February 29th, 2008, there are currently no open 7 technical issues. This two-step process was something 8 that we used with the ACRS was unique. Typically, we 9 supply one safety evaluation report. However, to 10 allow sufficient extra time for ACRS to review the 11 application, we did reach an agreement about 12 submitting it in two stages, and we do appreciate your 13 willingness to take it that way.

14 I'm pleased with the thoroughness of the 15 review conducted by the NRC. The staff had extensive 16 interactions with PSEG on several of these diverse 17 issues, as I've mentioned. And at this point, I'd 18 like to turn the presentation over to my Project 19 Manager, John Lamb, and he'll introduce the 20 discussions for the day.

21 MR. LAMB: Good morning. My name is John 22 Lamb. I am a Senior Project Manager in the office of 23 Nuclear Reactor Regulation, NRR. I am the Project 24 Manager in the Division of Operating Reactor 25 Regulatory Licensing, DORL, assigned to the Hope Creek NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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9 1 Generating Station, Hope Creek Extended Power Uprate, 2 EPU.

3 As you know, we only gave you 19 days to 4 review the steam dryer information. The staff 5 realizes the significant this places on the ACRS 6 members. On behalf of the staff, I would like to take 7 this public opportunity to thank the ACRS for 8 accommodating our schedule and reviewing the steam 9 dryer portion on a short turnaround. The staff 10 greatly appreciates the ACRS members' effort in this 11 regard.

12 To quote the famous mathematician and 13 astronomer, Johannes Kepler, I prefer the sharpest 14 criticism of a single intelligent man to the 15 thoughtless approval of the masses. So this quote 16 brings to mind our purpose over the next two days is 17 to convince you that the staff's safety evaluation, 18 SE, for the Hope Creek EPU provides the following --

19 one, there is reasonable assurance that the health and 20 safety of the public will not be endangered by the 21 proposed EPU and two, the proposed EPU will be 22 conducted in compliance with the Commission's 23 regulations.

24 After two days of hearing presentations 25 from the staff and the licenseI, we hope that you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVEJ N.W.

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10 1 agree that this will -- agree with this and will 2 recommend to the ACRS full committee on April 10th, 3 2008 that the proposed EPU amendment be issued and 4 reflect this in your letter report.

5 fore I go over the agenda, I would like to 6 present some background information related to the 7 staff's review of the proposed Hope Creek EPU. Hope 8 Creek is a boiling water reactor, BWR. The proposed 9 EPU would increase the maximum authorized thermal 10 level from the current licensed thermal power level of 11 3,339 megawatts thermal to 3,840 megawatts thermal.

12 This represents an approximate 15% increase from the 13 current licensed thermal power.

14 Hope Creek was granted a measurement uncertainty 15 recapture, MUR, power uprate of 1.4% in Amendment 16 Number 131 dated July 30th, 2001. The MUR changes 17 were based on the installation of the CE Nuclear 18 Power, LLC cross-flow ultrasonic flow measurement 19 system and its ability to achieve increased accuracy 20 in measuring feedwater flow. This MUR increased the 21 power from the original licensed thermal power of 22 3,293 megawatts thermal to the current licensed 23 thermal power level of 3,339 megawatts thermal. The 24 ACRS did not review this MUR as is the custom with 25 MURs.

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11 1 on Jule 25th, 1996, the NRC licensed Hope 2 Creek for full power operation at 3,293 megawatts 3 thermal. As you know, Hope Creek would not be the 4 unit with the highest thermal power level if you 5 approve the issuance of the proposed EPU amendment.

6 The units with the highest thermal power in the 7 country are Palo Verde 1, 2 and 3, at 3,990 megawatts 8 thermal which are pressurized water reactors, PWRs.

9 PWR units with the highest thermal power as 10 Susquehanna 1 and 2 at 3,952 megawatts thermal. South 11 Texas Projects 1 and 2, which are PWRs, are rated at 12 3,853 megawatts thermal. So this proposed EPU would 13 make Hope Creek the eighth highest unit in the country 14 at a licensed thermal power level of 3,840 megawatts 15 thermal.

16 As far as the method of NRC review, the 17 staff's review for the PSEG application was based on 18 NRC's review standard for extended power uprates. The 19 review standard includes a safety evaluation template 20 as well as matrices that correspond to maintenance 21 areas that are to be reviewed by the staff as well as 22 specific guidance and acceptance criteria that applies 23 to those areas. The staff plans to issue the proposed 24 EPU amendment in the beginning of May 2008 provided 25 ACRS writes a letter report that states that the Hope NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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12 1 Creek EPU should issued.

2 PSEG plans to implement the proposed 15%

3 Hope Creek EPU in two steps. One, a proposed 11.5%

4 increase will occur in the first operating cycle 5 following Hope Creek EPU approval. Then two, the 6 licensee will implement the remaining 3.5 percent 7 proposed uprate during a subsequent operating cycle 8 following the proposed amendment of the -- the 9 approval of the amendment. You will hear more detail 10 about this in a little while from PSEG.

11 Basically, PSEG's application followed the 12 guidelines of a constant pressure power uprate of 13 General Electric's topical report. After I conclude 14 my remarks, PSEG will provide an overview on their 15 licensing approach as well as their modifications 16 required and their implementation schedule. Today, 17 you will hear a great deal of more detail on fuel 18 methods from the staff and PSEG in both open and 19 closed sessions. PSEG applied for an EPU amendment by 20 letter dated September 18th, 2006. There were 37 21 supplements. The majority of these dealt with the 22 steam dryer. The staff spent a great deal of time 23 reviewing the steam dryer information to make a 24 finding of reasonable assurance. So like any good 25 movie plot, we will save the most interesting steam NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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13 1 dryer information until the second day.

2 The majority of tomorrow will consist of 3 steam dryer discussions in both open and closed 4 sessions. I would summarize the agenda as the 5 following. The bulk of day one is devoted to fuel 6 methods and the bulk of day two is devoted to steam 7 dryer. As you can see from the agenda and the slides, 8 the remainder of the time is devoted to operations 9 training, human factors, power ascension and testing, 10 containment analyses, flow-accelerated corrosion, 11 probabilistic safety assessment, risk evaluation, 12 materials and chemical engineering, electrical and 13 grid reliability, INC and source terms and 14 radiological consequences.

15 So this concludes my presentation as far 16 as the introduction. I would like to turn it over to 17 Mr. Thomas P. Joyce, PSEG Senior Vice President, 18 operations for Salem/Hope Creek. This is a position 19 Mr. Joyce has held since June 2007. Mr. Joyce has 20 more than 32 years of experience in commercial nuclear 21 power operations. Prior to working at PSEG, Mr. Joyce 22 was site vice president at Exelon Is Braidwood Station.

23 Mr. Joyce holds a bachelor of science degree in 24 nuclear engineering from the University of Missouri 25 and a master of business administration degree from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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14 1 Keller Graduate School of Management. Here is Mr.

2 Joyce.

3 MR. JOYCE: Good morning. My name is Tom 4 Joyce. As John Lamb stated, I am PSEG's Nuclear 5 Senior Vice President of Operations for both Salem and 6 Hope Creek units. I am very pleased to come before 7 the ACRS Subcommittee today and have my team, along 8 with a number of industry experts, present information 9 to support our application for the extended power 10 uprate of the Hope Creek facility. I, along with the 11 Hope Creek management team, have been actively engaged 12 in advancing this important plant initiative.

13 I am confident that our robust effort has 14 been reflected in the application and that the 15 presentations today and tomorrow will confirm the NRC 16 staff's conclusions in the safety evaluation. I also 17 wanted to take this opportunity to extend my 18 appreciation to the NRC's NRR staff's professionalism 19 throughout this process. The NRC process was 20 challenging and resulted in the desirable outcome of 21 a strengthened product. The regulatory challenges 22 ultimately serve to enhance our effort and further the 23 mutual goal of meeting the standards of projection of 24 the public.

25 With respect to my and the team's approach NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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15 1 to this project, the focus is first and foremost on 2 safety, both nuclear as well as industrial. Without 3 this cornerstone, no other objectives can be 4 satisfied. As you will hear over the next two days, 5 this project has evaluated a comprehensive and 6 exhaustive list of technical issues, all of which have 7 been resolved or addressed with sufficient safety 8 margins.

9 We will continue to evaluate information 10 related to our power uprate and take conservative 11 actions if necessary. As an example, you will hear 12 bout our power ascension testing program which 13 formalizes the safety philosophy by establishing a 14 criteria for conservative actions based on plant 15 conditions and data. This is the approach we take 16 when running the plant and we take the regulatory 17 safety obligation to the public and ourselves with the 18 utmost seriousness. Simply put, it is the right thing 19 to do.

20 With respect to your questions, it is my 21 expectation that if the presenter does not know the 22 answer during the individual topic discussion, we will 23 get you a satisfactory answer before the close of the 24 session.

25 Turning to the agenda, today we will be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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16 1 covering an overview of the EPU project, power 2 ascension and operations, fuels topics, containment 3 analysis response, flow-accelerated corrosion and 4 pressure and temperature limits. And tomorrow we will 5 be covering steam dryer vessel internals PSA and grid 6 reliability.

7 Principle presenters will be Paul Davidson 8 who is the Engineering Director at Hope Creek, Bill 9 Kopchick from the Operations Department, Don Notigan 10 from our Fuels Department, Ed Burns from Air and 11 Engineering and the PRA, and during the closed session 12 for the dryer, Dr. Alan Bilanin from CDI will also be 13 presenting some information.

14 So if there are no other questions or not 15 questions for me, I would like to turn this over to 16 Paul Davison to provide the overview of the uprate.

17 Paul?

18 MR. DAVISON: Good morning. As Tom 19 mentioned, my name is Paul Davison. I am the Hope 20 Creek Site Engineering Director. I'm also the EPU 21 Site Sponsor and also the Test Director for the EPU 22 project. The overview of this session will talk about 23 the extended power uprate and will cover the seven 24 topics listed on the slide -- the design of the 25 facility, the licensing strategy for our submittal, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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17 1 the impacted key plant parameters, facility 2 modifications performed to support the power uprate as 3 well as our remaining implementation actions.

4 Moving onto slide six, as mentioned 5 previously, Hope Creek Generating Station is wholly 6 owned and operated by PSEG Nuclear, LLC which is a 7 subsidiary of PSEG Power. The station shares a common 8 site with Salem Generating Station which is located 9 adjacent to the Delaware River near Salem, New Jersey.

10 The station is a General Electric BWR-4 design. We 11 operate on an 18-month fuel cycle. Our next refuel 12 outage commences in the spring of 2009. The station 13 also utilizes a natural draft hyperbolic cooling tower 14 for our normal condenser heat removal as well as the 15 Delaware River itself as our ultimate heat sink.

16 The operating license, as mentioned 17 previously, was issue in July of 1986 with commercial 18 operation commencing December of that same year.

19 From a containment perspective, Hope 20 Creek's primary containment structure is a General 21 Electric Mark 1 which is denoted by the inverted 22 lightbulb shape containment as well as a suppression 23 pool heat sink which is a torus. The original 24 licensed thermal power of LLTP was 3293 megawatts in 25 2001 through the Appendix K feedwater uncertainty NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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18 1 uprate we implemented and took the unit to 3339 2 megawatts thermal by using the AMAG or advanced 3 measurement in analysis group cross-flow system. That 4 system uses externally mounted ultrasonic transducers 5 on the common feedwater header to measure feedwater 6 flow with greater certainty.

7 The requested extended power uprate will 8 increase the licensed thermal power to 3840 megawatts 9 thermal. This is 115% of our current licensed thermal 10 power or 16.6% of our original licensed thermal power.

11 MEMBER BANERJEE: The AMAG system, will it 12 be re-calibrated for this flow rate?

13 MR. DAVISON: We've done two things -- one 14 in response to some industry experience. We've done 15 a full calibration at 100% power now coming out of our 16 refuel outage by using other ultrasonic devices on our 17 individual three feedwater lines and also, we use our 18 secondary systems. We use the venturis that were 19 installed during original construction, of course, as 20 well as balance-of-plant operating conditions, like 21 turbine first stage pressure, to make sure we're 22 always balanced and ensuring that we're never in an 23 over powered condition.

24 There is no specific re-calibration that's 25 required of the system when we go to power uprate.

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19 1 However, during our power ascension testing, the same 2 type of comparisons will be done to ensure that there 3 has been no change by the increase, approximately 16%

4 increase in feedwater flow and, of course, the 5 temperature change that occurs with that.

6 MEMBER BANERJEE: So was it calibrated 7 with a time-of-flight method originally or how was it 8 calibrated, just against venturis?

9 MR. DAVISON: No. The ultrasonics 10 themselves were statistically compared to three 11 individual sets of ultrasonics that were installed on 12 our individual feed lines. So general system 13 description is three feedpumps, three feedwater trains 14 that have individual lines where we put ultrasonic

'5 devices on, that goes into a common header, and that's 16 where the actual AMAG's cross-flow system is 17 installed. What we did was statistically compared the 18 data over long periods of time from the individual 19 flow elements which have greater accuracy, the 20 straight runs that are unobstructed to ensure that you 21 have the correct flow characteristics where the 22 ultrasonics were placed, and then did that comparison, 23 and we utilized the comparison to calibrate that.

24 The comparison to the venturis and the 25 first-stage term pressure are secondary checks in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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20 1 response to industry OE where folks have had problems 2 and have ended up over powering units.

3 MEMBER BANERJEE: So it's basically a 4 consistency check?

5 MR. DAVISON: Correct.

6 MEMBER BANERJEE: And at the higher power 7 you do that?

8 MR. DAVISON: Yes. The other thing that -

9 - the Appendix K uncertainty is taken out of our re-10 rate power, so we will not actually be utilizing the 11 cross-flow system for a reduced margin and greater 12 certainty. What we will be using the cross-flow 13 system for is to maximize the efficiency or accuracy 14 of our flow venturis. But that 2% -- 1.4% margin is 15 back into our licensing basis.

16 MEMBER BANERJEE: So the flow venturis, 17 they haven't had any sort of roughening at the throats 18 or anything like that?

19 MR. DAVISON: The operating experience of 20 fouling and defouling events, we do see minor 21 indications of that. In fact, one of the reasons why 22 we went and did the full power calibration coming out 23 of our last refuel outage was to check for them, 24 periodically check for that, because you do see some 25 buildup and sloughing off of the coating, the fine NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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21 1 coating that occurs on the venturi itself. As far as 2 damage or needing to replace due to erosion of our 3 venturis, no, we have not seen that at the station.

4 MEMBER BANERJEE: Okay. Thanks.

5 MEMBER MAYNARD: Could you -- if you're 6 going to do this later, that's fine, too, but the 7 reason you chose 3840 rather than going to the 3952?

8 MR. DAVISON: Yes. Actually, I'll take 9 you through this next chart just for a comparison and 10 then there is some further information, but the 11 business decision that was made back in the early 12 2000's, we initially set out to do a 120% uprate.

13 That's what the plant was designed for. In fact, 14 you'll hear about the significant margin in, like, our 15 condensate and feedwater systems because of that. At 16 the time, with unknown uncertainty with respect to the 17 grid and moving forward and the cost associated with 18 that, a business decision was made to go for a 15%

19 power uprate.

20 So it was strictly a business decision at 21 that time, because we needed to put in motion the 22 changes, primarily through General Electric and the 23 purchase of three low-pressure rotors and a high-24 pressure rotor to basically replace our entire turbine 25 train. So at that time, we made the decision we're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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22 1 going to buy the equipment that'll support a 15% power 2 uprate.

3 MEMBER MAYNARD: Okay.

4 MEMBER ARMIJO: So with this equipment on 5 the turbine, you're going to be limited to 115?

6 MR. DAVISON: Well, actually, right now, 7 as you'll hear, we're actually going to be limited to 8 111.5% this cycle. We will require even additional 9 modifications, primarily focused on the high pressure 10 turbine to change out the first four stages of 11 diaphragms to be able to get to 115% power.

12 MEMBER ARMIJO: Okay. But that'll be the 13 limit once you make those modifications?

14 MR. DAVISON: Correct.

15 MEMBER ARMIJO: Okay.

16 MR. DAVISON: Okay. ON the slide that you 17 have in front of you, because of the discussion I just 18 had, we started off -- and many of our initial 19 analyses were based on 120% -- when we focused in at 20 115, we did the balance or the remainder of the 21 analyses at 115%, and we were comparing Appendix K and 22 pre-Appendix K power levels. We thought we'd just do 23 a quick run through of a comparison of our OLTP, CLTP 24 and EPU power levels. You can pull it out and 25 reference it to our discussions later one.

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23 1 Vince will just point out a couple of key 2 items here where we initially set out as I mentioned, 3 to do the standard 20% uprate. Therefore, a large 4 amount of our EPU analysis was completed at that 120%

5 or 3952. So that's, the 3952 equating to 120%.

6 Appendix K uprate brought us to the 100% current 7 licensed thermal power of 3339. That's the center 8 bar. Our requested EPU license change request for 15%

9 power increases that or equates to 116.6 of our 10 original licensed thermal power. So reading across 11 the 3840 megawatts thermal line, you see that's 116.6%

12 of our original license, a 15% increase on our current 13 license, and that will be the 100% value when we reach 14 EPU conditions.

15 During the cycle, we'll be limited to that 16 111.5% based on our main turbine, specifically the 17 high-pressure turbine. And that's really maintaining 18 our main turbine 3% control valve wide open transient 19 response margin. That is why that turbine right now 20 will be limited to 111.5. Mention the modifications 21 that we'll need to do to be able to rate that unit --

22 that piece of equipment to 115%. And additionally, we 23 are focusing on cooling tower enhancements during our 24 peak summer atmosphere condition, mainly high 25 temperature.

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24 1 Our cooling tower will also start to limit 2 our megawatt electric output. We'll actually, in some 3 cases, have to reduce power by a few percent to ensure 4 that we maintain the appropriate margin with respect 5 to turbine back pressure. So again, the major 6 limiting component for year-round operation is the 7 high-pressure turbine. Summer months will be focusing 8 on cooling tower efficiency improvements.

9 Okay. Next slide -- we have made numerous 10 changes, both physical and licensing wise to get to 11 where we are today with this proposal. The 10 CER 12 50.59 process, of course, was utilized. Several 13 licensing actions in support of our EPU implementation 14 were also required. The adopted amendments have been 15 previously NRC reviewed and approved, and we fully 16 implemented them at Hope Creek. Those changes include 17 the full scope of the alternate source term was 18 approved for implementation in October of 2001. All 19 EPU analysis was performed using the AST methodology.

20 The reactor vessel pressure and temperature limit 21 curves were revised in November of 2004, currently in 22 place, and they have been updated to include the EPU 23 neutron fluence levels.

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25 1 utilized since December of 2004. We're currently 2 operating on our third cycle with fuel from two 3 different vendors, General Electric and Westinghouse.

4 The ARTS/MELLLA implementation was February of 2006.

5 This expanded the operating domain to reach rate of 6 power at lower core flow and also provides the 7 necessary reactor recirculation flow control range for 8 our ultimate EPU implementation.

9 The remaining open license amendment 10 request is our current submittal for EPU. The 11 application was submitted in September of 2006 and 12 accepted for review by the staff in October of the 13 same year. It utilizes the constant pressure of power 14 uprate license topical report for the non-fuel-related 15 topics in the extended power uprate topical report for 16 the fuel-related topis due to our GE/Westinghouse fuel 17 load.

18 Slide nine talks about the specific key 19 parameters that are changing with EPU. In addition to 20 the 501 megawatt thermal uprate required to change the 21 recirc flow operating range, there was no change in 22 the actual flow limit of 105 million pound mass per 23 hour2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />. The lower flow limit was increased from 76.6 to 24 94.8 million pound mass per hour since we did not 25 expand the MELLLA operating domain. Steam dome NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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26 1 pressure remains unchanged. The feed and steam flows 2 increase typically what you would see with a 15% power 3 increase. There is a minor delta between the feed and 4 steam flow and the numbers there, and that's due to 5 the constant CRD cooling water that's flowing into the 6 vessel, water inventory about 60 galls a minute.

7 MEMBER BANERJEE: Let me ask you a 8 question.

9 MR. DAVISON: Yes.

10 MEMBER BANERJEE: Since you're only going 11 up to, let's say, 116% or something, do you still have 12 some operating range which is going to be full control 13 there in MELLLA --

14 MR. DAVISON: Yes, with MELLLA, that's 15 correct.

16 MEMBER BANERJEE: So you'll have, what, 17 some region which is still you're able to control the 18 flow without control rods?

19 MR. DAVISON: Absolutely. The basic 20 operation of the unit will remain the same as we are 21 today. We'll be doing flow manipulations to change 22 reactor power for minor and then control rod 23 manipulations.

24 MEMBER BANERJEE: So perhaps at some 25 point, you could show us some typical operating domain NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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27 1 later one?

2 MR. DAVISON: Yes. In the fuels 3 discussion, we can show the power-to-flow map and we 4 can go through that. Okay?

5 All right. The final feedwater 6 temperature increases by 9 degrees Fahrenheit 7 primarily due to the higher main turbine extraction 8 pressure of the feedwater heaters themselves. Other 9 than the core thermal power increase of 15%, the 10 impact of EPU to the power plant is primarily in the 11 balance-of-plant steam delivery systems.

12 MEMBER ARMIJO: What will your core power 13 density be at EPU, and how does that compare to other 14 BWR-4s --

15 MR. DAVISON: Don?

16 MR. NOTIGAN: -- kilowatts per liter.

17 MR. DAVISON: Mr. Notigan, address that 18 question, please?

19 MR. NOTIGAN: Yes. Don Notigan, PSEG 20 Nuclear. We compared Hope Creek's power density to 21 the experience base from the licensing topical report.

22 Hope Creek will be below some of the maximum kilowatts 23 per liter density, but it is within the experience 24 range and fits right in with the curves. I'll be 25 presenting some of that in my discussion.

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28 1 MEMBER ARMIJO: Do you have a number?

2 MR. NOTIGAN: I believe it's less than 57 3 but I can look that up.

4 MEMBER ARMIJO: Okay.

5 MR. DAVISON: Okay. On slide ten, Vince?

6 We talked about the licensing approach. This is the 7 actual physical modifications that were required to be 8 implemented at the station in support of EPU. In 9 preparation for the EPU, we performed a rigorous 10 assessment of reductions in both operating and design 11 margins. Training, procedure changes, program 12 changes, testing changes were all implemented to 13 account for reductions in margin as a result of the 14 15% increase in addition to these modifications.

15 Some examples of the components and 16 systems that were impacted by this strategy of uprate 17 and assessment to manage the margin associated with 18 them, main steam line piping vibration and steam dryer 19 loading, no changes to the main steam system or the 20 actual vessel steam dryer were required. We did do 21 analysis to show that the margin exists. Obviously, 22 we'll be talking about that in greater detail on 23 tomorrow's session, but we'll also be implementing 24 monitoring which will be part of our monitoring plan 25 to ensure that there are no issues associated with our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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29 1 analytical assessment of the margin associated with 2 things like main steam line piping and steam dryer.

3 High-pressure turbine -- talked about in 4 addition to the actual physical change of the high 5 pressure turbine and the requirement to limit power to 6 111.5%. We will monitor that and keep power to 7 111.5%. Again, that was to maintain a 3% valve wide 8 open margin for transient response.

9 Condenser back pressure and condenser 10 demin., condensate demin., inlet temperatures will 11 also have some limitations really going back to the 12 cooling tower operations. No specific change is made 13 to the operating facility for that. However, we will 14 be monitoring condenser back pressure as we do all the 15 time, but specific focus in the summer months because 16 of our cooling tower limitations and essentially being 17 at the mercy of the environment. But there are 18 specific guidelines set up with Operations that they 19 have today even pre-EPU that in the event of a 20 challenge to condenser back pressure before a 21 transient would occur, they have the direction to 22 reduce reactor power.

23 Steady state operations with the reactor 24 feed pump -- we can essentially operate with one of 25 our reactor feed pumps. Hope Creek is designed with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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30 1 three secondary condensate pumps, three primary 2 condensate pumps and three reactor feed pumps. Right 3 now we can operate with a feed pump out of service up 4 to 100% power. Of course, with change of power to 5 115%, we will need to procedurally control the point 6 with which we can operate the unit with a flexiplace 7 or other primary or secondary condensate pump out of 8 service.

9 And the steam bypass capability, we did 10 require a license change coming out of this outage in 11 light of our high-pressure turbine replacement, which 12 reduced our main steam bypass, our bypass valve 13 capability from 25 to 22%, again, controlled in our 14 setpoints for our instrumentation as well as 15 procedurally for how we operate the reactor.

16 But in addition to those, there were many 17 changes that were actually physically done to the 18 plant. And what I will do is I'll just walk through 19 and cover the modifications that were done to the 20 facility that we needed to do to either increase or 21 maintain margin so that we can implement an EPU 22 project.

23 Starting in 2003, we did implement two 24 changes. The 500 kV breaker was added due to our 25 independent system operations which is Pennsylvania, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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31 1 New Jersey, Maryland, PJM, interconnect analysis for 2 the additional output that Hope Creek would have. The 3 breaker was added to ensure all grid stability 4 criteria were met. The new breaker was added to 5 provide backup line fault clearing. This prevents 6 tripping of Hope Creek and the interconnecting line 7 between Salem and Hope Creek switch yards to preserve 8 grid stability. And this will be reviewed in detail 9 in tomorrow's session on grid stability.

10 Also, the cooling tower internals were 11 upgraded to install new flow distribution piping, fill 12 material and realignment of the water distribution.

13 We're essentially making sure that the tower is 14 operating at its maximum efficiency.

15 Moving to 2004 -- I mentioned that we 16 replaced -- all three of our low-pressure rotors were 17 upgraded. This also eliminated the torsional stress 18 limitation by installing the GE monoblock design 19 rotors. We also installed the digital EHC, or 20 electro-hydraulic control system, and a turbine 21 supervisory instrumentation system upgrade to improve 22 control reliability as well as vibration monitoring 23 capability of our main turbine train.

24 The main generator nameplate rating was 25 increased due to the power uprate. In addition to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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32 1 nameplate rating which was analytical, we did have to 2 increase the standard water coolant system flows and 3 also the iso-phase bus cooling associated with that to 4 allow for the greater increase in power.

5 The two main turbine moister separators 6 and the piping between the high-pressure and low-7 pressure, we have two large moisture separators. The 8 internal chevrons or the moisture separator internals 9 themselves were replaced and that provided additional 10 efficiency as well as we gained approximately 6 11 megawatts electric by doing that. That's essentially 12 increasing our steam quality to the low pressure 13 rotors.

14 And then the alpha and bravo main power 15 transformers were replaced to match the previously 16 replaced Charlie phase transformer, three individual 17 phases. That experienced default due to solar-18 magnetic disturbances back in 2001.

19 MEMBER BONACA: Excuse me. I have a 20 question.

21 MR. DERRICK: Yes.

22 MEMBER BONACA: If you lose one feedwater 23 pump now, before the change, you stay at 100% power?

24 MR. DAVISON: No. The -- in response to 25 a loss of a feed pump, we will incur a intermediate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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33 1 runback on our recirc pump, so it will actually reduce 2 power automatically in response to the loss of a feed 3 pump.

4 MEMBER BONACA: With the low -- with the 5 power change after the occurrence?

6 MR. DAVISON: That occurs right now. Is 7 that correct, Bill?

8 MEMBER BONACA: Oh, now.

9 MR. KOPCHICK: That's right.

10 MR. DAVISON: Yes. The system's designed 11 with based on the rating of flow, loss of a pump --

12 it's an anticipatory runback to prevent degradation to 13 level and a reactor transient scram.

14 MEMBER BONACA: What level?

15 MR. DAVISON: I'm sorry?

16 MEMBER BONACA: To what power level?

17 MR. DAVISON: The intermediate runback, a 18 recirc takes us back to approximately 80% power.

19 MEMBER BONACA: And now with the new --

20 after the power uprate, you're just simply readjusting 21 the runback down to a lower value?

22 MR. DAVISON: The specific value for the 23 runback stays the same, correct?

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34 1 in the Operations Department. The runback on a trip 2 of a reactor feed pump is initiated with a reactor 3 feed pump concurrent with receipt of a Reactor Level 4 4 which is 30 inches. The plant response is to reduce 5 reactor recirc pump speed to 45%. At current licensed 6 thermal power, that will reduce me to approximately 7 80% current licensed thermal power. It will be 8 somewhat higher than that under EPU conditions.

9 MEMBER BONACA: Thank you.

10 MR. KOPCHICK: You're welcome.

11 MR. DAVISON: Okay. And the last 12 modification for 2004 were the addition of flow-13 induced vibration analysis via accelerometers 14 installation on many of our piping systems. The 15 accelerometers allowed us to collect the baseline data 16 to verify that we had no flow-induced vibration 17 problems. Critical piping is instrumented, and as 18 you'll hear in our discussion of power ascension 19 testing, we have Level 1 and Level 2 acceptance 20 criteria that we will be closely monitoring the piping 21 for vibration for power ascension. In addition, 22 numerous other balance-of-plant piping were 23 qualitatively walked down and will be walked down as 24 part of our power ascension testing program as well.

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35 1 removed? You say temporary. Is that -- was just in 2 for a short while or?

3 MR. DAVISON: No. It will remain 4 installed through the -- it's been installed and will 5 remain installed through the entire power ascension 6 testing program. So it remains installed today and we 7 periodically take readings just to verify that we have 8 not, you know, have any failed sensors or damaged 9 cables.

10 In 2006, so in that column, the 11 ARTS/MELLLA I mentioned previously was introduced.

12 The alpha steam jet air ejector heat exchanger was 13 converted from a parallel flow to a cross flow design.

14 That was already previously implemented on the BRAVO 15 steam jet air ejector, and that's really around 16 improving efficiency for summer operations of our off 17 gas air removal system. The main generator iso-phase 18 bus cooling system was upgraded to increase the air 19 flow as well as the heat exchanger of cooling water 20 flow, which is a cooling medium for that heat 21 exchanger.

22 The number 2 and 3 point feedwater heat 23 dump valves were replaced. That's to increase their 24 capacity to respond to transients, and numerous 25 setpoint changes have been made -- six safety relief NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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36 1 valves on the two main turbine moisture separators and 2 three relief valves on the number 5 point feedwater 3ý feedwater heaters were all increased due to the normal 4 operating pressures increase expected as part of the 5 EPU implementation.

6 We did modify six existing pipe supports 7 on the main steam lines in our turbine building. And 8 that was due to increased loading of the higher steam 9 flow when we have a turbine stopped off transient. So 10 we just -- the actual -- no additional lines were 11 installed. We just modified them to strengthen them.

12 And then strain gauges -- additional accelerometers 13 and thermal couples were added to the main steam 14 lines, RHR piping, recirc piping to assess the 15 acoustic characteristics of the associated piping 16 systems. And again, that data is necessary for the 17 steam dryer analysis which we'll be covering on 18 Friday.

19 Finally, in 2007, the condensate 20 demineralizer resin traps were upgraded with new 21 strainer elements, and that's to account for the 22 increased differential pressure across these traps 23 resulting in the increased flow we will have during 24 EPU conditions. The high-pressure rotor was finally 25 replaced, as I mentioned, in our last outage. The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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37 1 nozzles, diaphragms and packing were replaced to 2 support the increased steam flow of the rerate.

3 Again, additional modifications will be necessary to 4 take us all the way up to the full 115%.

5 Additional drywell main steam line strain 6 gauges were installed, really in response to industry 7 operating experience that other plants incurred 8 failures which limited or reduced the accuracy of 9 their data on the strain gauges, so we went and 10 installed eight strain gauges per location. That 11 allows redundancy so that we do have some type of 12 strain gauge failure, we will still have adequate data 13 coming to us for analysis when we do the uprate.

14 Small-bore piping changes associated with 15 the main steam lines really between the pressure 16 averaging manifold and the turbine stop valves 17 themselves were upgraded by adding two-over-one taper 18 fillet welds, and that's just to minimize fatigue-19 induced cracking on EPRI guidelines and some OE that 20 was out there. Numerous BOP instruments were rescaled 21 and setpoints were adjusted in support of the EPU.

22 And then finally, the reactor recirc pump 23 runback logic was changed for the trip of a primary 24 condensate pump. We used to have a full runback 25 associated with the trip of that pump. WE changed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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38 1 that to an intermediate run to take advantage of the 2 design capacity, extra capacity of our condensate and 3 feedwater systiem. It really is focused on minimizing 4 the transient to operations during a trip of the pump.

5 And the RCIC turbine exhaust high-pressure 6 trip setpoint was adjusted to 50 pounds to maintain 7 RCIC availability and that's associated with our 4-8 hour coping period following a station blackout event 9 in accordance with SIL-371.

10 CHAIR ABDEL-KHALIK: Is 50 psi the correct 11 number?

12 MR. DAVISON: Yes. And then, finally, 13 moving it forward into 2008, the online implementation 14 listed setpoints -- that's the main steam line hot 15 flow setpoints -- OPRM setpoints, APRM setpoints, and 16 hydrogen water chemistry flow adjustments control 17 bands will be changed subsequent to issuance of our 18 license change. So we're awaiting for that to do 19 online once we move forward.

20 In summary, all the changes required to 21 support EPU have been implemented with the exception 22 of the license change restraint setpoints.

23 Moving on to slide 12 for the 24 implementation itself. So with all the physical 25 modifications actually completed, the remaining tech NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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39 1 spec-driven setpoints that I mentioned before will be 2 implemented online in this operating cycle, the power 3 ascension in accordance with our test plan from 100 to 4 111.5% will then commence. The goal is to implement 5 prior to our independent system operation PJM grid 6 summer peak period which essentially begins June 1st 7 of this year.

8 That concludes my presentation pending 9 questions.

10 MEMBER MAYNARD: I'm still just a little 11 bit confused on your feed pump-condensate pump 12 capabilities. I thought earlier in the discussion you 13 said that you could operate with two of them?

14 MR. DAVISON: Correct.

15 MEMBER MAYNARD: Maybe I assumed that what 16 you were saying is you basically had three 50% pumps, 17 but you're talking about having runbacks any time you 18 lose one. Is that just -- you mentioned 19 precautionary. Could you actually operate at 100%

20 power with just two pumps?

21 MR. DAVISON: Yes. For clarification, 22 steady state operations, if we were to remove a pump 23 from service, coming out of an outage, have a 24 maintenance problem or have a pump that we need to 25 take out of service in a controlled fashion, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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40 1 operations would reduce reactor power, take the pump 2 out of service, increase reactor power back up. So in 3 steady state operations, no issues. The runback is 4 required because you have a transient associated with 5 the instantaneous loss of a pump, condensate or feed 6 pump, immediate level effects, so you have the runback 7 to protect from the low level scram.

8 MEMBER MAYNARD: Okay. That's fine. That 9 answers my question.

10 MR. DAVISON: Thank you.

11 CHAIR ABDEL-KHALIK: If there are no 12 further questions, we'll proceed with presentation.

13 MR. DAVISON: Thank you. I would like to 14 now Bill Kopchick. He's our Shift Operations 15 Superintendent for the Operations portion.

16 MR. KOPCHICK: Good morning. As Paul 17 Mentioned, I'm Bill Kopchick. I am the Shift 18 Operations Superintendent at Hope Creek. That means 19 for the operating shift personnel, senior reactor 20 operator, reactor operators and equipment operators, 21 they will ultimately report up through me. My boss is 22 the Operations Director who would be Paul's peer in 23 our management team. I've been licensed at Hope Creek 24 for 10 years. Prior to Hope Creek, I was a shift 25 technical advisor at the Oyster Creek Station. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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41 1 during power ascension, I'll fill a role as a Test 2 Manager as we perform our power ascension testing upon 3 approval of our license submittal.

4 My role in the development of the project 5 over time has been to make sure there has been either 6 a senior reactor operator or a reactor operator 7 engaged with the project. Any questions that were 8 operationally related would then come back to me for 9 approval or operations shift input, so we made sure 10 that operations personnel were aligned with the 11 project and were able to implement it on shift.

12 To my right is Paul Lindsay. I'd like to 13 afford Paul the opportunity to introduce himself.

14 MR. LINDSAY: Good morning. Again, as 15 Bill said, my name is Paul Lindsay. I work for 16 Mainline Engineering Associates. I am a former 17 licensed SRO at Hope Creek Station, also a former 18 mechanical design supervisor for Hope Creek and Salem 19 units. My role in the project has been primarily 20 mechanical design support. However, I was responsible 21 for the development of the test program as well as the 22 implementing test procedures.

23 MR. KOPCHICK: Thanks, Paul. The intent 24 of this portion of the presentation is to cover three 25 operationally- focused topical areas associated with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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42 1 the implementation of extended power uprate. These 2 will be operator training and the efforts we have 3 taken to ensure operator readiness for EPU 4 implementation and subsequent high-power operation.

5 Second is the impact of EPU on operator response to 6 transients and postulated events including the 7 operator actions, mitigating strategies and response 8 times. And lastly, I will outline our power ascension 9 testing program which has been designed to 10 successfully implement a safe and systematic plant 11 power ascension to extended power uprate power levels.

12 First in the area of operator training, as 13 Mr. Davis had mentioned, we have incorporated numerous 14 station modifications to prepare us for power uprate.

15 Some of these included new main power transformers, 16 high pressure and low pressure turbine replacements, 17 enhanced monitoring systems, and multiple instrument 18 replacements to include scaling and setpoint changes.

19 The majority of these modifications, as Paul stated, 20 particularly involving those that involve physical 21 changes, have been in place for one or more operating 22 cycles. For each of these, specific system training 23 was included in both non-licensed operator and 24 licensed operator requalification programs and thus, 25 the operators, including myself, are currently NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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43 1 familiar with the changes made, the operating 2 limitations required, and the characteristics of the 3 new equipment that has been installed.

4 In addition to the system training on 5 these previously mentioned modifications, we have 6 conducted EPU power ascension training, steady state 7 training, and transient training in both the classroom 8 and on the Hope Creek simulator for all operating 9 shifts. Regarding procedure changes, while EPU 10 implementation involves numerous procedure changes to 11 the station, the changes to the procedures associated 12 with the aforementioned system modifications represent 13 the majority. These changes have been trained on.

14 They are in place. Operators are currently familiar 15 with the precautions and limitations and operating 16 requirements associated with this equipment.

17 The balance of outstanding changes 18 associated with EPU implementation will involve 19 changes to tech-spec instrumentation setpoints which 20 obviously cannot proceed until a license change 21 request is approved.

22 CHAIR ABDEL-KHALIK: Now the 11.5% change 23 is going to be a mid-cycle change for this current 24 cycle. Has the simulator model in existence been 25 uprated to 11.5% and that's what the operators have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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44 1 been training on?

2 MR. KOPCHICK: Yes. What we did for the 3 simulator modeling is we've obviously done a pretty 4 extensive amount of analysis on plant performance at 5 EPU conditions up to 115% and in some cases, as Paul 6 mentioned, 120%. In an effort to ensure simulator 7 response would be as we would expect under EPU 8 conditions, we did run a battery of transients on the 9 simulator to include balance-of-plant system response 10 to ensure that the ANSI standard required margins for 11 performance of the simulator were met. That was 12 performed prior to the training being initiated.

13 A second facet associated with the 14 simulator that is probably pretty important is we 15 implemented a new balance-of-plant thermal hydraulic 16 model called THOR which is an advanced model that we 17 use to back up the analytical calculations that were 18 performed for balance-of-plant response. So the 19 simulator has been validated to respond as we expect 20 the plant to respond in EPU.

21 I would add that the documentation that 22 our station requires -- it's a corporate procedure to 23 formally document that testing per the ANSI standard -

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45 1 April 27th.

2 MR. DAVISON: Paul Davison. For clarity, 3 the simulator has two modes of operation, one for 4 training at the current licensed thermal power and 5 when they're doing EPU testing at the EPU rated so 6 they can actually run the plant as it would look and 7 appear to them at the uprated power. Is that correct, 8 Bill?

9 MR. KOPCHICK: That is correct. It is 10 really a function of setting up the initial power.

11 CHAIR ABDEL-KHALIK: Thank you.

12 MR. KOPCHICK: Getting back to procedure 13 changes, the balance of our outstanding changes are 14 associated with tech spec instrumentation changes.

15 Those procedures are complete and awaiting approval of 16 the license change request. Some changes --

17 MEMBER BONACA: Just to understand it 18 better, you're going to go to 111% power and then 19 later on another step up to 115% power?

20 MR. KOPCHICK: Correct.

21 MEMBER BONACA: What does it do to your 22 tech specs and to your protection system? I mean are 23 you setting it up for 111% power now and then later on 24 adjust it 115%, or do you have a different strategy?

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46 1 based on 115% power uprate. The limitation of 111.5%

2 current licensed thermal power is turbine related, so 3 from an operator perspective, that presents some small 4 challenge, because we will be operating at 97% power.

5 We will set up our procedure network. Obviously, 6 being an operator, we operate in accordance with 7 procedures to set limitations procedurally to keep us 8 at 111.5.

9 MEMBER BONACA: Which is 97%?

10 MR. KOPCHICK: Ninety-seven percent. That 11 is correct.

12 MEMBER BONACA: Okay. So could you just 13 elaborate a little bit? How do you train the operator 14 to see that? I mean your setpoints are set at 115%

15 power.

16 MR. KOPCHICK: Right. Okay. The way, as 17 an operator, I would control reactor power output is 18 I would use a heat balance that's updated every second 19 off of a plant process computer. The plant process 20 computer will give me a number in megawatts thermal.

21 Right now the way my license is set up, I'm limited to 22 3339 megawatts thermal. We use a 5-minute average to 23 control that power level. If I see the 5-minute 24 average approach or exceed that number, I will reduce 25 reactor recirc flow to maintain the 5-minute average NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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47 1 below the limit. That's how we intend to set that up 2 for the operator control, to minimize a number of 3 other parameters that have to monitor.

4 MEMBER BONACA: Okay. My concern was how 5 much do you have to change later on, but what you're 6 telling me, it's pretty much you're implementing 115%

7 power really --

8 MR. KOPCHICK: Right.

9 MEMBER BONACA: -- from your setpoints and 10 then you're controlling at another power level?

11 MR. KOPCHICK: That's correct. Our 12 procedure network sets the control band for the 13 operator as it would with any other system including 14 the reactor.

15 MEMBER ARMIJO: I just want to get a 16 clarification. You're currently in Cycle 14, is that 17 correct or?

18 MR. KOPCHICK: I think that's -- Don?

19 MR. NOTIGAN: This is Don Notigan, PSEG 20 Nuclear. Currently, we are in Cycle 15 at Hope Creek.

21 MEMBER ARMIJO: You're currently in 15 and 22 you're going to go to 111% during this cycle?

23 MR. NOTIGAN: That is correct, in Cycle 24 15.

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48 1 you'll go to the remaining up to 115?

2 MR. NOTIGAN: We have information in 3 another presentation that describes an implementation 4 plans for going up to the next power level. I don't 5 believe we're making a commitment for the next cycle.

6 MR. KOPCHICK: Okay? Okay, so regarding 7 procedures, some changes have been made to our 8 emergency operating procedures which I will cover in 9 our next slide. However, there are no new abnormal 10 operating procedures required for EPU implementation.

11 We did not require any new emergency operating 12 procedures as a result of EPU, but I will cover the 13 changes to the existing procedure network that we 14 accomplished.

15 Regarding operating experience, industry 16 operating experience associated with power uprates was 17 incorporated into our operator training. Hope Creek 18 reactor operators and senior reactor operators that 19 were involved with the test program development with 20 Paul Lindsay visited several sites that have 21 implemented extended power uprates and have utilized 22 this experience and additional OE in training 23 development. This experience has been incorporated 24 under both the power ascension test program and the 25 implementing procedure to accomplish the power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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49 1 ascension test which I will discuss in more detail 2 later. In addition, specific Hope Creek operating 3 experience and industry EPU experience has been 4 incorporated into individual system monitoring plans 5 on a system-by-system basis that will be used by both 6 operators and engineers implementing the power 7 ascension procedure.

8 In summary, operations personnel have 9 trained on and in many cases have been operating 10 equipment necessary to implement EPU at our station.

11 Such training has included power ascension testing, 12 steady state operation and transient response training 13 in the simulator to include lessons learned from other 14 facilities. In conjunction with planned just-in-time 15 training which we will perform prior to EPU power 16 ascension, these activities will ensure an informed 17 but cautious and questioning approach to the new EPU 18 power level.

19 The purpose of this slide is to discuss 20 the impact on operations with regards to response to 21 transients or assumed or postulated accident 22 conditions under EPU operating conditions. Hope Creek 23 has 123 post initiating event operator actions 24 credited in its plant risk program. There are no new 25 operator actions or tasks associated with implementing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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50 1 EPU at our station. Due to higher decay heat load, 2 there is a small impact on the time available to 3 detect, diagnose, and perform actions associated with 4 transients or accident conditions. However, the 5 impact does not adversely affect plant operators.

6 MR. WALLIS: This is because the times are 7 already quite low, isn't it?

8 MR. KOPCHICK: That is true. The 9 increased decay heat load is the basis for the 10 reduction in response times. I have several examples 11 I'll cover now to go over really what the changes look 12 like to me as the operator. Some examples of these 13 impacts are time to achieve cold shutdown following a 14 design basis ascent. This changes from 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> to 13 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />.

16 MR. WALLIS: There's oodles of time to 17 figure it out, though?

18 MR. KOPCHICK: There is. Tech specs in 19 the case of achieving cold shutdown would require 24 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> to achieve cold shutdown, so we'll change from -

21 - it'll take me 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> instead of 9 due to higher 22 decay heat load. The time for RPV water level to 23 reach the top of active fuel during a loss of coolant 24 event is expected or predicted to occur about 20%

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51 1 impact of wood collapse. And time to boil during 2 shutdown conditions, which is managed by our shutdown 3 outage risk management program, will shorten by less 4 than or equal to 15% under all conditions.

5 MR. WALLIS: What happens during ATWS? Is 6 there a shorter time to figure things out during ATWS?

7 MR. KOPCHICK: During ATWS conditions --

8 that is a good question -- we were audited by the 9 staff under the most extreme ATWS conditions. We ran 10 four scenarios under the audit conditions -- EPU 11 condition, MSIV closure ATWS, current license thermal 12 power condition with an MSIV closure in ATWS, and then 13 an ATWS following a turbine trip under both EPU and 14 current licensed thermal power conditions. What we're 15 looking at as far as changes to the operator, from my 16 perspective, is the actions or the way that we combat 17 an ATWS will not change.

18 We may be slightly different than other 19 facilities in that our process is if I have an ATWS 20 condition and reactor power remains over 4%, I will 21 immediate initiate standby liquid control. It was my 22 proceduralized process before and it will be post-EPU.

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52 1 standby liquid control is initiated 3.9 minutes after 2 the event. And we also have automatic feedwater 3 runbacks on a high-pressure condition that will reduce 4 RPV water level which is another stability mitigation 5 strategy that's used throughout the industry.

6 So the difference for me as an operator 7 under ATWS will not change. Obviously, it is 8 dependent upon what power level the ATWS -- post-ATWS 9 what power level I'm at, but my strategy is not going 10 to change.

11 CHAIR ABDEL-KHALIK: No manual actions are 12 required by the operators to reduce water level during 13 an ATWS?

14 MR. KOPCHICK: Procedurally, we do, in our 15 EOP network, purposely reduce RPV water level.

16 CHAIR ABDEL-KHALIK: Right. And 17 therefore, the time required for the operator to take 18 that manual action would likely be reduced under EPU 19 conditions? That was really the heart of the 20 question.

21 MR. KOPCHICK: I would have to take that 22 question for lookup to see if the time actually 23 changed, but as far as how I implement the actual 24 operator actions to combat an ATWS, I'm well within 25 any time that would change. And it's all really NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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53 1 dependent upon post-ATWS power level.

2 CHAIR ABDEL-KHALIK: So procedurally, 3 there is no time specified for the operator to reduce 4 level manually --

5 MR. KOPCHICK: That's correct.

6 CHAIR ABDEL-KHALIK: -- during an ATWS.

7 MR. WALLIS: But it is pretty quick. I 8 mean he has to do it pretty quickly now.

9 MR. KOPCHICK: We do. The first thing we 10 would do is inhibit ADS. We'd initiate standby liquid 11 control would prevent injection from other systems 12 that may inject on lowering level, and then we would 13 purposely reduce RPV water level below the feedwater 14 sparger input level to provide additional heating of 15 the water going in to further suppress power. I would 16 say that occurs within the first 5 minutes of an ATWS 17 event routinely during our training scenarios. But as 18 far as the time goes, I would have to go and take an 19 additional look at our case runs.

20 CHAIR ABDEL-KHALIK: If you can find that 21 information, that would be helpful.

22 MR. KOPCHICK: Yes. Paul, if you could 23 make sure we have that written down?

24 MR. DUKE: Yes. This is Paul Duke, PSEG 25 Licensing. We have simulator scenarios that we ran NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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54 1 with no operator actions, and we can share those with 2 you later today.

3 MR. KOPCHICK: Thanks. So I did cover the 4 impacts on some time durations associated with the 5 higher decay heat load under EPU conditions. Overall, 6 from a licensed operator perspective, the changes 7 don't represent a significant impact to our ability to 8 operate the facility. Specific changes to the 9 probablistic safety assessment and the top 20 post-10 initiating operator actions will be addressed in more 11 detail later in the presentation. Although there are 12 minor changes to operator response times in the 13 aforementioned events, there are no changes to the 14 mitigation strategies associated with these or other 15 design basis events that are required due to EPU.

16 As I mentioned, there are some changes to 17 our emergency operating procedures due to the effects 18 of EPU post-accident or post-event decay heat loads.

19 These changes are limited to changes in some of the 20 curves we use in our emergency operating procedures.

21 And these would include the heat capacity temperature 22 limit, pressure suppression pressure and boron 23 injection initiation temperature curves which I'll 24 present in the following slides.

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55 1 temperature limit. This is used when implementing the 2 emergency operator procedures. During challenges to 3 the primary containment, it's required for plant 4 operators to maintain plant parameters beneath the 5 heat capacity temperature limit curve. This ensures 6 that suppression pull temperature is low enough to 7 completely absorb the energy required to safely 8 depressurize the RPV. As can be seen from the slide, 9 the high pressure endpoint of the temperature of the 10 curve is decreased by approximately 10 degrees 11 Fahrenheit. The lower heat capacity temperature limit 12 curve is due to the effects of higher decay heat load 13 associated with the operation at higher EPU thermal 14 power.

15 As far as impact on the operator would go, 16 the requirements in the emergency operating procedures 17 under any challenge to the containment is to monitor 18 plan parameters associated with this curve and reduce 19 reactor pressure as required to maintain beneath the 20 curve.

21 CHAIR ABDEL-KHALIK: Now why the slight 22 shift to the right at low pressure? What's the 23 rationale for --

24 MR. KOPCHICK: At low pressure? We did 25 two changes really. When we modified our EOPs which NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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56 1 are currently in place, we included both the impact 2 from EPU, and these are the curves at low pressure.

3 On the left, you see the shift to the right. We also 4 implemented the new BWR owner's group emergency 5 protection guideline revision which is Revision 2.

6 The calculational methodology changed which is the 7 reason for the slight shift to the right at low 8 pressure.

9 CHAIR ABDEL-KHALIK: Now what is the 10 normal water inventory in the suppression pool gallon 11 wise?

12 MR. KOPCHICK: Usually about -- from the 13 operator's perspective, we measure it by inches -

14 CHAIR ABDEL-KHALIK: -- four pounds or 15 something that we can check the adequacy of this 16 calculation? If you can get it to us later on today.

17 Thank you.

18 MR. KOPCHICK: I understand -- a volume of 19 the suppression chamber.

20 CHAIR ABDEL-KHALIK: The volume of water 21 in the suppression chamber.

22 MR. KOPCHICK: Volume of water in the 23 suppression chamber. Okay? Any other questions on 24 heat capacity temperature limit? Next slide, please?

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57 1 suppression pressure limit curve. During operation 2 controlled by emergency operating procedures, plant 3 parameters must be kept within pressure suppression 4 curve or emergency reactor pressure vessel 5 depressurization is required. As shown by the slide, 6 the curve generally decreases by approximately two 7 pounds, again, due to the affect of the higher decay 8 heat associated with operating at elevated EPU.

9 CHAIR ABDEL-KHALIK: The units on the 10 horizontal access can't be feet.

11 MR. WALLIS: Yes, they don't make sense.

12 It must be inches. Can't be feet.

13 MR. KOPCHICK: Yes, sir. That is --

14 MR. WALLIS: It's a very strange design if 15 it's feet. It's a very strange design if it's feet.

16 MR. KOPCHICK: You're correct. It is in 17 inches and the span would be highest on the right, the 18 highest level indicated in the suppression pool level 19 that we can see by installed instrumentation and to 20 the left would be the commencement of uncover of the 21 vent pipe downcomers.

22 MR. WALLIS: This is water level above the 23 bottom of the floors?

24 MR. KOPCHICK: It's actually from the 25 instrument zero which is approximately three feet NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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58 1 above the bottom of the --

2 MR. WALLIS: Three feet above the bottom.

3 Okay.

4 CHAIR ABDEL-KHALIK: Now what actions is 5 the operator required to take if this limit is 6 exceeded.

7 MR. KOPCHICK: If I exceed, it would be 8 emergency reactor pressure vessel depressurization 9 opening up 5 safety relief valves to depressurize.

10 The limitation imposed is ensuring that in emergency 11 depressurization would -- the energy from the 12 depressurization would be able to be absorbed by the 13 suppression chamber.

14 As shown in this curve of the boron 15 injection initiation temperature, the calculated boron 16 injection initiation temperature decreased by between 17 12 degrees and 20 degrees Fahrenheit due to higher EPU 18 core thermal power. At Hope Creek, during an ATWS in 19 which reactor power remains above 4%, standby liquid 20 control is conservatively injected before suppression 21 pool temperature reaches 110 degrees. This operating 22 strategy, as I mentioned earlier, will remain the same 23 after EPU.

24 However, if the reactor is an ATWS 25 situation with a reactor power less than 4%, standby NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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59 1 liquid control must now be injected before the 2 suppression pool temperature reaches a conservative 3 140 degrees, previously 150 degrees was a result of 4 the curve. And again, this result is due to higher 5 EPU power.

6 So in summary, regarding the impact of EPU 7 on plant operators, the changes in operator responses 8 to transients or accidents under EPU conditions is 9 small. Procedure changes are limited to slight 10 changes in curves associated with limits already 11 contained in our emergency operating procedures.

12 Thus, by maintaining similar strategies and mitigation 13 approaches, the impact on operator proficiency and 14 training needs is minimized.

15 MEMBER MAYNARD: I'm just a little bit 16 confused on this curve and what you said. You talked 17 about a 4% power. If it's above 4% power, they're 18 required to initiate. Trying to relate that to this 19 curve.

20 MR. KOPCHICK: Okay. Looking at the 21 curve, 4% power is a highly observable indication for 22 operators. It's my APRM downscale limit, so when I do 23 achieve APRMs downscale, I will get 8 lights showing 24 where reactor power is. If I don't have the APRM 25 downscale, I don't have the 8 lights. It's under an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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60 1 ATWS condition which is obviously a rather busy 2 response for the operators. These are very highly 3 observable from a human performance perspective. So 4 procedurally, what we have keyed at the 4% observable 5 limit on APRM power, if I do not have the downscales, 6 the operators are trained and my procedures are set up 7 to immediately inject standby liquid control.

8 If I am below 4% power, I have the 9 downscales, then I watch suppression pool temperature.

10 So really, the curve doesn't line it up for operator 11 execution or implementation, but that is what we're 12 watching.

13 So what changed is currently, at 4% power 14 or below, I watch for and must inject standby liquid 15 control before suppression pool temperature reaches 16 150 degrees. Post-EPU, my 4% power will be a higher 17 power and the calculation we use for EOP curve 18 development will require us to inject at 140 degrees 19 by 750.

20 MR. LINDSAY: Just one item to add. This 21 curve does not actually show up in the EOPs whereas 22 the two previous curves actually show up. This shows 23 the change --

24 MEMBER MAYNARD: It sounds to me like the 25 operators don't really use this curve. They've got --

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61 1 MR. LINDSAY: That's correct.

2 MEMBER MAYNARD: -- pretty straightforward 3 power --

4 MR. LINDSAY: The guidance is for above --

5 MEMBER MAYNARD: -- temperature. That's 6 what you do, so --

7 MR. LINDSAY: Correct.

8 MEMBER MAYNARD: So this curve just show 9 that those actions ensure that you stay below -- stay 10 within your curve there?

11 MR. KOPCHICK: Yes, sir. That is correct.

12 MEMBER MAYNARD: Okay.

13 MR. WALLIS: Now the number on the curve 14, looks like 160 --

15 MR. KOPCHICK: Correct.

16 MR. WALLIS: -- it's just your number 17 doesn't sound quite -- it's not important really, but 18 the number you spoke about is not quite the same as 19 the number on the curve. That's --

20 MEMBER MAYNARD: That's what I understand 21 22 MR. WALLIS: That may kind of confusing.

23 MEMBER MAYNARD: -- is say if they're 24 using numbers that are below, they're not going off 25 this graph.

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62 1 MR. WALLIS: That's correct.

2 MR. KOPCHICK: So for the new curve, you 3 could say, I guess, 144 degrees --

4 MR. WALLIS: Yes, something like that.

5 MR. KOPCHICK: -- we inject standby liquid 6 control at 140. And currently, we inject at 150. The 7 curve would show 160. So in both cases, the selection 8 criteria is conservative.

9 MR. DAVISON: This is Paul Davison. I 10 have the answer to the follow-up question if you'd 11 like that now?

12 CHAIR ABDEL-KHALIK: Yes.

13 MR. DAVISON: The tech spec minimum 14 suppression pool is level or volume is 118,000 cubic 15 feet. Tech spec maximum is 122,000 cubic feet.

16 CHAIR ABDEL-KHALIK: Thank you.

17 MR. DAVISON: You're welcome.

18 MR. WALLIS: That is independent of its 19 temperature? This cubic feet always bothers me 20 because it's not a measure of mass. It's a volume 21 which changes if the temperature changes. You 22 actually do control volume, do you?

23 MR. DUKE: This is Paul Duke. We also 24 have controls on suppression pool temperature. We 25 have limits for continued operational and suppression NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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63 1 pool temperature.

2 MR. KOPCHICK: Tech spec limitations on 3 suppression pool temperature, I think, is what you're 4 referring to, Paul.

5 MR. WALLIS: It just seems strange. I 6 guess it's because cubic feet is what you measure by 7 means of the height.

8 MR. KOPCHICK: Is that what you --

9 MR. LINDSAY: Correct.

10 CHAIR ABDEL-KHALIK: are there any 11 additional questions for Mr. Kopchick?

12 MR. KOPCHICK: Next slide, please? Next 13 I'll present an overview of Hope Creek's power 14 ascension test program to include a discussion of our 15 preparation efforts, an overview of our test 16 organization and test conduct and a discussion of how 17 an incremental approach method will be used to achieve 18 final power levels and a brief discussion of the tests 19 themselves.

20 Preparation of EPU testing program began 21 approximately one year ago. The plan was built 22 utilizing the Vermont Yankee EPU approach to power 23 ascension and similar methodology and acceptance 24 criteria from the original Hope Creek startup test 25 program.

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64 1 The test plan aims to accomplish the 2 following three objectives -- perform sufficient 3 testing to demonstrate satisfactory equipment, 4 performance at the EPU power level, define a careful 5 monitored approach to EPU power and meet all 6 established commitments and regulatory criteria 7 associated with testing. Preparation efforts also 8 include a formation of a test team which I'll present 9 in the next slide, development of key personnel roles 10 and responsibilities such as the test director and 11 test manager, and benchinarking including several trips 12 to Vermont Yankee and Browns Ferry.

13 Based on these ef forts, a test plan and an 14 implementing test procedure was developed to 15 accomplish these objectives. The procedure has been 16 reviewed by the station's plant operations review 17 committee on two occasions, subjected to several 18 collegial reviews and two external reviews from 19 individuals experience with other EPU testing 20 programs. Based on the results of these reviews, 21 we've concluded that our test program is in line with 22 industry expectations for an EPU power ascension test 23 program.

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65 1 on the simulator on the power ascension test 2 procedure, are familiar with its contents, acceptance 3 criteria and expectations. In addition, alla 4 activities associated with this testing are considered 5 infrequently performed activities which require the 6 highest level of management involvement in accordance 7 with our station procedures governing such activities.

8 Thus, based on the familiarity of 9 operations with modifications already made, the 10 training performed and other preparation activities 11 including the conduct of periodic testing meetings, 12 benchrnarking efforts and department readiness reviews 13 which will be implemented prior to implementation, 14 Operations believes Hope Creek is well-prepared to 15 execute a successful test program.

16 Next slide. As shown from this slide, the 17 test organization will report directly to the Hope 18 Creek Generating Station Plant Manager. The Test 19 Director will work closely with the Plant Manger to 20 allocate resources and establish both the 21 administrative and technical procedures to support the 22 plan. The test team is led by the Test Manager, a 23 senior member of the Operations Department of which I 24 will be one, whose function is management oversight.

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66 1 also has the authority to stop the test at any time.

2 So either myself or the individuals who work directly 3 for me, the shift managers, have the command and 4 control authority to stop testing.

5 The balance of the organization is 6 selected from individual plant departments such as 7 Plant Engineering, Radiation Protection or Chemistry 8 based on their area of expertise. These individual 9 work closely on the development of the test plan and 10 implementing procedure, and they've been involved in 11 numerous testing preparation meetings are well-12 prepared to support EPU power ascension testing.

13 MR. WALLIS: It looks a long way down from 14 the top to the bottom here.

15 MR. KOPCHICK: We can --

16 MR. WALLIS: I guess it's necessary but --

17 MR. KOPCHICK: It is.

18 MR. WALLIS: -- that why you don't have a 19 leaner organization.

20 MR. KOPCHICK: I don't know that I can 21 comment on that, but really, there's reasons for the 22 different layers of challenges that we would expect to 23 have in executing our plan.

24 MR. WALLIS: Long as the test director 25 knows what's going on.

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67 1 MR. KOPCHICK: Mr. Davison will be one of 2 our test directors and he, as well as I, are 3 accountable to know --

4 MR. DAVISON: We will have our --

5 MR. KOPCHICK: -- what's going on.

6 MR. DAVISON: -- outage control center 7 staffed for the entire power ascension so that Ops can 8 focus on uprate. Paul Davison. We will have our 9 outage control center staffed through the entire power 10 evolution, increase evolution, and the Operations 11 folks can then focus on operating the plant, and the 12 rest of the test team will be focused on the data 13 collection and analysis and verification that --

14 MR. WALLIS: So if the GE startup 15 consultant notices something, he can get to you pretty 16 quickly?

17 MR. DAVISON: Absolutely. We'll all be in 18 the same room.

19 MR. WALLIS: All be in the same room.

20 Okay.

21 MR. DAVISON: That's correct.

22 MEMBER ARMIJO: You mentioned that -- at 23 least I heard -- that there would be more than one 24 test director? Is that correct?

25 MR. KOPCHICK: Paul?

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68 1 MR. DAVISON: Yes. We'll have people 2 responsible both on night and day shifts. So myself 3 will be the primary test director help organizing what 4 Bill said as far as making sure we have an 5 organization established. However, to man it around 6 the clock, we will have somebody else performing that 7 function.

8 MEMBER MAYNARD: Could you talk just a 9 little bit about the communications interaction 10 between the control room staff and the test team? You 11 know, who will the shift manager talk to or be 12 communicating with?

13 MR. KOPCHICK: If you take a look at the 14 slide -- I'm looking at my slide in front of me here -

15 - the shift manager will report to the IPA test 16 manager. It's required by our station procedures for 17 infrequently performed activity that the test manager 18 is organizationally senior to the shift manager. In 19 this case, they work for me. They are my direct 20 reports. The night shift test manager will be another 21 operations superintendent who was a previous shift 22 manager. At all times, for any testing we do, the on-23 duty shift has the command and control function. They 24 control the unit. If there are any upsets outside of 25 the testing, they will stop testing and respond to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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69 1 transient. So the command and control structure 2 really lies between the IPA test manager and the EPU 3 implementation and test team leader.

4 So I would expect the test team leader to 5 brief the control room crew on this is the test that 6 we are doing at this. Training will have already been 7 conducted. The operators are already familiar with 8 the tests we're going to do. And then the shift 9 manager will oversee the conduct of the test from a 10 higher level with management oversight by the IPA test 11 manager. If there are any problems, if there are any 12 delays or we need to proceed on to the next test, my 13 job as a test manager would then be to talk to Paul 14 who would be a test director. He will have technical 15 resources available to him, and Paul will be informing 16 the plant manager on status.

17 I'll go over some more detail in some 18 other slides as far as how the specifics of our power 19 plateaus and power ascension will occur and where we 20 intend to hold if that will be acceptable.

21 MEMBER MAYNARD: The shift manager still 22 has responsibility for the plant. If he's 23 uncomfortable with something, he can stop it?

24 MR. KOPCHICK: Yes, sir, at all times.

25 MR. WALLIS: This is who?

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70 1 MR. KOPCHICK: The shift manager. He is, 2 in fact, the senior license --

3 MR. WALLIS: Responsible --

4 MR. KOPCHICK: Correct.

5 CHAIR ABDEL-KHALIK: Will there be a 6 stand-alone computer on which this data are going to 7 be collected?

8 MR. KOPCHICK: Will be a stand-alone?

9 CHAIR ABDEL-KHALIK: As far as this.

10 MR. KOPCHICK: Operationally, we have a 11 system called a control room integrated display system 12 13 CHAIR ABDEL-KHALIK: Okay.

14 MR. KOPCHICK: -- which then feeds data to 15 a land network on a system we call Plant Historian 16 accessible by multiple engineers. We have automated 17 the data acquisition function of our specific system 18 performance plans to automatic data capture that 19 information. It's also available in trend format.

20 MR. DAVISON: This is Paul Davison. One 21 thing to add -- as I mentioned in the modifications, 22 when we did the temporary modifications to add 23 accelerometers and strain gauges, that is stand-alone 24 equipment that's inside the facility, in the plant 25 that we will collect data on and bring it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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71 1 electronically to the outage control center where the 2 analysis will be done to it. So that's a stand-alone 3 system because it's temporarily installed to collect 4 the accelerometer and strain gauge data.

5 CHAIR ABDEL-KHALIK: Right. My concern is 6 that -- I'm glad to hear that -- I'm not sure if 7 you're aware of the recent trip at Hatch which was 8 caused by a problem where you're collecting data 9 presumably from a stand-alone computer that caused the 10 plant trip because there was no adequate firewall 11 between that stand-alone computer and the plant 12 computer. And I just want to make sure that this is 13 not a problem that you have not thought of.

14 MR. LINDSAY: The primary means of 15 gathering data for the test, for the actual test where 16 we're perturbating the plant, we're going to be using 17 what we call our GTARS system which was the original 18 GE transient acquisition system. That has no feedback 19 or ability to cause any kind of control functions in 20 the plant. And again, as Bill said, we'll be 21 gathering data primarily off of our CRID systems 22 which, again, have no ability to provide any kind of 23 control feedback to the facility.

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72 1 using to collect your data and the plant computers --

2 MR. LINDSAY: Yes.

3 MR. KOPCHICK: As our plan is written, 4 yes.

5 CHAIR ABDEL-KHALIK: Thank you.

6 MR. WALLIS: What do you expect the role 7 of the NRC inspector to be in this? What is the staff 8 expect the role of the NRC inspector to be during this 9 process?

10 MR. DAVISON: This is Paul Davison. From 11 the perspective, you know, Bill mentioned that we have 12 a normal everyday monitoring system that we use for 13 troubleshooting monitoring the plant no different 14 there. That's our normal monitoring system. We have 15 stand-alone equipment that I mentioned which is not 16 integrated into the station. That's why we keep it 17 separate in the plant. We essentially bring the data 18 to the control room for analyses. We have specific 19 power plateaus and in our power ascension program.

20 Specifically, at 105, 110 and 111.5, we will actually 21 be submitting our data for NRC review, so we will 22 actually have plateaus there. That will be the off-23 site interaction. Of course, our senior and resident 24 inspectors will be, I'm sure, involved with --

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73 1 involved. Is someone here involved as well?

2 MR. DAVISON: That is correct.

3 MR. KOPCHICK: And I will cover that in a 4 follow on slide. At our power plateaus, we actually 5 have a 96-hour hold built in for concurrent staff 6 review of our results.

7 MR. WALLIS: Is this done by some sort of 8 computer display of what's going on or telephone or 9 how does this happen, this interaction with NRC 10 Headquarters?

11 MR. KOPCHICK: Well, we will -- as Paul 12 Davison mentioned, we'll be gathering data 13 incrementally upon receipt of the license change 14 request. Obviously, we'll be gathering data and 15 performing testing until we reach a plateau of 105%

16 power. That information will then be gathered and 17 presented to our plant operations review committee and 18 then transmitted. And Paul, do we have some --

19 MR. WALLIS: So it's not online? It's not 20 a sort of online thing?

21 MR. KOPCHICK: Paul Duke?

22 MR. DUKE: This is Paul Duke. Our current 23 plan is that we are going to set up a provision for 24 data transfer to NRR and to its contractor similar to 25 what VY did, that is that the data files will be at an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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74 1 online backup location accessible to NRC staff and to 2 its contractors.

3 MR. KOPCHICK: Okay. Regarding the 4 conduct of testing, the testing includes both Level 1 5 which is termination criteria, and Level 2, which is 6 hold acceptance criteria as well as steps to be taken 7 should either of these thresholds be reached. The 8 criteria used are similar to that used during the 9 original Hope Creek startup testing, other EPU 10 experience and the standard GE EPU testing 11 specifications.

12 Non-test equipment or plant performance 13 issues will be handled via the plant corrective action 14 process. The plant operations review committee is 15 responsible for reviewing the test procedure, changes, 16 deficiencies, plant terminations or holds and power 17 ascension to subsequent test plateaus.

18 As we previously discussed, we'll be 19 establishing a power ascension control center which 20 will be in our outage control center immediately 21 adjacent to the control room, and this will support 22 the test program. We have observed this also to be 23 successfully used at another facility, which is 24 Vermont Yankee.

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75 1 the shift will be focusing on operation of the plant.

2 The power ascension control center involving the 3 individuals in the previous slide that you saw will 4 support and gather the data for the testing.

5 Testing will utilize a similar approach to 6 that we had previously discussed at Vermont Yankee.

7 Baseline data will be taken at approximately 90% and 8 100% of current licensed thermal power and evaluated 9 to project results at higher power levels. Power 10 escalation will proceed along the constant rod line 11 using recirc flow at 2.5% increments. During power 12 ascension, hourly collection of dryer strain gauge and 13 vibration data is taken and moisture carry-over will 14 be determined.

15 The power plateaus we previously discussed 16 will occur at each 5% power level and the final power 17 level, i.e., 105, 110 and 111.5% of current licensed 18 thermal power. At each plateau, we will perform 19 detailed evaluations, walkdowns, and the majority of 20 our power ascension tests. Steam dryer performance 21 data will be transmitted, as we discussed, to the NRC 22 at each plateau followed by a 96-hour hold, as I 23 previously mentioned. Management approval will be 24 required prior to exceeding or proceeding to the next 25 power plateau.

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76 1 In addition to the specific tests 2 performed, the test team will be continuously 3 monitoring critical plant parameters under EPU 4 conditions on affected systems throughout power 5 ascension using EPU system monitoring plans. These 6 system monitoring plans have been developed and 7 include system baseline information at current 8 licensed thermal power level, OE from a database, and 9 determined expected EPU parameters and acceptance 10 criteria.

11 MR. ZABIELSKI: We seem to have lost the -

12 13 MEMBER MAYNARD: Yes. We'll get somebody 14 in here to take care of it. We have a handout to look 15 out.

16 MR. KOPCHICK: Okay. The next slide is 17 slide 24 labeled power ascension testing and major 18 test evolutions. The power ascension tests were 19 chosen based on a comparison of original Hope Creek 20 startup tests and EPU changes considering the GE EPU 21 test specifications and testing-related regulatory 22 commitments. Overall, the plan includes 12 power 23 ascension tests focusing on core performance, plant 24 chemistry, radiation protection, nuclear 25 instrumentation and pressure and feedwater controls.

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77 1 Testing is consistent with those tests performed 2 during the initial Hope Creek startup testing and that 3 performed at other stations implementing EPUs.

4 , Testing also focuses on steam dryer and 5 nuclear steam supply system piping integrity and 6 moisture carryover. Piping strain gauge data, as 7 previously mentioned, will be collected and trended 8 hourly during power ascension activities and 9 evaluated. Moisture carryover will be determined 10 every 2.5% increase in core thermal power.

11 As I mentioned previously, the specific 12 tests themselves will be supplanted by system 13 monitoring plans performed throughout the power 14 ascension process as well as plant and equipment 15 walkdowns in the field. These plans will ensure that 16 the major EPU effected systems remain within analyzed 17 limits as power ascension proceeds.

18 CHAIR ABDEL-KHALIK: So, typically, how 19 long does it take to go through a 2.5% step?

20 MR. KOPCHICK: We have set up, in our 21 submittal, for a 1% per hour ramp rate.

22 CHAIR ABDEL-KHALIK: One percent.

23 MR. KOPCHICK: So our schedule for power 24 ascension is based on that rate. It also includes the 25 holds that I previously mentioned at the plateaus at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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78 1 5%, 96-hour holds. So the ramp rate is 1% per hour, 2 so 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to answer your question.

3 CHAIR ABDEL-KHALIK: And the data 4 collection will commence once you reach steady state, 5 or are you going to also collect data during the power 6 ramp?

7 MR. KOPCHICK: The test procedure is set 8 up for discreet data collection at each 1%. The 9 systems, the computer systems that we have have trend 10 capabilities, and we will be able to capture data live 11 time as we raise power. However, the test program, 12 which is modeled against what we have from Vermont 13 Yankee, is discreet at 1% power. Paul?

14 MR. LINDSAY: I can offer at the 2.5%

15 increments, there is a 4-hour hold period for all the 16 systems to allow achievement of steady state, and 17 that's when the data is essentially taken. So at 2.5%

18 increments, we have a 4-hour hold. But of course, as 19 Bill said, at the 5% power plateaus, we'll be holding 20 for a 96-hour duration.

21 MEMBER ARMIJO: You mentioned a plant 22 water chemistry test during power ascension. Is there 23 anything special you're doing there or is it pretty 24 much routine monitoring the various --

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79 1 chemistry?

2 MEMBER ARMIJO: Yes.

3 MR. KOPCHICK: There are a battery of 4 tests that we will accomplish. Most of them are 5 routine. They do have Level 1 and Level 2 acceptance 6 criteria. Level 2 would be to make sure that we are 7 where we predict to be as far as conductivity in our 8 condensate system as well as reactor water 9 conductivity. Level 1 criteria would be associated 10 with our technical specifications and UFSAR 11 requirements. Anything else to add?

12 MR. LINDSAY: Essentially, what I could 13 add is all the tests are the normal tests via the 14 existing chemistry procedures. The key difference is 15 the frequencies will be much higher. We have a shift 16 lead daily, three times weekly readings. And 17 certainly in the area of moisture carryover, where we 18 take that, I believe, weekly at this time, we'll be 19 taking that every 2.5%.

20 MEMBER ARMIJO: Yes. Where I was going 21 with this is -- and you may have it later -- but 22 you're going to be modifying your hydrogen input and 23 how -- are you just going to just do it, or are you 24 going to get feedback from electrochemical potential 25 measurements in the startup?

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80 1 MR. KOPCHICK: Operationally, our intent 2 is to maintain our current injection rate of 9 3 standard cubic feet per minute. And Paul has some 4 details on the testing we intend to do once we would 5 achieve 111.5.

6 MR. LINDSAY: Well, essentially, as Bill 7 said, our hydrogen injection system will be placed in 8 manual for the duration of the testing so that we do 9 not artificially influence like the rad surveys and 10 things of that nature. When we achieve 111.5% power, 11 we have an existing procedure which will alter the 12 injection rate and determine the optimum level.

13 MEMBER ARMIJO: What's required based on 14 what kind of a monitor, an EPR, electrochemical 15 potential measurement or some other --

16 MR. LINDSAY: I believe that's correct.

17 MR. DAVISON: Paul Davison. For the part 18 of the noble metal chemical application which allowed 19 us to reduce our hydrogen injection rates, our reactor 20 water cleanup system has two types of monitors. One, 21 we have the durability monitors where we're able to 22 take coupons out and do samples. We also have the 23 ability to do the ECP measurement directly.

24 MR. WALLIS: I'm still curious about with 25 the NRC is doing all this time. Is there somebody NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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81 1 here all the time paying attention to this, or do you 2 all disappear for the weekend so that that's why 3 there's a 4-day hold period. No, seriously, I mean, 4 what is the NRC doing through this process? Is 5 somebody here sort of monitoring things all the time, 6 or is this person available in several hours, if 7 needed, or what?

8 MR. LAMB: This is John Lamb with the NRC.

9 The mechanical engineering branch will look at this 10 and, obviously, when they send that in, it's a 96-hour 11 hold, because that gives us time to actually analyze 12 it. So yes, regardless of when it gets sent in, we 13 will be available during that time. I think during 14 Vermont Yankee --

15 MR. WALLIS: So someone will -- should be 16 available all the time?

17 MR. LAMB: Yes. Like I said, they get the 18 information. Then they start analyzing it and if they 19 have a problem, then obviously, we'll be on the --

20 MR. WALLIS: So there isn't a here, this 21 person will work on the weekend if it's over a 22 weekend?

23 MR. LAMB: Yes.

24 MEMBER MAYNARD: That's also been my 25 experience at the resident inspector state --

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82 1 MR. WALLIS: Yes. I can understand that -

2 3 MEMBER MAYNARD: -- very involved with 4 these.

5 MR. WALLIS: I just wondered about the NRC 6 and when I come here on the weekend, there's nobody 7 here so I --

8 MR. LAMB: Well, this would be a special 9 case, obviously, during this --

10 MEMBER MAYNARD: There is always a number 11 24 hours a day, 7 days a week to get a hold of 12 someone.

13 MR. KOPCHICK: I would certainly add that 14 the resident inspector is highly engaged in our 15 activities in the control room, and when we proceed 16 with this test, I would expect that he would have many 17 questions for us and has asked questions along the 18 way. Our rapport with the resident has been sound and 19 it's also my expectation from my shift managers that 20 if there is any upset or any transient that would 21 require notification or activation of station 22 personnel to investigate an event, that the resident 23 is informed, and it's actually part of our procedures 24 that we do inform them.

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83 1 presenting details tomorrow regarding the procedures 2 and instrumentation, etcetera for the steam dryer 3 verification work? Does this require a closed 4 session, because this is sort of a generic big picture 5 of what you're going to do, but people want to know 6 the details of how are you going to do it.

7 MR. KOPCHICK: Yes, sir. We -- for the 8 additional hour, I believe for the second session 9 yesterday (sic), we will have a presentation --

10 CHAIR ABDEL-KHALIK: Tomorrow?

11 MR. KOPCHICK: -- tomorrow, correct --

12 that will detail the testing work we need to do on the 13 steam dryer and what the acceptance criteria will be 14 in detail. Paul Davison, do you have anything else to 15 add on the hour portion tomorrow?

16 MR. DAVISON: Paul Davison. That is 17 correct. We will be providing additional details with 18 respect to not only the complete testing matrix of 19 what we do at each particular power level but what we 20 do with the data, what the analysis is and how does 21 that factor back in, specifically on the steam dryer 22 with the limit curves and flow-induced vibration 23 monitoring acceptance criteria that we have.

24 CHAIR ABDEL-KHALIK: Thank you.

25 MR. DAVISON: Welcome.

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84 1 MEMBER BONACA: I have a question 2 regarding -- in your application, there is a statement 3 or a discussion that flow-induced vibration during 4 power escalation may increase SRV leakage. Are you 5 monitoring for that?

6 MR. KOPCHICK: We do have strain gauges 7 installed on main steam piping, accelerometers 8 installed on main steam piping to include SRVs. As a 9 test manager, there is an attachment in our test 10 procedure that will be executed as we raise power, and 11 there are some more details on that that I will ask 12 Mr. Davison to add.

13 MR. DAVISON: Yes. As mentioned, in the 14 modifications, we did install numerous accelerometers.

15 For example, our critical systems that will be 16 monitored with Level 1 and Level 2 acceptance criteria 17 -- extraction steam, the SRVs, both the actuators and 18 the tailpipes on a few of the SRVs, the recirc system, 19 feedwater, and main steam. So for example, baseline 20 data right now on main steam, we're at .035 g's.

21 That's RMS value. We anticipate that it will go to 22 approximately .048 g's which is, you know, obviously 23 well-below the .1 g standard for low vibration.

24 MEMBER BONACA: Because from the 25 application, it sounded like you had a program to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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85 1 monitor, in fact, leakage when you wrote the 2 application, and evidently, must that be successful in 3 controlling --

4 MR. KOPCHICK: SRV leakage at Hope Creek 5 has not been probably as pervasive as some other 6 stations have had. Nonetheless, in the development, 7 at least in my discussions with engineering personnel 8 who have been involved, I know that the attentiveness 9 to that has been high, thus the reason for the 10 installation of the accelerometers.

11 MEMBER BONACA: So I guess you don't 12 expect the uprate to result in unacceptable 13 performance from a leakage standpoint?

14 MR. KOPCHICK: I do not. Obviously, we'll 15 be monitoring that. Anything else to add, Paul?

16 MR. DAVISON: Yes. Paul Davison. We've 17 done a few things. One, we specifically have done 18 some upgrades to our pilot valves. We have two-stage 19 target rock relief valves. We've had excellent 20 performance with respect to tailpipe or through-seat 21 leakage as well as repeatability when we do our 22 testing out of refuel outages. The specific reason 23 for monitoring both the actuator valve body and the 24 tailpipes was due to the industry operating 25 experience, like at Quad Cities where they electro-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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86 1 matic r-el'ief valves experienced 'a high amount of 2 resonance and were actually getting damaged. Based on 3 our baseline readings, don't anticipate that. Based 4 on our steam-line flow characteristics, we would not 5 anticipate that occurring as well. But that's why it 6 will be carefully monitored.

7 MEMBER BONACA: Okay. Thank you.

8 CHAIR ABDEL-KHALIK: So what is your 9 history on SRV testing as far as setpoint drift?

10 MR. KOPCHICK: Setpoint drift testing --

11 well, I know there is a population of SRVs that we're 12 required to test each refuel outage. Operationally, 13 as far as setpoint drift, I don't know that I can 14 specifically speak to that as far as the results go.

15 From the operator perspective on SRV setpoint or 16 leakage or lifting, we have specific procedures that 17 the reactor operator will monitor tailpipe temperature 18 twice each shift with specific guidance.

19 MR. DAVISON: Yes, this is Paul Davison.

20 We have tech spec required 3% band allowable value for 21 the setpoints. We have not experienced large numbers 22 of failures with respect to those -- to that setpoint 23 band itself.

24 CHAIR ABDEL-KHALIK: Have you experienced 25 any failures?

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87 1 MR. DAVISON: Yes, we have. I can get the 2 specific data on the failure rate of those.

3 MEMBER BONACA: And the reason why I 4 raised that issue was that in the statement, the 5 application speaks specifically about a program that 6 you had to resolve problems resulting in SRV 7 surveillance testing exceeding a 3% tolerance. You 8 must have experienced that? I mean that's what you 9 have in your application?

10 MR. DAVISON: Yes. We'll get the 11 specifics on that.

12 MEMBER BONACA: That's why I was wondering 13 if, in fact, the power uprate would make it more 14 challenging just because of that.

15 CHAIR ABDEL-KHALIK: We're interested in 16 that. We're also interested in any incidents in which 17 the SRVs failed to open.

18 MR. DAVISON: I understand. Failure to 19 opens as well as setpoints history.

20 CHAIR ABDEL-KHALIK: Okay. Thank you.

21 MR. KOPCHICK: Okay. I'll proceed on.

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88 1 continue throughout the cycle and in RF-15.

2 In summary, Operations, myself included, 3 is ready to lead and support and the station's power 4 ascension test program and considers the station well-5 prepared to execute a careful monitored approach to 6 the target EPU power level. This concludes the 7 operations and testing portions of the presentation 8 pending any additional questions.

9 CHAIR ABDEL-KHALIK: Are there any 10 questions for Mr. Kopchick? Okay. Thanks. We're 11 well ahead of schedule, but at this time, I'd like to 12 take a break for 15 minutes and we will reconvene at 13 10:30.

14 (Whereupon, off the record at 10:16 a.m.,

15 and back on the record at 10:34 a.m.)

16 MEMBER BANERJEE: We're back in session.

17 Before we get started with the staff's presentation on 18 human performance, Mr. Davison has some information 19 regarding the power ascension test matrix that he 20 would like to present, and I guess more details will 21 be presented tomorrow.

22 MR. DAVISON: Yes. Thank you. Paul 23 Davison. As a follow-up to the questions asked 24 earlier when Bill was speaking with respect to 25 Operations, this was a chart or tabular form of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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89 1 testing that we'll be performing. We'll modify this 2 and I'll talk specifically to what will occur up to 3 and including 115% power. This just reflects our 4 current test plan, if you will, for this cycle to 111.

5 What this shows, in a broad view, is on 6 the y axis is the power level. You see 90 and 100 are 7 really baseline testing, and then we go 101, 102.

8 Those are those 1% steps Bill talked about. The 102.5 9 is a stop-point for us to take additional data. And 10 then what you see in -- and it just goes all the way 11 up to 111.5 -- some clarification on that -- the rows 12 in red, 105, 110 and 111.5 CF are the NRC-required 13 data transmissions. Those are the actual data packets 14 that will be sent of all the tests at those 15 requirements of our licensing condition.

16 Two other clarifications -- the 111.5 17 verus 111.5 CF -- the CF stands for cross-flow -- so 18 we'll bring the plant to 111.5%. We have a data 19 collection making sure we don't have any issues with 20 our cross-flow system, and then we'll put in the 21 correction factor of our venturis and maneuver to the 22 true most accurately defined 111%. That's why you see 23 111.5 twice on the chart.

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90 1 to 115%. This only, right now, captures our current 2 test plan for this cycle.

3 MR. WALLIS: So when you send this data to 4 the NRC, do you just send the whole other curves with 5 wiggles, or do you send some comparison with criteria 6 which have been established ahead of time or something 7 like that? What is it you send to them?

8 MR. DAVISON: We will send them all the 9 data. We will also send the comparisons which have 10 specifically defined acceptance limits in that.

11 MR. WALLIS: Okay. That's helpful.

12 MR. DAVISON: Correct. And it'll be the 13 same information we'll be sharing with Operations to 14 ensure that they're ready and concur with moving to 15 the next power level as well.

16 Across the top of the chart, percent power 17 being the leftmost column, the rest of the columns are 18 all the different tests that Bill went through. You 19 know, we talked about chem data. We talked about the 20 flow-induced vibration. I spoke to that.

21 The three grayed columns are the tests 22 that most translate to dryer performance -- main steam 23 on strain gauge which will be used to base off the 24 strain gauges, the loads that are going and inputting 25 on the dryer, running it through the finite element NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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91 1 analysis and coming up with the loads.

2 The moisture carryover Bill talked 3 specifically -- another secondary indication of some 4 type of dryer failure that would allow additional 5 moisture to carry over.

6 And then the main steam line 7 accelerometers will be used as a comparison and 8 validation of the strain gauge data to make sure that 9 there is no anomaly in the data where we're extracting 10 the dryer loading from the strain gauge data itself.

11 So those three columns grayed out are really 12 specifically related to the dryer. The rest of them 13 are just all of the bulk testing that we'll be doing 14 to make sure there's no other undetected anomalies in 15 the plant.

16 Tomorrow we'll go through the actual 17 specifics with Dr. Alan Bilanin here to actually go 18 through how we're going to do the analysis, what the 19 results will look, the graphs, the information that 20 we'll have to determine that we're below Level 1 and 21 Level 2 criteria and what happens when we go above the 22 Level 1 or Level 2 criteria.

23 CHAIR ABDEL-KHALIK: The test matrix at 24 115% will be identical to that at 111.5%, the very 25 last column --

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92 1 MR. DAVISON: That's correct. The 2 repetitiveness of that chart will continue down 3 through 115% ending in 115% with cross-flow applied 4 the whole data string across. So that'll just be a 5 continuation of that chart and we'll have that 6 tomorrow.

7 MEMBER ARMIJO: And that'll all be 8 completed in the following cycle, Cycle 16?

9 MR. DAVISON: No. We have no commitment 10 for actually uprating to the full 115% in our next 11 cycle. Primarily, what we wanted to do is get the 12 plant to 111.5%. That allows us to do all of our 13 testing, ensure that there are no anomalies. We will 14 monitor the plant's performance in the summer which is 15 the most taxing time of the year for the plant with 16 respect to performance. That data can then be 17 utilized to work with General Electric on what 18 modifications we may be doing on the high-pressure 19 turbine.

20 of course, the modification process that 21 I'm responsible for at the station has a lead time.

22 of course, the manufacturing process for General 23 Electric -- so we would not be putting that into the 24 next cycle just because we physically couldn't get it 25 done. Of course, we'd have to do all the business NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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93 1 analyses, because along with this, we'll be looking at 2 our cooling tower performance for summer months.

3 There is a whole environmental licensing 4 and modification process that would have to be 5 followed with respect to an addition of the cooling 6 tower to the site, a helper tower, if you will, if 7 that's what we need to do with our cooling tower.

8 So we do not have specific plans for the 9 next cycle, Cycle 16, only because of when we'll be 10 implementing this and the shortness until when that 11 next refuel outage is, which is in the spring of 2009.

12 MEMBER ARMIJO: Okay. But the 115%

13 testing will be done when you finally get --

14 MR. DAVISON: Correct, whether it was a 15 week later or five cycles later, our commitment will 16 be as soon as we go 111.5%, the next plateau, this 17 test matrix is back in place. Our testing center is 18 back and all the exact same testing methodology is 19 reapplied including transmittal of data to the NRC.

2.0 CHAIR ABDEL-KHALIK: Thank you for the 21 clarification.

22 MR. DAVISON: You're welcome.

23 CHAIR ABDEL-KHALIK: At this time, we'll 24 proceed with the staff presentation.

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94 1 Martin and I did the review for the human factors 2 portion of this EPU submittal. As you can see, we 3 reviewed the EOPs, AOPs, any human system interface 4 changes, SPDS, and training and simulator issues that 5 may have come up, and we wanted to ensure that this 6 did not affect the operator's performance adversely.

7 It's pretty straightforward. We didn't 8 have any new manual actions or changes to the 9 mitigation philosophies for the EOPs or AOPs. There 10 were some modifications to the parameters and some of 11 the levels because of decay heat because of the EPU, 12 and there were some setpoint changes as well.

13 In the realm of operator actions, we had 14 no new operator actions and the response times in 15 their safety evaluation that they credit are 16 unchanged, and the available times for the manual 17 actions and the action times for the manual actions 18 remain unchanged.

19 CHAIR ABDEL-KHALIK: Now there was a 20 question raised earlier about operator and manual 21 actions following an ATWS. And the question is do the 22 available times for manual actions change as a result 23 of EPU conditions?

24 MS. MARTIN: Okay. As part of my review, 25 I was informed that the manual action times -- you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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95 1 mean the actual time it takes the operator to perform 2 the action -- does not change -- is that what you were 3 asking me?

4 MR. WALLIS: Well, usually, it does in an 5 EPU.

6 MS. MARTIN: The actual time it takes them 7 to do the action?

8 MR. WALLIS: No. The available time.

9 MS. MARTIN: Available time?

10 MR. WALLIS: Right.

11 MS. MARTIN: I asked specifically, as part 12 of my review, do any of the actual -- available times 13 for the operator change, and I was told there weren't 14 change --

15 CHAIR ABDEL-KHALIK: So this statement is 16 based on response provided by the applicant rather 17 than an assessment as to whether or not there is a 18 potential for a change in the available times in 19 events such as ATWS required operator action to reduce 20 water level in the vessel?

21 MS. MARTIN: I'm sorry, could you restate 22 that?

23 CHAIR ABDEL-KHALIK: This statement or 24 this conclusion that the available times for manual 25 actions credited remain unchanged is simply based on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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96 1 input provided by the applicant rather than an 2 assessment, an independent assessment on your part as 3 to whether or not the available times would change?

4 MS. MARTIN: Yes.

5 CHAIR ABDEL-KHALIK: Okay. Would the 6 applicant care to provide any input into this as to 7 whether or not the available times would change?

8 MR. DUKE: This is Paul Duke. The number 9 of operator actions that are credited in design basis 10 analysis are relatively few. However, their times are 11 not changed. For example, in the containment response 12 analysis, it is assumed that containment cooling is 13 put into service after 10 minutes. That remains the 14 same. We understand the specific question with regard 15 to ATWS and water level, and we'll get additional 16 details on that specific question today. But in 17 general, the number of operator accidents credited are 18 relatively few in any design basis analysis and they 19 have not changed.

20 CHAIR ABDEL-KHALIK: I understand the 21 specified times in the procedures may not change, but 22 the analysis may indicate that the available times may 23 have changed, and that's the purpose of the question.

24 What is the change in the available times?

25 MR. DUKE: Well, for the example of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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97 1 containment response, the actions to put containment 2 cooling in service are no different for EPU versus 3 current licensed thermal power.

4 MR. WALLIS: I think it's the level 5 control that has to be done a little quicker.

6 MR. BOLGER: This is Frank Bolger from GE.

7 I wanted to point out that the Hope Creek does have a 8 system by which when there's a high pressure trip, 9 that will initiate a feedwater runback approximately 10 25 seconds after the pump trip. It also has an 11 automatic initiation of the SLC system.

12 MR. WALLIS: Yes., I think we've heard 13 that earlier, but usually, the level control shows up 14 when they do their probablistic safety analysis 15 because it turns out that the operator has less time 16 and then this, by some magic, is transferred into a 17 CDF. And this is usually how the CDF changes or one 18 of the dials that changes the CDF when you have an 19 EPU. I was a bit surprised that Hope Creek wasn't a 20 bit more specific saying its 10 minutes changes to 7 21 minutes or something specific like that.

22 CHAIR ABDEL-KHALIK: Is your implication -

23 24 MR. WALLIS: we're going to hear about 25 that later, right?

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98 1 CHAIR ABDEL-KHALIK: -- that these 2 automatic actions -- as a result of these automatic 3 actions, the available time for operator action from 4 lower to moderate levels do not track.

5 MR. BOLGER: This is Fran Bolger again.

6 There may be some other scenarios at which those 7 automatic actions would not occur. For example, if 8 the high-pressure trips do not occur, in those cases, 9 I think I would have to defer to PSEG for their 10 training of their operators.

11 MEMBER MAYNARD: I think we may be talking 12 about -- I don't know -- but I think it's important 13 that we get the distinction. I mean there's three 14 times that we're talking about -- the time that it 15 takes the operator to do an action, and apparently 16 that hasn't changed; the time credited for operator 17 action, and certainly that hasn't changed; but time 18 available before you would run into exceeding some 19 limit, I think, surely has to have changed for some of 20 these. It may not have changed any operator actions 21 or the time credited but I think that some of the time 22 before you would exceed a limit probably has changed.

23 MR. WALLIS: The available time must have 24 changed.

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99 1 Davison. PSEG understands the question and we will 2 provide a formal response to that so we can get you an 3 accurate answer to your question on available time.

4 CHAIR ABDEL-KHALIK: Thank you. Please 5 proceed.

6 MS. MARTIN: I also looked at the human 7 system interfaces and they didn't indicate any changes 8 that would occur due to the EPU that would affect the 9 operator's ability to interpret or visually see 10 anything they needed to. All of the changes will be 11 used with the design change process of PSEG.

12 The SPDS has a re-scaling in input-output 13 changes to feedwater control parameters due to the 14 EPU, and these are the curves that will be impacted by 15 the EPU. The training for operators to cover all the 16 changes due to the EPU will occur prior to 17 implementation, and these adverse event the simulator 18 updates that will occur due to the --

19 MR. WALLIS: Excuse me. Did anybody check 20 that these changes were appropriate? I mean we saw 21 all these changes to these curves. Did anybody check 22 that they're appropriate or you just accept the curves 23 as submitted?

24 MS. MARTIN: I don't actually look at the 25 curves. That's another group. Reactor Systems looks NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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100 1 at the acceptability of the changes to the curves.

2 MR. WALLIS: Reactor Systems looked at 3 those?

4 MS. MARTIN: Yes.

5 MR. WALLIS: Okay. So there was someone 6 who did review whether these were appropriate --

7 MS. MARTIN: Yes. That's later on.

8 Because of the few changes to credited operation 9 actions --

10 CHAIR ABDEL-KHALIK: Could you please go 11 back to the previous slide? Now you had gone through 12 this. Now my understanding is that operator training 13 has already been conducted. Is that correct?

14 MR. KOPCHICK: The question was has 15 operator training already been conducted prior to 16 plant operation at EPU conditions. That is correct.

17 Operator training on transient, steady-state, and 18 power ascension testing was completed. We also will 19 perform just-in-time training with each operating crew 20 prior to implementing the power ascension test 21 procedure.

22 CHAIR ABDEL-KHALIK: And the, I guess, the 23 simulator validation verification has already been 24 completed at 11.5% or at the 15%? You have two modes 25 of operation for the simulator?

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101 1 MR. KOPCHICK: Yes, sir, we do. We 2 operated the simulator at 111, 115% power to validate 3 that the simulator's response, as required by ANSI 3.5 4 and balance-of-plant testing, was acceptable. What is 5 outstanding by PSEG process is to document the results 6 of the that testing by our station procedures which 7 would then formally document the completion of the 8 ANSI standard test by April 13th.

9 CHAIR ABDEL-KHALIK: But nevertheless, you 10 went ahead and conducted the training --

11 MR. KOPCHICK: That's correct.

12 CHAIR ABDEL-KHALIK: -- with the simulator 13 as is?

14 CHAIR ABDEL-KHALIK: Yes, sir.

15 MR. DAVISON: Paul Davison. And the final 16 piece of that -- well, once we operate the plant 17 physically at that new power level, there will be 18 other comparisons and validation back to the simulator 19 with real plant data.

20 CHAIR ABDEL-KHALIK: Thank you.

21 MS. MARTIN: In conclusion, with respect 22 to human factors and the changes that will be made due 23 to the EPU, we found the things that were identified 24 by PSEG to be acceptable and that's it.

25 CHAIR ABDEL-KHALIK: Any questions for Ms.

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102 1 Martin?

2 (No audible response.)

3 CHAIR ABDEL-KHALIK: Thank you.

4 MEMBER BONACA: You will have an answer to 5 the question that you raised before regarding 6 available time, right?

7 CHAIR ABDEL-KHALIK: Correct. Yes, the 8 applicant will provide a response.

9 MR. DAVISON: That's correct.

10 MR. RAZZAQUE: This is Muhammad Razzaque 11 and I need to make an announcement. We agreed that 12 we'll be presenting early, but one of our reviewers 13 got an emergency call, and he is out now. He may not 14 be here in this period, so if there is any questions 15 me or Tony cannot answer, we have to get back to you 16 it looks like.

17 CHAIR ABDEL-KHALIK: Now we can probably 18 proceed with your part of the presentation and then 19 take a lunch break. And then at that point, we'll 20 make sure that everybody on your team who can directly 21 answer any questions that might come up can actually 22 be here.

23 MR. WALLIS: Excuse me. We're hearing the 24 staff's view of these things before we hear the 25 applicant's?

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103 1 MS. ABDULLAHI: It's an open and closed 2 session.

3 MR. WALLIS: Oh, it's an open and closed.

4 MS. ABDULLAHI: Right. This would be an 5 open session --

6 MR. WALLIS: Then we're going to have a 7 closed session from the applicant. That's why we're 8 doing it in this order?

9 MR. RAZZAQUE: Myself again, Muhummad 10 Razzaque and here, Nakanishi. Two of us will present 11 most of the material. Tony will discuss the fuel 12 methods, and I will provide the rest of the 13 information. I was mentioning about the reviewer, Dr.

14 Tai Huang -- he got the emergency call out, so he 15 should be back whenever he is.

16 MS. ABDULLAHI: This is Zena. If there's 17 a section, he's covering, we'll just postpone and 18 reschedule within some other slot.

19 MR. RAZZAQUE: Okay. He is -- he was not 20 planning to present unless -- as a support he was 21 here. Review scope -- the assistance branch looked at 22 the fuel system and nuclear design, thermal-hydraulic 23 design, overpressure protection, SLC system, transient 24 analysis, LOCA, ATWS and GE methods which Tony is 25 going to talk about after me.

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104 1 Fuel method was based on the generic 2 accepted -- NRC-accepted guidelines which basically 3 are ELTR-l and ELTR-2. Although this is a constant 4 pressure uprate since there is some legacy fuel still 5 in there, although they should not be limiting -- they 6 will be non-limiting, still, technically, ELTR-l and 7 ELTR-2 is the main guidance that were followed. And 8 all of them are NRC-approved methodologies.

9 The ACR was written on the format RS-001.

10 Review of system and nuclear engineering design, Cycle 11 15, the current cycle which would be the first EPU 12 cycle, predominantly GE fuel and some remaining 13 average of thrice burnt Westinghouse fuel, SVEA-96 14 fuel. SVEA-96 is expected to operate at less than --

15 well-below GE power and also at pre-EPU level and 16 expected that it will not be limiting. It will be the 17 GE fuel which should be the limiting.

18 MEMBER ARMIJO: Now I'm a little confused.

19 I heard or I saw in one document that there was some 20 twice burnt SVEA fuel in the core right now --

21 MR. RAZZAQUE: Yes.

22 MEMBER ARMIJO: -- and it's to just thrice 23 burnt?

24 MR. RAZZAQUE: That's right, eight of them 25 to be exact. Out of 764, 216 is the SVEA fuel. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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105 1 out of 216, 8 are twice burnt and the rest are thrice 2 or more. So on the average, their burn up is thrice.

3 Average burn up in the core is thrice.

4 MEMBER ARMIJO: Okay.

5 MR. RAZZAQUE: We can get --

6 MEMBER ARMIJO: You'll show us on the core 7 map where those things are?

8 MR. RAZZAQUE: Do you have that, Tony?

9 MR. NAKANISHI: We can provide that. This 10 is Tony Nakanishi with Reactor System. We can provide 11 that or the licensee may even --

12 MEMBER ARMIJO: Yes, if PSEG is going to 13 show that, I can wait.

14 MR. RAZZAQUE: Right. And we requested 15 for the power level that is expected in SVEA fuel 16 compared to GE fuel, and we have verified that it is 17 well-below GE power level. The way they placed them 18 in the core, particularly those eight bundles, the 19 power is still well-below GE bundle power level. That 20 we have verified.

21 Each bundle power will increase by about 22 4.4% which is the exact number being -- 6.8 megawatts 23 thermal to 7.2 megawatts thermal, which is about 4.4%V 24 and which is within the experience base that EPU has.

25 Normally, it ranges from 3 to 5-6%.

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106 1 MR. WALLIS: Why do you put thermal in 2 here?

3 MR. RAZZAQUE: Pardon me?

4 MR. WALLIS: I just wonder why you had to 5 put thermal in here? I mean would it be anything else 6 but thermal power you worry about?

7 MR. RAZZAQUE: Just to show how the big 8 bundle increases, what percent the big bundle 9 increased. That's just to give you an idea. It is 10 not a thermal limit. Just to give a sense. We know 11 that the average bundle increases 15%.

12 MR. WALLIS: Yes.

13 MR. RAZZAQUE: And big bundle doesn't stay 14 the same. It increases a little bit. That's all we 15 are trying to say. And it varies sometimes 5%, 6%.

16 This plant happened to have 4.4%. It's just a piece 17 of information. There is no regulatory connection to 18 that.

19 The thermal limits are the fourth bullet, 20 SLMCPR, OLMCPR, MAPLHGR, and LHGR, those are the legal 21 limits that have to be met. And they are determined 22 for each reload cycle including any mid-cycle 23 modifications which, in this case, will be the EPU.

24 And the hot excess reactivity and shutdown follows 25 GESTR-II which is the approved GE method.

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107 1 Thermal hydraulic design stability relies 2 on Option-III, and reload analysis will follow the 3 staff-approved methods and hence acceptable.

4 Equipment and startup reveal no changes required. So 5 this is information which was verified by the staff 6 that the equipment -- there was no change required for 7 the EPU as far as the equipment is concerned.

8 Setpoints for detection and suppression established 9 using the approved methods. And there will be a 10 generic penalty on the bypass void penalty as required 11 by the generic report, NEDC-33173P-A.

12 MEMBER BONACA: Now in addition to -- I'm 13 sorry.

14 CHAIR ABDEL-KHALIK: Go ahead, please.

15 MEMBER BONACA: In addition to the Option-16 III long-term solution, there is a backup system, 17 right?

18 MR. RAZZAQUE: There is a back up system?

19 MEMBER BONACA: I'm sorry?

20 MR. RAZZAQUE: Yes, there is a backup 21 system.

22 CHAIR ABDEL-KHALIK: Now this change, 23 11.5% power increase, will have a mid-cycle, so the 24 core that's in there is the core that's going to be 25 operated at 111.5%?

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108 1 MR. RAZZAQUE: Right.

2 CHAIR ABDEL-KHALIK: The reload analysis 3 that was presented prior to the beginning of Cycle 15, 4 were these analysis performed at the current licensed 5 thermal power?

6 MR. RAZZAQUE: It was at EPU. There has 7 been a server provided to the staff for EPU and that 8 is what we looked at for EPU. There may have been one 9 done for the current power level, too, but we didn't 10 look at that. We look at the EPU server to verify 11 some of the conclusions that we made.

12 CHAIR ABDEL-KHALIK: Okay. Thank you.

13 MEMBER BONACA: So I'm trying to 14 understand -- the protection system is already set at 15 115% power, and then you're operating all the way down 16 from 100% which is now going to be maybe 90% or 17 whatever to 97% and then later on to 100% of 115%

18 power? That's what you've done?

19 MR. RAZZAQUE: We are approving 15% and 20 we're expecting that will bound everything below. So 21 we reviewed one analysis which is 115%. There is the 22 ultimate objective. So based on that 115%, the 23 analysis -- the results that I will present will be, 24 again, based on the 115%. The first one here is the 25 overpressure protection results which was typically NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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109 1 done at 102% of 115%.

2 CHAIR ABDEL-KHALIK: Now in your 3 assessment of the overpressure protection, have you 4 looked at the history of the Hope Creek SRV 5 performance?

6 MR. RAZZAQUE: We did not specifically 7 look at the history.

8 CHAIR ABDEL-KHALIK: So what assumptions 9 are made in your assessment of the peak pressures 10 calculated --

11 MR. RAZZAQUE: One of the key --

12 CHAIR ABDEL-KHALIK: -- pressure 13 transients?

14 MR. RAZZAQUE: One of the -- there are few 15 key assumptions. One is that the SRV drift setpoint 16 will be within 3% plus or minus. That is the approved 17 limit. Another key assumption is that out of 5 SRVs -

18 - I believe I remember the number correctly -- one 19 will not open at all.

20 CHAIR ABDEL-KHALIK: Okay. Now --

21 MR. RAZZAQUE: Those are the like 22 assumptions that we look at --

23 CHAIR ABDEL-KHALIK: The question still 24 remains. Does the history of Hope Creek SRV 25 performance comply with the 3% tech spec limit on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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110 1 setpoint?

2 MR. RAZZAQUE: My understanding is that it 3 should be -- it's required to be, because tech specs 4 require that they have to be within plus or minus 3%.

5 And also, the -- it may be -- the licensee may correct 6 me, but for each cycle, each outage, they have to take 7 certain number of those SRVs and test and see whether 8 it stayed within that band.

9 CHAIR ABDEL-KHALIK: I fully understand 10 that. But the question is have you done an 11 independent examination as to whether or not this 12 assumption is indeed valid?

13 MR. RAZZAQUE: We have not done that 14 independent verification. There are certain 15 guidelines and regulations that the licensee will have 16 to follow. And as I said, that's what it is. Each 17 outage they have to be tested, and if it is exceeded 18 3%, it should be reported to NRC as a routine basis.

19 And when it is put back, it should be refurbished back 20 to 0% -- or within 1%, I think.

21 CHAIR ABDEL-KHALIK: So you do have access 22 to that information because if the setpoints had 23 indeed exceeded the 3% limit, they would have notified 24 the NRC.

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ill 1 regulations, I think. That's my understanding -- it 2 is reported as the LAR. And there is a whole data 3 available for each plant, so if we wish to, we could 4 go back and review it.

5 MR. DAVISON: That is correct. In 6 addition to the -- Paul Davison -- in addition to the 7 history that I'll be providing to you -- we're pulling 8 that for you now -- in the event that we have a number 9 of SRVs that would fail their 3% accuracy 10 requirements, we would have submitted that for the LER 11 process. That would have been a violation of our tech 12 specs that would have been clearly transmitted to the 13 NRC. But I will have the full listing of our failure 14 rates to the subcommittee.

15 CHAIR ABDEL-KHALIK: So if indeed there is 16 sort of a trend or a history of failure to meet the 17 tech spec limits or failure to even open, would the 18 staff go back and re-evaluate the overpressure 19 analyses in light of that data?

20 MR. RAZZAQUE: I'll tell you what we did.

21 Many years ago actually, I was directly involved in 22 that. It was a tech spec limit was 1%, plus or minus 23 1%, and the industry found that this is too tight.

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112 1 world. And we did an extensive review on that, looked 2 at the data set and everything based on industry. And 3 we also agreed to that, that 3 would be a reasonable 4 number. And we haven't done anything after that --

5 that is true -- except that if there is a noticeable 6 trend we observe, we will get to that specific 7 licensee. But generally, it is approved for 3%.

8 CHAIR ABDEL-KHALIK: So without sort of --

9 MR. RAZZAQUE: And it was based on a study 10 done and found to be industry-wide -- to us, found 11 acceptable to extend the range up to 3% without 12 affecting these results significantly -- I mean 13 staying within the limits and sort of like a tradeoff.

14 Like you're to be realistic. At the same time, we 15 have to meet our regulation. And 3% was decided that 16 was the one.

17 CHAIR ABDEL-KHALIK: So we will await the 18 data to be provided before we may possibly revisit 19 this issue.

20 MR. DAVISON: Correct.

21 CHAIR ABDEL-KHALIK: Thank you.

22 MR. RAZZAQUE: And based on those 23 assumptions that I mentioned, the results came out to 24 be within the limits. Obviously, they have to be to -

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113 1 1325 psig, and they met that. And SRV setpoint 2 changes were not necessary because it was a constant 3 pressure power uprate. Again, this would be analyzed 4 each reload. Each reload, it will be re-analyzed.

5 Standby liquid control system, as the 6 licensee indicated, they have both features normally 7 as well as -- the normal is manual, but it can be 8 automatic. The 86 gpm boron equivalency is satisfied.

9 We verified that. Sufficient margin in the pump 10 discharge relieve vales. Since the pressure increased 11 a little bit, the discharge pressure also increased a 12 little but. But still, there is plenty of margin at 13 the setpoint.

14 CHAIR ABDEL-KHALIK: I'm sorry, which 15 pressure has increased?

16 MR. RAZZAQUE: The discharge. The peak 17 pressure in the vessel will increase because of the 18 EPU.

19 CHAIR ABDEL-KHALIK: Okay.

20 MR. RAZZAQUE: And therefore, the pump 21 discharge pressure will increase, and we have to make 22 sure that the -- it's not too close to the SRV 23 setpoint. Otherwise, there will be an opening. And 24 that was verified and found to be a sufficient margin.

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114 1 not open during --

2 MR. RAZZAQUE: They do not -- they're not 3 expected to open, but in the analysis, one is allowed 4 to open. In the analysis --

5 MR. WALLIS: It's allowed to open.

6 MR. RAZZAQUE: -- one is allowed to open.

7 Concentration -- 660 production manager does not 8 change from before EPU or after EPU, and it is 9 confirmed for every reload cycle, before every reload 10 cycle.

11 CHAIR ABDEL-KHALIK: So with the core 12 design, it turns out that it takes the same boron 13 concentration to provide adequate shutdown margins if 14 all the rods are not inserted? It turns out to be 15 exactly the same? Is this fortuitous?

16 MR. NOTIGAN: This is Don Notigan, PSEG.

17 We've confirmed no change in the amount of standby 18 liquid control system for cold shutdown at EPU.

19 CHAIR ABDEL-KHALIK: Okay.

20 MR. RAZZAQUE: If you like, I can add to 21 that. The just plain -- higher power does not 22 necessarily change the concentration. It is a 23 combination of things like fuel batch fraction, 24 enrichment or new fuel design. Those we may change 25 but this part alone will not do it.

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115 1 CHAIR ABDEL-KHALIK: I understand.

2 MR. RAZZAQUE: And it doesn't change here.

3 AO0 transient analysis, there are three categories of 4 transient analysis broadly can be divided. One type is 5 to set the operating limit MCPR, and it turns out to 6 be turbine trip which is the one that set that.

7 MEMBER BANERJEE: With or without bypass -

8 9 MR. RAZZAQUE: No bypass.

10 MEMBER BANERJEE: We thought that with 11 bypass, sometimes it's more limited.

12 MR. RAZZAQUE: It could be, but in this 13 case, the -- as I'll show, either load reject nor 14 bypass -- turbine trip --

15 MEMBER BANERJEE: Are we going to discuss 16 this in more detail later one, these matters?

17 MR. RAZZAQUE: No, not -- we don't plan 18 to. We look at the limiting events and for each 19 category. There are several analyses required by 20 ELTR-l to be performed and find out which is the 21 limiting one. It turns out --

22 MEMBER BANERJEE: Well, let me understand 23 this. Do you do the uncertainties? In the void 24 correlation, there's a penalty put on the OLMCPR? How 25 much is that. Point?

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116 1 MR. NAKANISHI: This is Tony Nakanishi.

2 Point o one -- .01.

3 MR. WALLIS: I'm sorry. I'm confused.

4 I'm looking back at my notes. The peak ATWS pressure 5 is 1400-and something? We're trying to figure out 6 these pressure limits you've got here. Is ATWS 7 something different from what you --

8 MR. RAZZAQUE: Like the previous slide?

9 MR. WALLIS: -- different from what you're 10 talking about with overpressure protection? You're 11 going to talk about the ATWS pressure in some place?

12 Because if the ATWS pressure is higher than the SLC 13 pressure, that gives rise to recirculation --

14 MR. RAZZAQUE: Are you talking about the 15 MSIV closure?

16 MR. WALLIS: No. I'm talking about the 17 ATWS situation where the peak pressure is higher than 18 the SLC pressure so that you get recirc -- SLC valve 19 opens, overpressure valve opens during an ATWS, 20 recirculates for a period of time. The pressures are 21 higher than the pressures you talk about here. That's 22 a different topic, is it? You're going to talk about 23 that sometime or is someone going to talk about that?

24 MR. RAZZAQUE: This is all that you are 25 seeing is for the MSIV closure with --

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117 1 MR. WALLIS: Right, but the ATWS has 2 higher pressures than that.

3 MR. RAZZAQUE: ATWS pressure, we are going 4 to talk about ATWS.

5 MR. WALLIS: At some other time, okay.

6 MR. RAZZAQUE: Yes. Actually --

7 MR. WALLIS: I was just wondering --

8 trying to put this in context. You're going to get to 9 that at some -- okay -- that's all right.

10 MR. RAZZAQUE: Yes. We were talking about 11 the AQOs, anticipated operational occurrences, and 12 they're -- that's --

13 MEMBER BANERJEE: They have some 14 Westinghouse fuel in there. That GE method is sort of 15 approved for this?

16 MR. NAKANISHI: This is Tony Nakanishi.

17 We'll discuss more in terms of the GE methods 18 capability to model SVEA fuel, but we --

19 MEMBER BANERJEE: So will you go into the 20 OLMCPR at that point a little bit?

21 MR. NAKANISHI: Sure. I guess we need to 22 be careful not to get into proprietary information.

23 MEMBER BANERJEE: Right. Well, when are 24 we going to close the session?

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118 1 lunch.

2 MR. RAZZAQUE: Tony will discuss about 3 that matter at that time. The second category --

4 MEMBER BONACA: What about SLMCPR, are you 5 going to discuss that as well?

6 MR. NAKANISHI: We certainly can and the 7 planned presentation wasn't covering that, but we can 8 certainly discuss that further as a --

9 MEMBER BONACA: So -- but somebody's 10 planning to talk about ATWS?

11 MR. RAZZAQUE: Yes.

12 MEMBER BONACA: I didn't hear -- yes.

13 Okay. So there will be a discussion. I agree with 14 you that it is not part of the anticipated 15 occurrences, but we'll talk about ATWS.

16 MR. DelGAIZO: Excuse me. I'm a 17 mechanical engineer on the EPU project. On the 18 question of the SLC relief valve, the analysis -- when 19 SLC is credited in the analysis, those peaks have all 20 passed. The timer which has the time delay, it 21 ensures that SLC is initiated so that the peaks are 22 gone and the relief valve does not lift. However, if 23 the system is initiated earlier and the relief valve 24 does lift, there's a large margin required on the 25 reset to be sure that that relief valve is closed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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119 1 before SLC is required in the system. So the relief 2 valve could lift. It will recede. And if it goes on 3 the timer, it will not lift. And that's how the 4 analysis deals with it.

5 CHAIR ABDEL-KHALIK: But we will discuss 6 ATWS at a later time if necessary in the closed 7 session.

8 MR. RAZZAQUE: I was going to present the 9 result here in the open session.

10 CHAIR ABDEL-KHALIK: We'll do that after 11 lunch. But specific questions regarding operating 12 limit MCPR and safety limit MCPR, if necessary, we can 13 discuss them in a closed session. Please continue.

14 MR. RAZZAQUE: Okay. The overpressure 15 event is the MSIV closure with flux scram, and the 16 minimum water level transient is the loss of feedwater 17 flow.

18 LOCA wasa based on SAFER/GESTR codes using 19 equilibrium core. The licensing basis PCT for GE-14 20 was 1380 degrees Fahrenheit; and for SVEA-96, it was 21 1540 degrees Fahrenheit.

22 CHAIR ABDEL-KHALIK: Now this is an 23 interesting result. I mean we've been told that this 24 legacy fuel has a lot lower power than the GE-14 fuel, 25 and yet your LOCA analysis calculates a higher peak p-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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120 1 clad temperature in the legacy fuel than in the GE-14 2 fuel. Could you explain physically what's going on?

3 MR. RAZZAQUE: Yes. I'll try to explain.

4 And basically to give some understanding how -- and 5 I'll explain my understanding of how GE calculates 6 these numbers. And the way these numbers are --

7 MR. NAKANISHI: It's not proprietary, is 8 it?

9 MR. RAZZAQUE: Pardon me?

10 MR. NAKANISHI: Is it proprietary?

11 MR. RAZZAQUE: I don't think so. It's a 12 methodology -- should know. Yes, SAFER/GESTR method.

13 Yes, that is proprietary. I'm not talking about that, 14 but the process -- I'm talking about the process. The 15 process is that you assume equilibrium core, and 16 equilibrium core assumes one kind of fuel, either GE-17 14 or SVEA-96. It doesn't assume at the same time.

18 It does assume one at a time. Okay? So you calculate 19 use, for example, with GE-14 fuel, but the key 20 parameter which affects the PCT is the value of the 21 MAPLHGR, maximum average planar heat generation rate.

22 Actually, the code asks more of that. A 23 code really needs the input of average planar linear 24 heat generation in the exhale direction, and the peak 25 one is the MAPLHGR and that affects the PCT directly.

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121 1 Okay, so when they do the calculation for a given 2 core, given cycle, given fuel, assuming other 3 variables are -- should be correctly, they assume the 4 maximum possible MAPLHGR for that cycle and generate 5 the PCT for that fuel and did the same thing assuming 6 the maximum possible MAPLHGR for Westinghouse fuel, 7 and that gave a higher PCT.

8 But in the real core, it won't be like 9 that. It will be combined -- both fuel together and 10 there, the data showed that the MAPLHGR value would ii always be less than GE fuel. And therefore, the 12 assumption that -- when they calculated 1540 degrees 13 Fahrenheit, the MAPLHGR never is going to reach there, 14 in reality. It will be below, always below GE 15 MAPLHGR. And therefore, MAPLHGR value is the limited 16 value which we should look for.

17 And another information is that they do 18 not calculate, they do not run a LOCA analysis for 19 each reload. All they do is go and verify it that the 20 MAPLHGR is within the limit. If the MAPLHGR is, the 21 PCT is validated. Well, that's the process involved.

22 CHAIR ABDEL-KHALIK: So a LOCA analysis 23 was really not done for the Cycle 15 core as is?

24 MR. RAZZAQUE: It has been validated. It 25 has been -- by MAPLHGR.

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122 1 CHAIR ABDEL-KHALIK: I understand --

2 MR. RAZZAQUE: Yes.

3 CHAIR ABDEL-KHALIK: -- the way you -- but 4

5 MR. RAZZAQUE: Right. And --

6 CHAIR ABDEL-KHALIK: -- as is, would the 7 distribution of a fuel as is --

8 MR. RAZZAQUE: Right, unless there is --

9 CHAIR ABDEL-KHALIK: -- was not actually 10 done because it's part of a reload analysis for Cycle 11 15? Is that correct?

12 MR. RAZZAQUE: -- unless there is some 13 change in other parameters which they will then have 14 to redo it. But I don't know exactly when it was 15 done. Maybe you can --

16 MR. BOLGER: This is Fran Bolger from GE.

17 The way staff explained it is correct. You know, the 18 analyses are done with full cores of the two different 19 type, and those analyses are designed to be bounding 20 with respect to what would occur in a next core.

21 MR. WALLIS: And that's done for an 22 equilibrium core?

23 MR. BOLGER: That's correct.

24 MR. WALLIS: Now if it's done for a non-25 equilibrium core, now much does the PCT change? If NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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123 1 it's done for the core evolves -- how much does the 2 PCT change as the core evolves during a cycle? Have 3 any idea?

4 MR. BOLGER: Just sort of weighing whether 5 this is a closed session discussion or not.

6 CHAIR ABDEL-KHALIK: If it is, we can wait 7 until after lunch.

8 MR. BOLGER: Okay. Why don't we wait.

9 MR. WALLIS: Postpone it. Okay, that's 10 fine.

11 CHAIR ABDEL-KHALIK: Okay. I have another 12 question. Are these two-bundle designs hydraulically 13 matched?

14 MR. RAZZAQUE: The effect on LOCA is not 15 that significant.

16 CHAIR ABDEL-KHALIK: Regardless, the 17 question is are they hydraulically matched?

18 MR. RAZZAQUE: When originally a mixed 19 water analysis was done -- that was done many years 20 ago -- there have to be some pressure drop tests to 21 make sure that the assemblies have compatible pressure 22 drop. I think that probably would be the key 23 parameter which will effect, but the LOCA, it really 24 doesn't matter that much. But it does in the 25 transient.

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124 1 CHAIR ABDEL-KHALIK: Okay. Thank you.

2 MR. RAZZAQUE: Yes. And mixed water 3 analysis was approved many years ago. I don't know 4 when they first started using GE, but this one is --

5 we didn't' go reviewing the mixed core approval.

6 Basically, looked at the EPU.

7 MEMBER BANERJEE: So the hydraulic 8 characteristics are very similar, the fuel? I didn't 9 get the sense of the answer.

10 MR. NOTIGAN: This is Don Notigan, PSEG.

11 To support the EPU licensing, PSEG submitted on our 12 docket a thermal-hydraulic compatibility assessment 13 and report that has the details of how the GE 14 methodology was utilized to analyze the thermal-15 hydraulic performance of the SVEA fuel. In that 16 report, we concluded that introduction of the GE fuel 17 at that time into the Hope Creek core, which had had 18 SVEA-96 plus fuel in it, did not cause any change in 19 thermal-hydraulic imbalance.

20 MEMBER BANERJEE: Will the fuel there, 21 fossil or whatever it is, and the GE fuel, did they 22 have similar thermal-hydraulic characteristics? I 23 mean it's a straight question -- yes or no.

24 MR. NOTIGAN: They have similar, yes.

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125 1 different. I have slides to illustrate the 2 difference. And because of that difference, the 3 active flow through the two designs are slightly 4 different.

5 MEMBER BANERJEE: I think we should 6 discuss this in closed session.

7 MEMBER MAYNARD: Well, don't you take a 8 penalty in the analysis anytime you have a non-9 homogeneous core? I mean doesn't the analysis that 10 you do have some penalty into it when you've got 11 different types of fuel assemblies -- penalty?

12 MR. NAKANISHI: This is Tony Nakanishi 13 with Reactor Systems. I could add that sometime ago, 14 the licensee submitted a critical power correlation 15 supporting the SVEA fuel, and staff reviewed that and 16 approved that.

17 MEMBER BANERJEE: What about the void 18 correlation?

19 MR. NAKANISHI: Again, I guess we could 20 probably defer that to closed session.

21 MEMBER BANERJEE: Maybe, you know, we need 22 to know a little more details, Said, on this.

23 MR. NAKANISHI: Basically --

24 CHAIR ABDEL-KHALIK: When we're in closed 25 session, you can ask these detailed questions and, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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126 1 hopefully, both the staff and the applicant --

2 MEMBER BANERJEE: Hopefully, we will 3 understand the uncertainty in the void fraction for 4 the SVEA fuel? Do we have data?

5 MR. NAKANISHI: The approach that GE or 6 the licensee is taking is they're applying their NRR 7 methods topical which includes some of these --

8 accounts for these additional margins. We can discuss 9 that more in the closed session.

10 MR. WALLIS: How does MAPLHGR validate a 11 PCT?

12 MR. RAZZAQUE: How does it validate PCT?

13 MR. WALLIS: MAPLHGR has nothing to do 14 with LOCA, does it?

15 MR. RAZZAQUE: Yes.

16 MR. WALLIS: MAPLHGR is just for the heat 17 generation rate?

18 MR. RAZZAQUE: That's right and it affects 19 the stored energy, and therefore, ultimately the PCT.

20 MR. WALLIS: It'S an input to a PCT 21 calculation.

22 MR. RAZZAQUE: Exactly. That's --

23 MR. WALLIS: It doesn't validate. It's 24 just an input to it --

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127 1 input.

2 MR. WALLIS: -- if it's low enough --

3 MR. RAZZAQUE: The validate means that 4 when they design the core, they calculate the MAPLHGR 5 for that core and see whether it is less than the one 6 which was sued to calculate the PCT. That is the 7 validation.

8 MR. WALLIS: But it's not -- but more 9 things than just MAPLHGR influence PCT --

10 MR. RAZZAQUE: Yes, there are many things, 11 but the marketplace is the one --

12 MR. WALLIS: It's a sort of DPTC, D-13 MAPLHGR that you've -- someone's established so that 14 you know how one influences the other?

15 MR. RAZZAQUE: Assuming the other 16 variables --

17 MR. WALLIS: Maybe this can be explained 18 in a closed session or something? I'm confused.

19 MR. NAKANISHI: Or I guess I could say 20 that the baseline analysis, it will basically provide 21 sufficient leeway for cycle-specific differences. And 22 really, the key change from cycle to cycle is covered 23 by MAPLHGR.

24 MR. WALLIS: This is part of what I was 25 told would be answered in a closed session, is it?

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128 1 MEMBER ARMIJO: Or it would be --

2 MR. WALLIS: I think it is.

3 MEMBER ARMIJO: -- or you could get it.

4 MR. WALLIS: I'm going to get the answer 5 in the closed session.

6 CHAIR ABDEL-KHALIK: I think we'll have 7 more leeway to ask questions and receive answers 8 during that time.

9 MEMBER ARMIJO: I have maybe a very simple 10 question. Is SAFER/GESTR approved for use on SVEA-96, 11 or was it just an analysis that was done sort of 12 interesting but not really an approved analysis.

13 MR. RAZZAQUE: The process that works is -

14 - the way that was approved is that the -- when the GE 15 -- you have a GE core using GE methods. Now another 16 fuel is introduced. The -- first of all, there has to 17 be thermal-hydraulic compatibility with those two 18 bundles, and they have to be verified and checked.

19 And the other is that the licensee or the vendor or 20 both has to get enough information from the other 21 vendor about the fuel to perform the analysis. After 22 you get all the information that you need, which is 23 basically the information like fuel itself, like the 24 density, material properties, flow dimension and those 25 kind of things, then you use your code, GE code, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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129 1 assuming it's like a GE bundle although the dimensions 2 are different for every --

3 MEMBER BANERJEE: But here is the issue, 4 I think which --

5 MEMBER ARMIJO: It's more legal.

6 MEMBER BANERJEE: Yes, but what Sam and I 7 are both getting at is do we have the same database 8 with the SVEA-96 plus fuel, and maybe you need to 9 answer this in closed session, as we have with GE 10 fuel? We understand GE fuel because we have dealt 11 with this previously in approving things and so on.

12 So we know a lot about GE fuel. Do we know the same 13 about this Westinghouse fuel? I guess that's the 14 issue and the uncertainties in the various critical 15 power issues and the void fraction correlation.

16 MR. WALLIS: Do you use the same void 17 fraction correlation for the two?

18 MR. NAKANISHI: I believe the -- and GE or 19 licensee can correct me, but I believe that is true.

20 MR. WALLIS: Someone's checked that the 21 test is valid, equally valid --

22 MR. NAKANISHI: I guess --

23 MR. WALLIS: -- or bias in one way with 24 one fuel versus the other?

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130 1 staff additional conflict is the SVEA fuel has been 2 exposed a few times.

3 MR. WALLIS: Oh, yes, that's right.

4 MR. NAKANISHI: And if SVEA fuel were as 5 reactive as GE-14 fuel, for example, then we would be 6 a lot more concerned, and we would be providing a lot 7 more review associated with that.

8 MEMBER BANERJEE: If they go reload it, 9 will there be --

10 MEMBER ARMIJO: Well, I don't know if the 11 issue will come up.

12 MEMBER BANERJEE: Will that issue come up 13 at that point, or how will it be handled?

14 MR. NAKANISHI: They did the transition, 15 I believe, obviously, at a pre-EPU condition.

16 MEMBER BANERJEE: Will you feel more 17 comfortable to answer these questions when we were in 18 closed session?

19 MR. NAKANISHI: Absolutely.

20 MEMBER BANERJEE: Okay.

21 MR. WALLIS: Let's do that.

22 MR. RAZZAQUE: Actually, the way I 23 understand -- licensee may correct me -- they are 24 going to phase Westinghouse fuel out after Cycle 15, 25 or at most 16 maybe. Is that -- Cycle 16 will still NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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131 1 have some fuel left and then after that, no fuel?

2 MR. NOTIGAN: This is Don Notigan, PSEG.

3 We are looking at the core design requirements for 4 Cycle 16. We're starting that right now. And right 5 now it looks like preliminary, we will not have the 6 SVEA fuel in the next core in Cycle 16.

7 MR. RAZZAQUE: Basically, you're talking 8 about half a cycle, maybe less than that.

9 MEMBER BONACA: And when you did LOCA 10 analysis, what fuel did you use? Did you assume that 11 GE fuel would be limiting and then you assumed full 12 characteristics of the GE fuel to determine PCT? I 13 mean this is a mixed core and I'm trying to understand 14 how you do the thermal-hydraulic analysis, 15 SAFER/GESTR. What kind of fuel-related parameters are 16 you using?

17 MR. RAZZAQUE: Why the two separate PCT 18 was generated -- one for GE fuel, another for the 19 Westinghouse fuel --

20 MEMBER BANERJEE: Yes.

21 MR. RAZZAQUE: -- deeper.

22 MEMBER BANERJEE: But assuming separately, 23 then first of all you have full GE fuel or full SVEA 24 fuel?

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132 1 have the information for SVEA fuel to use that in the 2 code to calculate the PCT, and it turns out to be 3 different, higher actually, if you use the same 4 MAPLHGR.

5 MEMBER BANERJEE: Why is that?

6 MR. RAZZAQUE: That --

7 MEMBER BANERJEE: Well, it's --

8 MR. RAZZAQUE: It may be the fuel design 9 itself basically, because the fuel itself, the 10 thickness and the diameter and the material properties 11 will affect. And I can see that probably would be the 12 reason if we assumed, say, MAPLHGR and if all other 13 inputs are the same for the vessel and the core, the 14 geometry of the fuel probably would be the responsible 15 for change.

16 MEMBER BANERJEE: But this fuel is 17 supposed to have similar thermal-hydraulic 18 characteristics, right?

19 MR. RAZZAQUE: But not necessarily 20 material properties.

21 MEMBER BANERJEE: Well, is the cladding 22 different or --

23 MEMBER BONACA: Well, for one, the 24 cladding is twice-burnt or three-times burnt.

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133 1 number 1540 is coming when you've loaded the core with 2

3 MR. WALLIS: It's an equilibrium core full 4 of SVEA fuel. IT's an artificial.

5 MEMBER BANERJEE: So it's two artificial 6 cases because that's not the core in -- but they 7 should be two comparable cases, right? And two 8 comparable cases, you're getting some difference which 9 may not be important but it should be reconciled in 10 some way?

11 MEMBER BONACA: Yes. For example, you 12 know --

13 MEMBER BANERJEE: Why is different.

14 MEMBER BONACA: -- I look at this loading 15 and the four assemblies in the center of the core SVEA 16 fuels, so now, you know, my question that comes to 17 mind is will the flow preferentially goes in the SVEA 18 fuel versus the GE fuel? I don't know. I mean that's 19 the kind of questions we're raising, I believe, here.

20 And --

21 MR. RAZZAQUE: We reviewed --

22 MEMBER BONACA: -- then you have to take 23 into account the cladding is different cladding, in 24 this particular case, at least twice-burnt, I think.

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134 1 burnt as you said.

2 MR. WALLIS: The hot channel is GE fuel, 3 isn't it?

4 MR. RAZZAQUE: Yes, correct.

5 MR. WALLIS: So why do a PCT with SVEA 6 fuel?

7 MR. RAZZAQUE: Again, if you assume the 8 same MAPLHGR which you are assuming is this whole 9 bundle SVEA fuel.

10 CHAIR ABDEL-KHALIK: Artificial --

11 MR. RAZZAQUE: Artificial --

12 CHAIR ABDEL-KHALIK: -- cores essentially.

13 MR. RAZZAQUE: Basically, this is the 14 maximum possible the SVEA can go.

15 MR. WALLIS: Oh, this is the maximum --

16 MEMBER BANERJEE: Now having done the 17 calculation, you've raised a question that you need 18 not have raised probably. Why is it different.

19 MR. RAZZAQUE: I don't know. GE can anser 20 that, but my judgment tells me it will be -- because 21 when they use equilibrium core, the only difference 22 would be the information regarding the specific fuel, 23 so my judgment will tell that that would be causing 24 the difference.

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135 1 600 degrees?

2 MR. RAZZAQUE: It should not.

3 MEMBER BANERJEE: It's not 600 degrees.

4 MR. WALLIS: Well, he said 20 to 100.

5 MR. RAZZAQUE: Yes. It's about 150 or 6 160, something like that.

7 CHAIR ABDEL-KHALIK: Now with both of 8 these analyses, you have to provide input which 9 describes the performance of the -- characteristics of 10 the ECCS system, pump characteristics, etcetera. Now 11 is that input based on tech specs limits? Is it based 12 on actual historical measured performance? What did 13 you use?

14 MR. RAZZAQUE: Yes. There are tech specs 15 limits on the ECCS injection, flow rate, time, and the 16 analysis assumes that and the limiting condition to 17 calculate the worse scenario.

18 CHAIR ABDEL-KHALIK: So the same question 19 that I asked with regard to SRV performance applies 20 here. What is the historical performance of your ECCS 21 system vis-a-vis the limits in tech specs?

22 MR. WALLIS: Historical performance?

23 CHAIR ABDEL-KHALIK: Right, testing.

24 MR. WALLIS: Has it ever had to work?

25 CHAIR ABDEL-KHALIK: No, no, no. I mean, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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I *% f-1 you know, testing 2 MR. WALLIS: Oh, testing.

3 MEMBER BANERJEE: Is there a way to 4 measure it? That's the first thing.

5 CHAIR ABDEL-KHALIK: Do you have data to 6 indicate that you are always in compliance with tech 7 specs limits that are used in these analyses.

8 MEMBER BANERJEE: Difficult -- would have 9 to be.

10 MR. DAVISON: Paul Davison. If I could 11 just clarification on what specific requirements for 12 ECCS are you referring to?

13 CHAIR ABDEL-KHALIK: Pump characteristics.

14 MR. DAVISON: Okay. Yes, we performed all 15 IST testing on our RHR core spray, RCIC, HPIC pumps, 16 all our ACCS pumps. So I do quarterly IST performance 17 testing to verify that they're acceptable. I also 18 trend that data. I also keep unavailability data and 19 MSPI data on all of the safety pumps as well, safety 20 systems as well all below -- all in top quartile 21 performance ranges for all of our ECCS pumps. So 22 generically, the answer is we do testing programs and 23 we monitor per MSPI and SSPI unavailability to say our 24 ECCS system is robust and readily available.

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137 1 the previous operating history of Hope Creek, in all 2 the surveillance testing, none of these pumps have 3 ever fallen blow the tech specs limits?

4 MR. DAVISON: Not that I'm aware of but I 5 will go verify that fact. I'm not -- that -- I do not 6 have any data that says we've ever had a failed pump, 7 but I will go back and verify.

8 CHAIR ABDEL-KHALIK: Yes, if you would 9 verify that for us --

10 MR. DAVISON: Yes.

11 CHAIR ABDEL-KHALIK: -- I think that would 12 be -- thank you.

13 MEMBER MAYNARD: I'm not sure I understand 14 the applicability of that to EPU. That sounds like if 15 there's any issues, that's a current operating issue.

16 The licensees are required to operate within their 17 tech specs. You have tech spec limits on these 18 things. I'm struggling with tying it to EPU.

19 CHAIR ABDEL-KHALIK: Well, I mean if there 20 is historical information -- there may not be, okay --

21 but if there is historical indication that the pump 22 performance is consistently below tech spec limits, 23 then these analyses are essentially meaningless.

24 MEMBER MAYNARD: But that would also meant 25 that their current operating would be issues --

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138 1 CHAIR ABDEL-KHALIK: Right.

2 MEMBER MAYNARD: -- and when that occurs, 3 there's other regulatory mechanisms that come into 4 play for dealing with those issues, because your tech 5 specs, you have to comply. And being out of 6 compliance of finding that you've been out of 7 compliance for some time, there are regulatory 8 processes that deal with that --

9 CHAIR ABDEL-KHALIK: Granted.

10 MEMBER MAYNARD: -- because your current 11 analyses are based on that, too, so.

12 CHAIR ABDEL-KHALIK: Granted, but that 13 would be a piece of information that would allow 14 people to sort of put some perspective on the validity 15 of whatever analyses have been performed.

16 MR. RAZZAQUE: Basically, reemphasizing 17 our analyses, scope of the review is focused on the 18 EPU because they already approved a license to operate 19 at the current power level. We are not going back 20 unless we find something -- error. We look at the 21 extended area where they are coming into.

22 CHAIR ABDEL-KHALIK: Your know, again, I 23 fully understand this, but as an engineer, you look at 24 a number, you ask what is the error bar on this number 25 and what are the sources of possible uncertainties in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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139 1 this number, and that's what I'm trying to get at.

2 MR. RAZZAQUE: I understand. If anymore 3 question --

4 MEMBER BANERJEE: Just I hope when we come 5 to the closed session, you explain -- it's not mission 6 critical -- but why there is a difference in the PCTs 7 between the GE-14 and the SVEA-96. I'm assuming that 8 all the conditions are more or less the same, and 9 these bundles are supposed to be thermal-hydraulically 10 similar, so I'm still puzzled by this 160 degrees 11 difference.

12 MR. RAZZAQUE: We did not specifically 13 investigate -- spend time investigating why the 14 difference is for several reasons. One is the result 15 -- there is plenty of margin. Second is the SVEA will 16 be a limiting fuel and we know that. The MAPLHGR will 17 be way below that which are assumed. And --

18 CHAIR ABDEL-KHALIK: Nonetheless, it's 19 confidence or not confidence in the methods.

20 MR. RAZZAQUE: For interest of knowing, 21 yes. But the*--

22 CHAIR ABDEL-KHALIK: I think in the closed 23 session, perhaps GE, who did the analysis, will have 24 more information or --

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140 1 to know also whether the staff has investigated this 2 or not.

3 MR. RAZZAQUE: As I mentioned, we have not 4 specifically on this issue.

5 MR. WALLIS: Staff only did calculations 6 with the GE fuel --

7 MR. RAZZAQUE: No, we made sure that the 8 calculated values are well within the limits --

9 MEMBER BANERJEE: But did you do 10 confirmatory calculations?

11 MR. RAZZAQUE: Yes, we did.

12 MEMBER BANERJEE: Just with GE --

13 MR. RAZZAQUE: And it was bounded. The 14 next slide is that.

15 MEMBER BANERJEE: Okay.

16 MR. RAZZAQUE: All right. If you have no 17 more questions on this, I can move to the next one 18 which says that RELAP5 code was used for GE-14.

19 Again, we did not use SVEA because of the fact that 20 SVEA would be operating at a much less MAPLHGR than 21 GE, and therefore, it will be way below 1540. So we 22 picked one, and GE was the one we picked.

23 MEMBER BONACA: Because 1540 was 24 calculated assuming the same MAPLHGR --

25 MR. RAZZAQUE: That is correct.

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141 1 MEMBER BONACA: -- while, in reality --

2 MR. RAZZAQUE: It will be --

3 MEMBER BONACA: -- much lower?

4 MR. RAZZAQUE: Exactly, because of the low 5 power on those bundles. And Dr. Huang there, he --

6 you calculated using RELAP5, the GE-14, and if you 7 have more -- you want a more --

8 MR. WALLIS: The value was 300 or 400 9 degrees higher because of radiation --

10 MR. RAZZAQUE: Yes. Our -- his 11 calculation gave 1640 degrees. Okay? But that has 12 some built in conservatism.

13 MR. WALLIS: And you expect it about 300 14 degrees higher because you've ignored radiation --

15 MR. RAZZAQUE: Correct.

16 MR. WALLIS: -- which is historically --

17 MR. RAZZAQUE: We have done that before, 18 yes.

19 CHAIR ABDEL-KHALIK: Now tell me again, 20 what is the sort of the logic of doing confirmatory 21 analyses if you do them at conditions different than 22 or using assumptions different than what the applicant 23 is using?

24 MR. RAZZAQUE: Let me tell you my 25 understanding of this. We try to -- our review, staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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142 1 review, in most areas, at least what I did here was to 2 get a reasonable assurance, not to exactly try to 3 duplicate the licensee. First of all, it is not 4 possible, because the cores are different, models are 5 different, nodings are different. But we need to get 6 some idea whether the licensee's calculations are way 7 off or something. That is the reasonable assurance, 8 I think, what we are trying to achieve. And one way 9 to get the reasonable assurance would be run a code 10 which we are comfortable with, and use some bounding 11 type calculation. In other words, ignore radiation is 12 one way we did, because it's more difficult to review 13 factors and those things, hard to calculate.

14 Sometimes we don't want to spend too much time, 15 because we're trying to get reasonable assurance and 16 the code is different. That is the bottom line.

17 MEMBER BANERJEE: You ran RELAP5 in a mode 18 which was similar, however, with assumptions similar 19 to the GE calculation?

20 MR. RAZZAQUE: Yes, except those few --

21 one like radiation we didn't include, because we know 22 that will make things worse. It won't make things the 23 other way around. Otherwise, we would have included 24 it. And so things like that which will always make 25 the PCT higher. That's the assumption we will make, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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143 1 not the other way around. And we don't want to add 2 anything but that was the key assumption, that 3 radiation was ignored.

4 MEMBER ARMIJO: If you had run RELAP5 with 5 a SVEA fuel and you added several hundred degrees on 6 top of, let's say, what the GE analysis came up with 7 of 1540, you might have been on the border of 2200.

8 MR. RAZZAQUE: Well, if you straight take 9 -- just as taking 1640 --

10 MEMBER ARMIJO: For the equilibrium.

11 MR. RAZZAQUE: Three hundred. Yes, at 300 12 degree, it will still be 18-something. Besides, we 13 are taking 1540 for SVEA fuel which won't be happening 14 15 MEMBER ARMIJO: Yes. It's a hypothetical 16 17 MR. RAZZAQUE: Hypothetical.

18 MEMBER ARMIJO: -- doesn't exist.

19 MR. WALLIS: It would be very good, 20 though, to run RELAP5 with radiation. Does this TRACE 21 model, this phenomenon, okay? Does this scenario --

22 MEMBER BANERJEE: TRACE certainly runs BWR 23 with no problem now. We just had it done.

24 MR. RAZZAQUE: I am not sure about TRACE 25 will have the capability now -- do other --

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144 1 MEMBER BANERJEE: We have --

2 MR. RAZZAQUE: We don't know --

3 MEMBER BANERJEE: -- runs with TRACE and 4 FOX coupled.

5 MR. WALLIS: Yes. That's what should be 6 done.

7 MR. WANG: This is Weldon Wang. Actually, 8 I performed the RELAP5 calculations for this power 9 uprate. And the flow trace -- okay, so the reason we 10 chose RELAP5 at the time is really there is a RELAP5 11 deck available for the Browns Ferry, and we have 12 verified the geometry and the dimensions of the vessel 13 in both BWR-4 --

14 UNIDENTIFIED SPEAKER: For Hope Creek you 15 mean.

16 MR. WANG: -- for Hope Creek, right --

17 compared with Browns Ferry. However, we also noticed 18 that there are differences. For example, I believe it 19 was a letter c injection of the front. So, we, at a 20 certain point, we pick up a rule of five because we 21 think that job will be minimal so we can start to run 22 the code right away.

23 MR. WALLIS: I thought TRACE was supposed 24 to accept these other decks?

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145 1 for Browns Ferry.

2 MR. WALLIS: There is a TRACE deck? I 3 thought it was supposed to take a RELAP5 and translate 4

5 MEMBER BANERJEE: I hope you don't use 6 RELAP5 for Browns Ferry?

7 MR. WALLIS: That's what he did.

8 MEMBER BANERJEE: It's time to move on, I 9 think, to a better validated code.

10 MR. RAZZAQUE: So far, in EPUs, we've used 11 RELAP5 before -- Vermont Yankee, Browns Ferry and --

12 MEMBER BANERJEE: I know -- we have. This 13 doesn't meant you have to --

14 MR. RAZZAQUE: No.

15 MEMBER BANERJEE: -- harden --

16 MR. RAZZAQUE: We don't --

17 MR. WALLIS: It will be very interesting 18 to see if TRACE and RELAP5 and SAFER/GESTR, with the 19 same assumptions all the way through, how different 20 their answers are. It would be very interesting to 21 see rather than this conservatively-bounds sort of 22 idea. And if they differ significantly, then we might 23 begin to wonder why.

24 MEMBER BANERJEE: Well, the thing is LOCA 25 is not really a concern in these matters.

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146 1 MR. WALLIS: It doesn't seem to be.

2 MEMBER BANERJEE: There are other things 3 like the anticipated transients and things which are 4 very different where there are concerns, so --

5 MR. RAZZAQUE: The -- right, actually, the 6 PCT with EPU only increased 10 degrees F for GE fuel 7 and didn't increase at all for SVEA fuel. Again, we, 8 sometime ago --

9 MR. WALLIS: What is limiting the EPU?

10 It's not LOCA --

11 MR. RAZZAQUE: It looks like not LOCA.

12 Sometimes it is maybe by a few degrees, but this time 13 here, it is a few degrees. We have seen PCT even 14 going down. Remember in one case, we even discussed 15 that here.

16 MR. WALLIS: When the fluence goes down, 17 all kinds of things go down. I don't know why but it 18 does because they use it --

19 MR. RAZZAQUE: I thought we tried to 20 understand that phenomena -- why it goes down, 21 flattening affect --

22 MR. WALLIS: Right.

23 MR. RAZZAQUE: -- and redistribution of 24 the flow and those kind of things, so. PCTs never 25 comes out to be a very big change. I never saw more NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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147 1 than --

2 MR. WALLIS: What I it that limits these 3 EPUs?

4 MR. RAZZAQUE: Pardon me?

5 MR. WALLIS: Why don't they go to 40%

6 instead of 15? What is it that limits EPU.

7 MR. RAZZAQUE: MCPR will definitely --

8 minimum critical power issue, LGR --

9 MR. WALLIS: MAPLHGR or something like 10 that?

11 MR. RAZZAQUE: -- MAPLHGR, those kind of 12 things.

13 MEMBER BANERJEE: It's the fuel for the --

14 MR. WALLIS: No. It is the CPR.

15 MR. RAZZAQUE: Right.

16 MR. WALLIS: It's not the accident, 17 though. It's the regular --

18 CHAIR ABDEL-KHALIK: Please continue.

19 MR. RAZZAQUE: Okay. So staff calculation 20 verified not only the PCTs boundings, we bounded the 21 PCT basically. We didn't do exact calculations, but 22 I here what you are saying. The other is we also 23 confirmed the break size, the large-break LOCA -- we 24 confirmed that, and the break-spectrum, things like 25 that.

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148 1 Next slide is on ATWS. We present the 2 results. The top bullet represents the results, and 3 the first two basically talk about requirements. They 4 match the requirements, like they have to have 5 alternate rod injection which they have installed.

6 Boron capability is 86 gpm which they have --

7 MEMBER BANERJEE: Is this enriched boron?

8 MR. RAZZAQUE: Yes. And then they have 9 recirc pump trip installed. So those are required by 10 regulation, in 10 CRF 50.62. They have those. And 11 the they rely on te EOP, of course.

12 MR. WALLIS: So this is to reduce water 13 level or what?

14 MR. RAZZAQUE: Yes, water level basically, 15 because the pump trip will be automatic. They can do 16 it manually, too.

17 MR. WALLIS: So this is when the SLC 18 system is incapable of meeting the peak pressure, so 19 the relief valve opens.

20 MR. NAKANISHI: This is Tony Nakanishi.

21 The initial peak pressure, ATWS pressure is not 22 mitigated by --

23 MR. WALLIS: Before you use the SLC 24 system?

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149 1 have the pump trip.

2 MR. WALLIS: Oh, okay. And then this pool 3 temperature, that must depend on how the pool 4 temperature starts out which is a function of the time 5 of year and things like that. So is this based on the 6 highest pool temperature, or what is it based on?

7 MR. RAZZAQUE: It should be.

8 MR. WALLIS: Is it? If it's the average, 9 then it's not so good, because sometimes the pool 10 temperature is a few degrees above average.

11 MR. RAZZAQUE: The initial temperature --

12 maybe the --

13 MR. DENNY: This is Skip Denny of General 14 Electric-Hitachi. The accident analysis - -ATWS 15 accident analysis assumes a 95 degree pool 16 temperature --

17 MR. WALLIS: It assumes the worse -- yes.

18 MR. DENNY: The worse case tech spec 19 allowed.

20 MR. WALLIS: I thought it probably did.

21 Thank you.

22 MR. DENNY: Also, minimum tech specs --

23 MR. WALLIS: Yes, so it's t he worse. It's 24 the really conservative.

25 MR. DENNY: Yes, sir.

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150 1 MEMBER BANERJEE: It's pretty close to the 2 limit?

3 MEMBER ARMIJO: Yes, but at 3 degrees, 4 that's a sharp pencil.

5 MR. WALLIS: Yes, but it's very unlikely 6 that it's going to get anywhere near that. Ninety-7 five degrees is a very high temperature.

8 CHAIR ABDEL-KHALIK: What is the basis of 9 the 201 degree limit?

10 MR. DENNY: Skip Denny again, General 11 Electric-Hitachi. There are two concerns with ATWS.

12 One is NSPH which is a lot higher than this, 218 13 degrees. The 201 is based on ensuring that steam 14 discharge from the NSRVs is fully quenched and does 15 not potentially ingest into the ECCS suction or the 16 suppression pool cooling lines. So it's SRV discharge 17 temperature limiting. This is a bulk temperature 18 limit. It maintains at 218 degrees -- local 19 temperature at the discharge.

20 CHAIR ABDEL-KHALIK: Thank you.

21 MR. DENNY: Yes, sir.

22 MEMBER BANERJEE: Do you have any idea how 23 much water there is to suppress this compared to, say, 24 Vermont Yankee or Browns Ferry or per megawatt let's 25 put it. Is it --

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151 1 MR. WALLIS: About one cubic meter per 2 megawatt.

3 MEMBER BANERJEE: Well, is it about the 4 same or is it very different?

5 MR. DENNY: The ATWS analysis for Hope 6 Creek assumes the tech specs limit --

7 MEMBER BANERJEE: No, no, no. I'm just 8 asking a general question. How much water is there in 9 the suppression pool?

10 CHAIR ABDEL-KHALIK: We asked that 11 question earlier.

12 MEMBER BANERJEE: Oh, you did? Okay.

13 What did --

14 CHAIR ABDEL-KHALIK: A hundred and 15 eighteen thousand cubic feet minimum.

16 MR. DUKE: This is Paul Duke, PSEG. The 17 volumes in plants of similar rating such as Peach 18 Bottom and Browns Ferry is similar.

19 MR. DEVINE: Similar to Vermont Yankee, 20 too?

21 MR. DUKE: No, similar to Hope Creek. I 22 can't tell you the volume of VY but for Browns Ferry, 23 it's a similar volume with a similar rating.

24 MEMBER BANERJEE: But the rating is lower?

25 MEMBER BANERJEE: But rating is lower, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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152 1 right.

2 MEMBER BONACA: That's why you see some 3 plants that have a problem with the backpressure and 4 others don't.

5 CHAIR ABDEL-KHALIK: Please continue.

6 MR. RAZZAQUE: The last slide is my 7 conclusion which is basically repeating again that the 8 guidelines were followed, generic evaluations were 9 used which were previously approved. And our review 10 basically focused on the effect of EPU on the current 11 licensing basis, not necessarily to go back beyond 12 unless we come up with some problem.

13 MR. NAKANISHI: Should I keep going?

14 CHAIR ABDEL-KHALIK: No. What I would 15 like to do is break for lunch for one hour. We'll be 16 back here at 1:00 o'clock. AT that time, both the 17 staff's presentation and the applicant's presentation 18 on fuel methods will be done in a closed session.

19 MEMBER BANERJEE: So you get ride of this 20 open session matter?

21 CHAIR ABDEL-KHALIK: Right. Item 8 on the 22 agenda will now be moved into a closed session so that 23 you can ask whatever question you would like of the 24 staff, and we will reconvene at 1:00 o'clock.

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153 1 matter adjourned at 11:52 a.m. for a luncheon break 2 and holding of closed session.)

3 (Whereupon, at 2:24 p.m., open session in 4 the foregoing matter is resumed.)

5 CHAIR ABDEL-KHALIK: We're back in 6 session. Before we start on item 12 on the agenda, 7 there's a question regarding the standby liquid system 8 operation -- liquid control system operation that Mr.

9 Maynard has.

10 MEMBER MAYNARD: I hate to take a step 11 back, but we discussed this in a couple of different 12 sessions, and I'd like to pull it together. Under the 13 ATWS scenario, the peak pressure occurs before the 14 automatic implementation of the SLC system. However, 15 that peak pressure is higher than what the relief 16 valves for the SLC system. The operators talk about 17 that they're trained to go ahead an initiate that 18 before the automatic, so it's very possible that they 19 would be initiating that at a time when the pressure 20 is higher than the relief valve standpoint.

21 You've mentioned something about that's 22 okay because there's plenty of margin. I guess I'd 23 like to explore that margin and why it's okay to do it 24 at that time and lift the relief valves?

25 MR. DelGAIZO: Okay. I'm Ted DelGaizo.

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154 1 Because there's actually a regulatory requirement. I 2 think it's 100 pounds. It could even be 150. But 3 there's a requirement on the pressure that you'll be 4 when you credit SLC for injecting and the reset of 5 that relief valve. You're right, it is 1400 and it 6 resets somewhat below that. Not much. But we meet 7 that regulatory requirement which, again, I think is 8 100 psid, so that we're at least 100 pounds down below 9 that reset point at the time that the analysis shows 10 like it's going to inject. And the reason for that 11 big margin or that requirement for the delta P is 12 specifically so that if it does lift, it's assured to 13 recede and not be close to the reset point.

14 MEMBER MAYNARD: And during that time that 15 it has lifted, you're not losing more born than what 16 you need to be able to --

17 MR. DelGAIZO: Oh, no, we're not losing 18 any boron. It's recirculating.

19 MEMBER MAYNARD: It's recirculating.

20 MR. DelGAIZO: Right. So the boron is 21 just fine. What you have to be sure of is when the 22 time comes that the boron needs to go in, the relief 23 valve is reset.

24 MEMBER MAYNARD: Okay, fine. That answers 25 my questions.

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155 1 CHAIR ABDEL-KHALIK: Okay. Let's proceed 2 with the presentation then.

3 MR. DAVISON: Okay. Good afternoon. I'm 4 Paul Davison, again. And next to me to discuss the 5 containment analysis methodology and response is Mr.

6 Ted DelGaizo frm Mainline Engineering as well as Mr.

7 Skip Denny from General Electric-Hitachi.

8 For background, this is a simplified 9 depiction of the Hope Creek reactor building and 10 containment structure. Again, Hope Creek has that 11 Mark I containment as evidenced by the inverted 12 lightbulb shape and the attached torus which we also 13 refer to as the suppression pool. The drywell is a 14 steel pressure vessel which is encased in concrete, 15 and the torus is connected to the drywell airspace via 16 8 vent pipes. The vent pipes are connected to a 17 header that distributes the flow to the downcomers 18 which terminate approximately 3 feet under the tech 19 specs minimum required water level.

20 On the next slide -- get into the actual 21 containment response analysis being performed using 22 the NRC-approved General Electric methodology. The 23 results indicate that adequate margin do exist for 24 design basis accident conditions. Specifically, on 25 the codes, LAMB, M3CPT and SuperHEX were the primary NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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156 1 codes utilized for EPU.

2 CHAIR ABDEL-KHALIK: Now M3CPT was 3 developed for Mark III containment analysis. The 4 question is were there any modifications to either the 5 code or to the input required to apply to the Mark I 6 containment of Hope Creek?

7 MR. DENNY: This is Skip Denny of General 8 Electric-Hitachi. No, sir, there's no need to modify 9 the code itself. The code allows for three levels of 10 relief vent pipes basically and whether they go 11 horizontal or vertical. And so the inputs would be 12 set up for a Mark I containment to utilize just one of 13 those vent pipes allowed in the code itself. So the 14 code is, although designed particularly for the Mark 15 III containment, it handles all three containment 16 types, Mark I, II and III.

17 CHAIR ABDEL-KHALIK: Okay. The other 18 question is that SuperHEX has never really been 19 reviewed by the staff, and I understand this is one of 20 the codes that's been used for many, many years, and 21 it's -- the question then is what type of confirmatory 22 analyses have been done by the staff to confirm the 23 results of these analyses?

24 MR. LAMB: This is John Lamb with the NRC.

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157 1 expert should be coming shortly, so he'll be able to 2 answer those questions.

3 CHAIR ABDEL-KHALIK: All right.

4 MEMBER BONACA: I have also a question 5 regarding are these codes also the same used for the 6 analysis until now, or did you have some changes 7 either in the codes or inputs? I know you made the 8 change, for example, to the decay heat that you use 9 for the long-term. Could you identify what changes 10 you had in the methodologies used to address the power 11 uprate?

12 MR. DENNY: Yes, sir. Skip Denny again.

13 M3CPT is the code of record for Hope Creek. M3CPT has 14 a vessel model internal to it, and the current short-15 term analysis for Hope Creek uses the vessel model 16 internal to M3CPT. However, we now typically use a 17 LAMB code because its vessel model is more elaborate 18 than what's internal to M3CPT. And so with this, we 19 are using a LAMB blowdown particularly. And that 20 M3CPT will read LAMB blowdown directly.

21 MEMBER BONACA: So I guess LAMB kind of 22 sharpens the pencil somewhat?

23 MR. DENNY: A little bit. LAMB is 24 particularly useful because it can handle off-rated 25 conditions whereas M3CPT can't. LAMB has a highly NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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158 1 nodalized vessel model whereas M3CPT is basically a 2 tin can vessel model.

3 MEMBER BONACA: No. I guess by reading 4 the results, etcetera, clearly, I see acceptable 5 results. I was wondering of what the affect of the 6 power uprate really was analytically in values, and I 7 couldn't really see that because, I mean, you may have 8 more changes to the assumptions, for example, again, 9 the decay heat that you used to perform the long-term 10 containment analysis?

11 MR. DENNY: One of the slides that we're 12 going to be showing you is going to be exactly that.

13 MR. DAVISON: In two slides, we'll get the 14 actual table where we compare our current methodology 15 with the new methodology at our current licensed 16 thermal power and then taking that to the EPU as well.

17 MEMBER BONACA: Okay. So we can 18 understand what the effect really will be so far as a 19 delta, although I understand that if you sharpen your 20 pencil, you get within the limits. Okay. Very good.

21 MEMBER BANERJEE: So has LAMB been 22 approved for use now by the staff?

23 MR. DENNY: This is not the first time we 24 brought LAMB.

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159 1 been approved?

2 MR. DENNY: LAMB has been approved for 3 LOCA for many, many years.

4 MEMBER BANERJEE: Has been approved?

5 MR. DENNY: Approved.

6 MEMBER BANERJEE: Not just brought forward 7 and accepted? Is that correct, LAMB has been approved 8 for use?

9 MR. LAMB: I'm not sure. This is John 10 Lamb.

11 MEMBER BANERJEE: So it has been used for 12 LOCA before?

13 MR. LAMB: My understanding, yes, it's 14 been used before, but I'm not an expert in this area, 15 so Rich Lobel should be here shortly.

16 MEMBER BANERJEE: I guess Fran's going to 17 tell us.

18 MR. BOLGER: This is Fran Bolger. The 19 LAMB is an integral part of the SAFER/GESTR LOCA 20 methodology, and it is approved.

21 MEMBER BANERJEE: So it is approved.

22 CHAIR ABDEL-KHALIK: But is it a correct 23 statement that I made earlier that SuperHEX has never 24 been evaluated by the staff?

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160 1 some comments on their benchmarking that they have 2 done with the SuperHEX when they get here.

3 CHAIR ABDEL-KHALIK: Okay. Thank you.

4 MEMBER BANERJEE: So LAMB has been 5 approved in the SAFER/GESTR context. Has it been 6 approved -- Fran, don't run away -- has it been 7 approved in the containment context?

8 MR. BOLGER: This is Fran Bolger again.

9 As far as being separately reviewed and approved, I 10 don't really know. It has been presented in many 11 power uprates as part of the power uprate methodology.

12 And I believe it also is included in the ELTR and LTRs 13 that support power uprate.

14 MEMBER BANERJEE: Okay.

15 MR. WALLIS: This is a critical flow?

16 CHAIR ABDEL-KHALIK: Initial period of 17 LOCA -- blowdown period.

18 MR. DUKE: This is Paul Duke. We used 19 LAMB for ARTS/MELLLA implementation to calculate 20 blowdown flows for anulus pressurization and that was 21 part of the application. And I believe 22 MR. JOYCE: he staff reviewed that in 23 particular for anulus pressurization as part of the 24 ARTS/MELLLA amendment that was approved a few years 25 ago.

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161 1 MR. WALLIS: What do the letters stand for 2 in LAMB? It might tell us something about what's in 3 it.

4 CHAIR ABDEL-KHALIK: Please proceed.

5 MR. DAVISON: Going back to the slide, the 6 short-term analysis is dominated by the initial 7 blowdown flow rate and that results in a minimal 8 change due to the constant pressure nature of our 9 power uprate condition. The long-term response was 10 impacted due to the increase in the decay heat 11 associated with the EPU and it results in 11.3 degree 12 Fahrenheit increase in peak bulk suppression pool 13 temperature.

14 MR. WALLIS: There was some flow rate that 15 changed. I was surprised. What is -- where is -- the 16 sump pipe is bigger or something? I've lost it then.

17 I've seen no change in any of the blowdown flow rates?

18 I thought there was a 15% change in something, but I 19 lost --

20 MR. DENNY: There is a small increase in 21 the blowdown from current licensed power to EPU power 22 using LAMB, and you'll see that in the table that we 23 show you, a slight increase in containment pressure as 24 a result.

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162 1 it. I was surprised to read it somewhere in the SER.

2 But anyway, don't worry about it.

3 CHAIR ABDEL-KHALIK: And that slight 4 increase in blowdown flow is a result of what, even 5 though you're essentially at constant pressure?

6 MR. DAVISON: It's driving it, yes.

7 MEMBER BANERJEE: Well, you have more 8 stored energy in the core.

9 MR. DENNY: Yes. I believe it has to do 10 with more stored energy in the vessel liquid. It 11 happens around 10 seconds where the blowdown diverges 12 a little bit from current power to EPU power, and 13 that's what's giving us a slight increase in drywell 14 pressure. But it's basically that the flow rate is 15 decreasing as reactor pressure is decreasing, but with 16 LAMB, at EPU conditions, it doesn't drop off as fast.

17 CHAIR ABDEL-KHALIK: Okay. I think I 18 understand. More stored energy essentially in the 19 inventory within the vessel because your feedwater 20 temperature is slightly higher, the core temperature 21 is slightly higher, all that stuff. Okay.

22 MEMBER BANERJEE: The average void 23 fraction is higher.

24 MR. DelGAIZO: We also have a little 25 higher DP. In other words, the dome pressure is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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163 1 constant. The DP in the vessel increases slightly due 2 to the increased feed flow and the recirc and 3 everything and the big break is the suction line 4 break, so it could be a slightly higher pressure 5 there, too, even though the dome pressure is a 6 constant.

7 CHAIR ABDEL-KHALIK: Okay.

8 MR. DAVISON: All right. On slide 45, the 9 DBA LOCA containment analysis was performed at 102% of 10 the 3840 megawatt thermal rating. For the analysis, 11 the ANSI/ANS 5.1 methodology was -- uncertainty was 12 utilized for the extended power uprate licensed 13 topical report. This approach provides a more 14 realistic containment temperature response and differs 15 from the current Hope Creek UFSAR analysis based on 16 the previous made with decay heat methodology. We'll 17 actually look at those in tabular form in the next 18 page.

19 The analysis did credit passive heat sinks 20 including the drywell metal inner shell. The 21 containment vent system, metal piping and the torus 22 metal shell. These heat sinks are not credited in the 23 current Hope Creek UFSAR analysis, contribute to 24 approximately 2 degrees Fahrenheit decrease in the 25 peak bulk suppression pool water temperature.

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164 1 MEMBER BONACA: Passive heat sink.

2 MR. DAVISON: Correct.

3 MEMBER BONACA: What about your decay heat 4 curve after you complete it?

5 MR. DAVISON: Yes, next slide. I think 6 that's seven, right? I think it's approximately 7 7 degrees -- 11 total, right.

8 MEMBER BONACA: It's above 10 degrees 9 coming from changes in methodology -- inputs.

10 MR. DAVISON: Okay. The table displays 11 the peak drywell air --

12 CHAIR ABDEL-KHALIK: Back to this passive 13 heat sink is credited in long-term analysis, this was 14 not done in the original analysis?

15 MR. DAVISON: That's correct.

16 MR. DENNY: No, sir.

17 CHAIR ABDEL-KHALIK: Okay. Even though it 18 is an option that's available in the code, so --

19 MR. DENNY: There were no changes in the 20 code that would account for this.

21 CHAIR ABDEL-KHALIK: Thanks.

22 MR. DAVISON: Here's the table we referred 23 to a few slides back. It displays the peak drywell 24 air space pressure and temperature, the peak bulk 25 suppression pool water temperature and the peak wet NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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165 1 well airspace pressure and temperatures as compared 2 between current licensed thermal power, EPU, and the 3 design limits. So the first two columns specifically 4 under the CLTP 3339 megawatt thermal compares the 5 current UFSAR analysis methodology with the new EPU 6 method results. The most notable change is the 9-7 degree reduction in the peak bulk suppression pool 8 water temperature. This reveals the more realistic 9 results associated with the transition of 10 methodologies from MWt to the ANS 5.1 and the addition 11 of the passive heat sinks per SuperHEX.

12 The results using the EPU methodology for 13 the uprate, 3840 megawatts thermal, which is the next 14 column over -- this result showed that the margin 15 exists in the containment structural code and the net 16 positive suction head design limits. Therefore, the 17 design basis accident LOCA containment performance has 18 margin for all parameters at the EPU conditions.

19 CHAIR ABDEL-KHALIK: Now let's look at the 20 218 degrees F entry. This value was originally 212, 21 is that correct?

22 MR. DAVISON: Yes.

23 MR. DAVISON: Okay. Now what design 24 changes were made to increase that design limit to 218 25 degrees F?

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166 1 MR. DAVISON: There were no design 2 changes.

3 CHAIR ABDEL-KHALIK: So how is that design 4 limit increased to 218 degrees F from its original 5 value of 212?

6 MR. DelGAIZO: This is Ted DelGaizo. We 7 have calculations on both RHR and core spray thermal-8 hydraulic calculations in computer codes. They're 9 pretty detailed. And out of those calculations come 10 the NSPH calculation. What we did is in order to 11 bound the higher numbers that we were getting for EPU 12 -- and in fact, when we first started this project and 13 we looked at 120%, they were even a little bit higher 14 -- I think 215 might have been the max -- so we picked 15 a number that would bound all possible suppression 16 pool temperatures and did the NSPH calculation with 17 that assumption. So it's an assumed value, 218.

18 Now in addition to assuming that, we had 19 to do some other things. We had to check the seals on 20 the core spray pump and make sure they could handle 21 218. There were some other things that were done, but 22 basically, in order to change that to our new so-23 called design limit for suppression pool temperature, 24 we ran the NSPH calculations to show we had margins 25 with atmospheric in the containment, no overpressure, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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167 1 218 F, and we showed that we had sufficient --

2 MR. WALLIS: And this works because the 3 pumps are located way --

4 MR. DelGAIZO: Right, our pumps -- we 5 really have a great configuration.

6 MR. WALLIS: They're low down and --

7 MR. DelGAIZO: Right. The --

8 MR. DAVISON: They're vertical pumps. Our 9 minimum suppression pool water is 71-foot elevation in 10 the plant. Our pumps are located on 54 and they drop 11 down 15 feet.

12 MR. WALLIS: Oh, they're those long 13 tubular-type pumps --

14 MR. DAVISON: Yes. Multiple stages.

15 CHAIR ABDEL-KHALIK: So what is the 16 elevation difference between the pump inlet port 17 center line and the minimum water level in the 18 suppression pool?

19 MR. DelGAIZO: The inlet center line is 20 55-1/2 feet -- 55.6 roughly. The pool minimum is 71 21 feet and a half inch or -- it's basically 71 feet to 22 55-1/2, so I guess that's 16 feet. And as pointed 23 out, that's the pump's suction line. The impeller is 24 about another 16 feet down below that. And we don't 25 credit that. We went from the 71 to the 55, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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168 1 that's the elevation that had to be used in the 2 calculation. And we had 14.7 psia and the head loss 3 through the strainers and the friction losses through 4 the piping, we ended up with NSPH margin above the 5 required. And the required number we used is the 6 highest number the vendor tested. So in other words, 7 it basically is runout flow for the required -- NSPH 8 required, and it's actual flow for NSPH available 9 based on the computer code.

10 MEMBER BONACA: So let me just -- to 11 complete my question and that was if I assume the same 12 computer code used before, the same inputs as before, 13 there would be an increase in bulk pool temperature of 14 about 10 degrees Fahrenheit? I'm trying to understand 15 the contribution of the decay heat curve and the 16 passive heat sink credit.

17 MR. DelGAIZO: Well, the way I see that --

18 if you notice on this slide, under the CPPU method, we 19 actually have an 11 degree increase from the 201 to 20 the 212. Two of that is associated with the passive 21 heat sinks. I would say the other 9 is the decay 22 heat.

23 MEMBER BONACA: Okay. So the EPU 2840 24 would have been assuming the same conditions --

25 MR. DelGAIZO: Right.

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169 1 MR. DENNY: Two degrees in there for 2 passive heat sinks.

3 MR. DelGAIZO: Oh, it did?

4 MR. DENNY: I'm sorry.

5 MR. DelGAIZO: Yes, you're right.

6 MR. DENNY: Apologize. There's a little 7 correction. In the CLTP going from 210 to 201, that 8 included both changing from MWt to the ANS 5.1 which 9 gives you 7 degrees, and then the passive heat sinks 10 give you another 2 degrees, so that totals 9 degrees 11 decrease. The change from 201 to 212 is using the 12 same exact methodology but increasing core power.

13 That's giving you the actual EPU change.

14 MEMBER BONACA: All right. So where you 15 have the list of EPU method is really same power level 16 but taking credit for those things.

17 MR. DENNY: Correct.

18 MEMBER BONACA: I understand now the 19 table. These are the answer I needed.

20 CHAIR ABDEL-KHALIK: I'm trying to 21 reconcile the first two entries in the second column.

22 How can the new method predict a lower pressure while 23 predicting a higher temperature?

24 MR. DENNY: Yes, sir. I looked at that 25 also. The lower pressure occurs because the LAMB NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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170 1 blowdown versus M3CPT blowdown -- M3CPT doesn't have 2 the elaborate nodalization, so the blowdown early in 3 the event is more restrictive in LAMB than it would be 4 in M3CPT. So the M3CPT gave you a higher peak 5 pressure early in the event. In LAMB, it actually 6 goes out a little bit further, so the peak pressure 7 you see, 48.1, and its temperature is happening around 8 a 4-second for an M3CPT alone analysis.

9 MR. WALLIS: So there's more gas in there?

10 Is that it?

11 MR. DENNY: It's the resistance due to the 12 recirc lines. M3CPT doesn't have --

13 MR. WALLIS: I take it the partial 14 pressure of the non-condensables is bigger earlier?

15 Is that what it is that makes it -- presumably, this 16 pressure -- the saturation pressure of the steam plus 17 the non-condensables, that's the problem you have, is 18 that?

19 MR. DENNY: Yes.

20 CHAIR ABDEL-KHALIK: Yes.

21 MR. WALLIS: Do you have the steam tables 22 here?

23 CHAIR ABDEL-KHALIK: I do have a steam 24 table but the question is, you know, what is the 25 contribution of the non-condensable gas to this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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171 1 calculated pressure of 47.6?

2 MR. DENNY: They both have the same 3 initial containment pressures and temperatures.

4 CHAIR ABDEL-KHALIK: But the contribution 5 of the non-condensable, if you were calculating a 6 higher temperature, will be higher in the second 7 calculation, right?

8 MR. DENNY: Non-condensable gas gets 9 transferred to the suppression pool really quickly, so 10 -- I guess I'm not sure I understand the question.

11 The non-condensable gas is in the suppression pool.

12 MEMBER BANERJEE: I guess what would be 13 interesting is to look at the time at which these 14 peaks happen, because they are probably not 15 coincidence.

16 MR. DENNY: Exactly. In the UFSAR method, 17 you see that peak pressure at the roughly 4.4 seconds.

18 CHAIR ABDEL-KHALIK: If you have the 19 plots, I think that would be very helpful.

20 MEMBER BANERJEE: That would be help -- I 21 think that would explain it.

22 MR. WALLIS: Well, it's apparently at 295 23 -- pressure is 62 psia, so it's almost all steam in 24 the EPU method.

25 MR. DENNY: Yes, sir.

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172 1 MR. WALLIS: And there must be some notes 2 on gas and available at the other -- and then the 3 UFSAR method.

4 MR. DENNY: This is showing the peak 5 pressure. As the drywell pressure -- this is with LAMB 6 blowdown -- the drywell pressure rises and continues 7 to rise, and it goes to a little dip and peaks at 8 about 10 seconds. The FSAR figure which is what the 9 48.1 which uses only M3CPT blowdown comes up really 10 quick, peaks at about 4.5 seconds and then comes back 11 down and actually stops dropping. It shows it's 12 allowing a lot of energy out a lot earlier than what 13 LAMB does, because LAMB restricts that blowdown a 14 little bit more due to the nodalization. When fluid 15 leaves the recirc line, fluid has to be made up from 16 the vessel. For M3CPT, that vessel makeup is almost 17 instantaneous, so you get a lot fast blowdown with the 18 M3CPT model.

19 MR. WALLIS: Well, it has to do with the 20 sweeping out of non-condensables, and the partial 21 pressure of the non-condensables, presumably plus the 22 vapor pressure of the steam, equals the pressure you 23 get.

24 MR. DENNY: Yes, sir.

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173 1 from the steam tables, the EPU method corresponds 2 almost exactly to pure steam. That's because it's 3 later in the process.

4 MR. DENNY: Exactly.

5 MR. WALLIS: And LAMB does a good job of 6 modeling the non-condensables sweep power? That's --

7 that depends upon the mixing model which often isn't 8 all that good.

9 MR. DENNY: LAMB is not doing anything 10 with containment. It's just a vessel blowdown.

11 MR. WALLIS: I'm sorry.

12 MR. DENNY: The M3CPT is --

13 MR. WALLIS: It's the other one that's 14 doing the vessel. But this is assuming a mixed 15 containment? What does it assume about that?

16 MR. DENNY: It assumes -- it follows the 17 air blowing out in the --

18 MR. WALLIS: So there's a well-mixed 19 containment?

20 MR. DENNY: -- suppression pool itself.

21 Initially, yes, sir. Basically, I guess, the 22 conclusion is the -- because of the LAMB -- the M3CPT 23 blowdown, the non-condensables get swept into the 24 suppression pool a lot faster.

25 MR. WALLIS: Okay.

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174 1 CHAIR ABDEL-KHALIK: But if it is a well-2 mixed containm-ent, how can there be a zero 3 contribution to the total pressure from the non-4 condensable gas at any power?

5 MR. DENNY: Because it's swept. It gets 6 swept out. Even with the mixed containment, it gets 7 swept out.

8 MR. WALLIS: It would be nice if you could 9 show the non-condensable contribution here somehow, 10 but -- do you have another plot that shows that?

11 MR. DAVISON: No.

12 MR. DENNY: I don't know if we have vent 13 flows. No.

14 MR. WALLIS: That's a sort of reality 15 check is to look at that.

16 MR. DENNY: I can look and see if we have 17 vent flows where it would show air flow --

18 MR. WALLIS: Right.

19 MR. DENNY: -- and air drops off quickly.

20 MR. WALLIS: Maybe you can bring that 21 tomorrow or something.

22 MEMBER MAYNARD: Are these numbers in your 23 table? For the 3840, is that actually 3840 or is it 24 3952? The chart says 3952 and you earlier said that 25 you did the analysis basically at the 120 --

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175 1 MR. DENNY: I'm sorry. You're talking 2 about power. I'm trying to figure out what numbers 3 you were looking at.

4 MEMBER MAYNARD: This chart says 3952 and 5 it looks like it would peak at -- looks like about 6 50.6. I see about 50.6 here.

7 MR. DelGAIZO: You know, I think all these 8 values except the pool are 3952. I think the problem 9 is here that --

10 MR. DENNY: Right. The short-term 11 analysis was done at 102% of 120% uprate.

12 MEMBER MAYNARD: Okay.

13 MR. DENNY: Yes, sir.

14 MR. DelGAIZO: The number that is done at 15 102% of 3840 are those suppression pool temperatures 16 which were redone to check 3840. The others were left 17 alone because they were fine.

18 MEMBER MAYNARD: Okay.

19 CHAIR ABDEL-KHALIK: Can we go back to the 20 table and clarify this?

21 MR. DelGAIZO: I'm saying I think if you -

22 - I think the words on this were that the 3840 column 23 is 3840 or greater, and the one that is actual 3840 is 24 suppression pool temperature. The others are 3952.

25 And that's why it is include --

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176 1 MR. DENNY: Air pressure would also be the 2 long-term analysis.

3 MR. DelGAIZO: Okay. The same for both of 4 those.

5 CHAIR ABDEL-KHALIK: So could you please 6 clarify which of the entries in the fourth column 7 correspond to what power level?

8 MR. DelGAIZO: Paul, do you have Table 4-1 9 there from the PUSAR? My understanding is that of the 10 -- the only row that is -- 3840 is suppression pool 11 temperature, but I could be wrong. That's why I'd 12 like to check on it.

13 MR. DENNY: Suppression pool temperature 14 is this one here.

15 MR. DelGAIZO: Right.

16 MR. DENNY: Bulk pool temperature --

17 MR. DelGAIZO: Peak, right -- bulk --

18 MR. DENNY: -- peak wet well pressure --

19 MR. DelGAIZO: Right.

20 MR. DENNY: -- and peak wet well 21 temperature would all be from the long term analysis, 22 the SuperHEX. That's at 102% of 3840. That's the 23 bottom three rows is 102% for EPU, 102% of 3840. The 24 upper two rows, the 50.6 and the 298, that was done at 25 102% of 120% uprate.

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177 1 CHAIR ABDEL-KHALIK: Does that answer your 2 question, Otto?

3 MEMBER MAYNARD: Yes.

4 MR. DUKE: This is Paul Duke. The only 5 value that we're reporting based on the 3840 is the 6 suppression pool temperature.

7 MR. DENNY: I'm sorry.

8 CHAIR ABDEL-KHALIK: So for the record, 9 could you please state where these entries correspond 10 to?

11 MR. DUKE: The CPPU analysis is based on 12 102% of 3952 megawatts with the exception of the bulk 13 suppression pool temperature, which is based on 102%

14 of 3840 megawatts.

15 CHAIR ABDEL-KHALIK: Thank you.

16 (Off the record comments.)

17 MR. DAVISON: Okay?

18 CHAIR ABDEL-KHALIK: So back to the table, 19 I mean I understand conceptually how you can have a 20 temperature limit of 218 degrees F because of the 21 elevation difference. But somehow it doesn't make 22 sene to have a temperature limit greater than the 23 saturation temperature of the pool when you're saying 24 that you're utilizing that limit corresponding to a 25 containment pressure of one atmosphere.

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178 1 MR. DelGAIZO: Well, but that's the 2 artificiality we're driven to by the reg guide. I 3 mean I agree. The reg guide forces us to assume 14.7.

4 We agree that at 218, we have to be higher than 14.7.

5 In fact, if we even took that up to saturation 6 pressure, we'd do wonderfully on margin. So it is 7 very conservative to do --

8 MR. WALLIS: In regulatory space, you can 9 violate the laws of physics if you want to.

10 CHAIR ABDEL-KHALIK: Well, thank you.

11 Please continue.

12 MR. DAVISON: That really covered what's 13 on page 47 when you take in that 218 and the 14.7 psia 14 into account. The minimum net positive suction head 15 margin availability is conservatively determined to be 16 1.7 feet for our residual heat removal pumps and 1.2 17 feet for the core spray pumps. Therefore, the ECCS 18 net positive suction head is provided without 19 crediting containment overpressure.

20 And the final slide, 48, this part of the 21 EPU, non-LOCA events were also analyzed. There was a 22 request for information regarding our Appendix R, and 23 the following information is provided. This table 24 displays the peak drywell airspace pressure, peak 25 drywell airspace temperature and the peak bulk NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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179 1 suppression pool temperature is compared between CLTP, 2 EPU, and the design limits for the limiting Appendix 3 R event. The parameters are not significantly 4 impacted by the Appendix R event, the EPU power 5 conditions, and significant margin continues to exist 6 respective to the containment design analysis limits.

7 CHAIR ABDEL-KHALIK: Could you 8 qualitatively explain where the Appendix R limiting 9 scenario is?

10 MR. DAVISON: Let's see, Bill do you have 11 that in your notes? Shelly? From the remote shutdown 12 panel, right, RCIC is -- there's fire, scram, SRV 13 opening, remote shutdown panel. RCIC has to be placed 14 in service within 10 minutes, and suppression pool 15 cooling is placed in service within 20 minutes which 16 was previously time-validated by operations. The 17 scenario and the actions that come out of that is our 18 most limited.

19 CHAIR ABDEL-KHALIK: Okay. Thank you.

20 MR. DAVISON: And that ends the 21 containment response session. Any additional 22 questions?

23 CHAIR ABDEL-KHALIK: I guess the question 24 was raised earlier as to what independent 25 calculations, if any, the staff has performed in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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180 1 support of the calculations presented by the applicant 2 with regard to containment response.

3 MR. LOBEL: Excuse me, this is Richard 4 Lobel. The staff didn't perform any independent 5 calculations for Hope Creek. The staff has previously 6 performed independent calculations. We did some for 7 Duane Arnold a long time ago comparing our code 8 CONTAIN. I think we used -- if I remember right, we 9 used CONTAIN. It was either CONTAIN or MELCOR we used 10 to compare it with SuperHEX. And more recently, we 11 did mass and energy, independent mass and energy 12 release and containment calculations for the Vermont 13 Yankee power uprate and the agreement for both was 14 very good.

15 The mass and energy calculations 16 calculated by Vermont Yankee were conservative 17 compared to the staff calculations that we did we 18 RELAP. So we didn't feel it was necessary to do 19 independent calculations for another BWR core 20 basically the same type of design using the same --

21 comparing the same codes again. So we didn't do any 22 independent calculations for Hope Creek.

23 CHAIR ABDEL-KHALIK: So it was the same 24 suite of three codes used by Vermont Yankee?

25 MR. LOBEL: Yes.

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181 1 MR. WALLIS: I'm surprised you didn't do 2 any calculations. I mean here Said and I are doing a 3 hand calculation on the vapor pressure and the gas 4 pressure and so on to check that it makes sense.

5 Don't you do that routinely, I mean look at numbers 6 and say do they make sense physically? I would think 7 you'd always do that.

8 MR. LOBEL: Well, we do that kind of 9 thing. I was speaking to more formal calculations 10 with computer codes.

11 MR. WALLIS: Well, but the hand 12 calculations might be more believable in some context 13 than the computer calculations.

14 MR. LOBEL: Well, that's part of the 15 review to -- I mean that's a major part of the review 16 to look at the number and see that the numbers make 17 sense.

18 MR. WALLIS: Yes. And you make 19 calculations, too, don't you? Yes.

20 MR. LOBEL: The timing of the -- well, and 21 we also not only within a given submittal, but we have 22 the benefit of previous calculations from other 23 licensees so we can compare things.

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182 1 the temperature by a certain amount, you can easily 2 check that yourself and see is that reasonable.

3 MR. LOBEL: Sure.

4 MR. WALLIS: And do they make an error of 5 a factor of 10 or something. I would hope you guys do 6 that sort of thing.

7 MR. LOBEL: We do that sort of thing and 8 like I was going to say, we also compare calculations 9 between different submittals to see that, between 10 submittals, that if there is a difference in a number, 11 to try to explain the difference in terms of size of 12 vessel, size of containment, amount of water, 13 different technical specification limits and that kind 14 of thing. That's a big part of the review.

15 MR. WALLIS: Right.

16 MR. DelGAIZO: Sir, I would like to say 17 also -- this is Ted DelGaizo -- that we got our eyes 18 on that very subject which had to do with previous 19 margins we had shown on MPSH and the margins we were 20 showing here, and the staff made a nice catch on where 21 there were some disconnects which we explained that 22 did make sense actually when we dug into. So I think 23 there's no question they look pretty hard at MPSH from 24 our standpoint.

25 MR. LOBEL: I understand there was a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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183 1 question, too, about the LAMB code? Is there a 2 question?

3 MR. WALLIS: Oh, what's it based on? What 4 model does -- critical flow.

5 MR. LOBEL: Well, I think the GE people 6 could do a better job than I can, but it's 7 essentially, as I understand it, an ECCS code.

8 MR. WALLIS: It's a MUDI model for 9 critical flow?

10 MR. LOBEL: I believe so, yes, MUDI SLP 11 model for critical flow.

12 MR. DENNY: LAMB has both MUDI SLP and a 13 homogeneous equilibrium. And for Hope Creek, we used 14 homogeneous equilibrium.

15 CHAIR ABDEL-KHALIK: Is that conservative?

16 MR. DENNY: It is --

17 MR. LOBEL: It is in terms of mass flow.

18 MEMBER BANERJEE: It gives you a lower 19 sump speed.

20 CHAIR ABDEL-KHALIK: So it is not 21 conservative.

22 MR. DENNY: No, it is conservative. It is 23 not as conservative -- SLP would give you a higher 24 blowdown, yes. But is the licensing basis blowdown 25 method. Now the M3CPT UFSAR one that you have here NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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184 1 from their table, URSAR one was M3CPT with homogeneous 2 equilibrium. Now we use LAMB with homogeneous 3 equilibrium.

4 CHAIR ABDEL-KHALIK: Would the staff care 5 to comment about the appropriateness of using a 6 homogeneous equilibrium model for the blowdown phase 7 of the LOCA with regard to containment analysis.

8 MR. LOBEL: There was a staff evaluation 9 of a GE topical report using the homogeneous 10 equilibrium model that was done a long time ago. I 11 can't remember the date. And the staff concluded that 12 using the HEM was acceptable and conservative, not 13 because of the homogeneous equilibrium model itself 14 but because of the GE modeling that went along with it 15 resulted in a conservative calculation. And I don't 16 remember offhand what the details were, but it was a 17 staff evaluation of a GE topical report. I can get 18 the number of the topical report. I don't remember 19 offhand what -- why the conclusion was what it was, 20 but I remember it had to do with the GE modeling.

21 MR. BOLGER: This is Fran Bolger. You 22 know, the standard review plan for mass-energy release 23 requires that the blowdown had to be conservative 24 relative to data. The homogeneous equilibrium model 25 as it applied includes a multiplier in the sump-cooled NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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185 1 region, and that multiplier will yield blowdown rates 2 which are conservative.

3 MEMBER BANERJEE: The multiplier if you're 4 in sump-cooled blowdown. It's not sort of like a 5 Fauske multiplier, something like that? What do you 6 have there?

7 MR. BOLGER: I don't have the details on 8 how the multiplier was derived.

9 MEMBER BANERJEE: Anyway, whatever the 10 multiplier is, certainly it will be okay. It won't be 11 conservative in the sump-cooled range. It can just be 12 sort of a curve-fit to date probably and there are 13 various models. But in the two-phase region, I don't 14 see that saturate agreeing that it would be 15 conservative?

16 MR. WALLIS: So the bigger the pipe the 17 closer you get to homogeneous, don't you --

18 MEMBER BANERJEE: And the longer the pipe.

19 MR. WALLIS: - and the more weaker is very 20 close to homogeneous.

21 MEMBER BANERJEE: Yes, if you have a long 22 and big pipe, it's pretty close, but it depends on the 23 scenario I suppose. Short pipes, you're not 24 homogeneous.

25 MR. WALLIS: But it's been approved by the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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186 1 NRC so --

2 MR. LOBEL: If I remember the --

3 MEMBER BANERJEE: Against the laws of 4 physics. That's what you said --

5 MR. LOBEL: -- if I remember the topical 6 report, the analysis was for long pipes. It wasn't 7 just modeling a nozzle. It was modeling flow through 8 the pipe --

9 MEMBER BANERJEE: Yes. If it's a long 10 pipe, it'll be pretty good.

11 CHAIR ABDEL-KHALIK: We would appreciate 12 that reference.

13 MR. LOBEL: Okay.

14 CHAIR ABDEL-KHALIK: Please continue.

15 MR. DAVISON: That was the end of the 16 containment analysis actually.

17 CHAIR ABDEL-KHALIK: We'll continue with 18 the next presentation.

19 MR. DAVISON: Thank you, gentlemen. That 20 takes us to slide 50, start with the FAC presentation.

21 Hope Creek's FAC program was developed in accordance 22 with the industry standard from the NRC Generic Letter 23 89-08 requirements and, of course, the EPRI Guidance.

24 In 2006, the bases document was updated to include the 25 system's susceptibility evaluations including the wear NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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187 1 associated with both single- and two-phase flow. The 2 susceptible non-modeled analysis captures piping not 3 suitably modeled due to uncertainty of the operating 4 conditions or the actual small-bore pipe 5 configurations themselves. The non-modeled analysis 6 is used to prioritize inspections and proactive 7 replacement of the piping with non-susceptible 8 materials.

9 CHECWORKS, which Hope Creek has used since 10 Refuel Outage Number 6 was upgraded in 2007 to the 11 latest version and reflects the targeted power uprate 12 for 111.5% conditions. The living program consistent 13 of the predictive software and inspection results 14 trending and the operating experience ensures that our 15 inspections and replacement strategy --

16 MR. WALLIS: Now as I understand 17 CHECWORKS, it sort of evolves. You get it and then as 18 you get experience, you change the way it predicts 19 what's going to happen. And so it's very plant 20 specific.

21 MR. DAVISON: That is correct.

22 MR. WALLIS: And so when it says 23 predictive analysis here, it's really -- a lot of it 24 is based on your operating experience and inspection 25 and so on that gives it a much more realistic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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188 1 predictive capability?

2 MR. DAVISON: That's essentially 3 customized to the actual station and then we continue 4 to factor in --

5 MR. WALLIS: The more years you've been 6 using it, the better it should be?

7 MR. DAVISON: Correct. That is correct.

8 CHAIR ABDEL-KHALIK: Did I hear you 9 correctly saying that this has been essentially 10 extrapolated to the 11.5% power increase?

11 MR. DAVISON: Yes. So what we actually 12 did was we -- knowing that this cycle will be running 13 at 111.5%, we actually put it in for the full cycle.

14 We updated the model and then we went forward to look 15 to see if there is any earlier inspections -- or 16 excuse me -- later inspections in subsequent refuel 17 outages that because of the uprate would need to be 18 done earlier. So we actually plugged it in early, did 19 all of our extrapolations to determine if there were 20 things we needed to do ahead of time, our last refuel 21 outage in other words.

22 CHAIR ABDEL-KHALIK: How do you correct 23 for the fact that you are going to be operating part 24 of the cycle at the current licensing thermal power 25 and part of the cycle at the elevated power in trends NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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189 1

2 MR. DAVISON: We put 111.5 for the whole 3 cycle.

4 CHAIR ABDEL-KHALIK: Okay.

5 MR. DAVISON: We increased the wear rate.

6 CHAIR ABDEL-KHALIK: But if you're trying 7 to learn from this model to be able to extrapolate, 8 you ought to be able to extrapolate correctly.

9 MR. DAVISON: Correct. What we needed to 10 do is to do the initial prediction. What we didn't 11 want to do is wait until we got to EPU, updated the 12 model with 111.5 and find out that we should have 13 pulled up inspections early and it was too late 14 because our last refuel outage was in the fall of 15 2007. So that's essentially what we did to it.

16 CHAIR ABDEL-KHALIK: Okay.

17 MS. KUGLER: This is Shelly Kugler. Just 18 to correct Paul real quickly. The model was actually 19 -- was inputted that mid-cycle, we'd actually go to 20 111.5% -- it didn't -- the full cycle was not in there 21 -- so we could more accurately model with the EPU.

22 CHAIR ABDEL-KHALIK: Okay.

23 MR. DAVISON: Thank you, Shelly. On page 24 51 for what was the impact, the change of the EPU 25 conditions did not result in any actual new systems NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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190 1 being added to the FAC program. The evaluation of the 2 inspection scope for the next two refuel outages did 3 not identify any current scheduled inspections that 4 needed to be performed earlier. That was that 5 predictive and looking back to see if we needed to 6 pull things up. So nothing was identified.

7 However, changing wear rates will occur as 8 part of the EPU implementation. Therefore, additional 9 baseline testing was added to the program scope. In 10 fact, 9 new baseline components were added to the last 11 refuel outage back in the fall, and 18 will be added 12 to the next refuel outage which is our spring 2009 13 outage. The program is continuously updated to 14 incorporate the operating conditions, as we mentioned 15 earlier -- water chemistry, inspection results and any 16 configuration changes that we would make via 17 modification like as in small-bore piping.

18 Approximately 110 components are inspected 19 each outage if you normalize them to how many we do 20 per outage. As a result, numerous components have 21 been replaced with FAC-resistant piping; typically, 22 small-bore piping over the last several outages.

23 MEMBER ARMIJO: Along those lines, could 24 you fill me in on the extent to which you use, for 25 example, chrome-moly steels in your plant and the more NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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191 1 vulnerable materials?

2 MR. DAVISON: Yes. Most of the original 3 piping, small-bore piping wise, is carbon steel.

4 MEMBER ARMIJO: Carbon steel.

5 MR. DAVISON: Right. So everything we 6 replace, piping system wise, is with the higher chrome 7 content, chrome-moly steel so that it's FAC-resistant.

8 Still, you know, puts -- it's captured in the program 9 as an upgraded material that is not susceptible, but 10 all the replacements we do have the less susceptible 11 materials.

12 MEMBER ARMIJO: How about your bigger 13 lines, steam lines, extraction lines, other stuff?

14 MR. DAVISON: Almos't all of that is 15 carbon. It's all susceptible. No specific 16 replacements done. When we have an issue -- for 17 example, back in 3R14, our last refuel outage, during 18 the previous cycle, we had a through-wall leak of an 19 extraction-steam piping T. Most of that large piping 20 had been replaced with the upgraded piping materials.

21 However, the T -- it's a 26-inch T -- was not, so it 22 still remains susceptible. There was a kind of a 23 discontinuity between the inner diameters of the T 24 versus the piping in an upstream valve. It 25 accelerated some wear. It was in the FAC program, did NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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192 1 not detect it. We had a through-wall leak about 3/8-2 inch by 1-inch actual hole in the piping. When we 3 went in to do the repair, which was go inside the 4 piping in-body and do weld build-up on the ID of the 5 pipe, we used FAC-resistant material when we did the 6 repair on that T.

7 MEMBER ARMIJO: With a weld build-up?

8 MR. DAVISON: Correct, on the ID of the 9 pipe. That's correct.

10 MR. WALLIS: This feedwater heater number 11 1, that's extracting wet steam, is it? That's -- I 12 just wondered if the wetness changed significantly 13 when you extracted more, presumably, with the upgrade 14 and if the CHECWORKS really did a good job of taking 15 account of that?

16 MR. DAVISON: Well, it was the -- that's 17 our -- I mean that's why it's up on the screen. That 18 is our highest prediction of change of wear rates 19 roughly from 10 to 12 mils per year, which is why it's 20 a target force mainly driven by the increased 21 extraction pressure related to the turbine 22 replacements and, of course, the power uprate 23 condition.

24 MR. WALLIS: It's the pressure. Is it 25 steam or is it steam with droplets in it? Is that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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193 1 part of the problem with the wearing?

2 MR. DAVISON: I don't know if there's 3 anyone who can specifically help me with that. I know 4 it takes into account the liquid drop impingement --

5 MR. WALLIS: It probably does because 6 that's --

7 MR. DAVISON: -- part of it as well.

8 Correct. And it also factors in cavitation in other 9 circumstances as well.

10 MR. WALLIS: It's not really a safety 11 issue anyway unless someone happens to be in the 12 vicinity.

13 MR. DAVISON: Which is a locked high rad 14 area for us in that condition. Nonetheless, we don't 15 want to have steam leaks. In fact, we did an extended 16 condition on the other ones and we'll be affecting 17 some repairs because we do have some thinning, not 18 anything that would go through-wall, but we are going 19 to repair those, same methodology using the improving 20 materials.

21 MEMBER ARMIJO: As a weld?

22 MR. DAVISON: Correct, ID build-up, inside 23 diameter build-up of the piping T.

24 CHAIR ABDEL-KHALIK: The 10 to 12 mils per 25 year, does that correspond to this maximum average NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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194 1 wear rate --

2 MR. DAVISON: Yes.

3 CHAIR ABDEL-KHALIK: for that 4 particular line?

5 MR. DAVISON: It's actually 10.5 to 12.3 6 is the prediction in increase. It's a .0023 inches 7 per year increase in wear in that location.

8 CHAIR ABDEL-KHALIK: And just for 9 reference, how thick is the pipe?

10 MR. DAVISON: It's -- we do have a nominal 11 thickness on that, in the piping. I think it's 1-12 inch, but we can get that.

13 CHAIR ABDEL-KHALIK: How big is the line?

14 MR. DAVISON: Twenty -- do you have the 15 piping size, Shelly or Paul?

16 MEMBER ARMIJO: What pipe are we talking 17 about?

18 MR. DAVISON: Extraction steam in the 19 number one feedwater.

20 MR. WALLIS: It's probably way above the 21 thickness necessary to meet the requirement.

22 MR. DAVISON: Oh, yes, structural 23 integrity, even with the through-wall, was never 24 challenged. We did do structural analysis to make 25 sure that even with the leak, we didn't have a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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195 1 structural integrity problem. This is strictly just 2 through-wall leakage. And we have a set of PNIDs we 3 can pull these --

4 MR. WALLIS: That's fine. We'll follow up 5 later.

6 MR. DAVISON: Okay. So we talked about, 7 you know, the highest one being this number one 8 feedwater heater. We will be performing additional 9 inspections in that particular area to validate the 10 model and make sure we check it going forward, because 11 that's our number one focus area.

12 Okay. And the last slide, 52, we have 13 incorporated EPU into the model, made the necessary 14 adjustments to our inspection program. No new scope 15 was specifically added. Implementing EPU does not 16 cause any near-term pressure boundary challenges 17 associated with FAC and our components. They're 18 adequately verified, inspected and checked in the 19 model itself. And we don't foresee any specific 20 challenges with increased flow.

21 If there are no questions, I'll go right 22 into patient curves. Okay. In slide 53 and actually 23 54 and 55 are the three actual patient curves that 24 were adopted back in November of 2004 when we did the 25 uprate for the neutron fluence associated with the EPU NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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196 1 conditions to ensure that the fracture toughness of 2 the vessel material bounds the structural integrity 3 requirements. The fluence was developed using the NRC 4 methodology in accordance with the GE topical report.

5 The curves are applicable through the end of life 6 which is less than 32 effective full power years.

7 For all three individual curves, the upper 8 vessel limit shown as the dashed line to the right 9 there is impacted by the stress level increase 10 associated with the feedwater flow, the feedwater 11 nozzles flow and temperature changes associated with 12 the EPU. The fluence impact on the belt line, which 13 is the solid line, does not become limiting, and 14 ultimately, the upper shelf energy remains greater 15 than the code requirement for the design of the life, 16 50 foot-pounds.

17 One thing to add -- we are a member of the 18 Integrated Surveillance Program for all the U.S. BWRs.

19 However, Hope Creek is the only Hitachi vessel in the 20 United States, and our specific data is actually only 21 used for Hope Creek itself.

22 The first of three capsules were removed 23 at the end of Cycle 5. Two capsules remain in the 24 vessel. The second capsule will be removed in 25 approximately 2014, which is one year earlier than the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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197 1 pre-EPU predication for the quarter-t fluence level.

2 The third capsule remains in the vessel for future 3 considerations. No specific plans on removing that 4 capsule right now.

5 MEMBER ARMIJO: I guess I don't understand 6 the issue about the Hitachi vessel. Now you can use 7 the data from the other plants but they're not using 8 the data from your plant? Or how --

9 MR. DAVISON: Yes. Actually, we are a 10 member of the Integrated Surveillance Program because 11 we share costs with the other folks who are in that, 12 and we share lessons learned, generic lessons learned.

13 Because we are the only Hitachi vessel, we really --

14 our data goes in and we use our own data. Nobody else 15 can use the data. We're in it for the --

16 MEMBER ARMIJO: You can't use other 17 people's data either --

18 MR. DAVISON: Not the specific data, 19 correct. If they do lessons learned, changes in 20 methods, something comes out that's applicable to 21 everybody, we will take those learnings, so we want to 22 be part of the learning organization from the, you 23 know, the body of OE. But as far as data in-data out, 24 it's our Hitachi vessel.

25 MEMBER ARMIJO: Okay.

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198 1 MR. DAVISON: And that really ends my 2 update on the curves unless there are specific 3 questions. They've been in effect since 2004. We 4 will be submitting for license renewal in August of 5 2009. At that time, they would be updated again and 6 that methodology would be adopting or changing to the 7 RAMA code for the fluence levels.

8 MR. WALLIS: Does this uprated power 9 change the embrittlement life of the vessels 10 significantly?

11 MR. DAVISON: No, it does not.

12 MR. WALLIS: It doesn't change it by year 13 or something like that? It's less than -- presumably, 14 there's more fluence? Is there more fluence or less -

15 - depends upon how you arrange things, doesn't it?

16 MR. DAVISON: Yes. There will be more 17 fluence.

18 MR. WALLIS: Okay, more fluence.

19 MR. DAVISON: In fact, when we get to 20 vessel internals, we'll talk about the individual 21 fluence levels --

22 MR. WALLIS: We'll do that tomorrow?

23 MR. DAVISON: -- on not only the internal 24 components but the vessel itself.

25 CHAIR ABDEL-KHALIK: Are there any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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199 1 additional questions for Mr. Davison?

2 (No audible response.)

3 CHAIR ABDEL-KHALIK: Are there comments 4 that the staff would like to make on any of the topics 5 that were presented today?

6 (No audible response.)

7 CHAIR ABDEL-KHALIK: Okay. We're 8 adjourned for today.

9 (Whereupon, at 3:21 p.m., day one of the 10 foregoing matter was adjourned.)

11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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CERTIFICATE This is to certify that the attached proceedings before the United States Nuclear Regulatory Commission in the matter of:

Name of Proceeding: Advisory Committee on Reactor Safeguards Docket Number: n/a Location: Rockville, MD were held as herein appears, and that this is the original transcript thereof for the file of the United States Nuclear Regulatory Commission taken by me and, thereafter reduced to typewriting by me or under the direction of the court reporting company, and that the transcript is a true and accurate record of the foregoing proceedings.

Charles Morrison Official Reporter Neal R. Gross & Co., Inc.

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Ag_)e-njd-)a Day 1

" Introduction Tom Joyce

" Hope Creek EPU Overview Paul Davison

" Operations Bill Kopchick o Power Ascension and Testing Bill Kopchick

" Fuel Methods Don Notigan o Containment Analysis Methodology .Paul Davison and Response o FAC and Pressure-Temperature Limit Curves Paul Davison Day 2 o Steam Dryer and Vessel Internals Paul Davison o Probabilistic Safety Assessment Ed Burns Grid Reliability Paul Davison aoere etf CGf qeRA'n 1-3

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Background

Licensing Approach Hope Creek Plant Overview EPU Parameter Changes EPU Major Plant Modifications EPU Implementation Schedule Conclusions HoPeCreek 1-5 000*0004*01090*00000000000QOOOOOOOOQOIOOQI004,f

- - :~y(.I,1pIhrT Hope Creek Generating Station n 100 percent owned and operated by PSEG Nuclear, wholly owned subsidiary of PSEG Power.

o Operating License issued 7/25/1986

" Boiling Water Reactor- GEType 4

" Mark 1 Containment

" Thermal Power o Original license 3293 MWt o 1.4 % Appendix KUprate 3339 MWt

- Implemented 2001 o 15% Requested Uprate 3840 MWt

• U~PMGSTAIION 1-6

Hope Cree EU Ovevie MWt versus %Power 3952 MWt --- 120.0% ------------------ 118.4% ----------

- 102.9%

3840 MWt EPU 116.6% 115% --------------- 100% ----------

3723 MWt TPU --- 113.1%- ---------- 111.5% ---------------- 97.0% -----------

3339MWt CLTP(AppK) 101.4% -------------------- 100% - 87.0% ----

3293 MWt OLTP 100 % -% - - 98.6% ------------------- 85.8% -----

% 3293 MWt  % 3339 MWt  % 3840 MWt OLTP Power CLTP Power EPU Power

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Licensing Approach Alternate Source Term o Amendment 134 Pressure/Temperature Limits o Amendment 157 GE14 Fuel Transition o Amendment 158 ARTS/MELLLA e Amendment 163 Ei EPU License Amendment 0

,yope~ 1-8 I -8

Parameter Changes Parameter CLTP EPU (115%)

Core Thermal Power (Mwth) 3339 3840 Full Power Recirc Flow Range (Mlbm/hr) 76.6-105 94.8-105 Nominal Steam Dome Pressure (PSIA) 1020 1020 Feedwater Flow (Mlbm/hr) 14.37 16.74 Main Steam Flow (Mlbm/hr) 14.40 16.77 Final Feedwater Temp (Degrees F) 422.6 431.6 1-9

Hop, reek Ee zai wi 2003 2004 2006

• 500kV Breaker for Grid e Installed LP Turbines & e Implemented Stability (required by PJM) Controls (DEHC and TSI) ARTS/MELLLA

• Installed Cooling Tower e Increased Main Generator

• Upgraded 'A' Steam Jet Air Upgrade Rating Ejector e Installed Turbine Moisture

• Upgraded Iso-Phase Bus Separator Upgrades Duct Cooling 9 Replaced A & B Phase Main

• Feedwater Heater Dump Station Transformers Valve Upgrades 9 Temporary Vibration

• Replaced Moisture Monitoring Equipment (for Separator Relief Valves baseline data acquisition)

• Replaced 5th Pt FWH Relief Valves

• Upgraded MSL Pipe Supports

• Installed MSL Strain Gages in Drywell Hpcreek 1 -10

~F~ERATu4a STAttOf~ 1 10

2007 2008 (After License Amendment)

• Upgraded Condensate Demineralizer

• MSL High Flow Setpoints Resin Trap Strainers o OPRM Setpoints o Installed HP Turbine o APRM Setpoints

• Installed Redundant MSL Strain Gages o HWCI

• Modified MSL Small Bore Piping Socket Welds

• BOP Instrumentation Replacements, Scaling, and Setpoint Changes

• Raised RCIC Turbine Backpressure Trip Hqpe"reek

( 0gc 1 -11

EPU Projected Implementation Schedule Plant Physical Modifications o Complete Ei Tech Spec Setpoint Changes o Online following License Amendment E] Power Ascension from 100% CLTP to 111.5% of CLTP o Spring 2008 Ht.o..ree~, 1-12

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0tý,ns, S na Tes.[,n Overview

• Operator Training

• Operator Response Power Ascension Testing f Hpe Cree qTerO 1 -14

Plant Modifications Classroom &Simulator Training Procedure Changes Operating Experience r//t*eCreek-11 0~~~~~00000000000000000000000000000000

Rie'-'pqnt No New Operator Actions Result from EPU Changes to Response Times u Detection &Diagnosis Time c3Time to Achieve Cold Shutdown Increases s Accident Time to Reach TAF Decreases Ei Time to Boil During Shutdown Decreases No Mitigating Strategies Affected Minor Changes to EOPs HCTL, PSP, BIIT

• Hope Creek; GFMr TAV?

1 -16

,e, pýonj Emergency Operating Procedures E

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ID CD_

400 500 600 700 800 900 1000 1100 RPV Pressure (psig)

Heat Capacity Temperature Limit(HCTL)

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Emergency Operating Procedures 40-

- EPU 35 - -- __

CLTP 0LT ca 30-n 25- -

E 20-o 15 in CL U)

Suppression Pool Water Level (ft)

Pressure Suppression Pressure (PSP)

HlPe Creek 1 -18

Emergency Operating Procedures CL E

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3 U) 10 Reactor Power (%)

Boron Injection Initiation Temperature (BUT) a I` Cmekr,)

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P -Wt A~s.esl TeStin Preparation Organization &Conduct of Testing Incremental Approach (Power Plateaus)

Major Test Evolutions (IY=-peIreel 1 - 20

Preparation o Test Objectives o Satisfactory Equipment Performance o Careful, Monitored Approach to EPU Power o Meet All Established Requirements o Roles &Responsibility Development/Industry Benchmarking o Test Plan &Implementing Test Procedure Development E] Power Ascension Test Training

- 1-pe2 1 - 21

BI1Q)win A-c-aIla Te- i HOPE CREEK EPU IMPLEMENTATION & POWER ASCENSION TEST TEAM ORGANIZATION II HCGS PLANT MANAGER I a-- ---

II Test Director III Project Manager II Licensing Environmental Licensing I

y IPA Test Manager 11 EPU Implementation & Test Team Leader II Ii EPU Implementation & Test Team IPA Coordinator Implementation Lead Pwr Ascension Lead II l,

EPU Lead Responsible Engineer ,lI Team Member Core Performance fl- Team Member Chemistry/Radiation Team Member Lii Team Member I I&C/Digital Feed Pressure Reg/Feedwater I

Team Member Team Member Turbine Valve/MSIV M Vibration Monitoring Team Member Performance Monitoring H GE StartUp Consultant 1 C-

• HbeCekj 1 - 22

Incremental Approach mCommitments in PUSAR; LCR H05-01; and ELTR-1 o Similar to Approach Used in Other EPUs E] Baseline Data at 90% and 100% Followed By Constant Rodline Power Ascension at 2.5% Increments Ei Power Plateaus at Each 5% Power Step &Final Power

• HbPeCreek 1 - 23

-0) *N-~,.

en* b, Major Test Evolutions o Twelve Power Ascension Tests E] Steam Dryer/Critical Piping Monitoring Program E] EPU System Monitoring Plans Plant Walkdowns

• H~oeCreek; 1 - 24

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Cycle 15 EPU Core Design

• Core loading consists of 216 SVEA-96+ and 548 GE14 fuel assemblies

• All fuel assemblies have PCI resistant design (barrier liner clad) and integrated debris filter features 0

1- 26

Application of NRC Approved GE Methods to Core Design

&Safety Analysis for EPU Confirmatory Evaluations of Key Fuel Parameters Were Performed for Legacy Fuel (non-GE fuel) o Limitations and Conditions from NRC-Approved Licensing Topical Report NEDC-33173P "Applicability of GE Methods to Expanded Operating Domains" Applicable to Hope Creek EPU Were Fully Implemented o All Cycle Specific Core Design Calculations and Reload Evaluations for EPU Are Complete o Supplemental Reload Licensing Report Is Complete 1 -27 soQooooQoo~ooQooooooooo00000000000000000000o

Confirmatory Evaluations for SVEA-96+ Fuel in Cycle 15 EPU

• Low Reactivity Profile o BOC average bundle exposure = 33455 MWD/STU

• Maximum Bundle Powers of SVEA-96+ Fuel in Cycle 15 at EPU are Less than Maximum Bundle Powers Experienced in Cycle 14 at CLTP

• SVEA-96+ Fuel is Non-limiting with respect to MFLCPR, MAPLHGR and MFLPD Thermal Limits SVEA-96+ Fuel Does Not Contribute to Safety Limit MCPR

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Limitations and Conditions for Hope Creek EPU o SER Imposes 25 Limitations and Conditions for Use of GE Methods on Expanded Operating Domains o 14 of 25 applicable to Hope Creek EPU Cyclel5

- All 14 limitations and conditions met o 11 of 25 not applicable to Hope Creek EPU Cycle 15

- No TGBLA04, No MELLLA+, and No TRACG AOO 1Ce1-29 DO 0 0 0 00 0 0 0 00 0 0 0 00 0 0 0 0 00 0 0 0 00 0 00r0 0 00O

Conclusion o Application of NRC Approved GE Methods with GEl 4 Fuel Design o Three Consecutive GE14 Reloads o Fuel Performance consistent with the EPU Reference Plant Experience Base o Confirmatory Evaluations Performed for Legacy Fuel (non-GE fuel) o Legacy fuel will be non-limiting in EPU core operation Ho

~FNER~8TA1r1Qff ek 1 - 30

Conclusion Limitations and conditions from NRC Approved Licensing Topical Report NEDC-33173P applicable to Hope Creek EPU were fully implemented All EPU Cycle Specific Core Design Calculations and Reload Evaluations are Complete Ei Supplemental Reload Licensing Report'is Complete Ei Fuel Methods and Analyses Confirm the Safe Operation of the Fuel inthe Hope Creek 115% Extended Power Uprate 1 - 31

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Limitations and Conditions from NRC Approved Licensing Topical Report NEDC-33173P Applicable to Hope Creek EPU Were Included inthe Hope Creek SER All Applicable Limitations and Conditions inthe Hope Creek EPU SER Were Fully Implemented 0

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00**90000*0009000000900000000006000000000000 Limitations and Conditions for Hope Creek EPU SER Imposes 25 Limitations and Conditions for Use of GE Methods on Expanded Operating Domains o 14 of 25 applicable to Hope Creek EPU Cycle15

- All 14 limitations and conditions met o 11 of 25 not applicable to Hope Creek EPU Cycle 15

- No TGBLA04, No MELLLA+, and No TRACG AOO 1- 34

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SER Limitation or Condition Y

Disposition TGBLA06/PANAC1 1 methods used for Cycle 15 Core Design Power-to-Flow ratio =41 MWt/Mlbm/hr (3840 MWt) / (94.8 Mlbm/hr) 0.02 added to the Cycle 15 dual loop and single loop SLMCPR for EPU operation C

1- 35

SER Limitation or Condition

1. Disposition R-factor calculation at a bundle level confirmed to be consistent with hot channel axial void conditions 7 ECCS-LOCA analyses included top and mid-peaked power shapes Fuel Rod T-M Acceptance Criteria met for U02 and GdO2 rods

,HopeCreek 1 -36

~&oFN~AArJJ4a S~Ar~ct~ I 36

SER Limitation or Condition

1. Disposition Analysis results demonstrating compliance with T-M 10 criteria documented in SRLR; analysis results will be supplied to NRC as attachment to EPU Core Operating Limits Report 13% margin calculated to screening criteria for fuel melt 11 (TOP); 22% margin calculated to screening criteria for pellet-cladding mechanical interaction (MOP) 17 Bypass voiding confirmed to remain below 5%at all LPRM levels when operating at steady-state conditions

\ENEJOQATJOOjOQ8TOOf 1 - 37

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SER Limitation or Condition

1. Disposition OPRM cell calibration errors due to presence of 18 bypass voiding at low-flow conditions were accounted for in cycle specific evaluations of OPRM setpoint 0.01 added to Cycle 15 OLMCPR for EPU conditions to 19 account for uncertainty in Findlay-Dix void quality correlation Plant specific application of GE methods to SVEA-96+

Fuel has been justified e ee 1 -38 JPLflON 1 38

SER Limitation or Condition

1. Disposition Plant specific application of TGBLA06 to SVEA-96+

Fuel has been justified 1- 39

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1. 25 EPU Reference Plant Experience Base Comparison HCGS 115% Consistent with Metric Value EPU Value Experience (Y/N)

Max. Bundle Power (MW) 7.58 7.18 Y Max. Bundle Power/Flow Ratio 0.89 0.77 Y (MW/(Ib/hr xl.OE-04))

Exit Void Fraction of Max. Power Bundle 0.90 0.88 Y Max. Channel Exit Void Fraction 0.90 0.88 Core Avg. Exit Void Fraction 0.77 0.76 Y Peak LHGR (kW/ft) 13.4 12.52 Y Peak Nodal Exposure (GWd/ST) 58.8 57.97 Y dpeCreek 1 - 40

• ",.&-~~~~~ F'-**,-* .,7" Conclusion Ei Limitations and Conditions from NRC Approved Licensing Topical Report NEDC-33173P Applicable to Hope Creek EPU Were Included inthe Hope Creek SER All Applicable Limitations and Conditions inthe Hope Creek EPU SER Were Fully Implemented o Fuel Methods and Analyses Confirm the Safe Operation of the Fuel inthe Hope Creek 115% Extended Power Uprate k,,*",.4e rAn

• 1 - 41

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I 1 - 43

inaf Re p~ -rs Used NRC Approved GE Analyses Methods Primary Analysis Codes

• LAMB -- Blow-Down Flow Rates

• M3CPT -- Short Term Pressure &Temperature Response

• SHEX -- Long Term Containment Response Short Term Results Minimal Containment Impact

" Small Blow-down Flow Rate Change due to Constant Pressure Power Uprate Long Term Results o Increased Peak Bulk Suppression Pool Temperature o Increased Decay Heat Loading ffHp*Cr~eek; 1 - 44

Analyses

" Analyses at or above 102% of 3840 MWt

" Decay Heat by ANS/ANSI 5.1-1979 with 2a Uncertainty

" Passive Heat Sinks Credited in Long-Term Analysis Results All Containment Parameters Remain Below Design Limits Analyses Comparison E] CLTP Response Compared using CPPU Methodology (1peCreeI-4 ~1 - 45

-;--n,-,t9 se ctne 0a, G-mpais Hope Creek DBA LOCA Containment Performance Results CLTP Parameter 3339 MWt EPU Design UFSAR EPU Method 3840 MWt Limit Method Peak Drywell 48.1 psig 47.6 psig 50.6 psig 62 psig Air Space 2910 F 2950 F 2980 F 3400 F Peak Bulk 210 0F 201FF 212.30 F 218°F Pool Temp Peak Wet 27.5 psig 27.6 psig 27.7 psig 62 psig Well Air Space 210 0F 198.2 0 F 212.2 0F 310 0F

!HopeCreek 1 -46

~~~:¶mRATJMa 8TAYWM I 46

Is E* V B RHR and Core Spray NPSH-Available Assumptions mBulk Pool Temperature - 2180 F Ei Containment Pressure = 14.7 psia NPSH-Required Based on Maximum Tested Flows NPSH-AVAILABLE > NPSH-REQUIRED 1 -47

Appendix R Analysis Responses Parameter CLTP EPU Design Limit Peak Drywell 9.3 psig 11.1 psig 62 psig Pressure Peak Drywell 300.20 F 300.30 F 3400 F Temperature Peak Bulk Pool 195.50 F 206.30 F 2180 F Temp I I II g pc~e 1 - 48

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Program Overview

• Program Meets Generic Guidance o Generic Letter 89-08 o EPRI Tech Report 1011838 (NSAC 202L)

• Basis Document updated 2006 Susceptible Non-Modeled (SNM) analysis completed 2006 CHECWORKS predictive model upgraded 2007 Program incorporates:

e Predictive analysis using EPRI software o Component re-inspections (trending) o SNM o Operating Experience - Industry &Plant o Engineering Judgment 1 -50

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-0 *- **'eatd Qorsigo EPU Impact Ei No additional -systems added to FAC program o Previously inspected components reviewed for impact to next scheduled inspection - No impact o EPU.Baseline Inspections n EPU Flow and Temperature Changes Maximum average wear rate increase: 23.2% (#1 FWH Extraction- Steam subsystem)

"ISreek 1 -51

Conclusion FAC Program active; takes into account changes in plant configuration and operating conditions Results of EPU impact incorporated into inspection scope to ensure no near-term pressure boundary issues as a result of EPU

" STAON 1 -52

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HCGS PV &InternalsI~

- fet Fluence HEAD VENT U - HEAD SPRAY Flow Induced Vibration (FIV)

Structural Effects IGSCC STEAM OUTLET (TYR OF 4)

Post-EPU confirmation inspections

- TOP GUIDE JET PUMP m- REORC INLL-(TYR OF 10)

!7 RECIRC LOOP SUCTION CORE PLAT E CRD HOUSING I TO CLEANUP COOLING WATER S M SUCTION HqeLGWek 2-2

Em-,P lu'n *R P`:I Irradiation-Assisted Stress Corrosion Cracking (IASCC)

Components exceeding IASCC fluence threshold of 5x102o n/cm 2 Shroud Top Guide o Incore Dry Tube Assembly

[ Shroud inspection remains lAW BWRVIP-76.

Top Guide inspection program will be implemented following EPU o Grid beams will be inspected lAW BWRVIP-183 o 10% cells will be inspected within 12 years, 5%in 6 years o Sample locations will be high fluence locations

, Incore dry tubes will be inspected lAW GE SIL 409 9-11

Results of evaluation - EPU will not adversely affect RPV internals

• Vibration levels for EPU estimated by extrapolating prototype plant data and GE experience

• Shroud, shroud head &moisture separator, jet pumps, feedwater sparger well below GE acceptance criteria Jet pump sensing lines - no resonance with recirc pump vane passing frequency E2-4

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-P-Results of evaluation - EPU will not adversely affect RPV Evaluated components with CLTP fatigue usage factor

>0.5 and experience changes inoperating parameters o All remained acceptable with respect to stress and fatigue.

- Main Closure Studs

- Shroud Support

- Core Spray Nozzle Verified that modified components, three RPV nozzle weld overlays, acceptable for EPU operation.

Hope Creek has no ASME flawed components accepted for continued service by analytical evaluations HoCreek2-5

IGSCC program implementation not changed by EPU

[ EPU causes slight changes to temperature, pressure and flow for reactor coolant pressure boundary materials; negligible effect on tensile stresses o EPU results in higher oxygen generation rates; hydrogen injection rates will be adjusted to compensate E] No material changes as a result of EPU HoC# k 2-6 GEN~AArN.~ S TAT/ON 2-6

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Jet pump wedges lAW BWRVIP-41, Rev. 1 Changed core resistance Feedwater spargers and end brackets o Increased flow Shroud head bolts Increased feedwater flow impacts bolts HpCreek 2-7 2-7

s~e I *,re Steam Dryer Design Margin Power Ascension Test Plan Hope Creek 2-8 GENC0000A0 00,000 000rA0 000 00N00 2-8 o

j,ea p,e C,rre e,k Ste-am Dry,e-,r;'D_'easii gn H-Curved Hood 3rd generation of GE steam dryer design Modified on-site prior to operation Baseline Inspections done o Per BWR VIP recommendations o No fatigue cracking identified 0*eCre 2-9

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• I W0 *

• 19, Outer Hood 0.5" Center outlet Plenum 0.5" Tie-bars 2" x 2" Reinforced middle and inner hood to end plate joint Center, Support lugs on RPV ID Outlet Plenum (not shown) leveled Hood to end plate reinforcement N'J I...

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• 1" 2- 10

Sie- tf D a'ns, MSL Flow MSL Flow Dryer EPU MSL Branch Velocity Velocity Drye r EPU LBrn (ft/sec) OLTP (ft/sec) EPU Configuration Operation Dead Legs Vermont 140 168 Square Hood 120% OLTP None Yankee Quad Cities 168 202 Square Hood 117% OLTP None Unit 2 Susquehanna 135 153 Curved Hood 120% OLTP Loops A and Units 1 and 2 D Hope Creek 141 167 Curved Hood 116.6% OLTP None Crro 2-11

Hop Cree Mai Sta Lie C D A A

Upper dr1y%%Cll locationi

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K Dashed red-lines show location of SSES 26-inch MSL dead branches, which do not exist at HCGS.

HopeWCreek 2-12 0000000000000000000000000000000000000000000o

Q000000000000000000000000000000000-0000000000o Locations (all are welds) Stress Ratio Stress Ratio Shift SR-alternating SR-Peak Outer hood vane bank /perforated 2.18 4.64 -7.5%

entry plate Inner hood / hood support (stiffener) 2.22 4.64 +5.0%

Middle vane bank / base plate 2.24 4.59 +5.0%

Outer hood vane bank top vertical plate 2.27 4.72 -7.5%

/ perforated entry plate Skirt / upper support ring 9.36 1.58 0%

Inner hood / outlet plenum end plate 4.34 1.83 -10%

Cover plate / outer hood 3.72 2.42 -7.5%

Inner vane bank side panel/outlet 23.98 2.43 +5%

plenum end plate 23.98_2.43_+5%

HopeCheek 2-13

S .. D.... ........-

. . I 1 IA. -, I .II Monitoring

• MSL strain gages

• MSL accelerometers

• MSL moisture carryover Evaluation

" Strain gage limit curves

" Power ascension rate of < 1% CLTP/hr

" Collection of strain gage data at every 1% increase o Used for trending

" Evaluation every 2.5% power

" Power plateaus at each 5% power step and final EPU power Reporting o Provide data for NRC review at each plateau (5%power) iH/iec2eek GEE~,~SAIN2-14

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Strain gage data shows a relatively quiet plant.

ACM revision 4 used to improve predictions at low frequencies FEM performed with harmonic domain methodology for more accurate results Biases and Uncertainties were accounted for in-both ACM &

FEM Alternating stress ratios at EPU remain-above 2 Slow and Measured Power Ascension Plan

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Revision 4 o 0 Hz-60 Hz -((

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Revision 4 is identical to Revision 2 for 60- Hz - 200Hz Revision 4 n Based on Benchmark of Quad Cities utilizing Hope Creek's EPU Mach Number Blind Benchmaark of Quad Cities was-completed at higher Mach Number ACM Predictability same at both power levels HpeCreek2-19

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Hdjiiecreek9 GgrATNGT Th2 -- 20

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Performed in harmonic domain which results in more accurate results El Harmonic domain utilizes 1% damping over entire frequency range Time domain requires "pinning" structural damping at two frequencies o Between the two pins, damping was under-predicted o Below the lower pin and above the higher pin, damping was over-predicted

=. Actual stress for each frequency can be quickly calculated Benchmarked time domain and frequency domain o Results the same when differences indamping are accounted for G2-21

Pressures are deduced from circumferential strain measurements made on Main Steam Lines Strain measurements contain noise in addition to acoustic pressure fluctuations Strain measurements are conditioned by removing following noise signals o]

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Most significant impact of signal conditioning occurs at-((

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Strain Gage Error (( (3)))

Strain Gage Location Error (( (3)))

Pressure Sensor Error (( (3)))

Total Bias &Uncertainty accounted for by increasing appliediload.

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~-HojeGreek 2 -23

'~rAroN 2-23

FEM modeling benchmark Independently validated CDI's capability to model a complex structure Developed a Unit 2 Steam Dryer FEM Performed Forced Vibration Test utilizing Hope Creek Unit 2 steam dryer FEM Predictions Compared Favorably with Test Data FEM Bias and Uncertainties Derived e2 - 24

-Elem tit-Model' Wasa Effect on Bias Effect on Source (%) Uncertainty (%)

Shaker Tests Discrete Mesh Error Discrete (3)))

Frequency Error, Bias and Uncertainty are not frequency dependent Calculated loads increased by FEM bias and uncertainty.

1H( peCreekP 2 - 25

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Frequency shift of load between +/-10%

Lowest stress ratio among all shifts was used as stress ratio for that node A2 - 26

Smallest alternating stress ratio 2.18 Conducted test at 1/8th scale 1/8-Scale Model Testing (SMTs) predicted onset of Safety Relief Valve (SRV) acoustic resonance SMT results not used to define CLTP dryer loads (311) o Test predicted an increase of ((

(3 )))

fHtpe Creek*

2 -27 G~igCRAr~NC '~TAraN 2-27

MSL Strain Gage Data Shows a Relatively Quiet Plant.

ACM Revision 4 Used to Improve Load Predictions at Low Frequencies FEM Performed with Harmonic Domain Methodology for More Accurate Results Biases and Uncertainties Accounted for-in ACM &FEM Margin to Stress Limits at EPU Remains Greater Than 100%

G~E G2-,re 28

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Purpose of EPU Risk Evaluation E] Provide risk perspective regarding effect of EPU implementation o Estimate change in Full Power, Internal Events CDF and LERF produced by EPU implementation o Identify qualitatively changes in risk from other sources (e.g., external events and shutdown configurations) produced by EPU implementation o Compare with RG 1.174 for risk significance of change 2H-230 00000000000000000E00A000N00000A0000N

Risk Evaluation Process Overview n EPU submittal based on deterministic evaluation of licensing criteria, i.e., not a risk-informed submittal.

mRegulatory Guide 1.174 provides quantitative measures that provide risk perspective on EPU submittal.

mQuantitative risk metrics chosen by NRC in RG 1.174 are Core Damage Frequency (CDF) and Large Early Release Frequency (LERF).

n RG 1.174 acceptance guidelines consider both initial values and magnitude of changes in CDF and LERF as a result of proposed changes.

H/ ICrleek 2-31

Risk Evaluation Methods E3 Identify plant configuration and procedural changes

• Use updated PRA models

• Identify those PRA elements affected by changes

• Incorporate hardware and procedure changes in PRA model EiUse realistic success criteria and limits

• Calculate risk metrics (ACDF, ALERF)

• Compare results with Reg. Guide 1.174 Guidelines

~~A 2- 32 000*0000000000offoooo0000000000000000000000oo

ba!b¶¶"fis. y -at me EPU Changes Possible PRA Elements Affected Success Criteria (Depressurization, ATWS overpressure)

Power Level HRA (Allowed Timing)

System Fault Trees (SORV probability I Challenges)

Level 2 (Core Melt Progression Timing)

HRA Configuration Changes System Fault Trees Initiating Events (Reduced Margin)

Hardware Changes aPhysical Changes System Fault Trees oReliability changes (bounding) Data (including Initiating Events) 1 Procedural changes HRA (Time available and EOP limits)( )

Procedural__changes_ Success Criteria (1) Changes in time to cues based on RPV water level, PSP, HCTL, BIIT.

(H---Cr k 2 -33 G~IJERAT~N~ ~rKI ION 2 33

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~l.afeý-A-.,e.*. at ai Hope Creek PRA Model Scope and Quality o Internal Events PRA developed inaccordance with ASME PRA Standard to meet Capability Category 1-o Industry Peer Review conducted November 1999 PRA Model extensively modified in2003 to resolve all recommendations (i.e., F&Os) o PRA self-assessment against ASME PRA Standard Addendum B June 2006 confirms 92% of Supporting Requirements meet Capability Category 110) o External Events and Shutdown Conditions addressed, but not quantified (only scoping studies available) o Assessed to be very small contributors to change in risk associated with EPU implementation

() Capability Category IIis expectation for PRAs to support risk informed submittals.

Hdpe Creek-GEEAIGSAIN2 - 34

B~-~ A ss EPU PRA Changes ASME PRA Element Modified Initiating Event Frequency to reflect potential for increased IF challenges due to reduced margins (e.g., %flow margin)

Slight change in system success criteria (RPV Depressurization, SC ATWS over pressure, modified number of SRV challenges)

No significant impact due to. hardware changes (e.g., replaced "in-kind" with like equipment), however, modified SORV probability No new accident sequences identified AS Reduced time available for crew diagnosis and execution HR No significant impact due to procedural changes (HCTL, PSP, BIIT HR changes are assessed as negligible)

HopCrek. 2 -35 GENEflANG ~A ON 2 35

Summary Comparison Baseline (CLTP) and Uprated (EPU) CDF and LERF for Hope Creek Internal -Events Model Change in RG 1.174 Risk Risk Metric CLTP EPU Risk Metric Characterization CDF 9.42E-06 1.01 E-05 6.8E-07 Very Small LERF 2.37E-07 2.98E-07 6.1 E-08 Very Small

<Hi--- Creek* 2 -36 GeNCRAYNO ~TATJON 2 36

1Probabilisi

- t Styii AssessmenrO OO

___ OOO OOt_

Acceptance Guidelines for CDF LL a

0 10-5 1.6 10-6 10-5 104 10-3 CDF -- )

E0 Upper bound estimate of CDF change for power uprate Acceptance Guidelines for Core Damage Frequency (CDF)

(Uses HCGS Level 1 and 2 PRA for Internal Events)

HGCNEfr eG STAT)ON 2 - 37

Probblsi Saet Assssen Acceptance Guidelines for LERF U-

-J 10.6 10-7 10-6 1o-5 0- LERF -I-

] Upper bound estimate of LERF change for power uprate Acceptance Guidelines for Large Early Release Frequency (LERF)

(Uses HCGS Level 1 and 2 PRA for Internal Events)

&%qaft 2 - 38

Pr - A' - -

I Summary of EPU Risk Impact

• Risk impact was evaluated using standard PRA methods (quantitative and qualitative)

• Quantified risk impact is a small percentage of current plant risk

• ACDF is a very small risk change per Reg, Guide 1.174

• ALERF is a very small risk change per Reg. Guide 1.174

• Risk impacts from external events and shutdown conditions are either negligible or minor 2--

(# 39

Grid Relabiit

- (GEE-AIN STATION 12-4

EteJftoti1Ia 0 PJM Planning Requirements

• Hope Creek operates within PJM Interconnection

• PJM members required to follow FERC approved Regional Transmission Expansion Planning (RTEP) process o Feasibility Study o System Impact Study o Generation Interconnection Facilities Study o Interconnection Service Agreement (ISA) - FERC Docket ER05-815-001

• HopC reek*

2 - 41

PJM System Impact Study for Hope Creek E] Met all Criteria except MAAC Criteria IVStability Requirements o System stability maintained without loss of load during and after:

- A. Three-phase fault with normal clearing time.

- B. Single phase-to-ground fault with delayed clearing.

- C. Loss of any single facility with no fault.

o Results: Unstable for single-line-to-ground fault at Hope Creek on 500 kV Hope Creek-Red Lion 5015 line with stuck bkr 3-4 (60X).

E]Modification: Breaker 2-4 (62X) subsequently added in series with breaker 3-4 (60X) as part of EPU Design Change Package to resolve and comply with Criteria IV H2e2-42

-ElecrOica 1G1rid Reiability - Addition of Breaker 62X PSEG Nuclear Hope Creek and Salem 500 kV Switchyards Red Lion New Freedom East Windsor New Freedom 5015 Line 5023 Line 5021 Line 5024 Line (25 mi) (43 mi) (109 mi to Deans) (50 mi)

Identified as worst case fault 62X added for EPU C,*NqRA TATON 2 - 43

Artificial Island Operating Guide Updated for EPU

" Interconnection Facilities Study performed and results documented in Artificial Island Operating guide (AIOG)

" One, two, and three unit operation o 3805 MW max. supplied by Artificial Island with 1320 MW from Hope Creek Power System Stabilizers (PSS) inand out-of-service o PSS provides input to regulators to damp small-signal oscillations.

" Trip-A-Unit Scheme enabled and disabled o Selective tripping of Salem Unit 1 or 2 improves system stability by reducing power transfer over critical lines after severe transmission contingencies HpeCreek2-44

000000000*000000000000000000000000000-00000oo tcal GO- RF[ell',abL Increased power output studied in accordance with- FERC approved PJM planning process.

Reliability maintained by real-time contingency analysis tools and load dispatching within stability limitations oe k2-45

Full Core Map Hope Creek Cycle 15 Vendor Fuel Type Location Map 3 5 9 11 13 1s 17 19 21 73 2s 77 79 31 33 3S 37 31 41 43 45 47 40 51 S3 55 51 so X SVEMS+ Twive Burned S

$VEAW+Fuel L. GE14 Fuel SVEA9+ Four Times Hopncfmk 31 ON A N A ON 31

'bac-Aý, LkfS MELLLA Power / Flow Map Power / FLow Operating Map for Hope Creek EPU 120 120 110 /

3840 MWt 110 100 100 MELLLA Boundary 90 90 CD 3339 MWt 80 80 cv, 70 70 0 60 60 CL 50 50 40 40 30 30 0

20 20 10 10 0 0 0 10 20 30 4(0 50 60 70 80 90 100 110 Core Flow (% Rated) cAYkh 50

w w w Je 15 CoeD~ sin Cycle 15 Bundle Inventory Summary Fuel Product Line Cycle Quantity Batch Enr. Batch Ave.

Loaded w/o U-235 Exp.

(GWDIST)

SVEA 11 16 3.60 36.76 SVEA 12 200 3.61 33.19 GE14 13 164 4.02 23.33 GE14 14 156 3.93 14.43 GEl4 15 228 4.00 0.00 Cycle 15 Total 764 3.88 17.41 HopeCreek 60

~c~R4rNc srAri~ 60

0

ý5 P Lý 13A/,K Lt P SLMC Hstogra

%Contribution of Bundle Type to EPU Cycle 15 SLMCPR 40 35 33.7 33.2 30 r-25

.0 20 0

C 15 GE14 Fresh 10 5

0.2 0

Type 1 Type 2 Type 3 Type 4 Type 5 Bundle Type 61