ML20207H652

Transcript of Commission 860721 Discussion/Possible Vote on Full Power OL for Facility in Washington,Dc.Pp 1-76. Supporting Documentation Encl

ML20207H652
Person / Time
Site:	Hope Creek
Issue date:	07/21/1986
From:	NRC COMMISSION (OCM)
To:
References
REF-10CFR9.7 NUDOCS 8607240382
Download: ML20207H652 (97)

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ORIGINAL UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the matter of:

COMMISSION MEETING Discussion /Possible Vote on Full Power Operating License for Hope Creek (Public Meeting)

Docket No.

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Location: Washington, D. C.

Date: Monday, July 21, 1986 Pages: 1 - 76 ANN RILEY & ASSOCIATES Court Reporters 1625 I St., N.W.

8607240382 860721 Suite 921

%, 7 10CFR PDR Washington, D.C. 20206 (202) 293-3950

ocr 1 D I SCLA I MER 2

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5 6 This is an unofficial transcript of a meeting of the 7 United States Nuclear Regulatory Commission held on e 7/21/86 .

In the Commission's office at 1717 H Street, 9 N.W., Washington, D.C. The meeting was open to public 10 attendance and observation. This transcript has not been 11 reviewed, corrected, or edited, and it may contain 12 inaccuracies.

13 The teanscript is intended solely for general 14 i nf orma t t'ona l purposes. As provided by 10 CFR 9.105, it is 15 not part of the formal or informal record of decision of the 16 matters discussed. Expressions of opinion in this transcript 17 do not necessarily reflect final determination or beliefs. No 18 pleading or other paper may be filed with the Commission in l

19 any proceeding as the result of or addressed to any statement 20 or argument contained herein, except as the Commission may 21 authorire.

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1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3

4 DISCUSSION /POSSIBLE VOTE ON FULL POWER OPERATING 5 LICENSE FOR HOPE CREEK 6

7 ---

8 Public Meeting 9 ---

10 11 MONDAY, JULY 21, 1986 12 1717 H Street, N.W.

13 Washington, D.C.

14 15 The Commission met, pursuant to notice, at 16 10:00 a.m., before the HONORABLE LANDO W. ZECH, JR., presiding 17 18 COMMISSIONERS PRESENT:

19 LANDO W. ZECH, JR., Chairman of the Commission 20 THOMAS M. ROBERTS, Member 21 JAMES K. ASSELSTINE, Member 22 FREDERICK M. BERNTHAL, Member 23 24 25

2 1 STAFF AND PRESENTERS SEATED AT COIO!ISSION TABLE:

2 S. Chilk W. Parler 3 J. Roe R. Vollmer 4 B. Bernero J. Taylor 5 D. Wagner- R. Starostecki 6 J. Ferland C. McNeill 7

8 AUDIENCE SPEAKERS:

9 G. Lainas 10 B. Borchardt 11 12 13 14 15 -

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3 1 PROCEEDINGS 2 CHAIRMAN ZECH: Good morning. Today's Commission 3 meeting is for the purpose of considering the authorization of 4 full power operation of the Hope Creek plant. We will hear 5 from the Nuclear Regulatory Commission Staff regarding their 6 evaluation of the utility's preparation and readiness for the 7 license. Following the staff presentation we'll hear brief 8 comments from representatives of Public Service Electric & Gas 9 who are here today.

10 At the conclusion of the presentations I will ask 11 the Commission to vote on whether or not to grant approval for 12 the staff to authorize full power operation of the Hope Creek 13 Station.

14 At the conclusion of our meeting this morning, after 15 the vote we'll adjourn the meeting and then we'll have a 16 five-minute recess and we will reconvene to have an

, 17 affirmation session, which is a public session. Those that 18 are interested are invited to attend.

19 Do any of my fellow Commissioners have any opening i 20 remarks?

21 (No response.]

22 CHAIRMAN ZECH: Mr. Roe, proceed.

23 MR. ROE: Thank you, sir. We are here today to seek

.1 24 Commission approval for issuance of a full power operating 25 license for the Hope Creek Generating Station. Here at the

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4 1 table we have from the staff Jim Taylor, Director of 2 Inspection and Enforcement; Rich Starostecki, Region I, 3 Director of the Division of Reactor Projects; Dick Vollmer, 4 Deputy Director of Nuclear Reactor Regulation; Bob Bernero who 5 is Director of BWR Licensing; and Dave Wagner, Project Manager 6 for Hope Creek.

7 The owners of the plant, Public Service Electric &

8 Gas Company are also represented here by James Ferland, the 9 Chief Executive Officer; Richard Eckert, the Senior Vice 10 President Nuclear and Engineering; and Corbin McNeill, Vice 11 President, Nuclear.

12 This is Public Service Gas & Electric's third 13 nuclear plant. They are already operating two pressurized 14 water reactors, Salem 1 and 2, on the same site. Hope Creek 15 is a boiling water reactor, the last one in the United States 16 to be built with a Mark I containment.

17 Now I ask Dick Vollmer to proceed with the staff's 18 presentation.

19 MR. VOLLMER: Thank you, Jack. Just a couple of 20 comments. The initial part of the staff briefing will be given 21 by the Licensing Project Manager, Dave Wagner. Then, because 22 Hope Creek is a BWR with a Mark I containment, we thought the 23 Commission would be interested in a discussion on severe 24 accident considerations, and Bob Bernero will be prepared to 25 discuss that, and then we'll turn it over to the Region for

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5 1 their comments.

2 As you may be aware, Hope Creek was initially sited 3 at Newbold Island, New Jersey, which had a relatively high 4 population density around the site. And due to this 5 consideration, there were a number of design features that 6 Hope Creek has that are carryovers from the Newbold Island 7 days, and we'll address some of these because they are 8 unique. In particular, they have a secondary containment of a 9 concrete, 400 million cubic feet concrete secondary 10 containment which is unique to any of the BWRs.

11 Finally, I wanted to indicate my views on Hope Creek 12 as I saw it. I was up there a few months ago with the NRR 13 management review meeting, which we do a week or few before 14 plants are licensed. And I was particularly struck in my 15 review of the plant by the cleanliness of the plant. Even 16 though there was work in progress, the plant was very clean 17 and well organized. Talking to the people, operations people, 18 maintenance people, the attitudes seem very professional, they t

19 seem to know what they were doing.

20 Secondly, the training facilities were extensive and 21 seemed to be very well organized. Not just the training for 22 plant operators, but also very extensive facilities for the 23 mechanics, maintenance people, I&C, electrical -- they had a i 24 great deal of in-plant equipnent that they could learn their 25 arts at in the training facility. -

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6 1 And thirdly, at that meeting we discussed a number 2 of issues which were fairly current topically in terms of 3 licensing. For example, at that time the EQ issue had arisen 4 at a number of plants, and I asked the Licensee about that and 5 they had taken the lead, based on NRC correspondence, and had 6 already checked out their Limitorque valves as to the wiring 7 problem and found that any corrections that needed to be made 8 were made. So they seemed to be responsive to current 9 licensing issues.

10 So my overall impression was good, and I think as 11 you hear from Dave and others, the Licensee seems to be on top 12 of the issues of the day.

13 Dave, do you want to take over?

14 MR. WAGNER: Thank you. Good morning, gentlemen, I 15 am Dave Wagner, I'm the Licensing Project Manager assigned to 16 Hope Creek. In this morning's presentation, if I could have 17 slide number 2, please.

18 [ Slide.]

19 In this morning's presentation we'll be discussing 20 plant background, unique design features of Hope Creek, major 21 FSAR review issues, shift staffing, severe accidents, and the 22 inspection program. We welcome your questions at any time 23 during our presentation.

24 (Slide.]

25 Hope Creek is owned by Public Service Electric & Gas

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1 Company and the Atlantic City Electric Company. Ownership 2 percentages are 95 percent and 5 percent, respectively.

3 PSE&G is the operator of the facility. Hope Creek 4 is a BWR-4 with a Mark I containment. Except for that Mark I 5 containment, Hope Creek is similar to Limerick Units 1 and 2 6 and Susquehanna Units 1 and 2. The rated electrical output of 7 Hope Creek 1067 megawatts.

8 The Hope Creek physical plant was originally sited 9 in Newbold Island, New Jersey. Newbold Island was an island 10 in the center of the Delaware River which was about 4 1/2 11 miles south of Trenton, New Jersey and about 11 miles north of 12 Philadelphia; very high population density areas.

13 Due to the high population density and at the 14 suggestion of the Atomic Energy Commission, the physical 15 plant, including all of the design enhancements, were 16 relocated down to Artificial Island, New Jersey adjacent to 17 Public Service's Salem generating station.

18 COMMISSIONER ASSELSTINE: You said as suggested by 19 the AEC. Did that mean that the staff rejected the Newbold 20 Island site as being too high population density?

21 MR. BERNERO: Dave wasn't in the staff at that 22 time. It was an offer they couldn't refuse, I think is a 23 better way to characterize it. It was very hard to find it 24 acceptable at Newbold Island, and "if you offer to move, we'll 25 offer to do a review in blinding speed."

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1 COMMISSIONER ASSELSTINE: Okay. But they kept some 2 of these additional safety features --

3 MR. BERNERO: Yes. In effect, they carried the 4 engineering design over.

5 MR. WAGNER: The nearest population center of 5000 6 persons or more is Salem, New Jersey, about eight miles 7 northeast of the facility. The Salem, New Jersey population 8 is about 7000 persons. The nearest densely population center 9 of 25,000 persons or more is Newark, Delaware, about 18 miles 10 north-northwest.

11 The Hope Creek low power license was issued April 12 11, 1986; initial criticality was achieved June 28th, 1986.

13 And the Licensee estimates it will be ready for authorization 14 for operation above 5 percent power on July 30th, 1986.

15 Slide No. 4, please.

16 [ Slide.]

17 Hope Creek is designed with a number of features 18 which deserve our attention. When you first saw the pictures 19 of Hope Creek in your briefing book you might have guessed 20 that there were three PWRs located at Artificial Island, but 21 that's not the case. The oddball in the picture is Hope 22 Creek. And as Mr. Vollmer mentioned, it has a secondary 23 containment which is made out of reinforced concrete. The 24 minimum thickness of this reinforced concrete is about 18 25 inches.

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9 1 The secondary containment has a volume of about 4 2 million cubic feet, and is designed for a pressure 3 differential of 3 psi. The blowout panels are designed for 2 4 psi.

5 Most BWRs use a secondary containment which, above 6 the refueling floor, is a sheetmetal structure. The typical 7 leakage rates are 100 percent per day in-leakage on other 8 types of BWRs; Hope Creek's secondary containment is rated at 9 10 percent per day in-leakage.

10 An additional carryover from Newbold Island is a 11 positive pressure MSIV sealing system comprised of an inboard 12 and an outboard system. Each of these systems is supplied 13 with sealing air from an independent instrument gas receiver.

14 The inboard system pressurizes the volume between the two 15 MSIVs, and the outboard system pressures the volume between 16 the outboard MSIV and the main steam stop valve.

17 Most other BWRs employ an MSIV sealing system also, 18 however, it is one system operating between the two MSIVs and 19 it's an evacuated system. A vacuum is drawn between these two 20 valves. Whereas at Hope Creek, the volume between the valves 21 is pressurized for each system. The bottom line is after an 22 accident, if one were to occur at Hope Creek and the MSIV 23 sealing system were actuated, the sealing system, the 24 compressors, would pressurize the volume both inboard and 25 outboard above the pressure inside the containment, resulting i

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10 1 in leakage into the containment versus leakage outside of the 2 containment.

3 Finally, due to the brackish water of the Delaware 1

4 River at the Artificial Island site, Hope Creek uses a closed 5 circuit cooling water system to remove plant equipment heat 6 loads. This system is called the safety Auxiliary Cooling 7 System. The plant head loads are removed by the SACS and the 8 heat is exchanged with the river water service water system.

9 The SACS includes a number of radiation monitors to

, 10 detect any leakage from the in-plant water cooling systems.

11 [ Slide.]

12 During our review of the Hope Creek application, the 13 staff spent significant amounts of times on certain FSAR 14 issues, and these issues are identified on this slide.

15 Regarding solid state logic modules, in place of 16 relays at Hope Creek in certain non-NSSS engineered safeguard 17 feature systems, Hope Creek uses solid state logic modules to t

18 provide logic and actuation functions for these systems, 19 During our review, we noted that the solid state 20 logic modules represents a common actuation path for automatic 21 and manual initiation of these non-NSSS ESF systems. In 22 response to this concern, PSE&G provided the staff an analysis 23 which indicated that each non-NSSS ESF system using solid 24 state logic modules has redundant transor channels from which 25 the logic actuation can take place.

11 1 No solid state logic modules are used in NSSS ESF 2 systems. For example, the emergency core cooling system and 3 the RHR containment spray and drywell sprays are the 4 traditional GE relay logic, as is the reactor protection 5 system.

6 During preop testing, a number of incorrect 7 actuations of solid state logic modules occurred. The 8 incorrect actuations occurred, one, due to humidity, excessive 9 humidity; and two, due to electromagnetic interference and 10 radio frequency interference. The incorrect actuation due to 11 humidity was resolved by increasing the spacing on some wires 12 internal to the solid state logic module, and it appears that 13 PSE&G has resolved this problem.

14 The EMI/RFI problem was resolved by adding an input 15 filter to the solid state logic devices, and also zoning some 16 rooms in the facility radio-free zones. And this also appears 17 to have resolved this problem.

18 But due to these anomalies encountered during the 19 preop tests and coupled with the fact that this is the first 20 time use of Bailey 862 solid state logic modules in a nuclear 21 application, the staff has had some concerns about the 22 reliability of these devices. In response to this concern, 23 the Licensee, during the first refueling cycle, will conduct a 24 three-faceted reliability program.

25 This program will consist of, one, tracking

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12 1 reliability of the solid state devices in-plant during i 2 operations; two, tracking the solid state logic module 3 reliability in other industrial applications -- they are used 4 in a couple of other fossile plants; --

and three, a 5 third-party consultant is being brought onboard by PSE&G to 6 conduct life cycle testing of these modules.

7 COMMISSIONER ASSELSTINE: Have solid state modules 8 been used in other plants? Is there another manufacturer for 9 them other than Bailey?

10 MR. WAGNER: The Clinton power station uses solid 11 stato circuitry.

5 12 COMMISSIONER ASSELSTINE: But not Bailey ones?

13 ER . WAGNER: Not Bailey ones. I believe it's a GE 14 system.

15 COMMISSIONER ASSELSTINE: Okay. And they're farther 16 behind so I take it we don't have an extensive testing 17 experience of those, or do we? Do you know what they show?

18 MR. BERNERO: They have had lab testing and bench 19 testing, and they haven't, to my knowledge, experienced the 20 pre-operational test spurious actuations that were encountered 21 here.

22 Now, Public Service Electric & Gas here at Hope 23 Creek has apparently gotten their arms around the problem and 24 solved it by filtering the radio frequency and interference '

. 25 and so forth. And this program that Dave just characterized l

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13 1 is a reliability assurance program, kind of a confirmation 2 thing for the first fuel cycle.

3 CHAIRMAN ZECH: But it will bear careful watching 4 between now and the time they conduct this review.

5 MR. BERNERO: Certainly.

6 CHAIRMAN ZECH: If it's the first time we're using 7 this equipment, certainly we should take a very conservative 8 approach and the utility should be mindful that in any 9 problems they have they should make a special point of looking 10 to see whether these solid state logic modules have any 11 contributory part in any problems that come up.

12 MR. BERNERO: Right. If their net improvement - .

13 When I spoke to the Commission in one of the near-term 14 operating license briefings not long ago, I recall telling you 15 of the focus at that time. The staff was considering

~16 requiring the installation of testability that could be right 17 through the whole senor through actuation at power. That is a 18 generic issue on all plants but Westinghouse right now. And 19 actually, that is some aside or beyond the real issue, in our

20 mind.

21 The real issue is can you have confidence in the 22 reliability of the system. Obviously, surveillance testing 23 merely tells you about reliability; it doesn't put it into the 24 circuit.

25 So I'm satisfied that the owner is sufficiently

14 1 conscious and that the program is sufficiently comprehensive 2 to really track this reliability, and either we have the 3 assurance at the end of the fuel cycle or we take measures to 4 obtain the necessary reliability by other means.

5 CHAIRMAN ZECH: They should be mindful of it and so 6 should we.

7 MR. BERNERO: Yes. I think both are.

8 COMMISSIONER BERNTHAL: I'm sure I was given the 9 answer to this question when I was up there a few months ago, 10 but I've forgotten what it was, and that probably means I 11 wasn't satisfied.

12 But I wouldn't be surprised if we were having this 13 conversation fifteen years ago, quite frankly, but solid-state 14 logic modules are not exactly something that is 15 Johnny-come-lately, and I guess even more surprising is that 16 we would be having to concern ourselves with a fundamental 17 design question like RF leakage and humidity in operation.

18 How does that happen?

19 MR. BERNERO: I would suggest that we defer to the 20 owner to respond to how did they run into humidity problems.

21 I would just say --

22 COMMISSIONER BERNTHAL: Well, the owner didn't 23 design them, though. Bailey designed them.

24 MR. BERNERO: Yes, but the owner is responsible for 25 the procurement and the satisfactory engineering of the

15 1 plant. They aren't the only ones who have encountered 2 problems with solid-state equipment.

3 I am sure you are aware of plants where solid-state 4 equipment in the control rooms with slight heat-up, heat-up 5 that the human beings can tolerate, causes the solid-state 6 equipment to start acting strangely and giving spurious 7 signals and so forth. It's one of the reasons --

8 COMMISSIONER BERNTHAL: But it wasn't heat here. It 9 was humidity and RF leakage.

10 MR. BERNERO: Yes, but environmental causes, 11 environmental causes.

12 COMMISSIONER BERNTHAL: Agreed.

l 13 MR. BERNERO: There are many who are suspicious of 14 the advances of science into solid-state as being a more 15 delicate, less reliable approach than the old brute-force 16 relays and things like that, and that's one of the reasons for 17 the Staff's apprehension.

18 But on the other hand, we are often criticized for 19 forcing the reactors into a 1948 design mode. It's not a 20 clear picture, really.

21 MR. WAGNER: Another significant issue involved 22 turbine overspeed protection. In its letter to the 23 Commission, dated December 18, 1984, the ACRS recommended that l 24 the Staff and the Applicant rereview some kind of testing i

25 program to ensure that turbine roll-up after loss of load will I

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16 1 be limited to the turbines' designed overspeed, which in the 2 case of Hope Creek is 120 percent.

3 In response to this recommendation, PSE&G submitted 4 a GE standard test abstract, and it's a pre-op test normally 5 run during GE start-up tests, and it's the generator load 6 rejection at 100 percent. Basically, the utility was planning 7 to take the turbine and the reactor, of course, up to 100 8 percent, open up the generator output breakers, thereby 9 causing an overspeed of the turbine, and a power unload 10 balance relay would detect this loss of load and scram the 11 reactor and, of course, shut down the turbine without ever 12 reaching the electrical and mechanical overspeed trip 13 setpoints.

14 We reported on this proposed testing in Supplement 15 No. 5 to the SER. The ACRS, when they read our SER, balked at 16 our answer, our response.

11 In a memorandum to the Commission dated June 9th, 18 the ACRS expressed continued concern over this issue and 19 requested -- and recommended that the Staff provide 20 justification for the turbine overspeed protection at Hope 21 Creek.

22 On June 26, the Staff and PSE&G met with Mr. Glenn 23 Reed of the ACRS to discuss this issue. Mr. Reed is Plant 24 Manager of the Point Beach Nuclear Power Plant, had experience 25 with turbine -- excessive turbine roll-up, roll-up beyond the

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. 1 17 1 design overspeed. At Point Beach t this resulted in lowering i

2 the trip setpoints four to five percentages, so the trip 3 setpoints were about 104 and 105 percent, as opposed to 110 4 and 112 where they had been originally.

5 Anyhow, we discussed this issue with Mr. Reed, 6 pointed out differences between Westinghouse turbines, as at 7 Point Beach, and the GE turbine, as is at Hope Creek, and he 8 was reasonably satisfied that this testing program that PSE&G 9 has instituted will meet the recommendations of the ACRS, and 10 he has so stated in a letter to Mr. Stello dated July 15th.

11 The last issue regards control room ventilation and 12 habitability. Also in this December 1984 letter, the ACRS 13 suggested that the Staff and the Applicant look into possible 14 losses of both HVAC trains at the Hope Creek control room.

15 Such events have happened at other facilities in the past.

16 The primary emphasis was to be on the heat-up 17 effects of the instrumentation within the control room, the 18 instrumentation drift, et cetera. PSE&G provided information 19 on this applicable to the Hope Creek control room, did a 20 computer modeling simulation of the Hope Creek control room, 21 and submitted it for Staff review.

22 The Staff found that what PSE&G submitted was 23 acceptable. They meet all of our requirements, and this issue 24 is under further review under the auspices of Generic Issue 25 83, control room habitability, and if additional requirements

s 18 1 come out of the resolution of that generic issue, they, too, 2 will be applied to Hope Creek.

3 COMMISSIONER ASSELSTINE: Does the additional work 4 that the Staff has done -- do you know if that has satisfied 5 the ACRS as well?

6 MR. BERNERO: I believe the ACRS is satisfied that 7 this is being dealt with generically. They have a very strong ,

8 feeling on that control room habitability and have been 9 outspoken in saying, "Yes, do that work," and that's quite 10 active.

11 COMMISSIONER ASSELSTINE: But presumably they knew 12 about the generic effort ahead of time. I take it there's 13 concern --

14 MR. BERNERO: Well, you've got to remember the time 15 here. The original ACRS letter was quite some time ago.

16 COMMISSIONER ASSELSTINE: Okay.

17 MR. BERNERO: And I'm confident that right now the 18 ACRS is satisfied that there is -- there was a brief lull on 19 the generic activity that I think was a concern with the ACRS 20 during our organizational transition, and I think that was the 21 reason they tacked that on with the turbine overspeed.

22 COMMISSIONER ASSELSTINE: Okay. Do you think they'd 23 be satisfied with the generic treatment in lieu of doing --

24 MR. BERNERO: In lieu of anything on -- yes, that's 25 my understanding and confidence.

19 1 COMMISSIONER ASSELSTINE: Fine.

2 MR. WAGNER: In addition to this, Hope Creek does 3 have emergency procedures in case that they do lose both 4 trains of HVAC in the control room.

5 The final subject that I will discuss this morning 6 is shift staffing. Currently at Hope Creek, they are 7 employing five eight-hour shifts.

8 CHAIRMAN ZECH: Excuse me. Are you going to talk to l 9 us any about containment design, which is on your slide up 10 there?

11 MR. BERNERO: Yes, right after this, I will.

12 CHAIRMAN ZECH: All right.

13 MR. WAGNER: Slide No. 6, please.

14 [ Slide.]

15 MR. BERNERO: We're just a little out of order here.

16 CHAIRMAN ZECH: That's fine. Go ahead.

17 MR. WAGNER: Of the five shifts, four shifts are on 18 a six-day-on, two-day-off schedule with the fifth shift in 19 training or requalification. The dual-role STA/SRO is used on 20 all five shifts at Hope Creek presently.

21 Hope Creek meets the requirements for engineering i

22 expertise on shift and operating experience.

23 Regarding crew training, if I could have Slide 24 No. 6, Back-up No. 1, please?

25 (Slide.]

20 1 Formal shift training commenced at Hope Creek in May 2 1984. First cold licensing exams were given in July 1985.

3 Mr. Starostecki will talk about the pass / fail rate for these 4 tests later on.

5 Those that passed the exams have continued on in 6 crews. An interesting note is that each shift at Hope Creek 7 has at least one previously licensed BWR operator, and all of 8 the current shifts have been in place as shifts, and the men 9 have worked together for at least six months.

10 I'd like to turn the microphone over to Mr. Bernero 11 now, who will talk about severe accidents and MARK I 12 containments.

13 COMMISSIONER ASSELSTINE: At some point, maybe later 14 on when we get-to the Region's presentation, could you talk a

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15 little bit about overtime rates for operators?

16 MR. STAROSTEC$3 : We'll be prepared to do that.

17 COMMISSIONER ASSELSTINE: Thanks.

18 MR. BERNERO: May I have Slide No. 7, please?

19 [ Slide.]

20 Gentlemen, I would like to give you what I might 21 call the 12-minute version'of MARK I containment issues with 22 respect to this plant. I'm not trying to starve you of 23 information, but it's a subject close to me heart, and I could 24 talk about this for hours if left unchecked.

25 [ Laughter.]

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21 1 Really, when we look at severe accidents, there are 2 two aspects of concern to us as regulators, the prevention of 3 the occurrence of a severe accident and mitigation thereof 4 should one occur. As we stated in the Congressional response 5 to Mr. Markey just a little earlier -- well, last week 6 basically -- we consider that there is a substantive objective 7 there to prevent, to have the likelihood of a severe accident 8 very low, and also that if one occurs, there is substantial 9 assurance that the containment will mitigate the consequences.

10 Now before going into the containment, I would like 11 to briefly touch on severe accident occurrence with respect to 12 this plant, which, by chance, happens to be -- its history 13 makes it a rather unique, durable plant in that respect.

14 If you look at your slide there and as shown on the 15 screen, in ATWS, the anticipated transient without scram, they 16 have complied with the ATWS rule and even gone beyond it. If 17 you look at the third item there, the standby liquid control 18 system is automatic in this plant. and that's the feature that 19 in the ATWS rule we elected tQ (pp;/ only to future plants, 20 new designs, and this plant has gone ahead of the average in 21 that regard.

22 COMMISSIONER ASSELSTINE: Bob, why did they 23 voluntarily decide to automate SLC?

24 MR. BERNERO: I think it was a carryover of earlier 25 activity -- I mean, it was the spirit of carryover. It wasn't

o 22 1 that back in 1974, at least not to my knowledge, did they have 2 any piece of paper that said that they would have an automatic 3 standby liquid control. I think it was a carryover of that 4 spirit.

5 CHAIRMAN ZECH: Why don't we ask the Licensee if 6 they'd be prepared to respond to that when they come up?

7 MR. BERNERO: Yes. I'm sure that Corbin McNeill 8 would know about that.

9 COMMISSIONER ASSELSTINE: I think that's a 10 commendable step.

11 MR. BERNERO: Yes, yes. And I think it betrays an 12 attitude of facing safety issues, responding to them, and not 13 simply complying with the minimum requirement.

14 COMMISSIONER ASSELSTINE: Yes.

15 MR. BERNERO: Now if you look at station blackout 16 challenges, like any BWR of this broad vintage -- you know, 17 all of the MARK Is and even the MARK II containment BWRs, 18 there are two systems to cope with station blackout, two AC 19 independent systems, and they are diverse as well as redundant 20 to one another, the reactor coolant isolation cooling system, 21 RCIC, and the HPCI, the high-pressure coolant injection 22 system.

23 This plant also has an electrical system which is 24 difficult to describe. I merely indicate here on the slide, 25 four standby diesel generators. They really have what amounts

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23 1 to a four-train system. It's something akin to Division 1 and 2 2 being further subdivided into Division 1(a) and 1(b), 2(a) 3 and 2(b), so that each RHR pump or LPCI pump has its own 4 dedicated diesel generator, and it is a single train, and it's 5 an independent or relatively independent single train.

6 There is a gas turbine generator on the site, and 7 they have rather extensive battery design reflecting the AC 8 power design, so that in general the system reliability, and 9 in particular the ability to cope with blackout, is a lot 10 better here than you'll find in most, again beyond the 11 average, ahead of the curve.

12 COMMISSIONER ASSELSTINE: I take it those design 13 features, particularly the separation to some extent into the 14 four trains kind of approach, the gas turbine as the backup, 15 begins to approach some of the European designs in some 16 respects.

17 MR. BERNERO: Oh, yes, indeed. I'd say it does.

18 They also reflect this attitude in their operating

19 procedures, you know, their ability to cope with transient 20 response. They have as up-to-date procedure packages 21 available, and they're up there prepared to go -- you know, 22 right now, we're reviewing Emergency Procedurc Guidelines, 23 Revision 4, with the owners' group, and these people are 24 standing there at the door all set to move in. So that in 25 general, I would say, they are exceptional with regard to the l

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24 1 prevention of severe accidents.

2 Now if you turn to the containment -- may I have 3 Slide 8, please?

4 [ Slide.]

5 It helps if you break down the MARK I containment 6 issue into five elements. The first four are physical 7 behavior or system issues -- hydrogen and its control, sprays 8 and their reliability or efficacy of sprays, pressure control 9 and pressure management; where does core debris go, what does 10 it do; and lastly and very importantly with the boiling water 11 reactor, training in procedures.

12 If you recall the Reactor Safety Study, WASH-1400 13 basically had a somewhat quiet comparison between a BWR and a 14 PWR in its results. Not many people emphasize that 15 comparison, but in essence, the Reactor Safety Study findings 16 suggest that a boiling water reactor is appreciably less 17 likely to cause a core melt than a pressurized water reactor.

18 In fact, many of the core melts expected there were caused by 19 the containment, by containment failure leading to cavitation 20 and injection failures.

21 And secondly, the Reactor Safety Study, its results 22 basically indicated that if you have a large-scale core melt 23 in a boiling water reactor, a fairly large release is bound to 24 occur.

25 Now at the time, the emergency operating procedures

25 1 in place in plants were primitive. You know, they were 2 pre-TMI. And the key in a boiling water reactor is procedures 3 and training to use the equipment to best advantage, because

~

4 the system is very adaptable, and the containment, in 5 particular, depends on this.

6 May I have Slide 9, please?

7 [ Slide.]

8 COMMISSIONER BERNTHAL: Bob, I think that the point 9 you just made bears some emphasis, because in a hearing on 10 Capitol Hill last week and generally, I think, in the r.adia 11 recently there has been this emphasis on the fact that .s' you 12 have a core melt, there is a higher probability for 13 radioactivity escaping the containment in these systems.

14 It has rarely been said that, by most of our PRAs, 15 as I understand it, there is a lower probability of having 16 that core melt to begin with, and there is always this 17 tradeoff that we have between prevention of a core melt and 18 mitigation of a core melt if it occurs. And one could also 19 point to Fort St. Vrain where there is no containment at all, 20 because we believe that the probability of a core melt 21 accident there is extremely low.

22 So variations on the scale and the balancing of 23 those two considerations is something that seems to have been 24 missed recently in the press and some of the commentary on the 25 BWR liARK I design.

26 1 MR. BERNERO: Yes. I would add, though, given 2 really systematic exploitation of the design capability, it is 3 my personal belief that the core melt frequency in a boiling 4 water reactor can be driven so low that it's really tough to 5 quantify, that you're into common cause, super seismic events 6 and things like that, and you're way low.

7 In the present range of debate, in the frequency 8 realm of 10 to the -4 per year to 10 to the -5 per year, we 9 fully expect to have a two-pronged approach in the severe 10 accident issue -- that is, one, get it low and keep it low as 11 far as the occurrence of the core melt, but secondly, have 12 substantial assurance of mitigation from the containment.

13 It's hypothetically possible that if you really do 14 the job on prevention, you could almost moot the containment 15 as, you know, you indicated, say at Fort St. Vrain.

i 16 But we're not following that now. We are looking 17 very hard, and so is the industry, at the containment, 18 especially the MARK I.

19 CHAIRMAN ZECH: Well, we want to look at both. We 20 want to prevent it, and we want to mitigate it.

21 tiR. BERNERO: Oh, yes. Yes, both fronts.

22 CHAIRMAN ZECH: Even though it's very, very small, 23 we recognize that the risk is small, but I think our effort 24 should be to prevent it and to mitigate it.

25 MR. BERNERO: Yes, a two-pronged approach.

27 1 CHAIRMAN ZECH: Right.

2 MR. BERNERO: Now the picture you have in your books 3 and which is on the screen right now is the Hope Creek 4 Generating Station. You often see MARK I pictures, and they 1

5 differ a little bit one to the other, but this one, if you 6 look, you can see the big reinforced concrete building around 7 it.

8 And notice the Mark I is an upside light bulb, 9 that shape, and the characteristic of that shape is though it 10 is designed for fairly high pressure, typically, 50 psi or 60 11 psi design pressure, something like that, it's small. It has 12 a rather small interior volume, much of which is occupied by 13 hardware. And it makes it vulnerable to hydrogen which can 14 cause abrupt overpressure by igniting, and to overpressure 15 failure -- any incident where you're not removing heat. If 16 you isolate the system, -- remember, a boiling water reactor 17 is an open system rejecting large quantities of energy out to 18 the turbine, and under emergency conditions the first thing 19 you do is bottle it up and make it very sensitive to the 20 residual flow of energy into this somewhat constrained volume 21 or capacity.

22 Now, looking at the design, one of the things I'd 23 like to single out for your attention as you look at the 24 picture, in any core degradation / core melt, the bulk of the 25 more volatile activities -- the iodines and things like that

4

. +

28 1 -- they come out first. You.know, they cook right out of the 2 core rather early in the thing, before the core can get out of 3 the reactor vessel. And the boiling water reactor, except for 4 a couple of relief lines in older BWRs, the safety and relief

, 5 valve lines go down into the suppression pool.

6 So that this thing is like a Turkish water pipe; 7 it's running down into the water with the early volatile 8 releases. And then if you continue a core melt sequence, then 9 what you have is the molten core falling to the lower cavity 10 area there. You see it's rather constrained. And then a 11 modest amount of floor space surrounding it before you get out 12 ot the wall of the light bulb.

13 Now typically, the wall of the light bulb is steel 14 with a little space behind it, and then all that massive 15 concrete you see all around. And the suppression pool is out 16 in the torus there.

17 So the issues in Mark I are what about the hydrogen 18 -- there are sprays in that containment, and they can help a 6

l 19 great deal by trickling water down the walls and unto the 20 floor, if only you can have them there at the time of a severe 21 accident. It's a very valuable thing to have. And questions 22 arise about debris travel; with the walls so close, can the 23 debris reach the wall very easily.

24 And pressure management itself. You've got a good 25 filter out there, almost a million gallons of water out there

e 29 1 in that torus, but is it possible to control venting from the 2 vapor space above the torus and be assured that any 3 radioactivity released by core melt is going to bubble through 4 that pool," scrubbing virtually all the radioactivity but the 5 noble gases, and then you're just releasing noble gas which is 6 a much more tractable off-site problem.

7 So those are the issues. And now let me just 8 briefly touch on Hope Creek in Slide 10.

9 [ Slide.]

10 And where they are.

11 COMMISSIONER BERNTHAL: Excuse me, Bob. Are you 12 going to say something more, a couple sentences at least, 13 about the question of bypassing -- the possibility of 14 bypassing the suppression pool?

15 MR. BERNERO: Yes.

16 COMMISSIONER BERNTHAL: Just to re-educate us and 17 refresh our memory a little bit on that.

18 MR. BERNERO: Now if we look at this slide, I've 19 just got a very short statement on each one and I wanted to 20 use it to touch on them. First with respect to hydrogen, as 21 you know, Mark I's and Mark II containments, by 10 CFR 50.44, 22 are inerted, and this plant is in full compliance with the 23 50.44.

24 As we look at the severe accident issues in 25 hydrogen, there are only two questions that would come back

30 1 up. One is, are we still satisfied that we have the 2 appropriate tolerance of non-inerted operation at the 3 beginning and end of a run. You know, the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that are 4 allowed. That might be routinely reconsidered here. And 5 secondly, and it's associated with containment venting, don't 6 ever forget that this is hydrogen control by oxygen control.

7 We're not controlling hydrogen; we're controlling oxygen. And 8 if you vent this stuff out, virtually every place you might 9 vent it is oxygen-rich. So by venting you can create a 10 flammable mixture, or achieve a flammable mixture in some 11 space. So you have to give some thought to that, and that 12 will come up in the pressure control.

13 With respect to sprays, all of the BWRs have the 14 drywell sprays. They are a pressure-controlled device and 15 they are an alternative mode of the RHR system. I told you 16 earlier this particular plant has very reliable RHR. And 17 therefore, you would say they have the very reliable 18 capability of operating sprays.

19 However, a priority is given to the operation of RHR 20 that is in the RHR mode as against the spray mode, so that we 21 would like to see, even if you lose RHR or even if you're 22 desperately trying to operate in the RHR mode, that there is a 23 highly reliable and preferably AC-independent means of 24 actuating the drywell spray.

25 Now at this particular plant, they have a service i

l

31 1 water cross-connection but that, of course, requires AC 2 power. And they can cross-connect to the fire protection 3 systems, and that gets you into some kind of AC-independence.

4 We're looking at this on all of the plants for both 5 the apparatus and the procedural mechanisms in training, to be 6 able, say, within a period of an hour to have a high level of 7 assurance that there will be water sprinkling down the inside 8 of that containment onto the floor if we're in one of these 9 severe accidents. Now keep that in mind as we go into 10 pressure and we start talking about containment bypass.

11 Now, pressure management. They have implemented the 12 venting procedures in the procedure guidelines for the last 4

13 two revisions, and that means that the operator will open the 14 big two-foot diameter -- typically it's 22, 24-inch diameter 15 valve -- so that the wet well vapor space is opened, and the 16 effluent from core melt we hope will bubble through the. pool, 17 obtain that scrubbing decontamination factor, then only the 18 noble gases or non-condensibles will go out.

19 The question is -- there are many questions I should 20 say. One is, how can you be sure it will bubble through. You 21 have to be satisfied that your bypass of the pool through 22 vacuum breakers is non-significant. That's a system 23 reliability issue. Secondly and perhaps most importantly in 24 the Mark I containment is debris bypass; that the core debris 25 will actually reach over and etch a hole right through the

32 1 drywell wall and give you a direct failure into containment.

2 Now if you look at that picture -- would you go back 3 to slide 9 again, please.

4 [ Slide.]

5 If you look at that picture, I think it's iraportant 6 to keep in mind -- and this is a characteristic of essentially 7 all Mark I containments. There are two plants -- Brunswick is 8 slightly different but it doesn't affect this finding 9 significantly. If you come over and get to the wall of the 10 light bulb, there are only two geometries that the debris can 11 find behind the wall or at the wall. One is, it's one of 12 these big vent pipes where it would go down into the torus 13 room, and that's an issue that one has to pursue; what would 14 happen.

15 The other is that it will reach the wall at the 16 solid part in between the vent pipes and it will obviously 17 melt a hole in that steel shell pretty quickly. But then 18 behind the steel shell you have what amounts to a seal, a 19 crude seal. You've got a construction gap usually filled with 20 some kind of foam plastic of some sort, and then that's what 21 separates the freestanding steel shell from all of that 22 shielding concrete. And that's a closed gap.

23 The Dresden plant had a fire in that plastic from 24 welding about six months ago or eight months ago, and it was a 25 vivid demonstration that (a) it's very hard for oxygen to get

33

~

1 in to sustain the combustion; and (b) it's also very hard to 2 get weter in there to put the fire out. It's a very tight 3 area. So that if you visualize the corrosion of molten core 4 material eating in there, it immediately starts to coagulate 5 the wound by reacting with the concrete it finds in there, and 6 of course igniting this plastic and burning it away quickly.

7 But the idea is it's not a free path to atmosphere. A very 8 important thing.

9 COMMISSIONER ASSELSTINE

Do you get any hydrogen 10 generation through that kind of interaction?

11 MR. BERNERO: Oh, yes. When you react with concrete 4

12 you will get hydrogen and lots of CO2. But the water in the 13 concrete gets leeched out very quickly, and you get the 14 hydrogen --

4 15 COMMISSIONER BERNTHAL: A good oxygen core is what 4

16 you're saying. Or are you saying that?

17 MR. BERNERO: It's oxygen poor, yes. This 18 atmosphere is -- it's a reducing atmosphere. And remember, i 19 you still have a lot of zirconium in that melt. The BWR, all 20 the current estimates indicate there's lots of unreacted 21 zirconium in that melt.

22 Now if you look at the floor, the floor is not very 23 large, and I like to make the analogy to Hawaiian volcano 24 lava. What does corium look like after it melts through the 25 bottom of a reactor vessel in a boiling water reactor? It has i

, -. - . . ~ , - . - . . . , . , . .- . - - , - . - , . , - , . ,- - . - , ,,.--- ,., - - . . . . - - - , - - - . .

34 1 to dissolve an awful lot of inert metal to get out. You know, 2 the stub tubes, control rod drives and all that hardware.

3 Does it look like hot consomme? You know, very free flowing, or does it look like Hawaiian volcano lava that we see on the

~

4 5 television about once a year when Mauna Loi erupts. And it's 6 a crusty, a dark, crusted, very viscous material.

7 Because if it's crusted and viscous, and especially 8 if we can sprinkle water on it to enhance the crusting of the 9 front edge of it and the top of it, then its corrosive force, 10 the hot melting corrosive force, is directed downward on what 11 amounts of a semi-infinite supply of concrete down below. A 12 highly desirable thing.

13 So when we think of containment bypass, we also have 14 to think of debris travel and spray availability. Do we have 15 substantial assurance that the sprays, in the majority of 16 cases if not all, will be spraying water on this debris? If 17 we do, if we can be assured that there is a very low 18 likelihood of bypass either through eating the containment 19 wall up or by vacuum breaker bypass, we can then be assured 20 that radioactive fission products released after the early ,

21 volatile ones -- remember, the early volatile ones are already i

22 in the pool water -- that the later ones will also go into the 23 pool water.

24 So that's the principal focus of the containment 25 venting; it's a filtered vent containment strategy.

i

l* 35 1 Some of the other issues we have to look at --

, 2 remember what I said about hydrogen. You now have hydrogen 3 venting out through a valve. The valve is designed like the i 4 containment is, but from plant to plant you get differences.

i

.5 How thick is the duct downstream? If it ruptures from this 6 release, where have you vented this radioactive noble gases, 7 hydrogen mixture and some steam?

~

8 COMMISSIONER ASSELSTINE: What's the atmosphere like

, 9 in those torus rooms?

j 10 MR. BERNERO: It's air. It's like the reactor l 11 building. So that it raises that issue: where does this 12 stuff go after you vent it? And, does it vent on the roof of 13 the building or does it vent in the reactor building itself?

14 So those are issues that we need to pursue.

4 15 Now what we are doing, and we're studying the core 16 debris as -- you know, it's really a synergistic question.

17 You have to look at these in an integrated way, and we're i 18 working with the IDCOR group and the owners' group because l 19 they have a marriage of necessity. IDCOR looks at severe 20 accidents; the owners group is the agent -- this is the BWR 21 owners' group -- for the emergency procedure guidelines. And 22 Revision 4 of those guidelines and the IDCOR effort are being 23 dealt with together, and that's what we're doing right now; 4

24 discussing this with ACRS and with the owners.

25 And having chosen the integrated solution, then the i

36 1 procedures and the training are implemented. That's all I --

2 I think I went beyond 12 minutes.

3 CHAIRMAN ZECH: Just a little bit, Bob. But it was 4 very enlightening and I appreciate it very much. I think we 5 all do.

6 MR. BERNERO: So I'd like to turn it over to Rich.

7 MR. STAROS'TECKI: Slide No. 11, please.

8 (Slide.]

9 COMMISSIONER BERNTHAL: Excuse me, if I may just 10 before we go on, Bob. This plant of course has the desirable 11 feature that you have that additional barrier against release 12 with large volume. Most of the Mark Is, I guess all the other 13 Mark Is don't have that. Just to recap, what in your judgment 14 is the greatest single vulnerability or concern that remains 15 then about this design in the severe core melt scenario?

16 MR. BERNERO: If you put it in terms --

17 COMMISSIONER BERNTHAL: What's the greatest unknown 18 at this point? Where is the --

19 MR. BERNERO: I'd say pool bypass. That's what I 20 would say. If you put it in terms of -- the owners, of 21 course, are interested in how big is the fix; you know, what 22 are the candidate fixes. And none of those look --

23 COMMISSIONER BERNTHAL: Yes, but by which 24 mechanism? Do we know by -- what is the most likely mechanism 25 in your judgment for that?

t

37 1 MR. BERNERO: My own feeling is that by the means I 2 indicated -- you know, assured spray and so forth -- that 3 debris bypass is going to be much more controlled than the 4 system reliability bypass; you know, that is, vacuum breaker 5 or something like that.

6 CHAIRMAN ZECH: All right. Proceed.

7 MR. STAROSTECKI: Dr. Murley was planning to be here 8 this morning and I apologize for his absence. He had to be 9 away due to a death in the family. But there are a number of 10 people from the Region I office here, including the Senior 11 Resident Inspector, so if there's any detailed questions we'd 12 be happy to answer them.

13 I'd like to make some general observations about 14 Hope Creek before we get into some detailed discussions of the 15 slides.

16 We've basically been very happy and satisfied with 17 the construction effort at Hope Creek. There have been very 18 favorable SALP reports and very good positive trends. And 19 we've sat down and we've tried to understand why that's 20 occurred. We've had a number of pl, ants in the past few years 21 that have come up for licensing and we've had experience 22 obviously with Millstone-3, Shoreham, Limerick and the 23 Susquehanna units in the last four years.

24 And one of the things that sticks out -- and it's 25 true also at Hope Creek -- is that the senior utility

.+ 38 1 management has been involved in the construction. And in the' 2 Public Service organization there is a dedicated Vice 3 President for Engineering and Construction. He has been 4 onsite at that plant and he's had his engineers onsite.

5 He gave very strong support to the Quality 6 Assurance / Quality Control staff early on, and I recall Tom 7 Murley and I going to the site three or four years ago and we 8 would be talking to the QA managers, and they felt that they 9 were in control. They've been very prompt with stop work 10 orders early on. They've had nine stop work orders in six 11 years. They weren't all in one year; they were spread out.

12 There has been a good involvement by the utility in 13 the engineering of the plant from the beginning. This is not 14 one of those plants that's been turned over to an architect 15 engineer. -

16 So from a construction standpoint they have had an 17 experienced engineering staff working close with the architect 18 engineer and located on site. We have satisfied ourselves 19 that this works, obviously through a large number of direct 20 inspection hours, but we also like to rely heavily on our team 21 inspections because that is where we get an awful lot of 22 synergistic effects from the various disciplines that we 1

23 involve in our teams, plus we send our supervisors out there 24 as these team leaders.

25 We have had three types of team inspections. one of

__ _ _ _ _ . . _ _ _ _ - - _ . . _ _ _ _ _ ._ . . _ . . ~ ._.

.* 39 1 them we call regional construction team inspection. 'We 2 basically have patterned an approach that IE uses in the 3 construction appraisal team inspections, and we performed such 4 an inspection in September 1983 with very favorable results.

5 We have had two nondestructive examination team 6 inspections, one done in the fall of 1982, one done in the 7 spring of 1985, where we have independently verified what the 8 utility has done in terms of radiographic testing, dye 9 penetrant testing, and ultrasonic inspections.

10 Then in December of 1985 we had a team inspection to 11 look at the as-built plant to see that it conforms with the 12 documentation, the tech specs, and the FSAR.

13 Another interesting feature of the Hope Creek 14 station is the fact that its architect engineer constructor is 15 Bechtel San Francisco, and when you look at the Northeast, 16 Bechtel San Francisco has been the architect engineer and 17 constructor for the Susquehanna 1 and 2 units, the Limerick 1 18 unit, and they are currently doing the Limerick 2 unit and 19 also Hope Creek.

20 We see that there have been good communications and 21 coordination between Bechtel and General Electric on all these 22 four units. The utilities have been involved, so it is this 23 good communication that is somewhat a side benefit, almost, of 24 standardization because you are dealing with one NSSS vendor, 25 and although the reactors may be somewhat different and the

i' 40 1 containments definitely are different, this'is a potential 2 benefit.

3 There have been independent looks at Hope Creek, and 4 obviously we will touch briefly on the IDVPs that have been 5 done for Hope Creek.

6 After construction completion, we found that this 7 utility did plan well for operations. The operations staff has 8 been essentially in charge of the site since December 9 1984. They got the people together early on and they factored 10 in the construction needs into the operating plan, and 11 activities were controlled more rigidly. Sometimes you will 12 see at a construction plant the construction habits carry on 13 right up until fuel load. That hasn't been the case here.

14 They have had a transition plan, they have been in 15 control of site activities, and in the last year or so they 16 have been very aggressive in reviewing activities of sister 17 plants. I have been very surprised to see that a number of 18 problems that we identify at GE plants around the country, the 19 engineering at Hope Creek has seen those problems, anticipated 20 them and ,in some cases has proposed solutions before we have 21 been even able to issue bulletins or notices.

22 They have also taken some interesting initiatives.

23 To further understand and improve their operations, they have 24 sent their operating staffs to sister plants to observe the 25 activities. They have even sent people to the Swedish plants

'.- 41 1 to take a look at how they have done their maintenance and how 2 the crafts are doing the work. So when we say they have sent 3 people to Sweden, they have sent crafts people in addition to 4 the supervisors and managers. That is an interesting comment 5 on the pro-active posture.

6 Now, this is not to say that they haven't had 7 problems. There have been some difficulties that I would like 8 to get into during the preoperational and startup phase of 9 this plant, but they are very interesting indicators of how 10 this utility has dealt with these problems. In particular, I 11 will be talking about engineered safety features actuations 12 during the time period since they received their license and 13 what we are doing because of that.

14 The startup program is not done. We don't expect it 15 will be done.for another one week to maybe two weeks, and we 16 will be working with the utility on that. It is our intent 17 not to make a recommendation to NRR on license issuance until i

18 we resolve some of these questions such as the ESF actuation.

i 19 In summary, it has been an experienced staff 20 involved in the construction of the plant. They have had very 21 aggressive management involvement. The vice president who has 22 reported to the Salem / Hope Creek site in April of 1985, was 23 previously the resident manager at Fitzpatrick, so he has had 24 experience, and I think there have been a lot of lessons 25 learned from Salem. The Salem management experience with the i

. _ , - _ ,. ~.-_ _ _ , _ , _ . . . _ _ _ . _ . _ _ , _ . _ , . _

_ _ _ _ , _ _ . . . _ . . _ _ _ _ _ _ . . _ . . _ . . . . _ . . _ _ . _ _ _ . _ . . _. , . , . . . _ , , , - . _ _ ~ , , . _ _ . . _ . _ , , . _ , _ . . . _

l 42 1 reactor trip breaker failure has caused a different approach 2 at both Salem and Hope Creek. i i

3 With that, I would like to touch briefly on each of 4 the bullets that I have in Slide 11. Could I go to Slide 12, 5 please, and we can talk briefly on construction.

6 '[ Slide.]

7 COMMISSIONER ASSELSTINE: Rich, when you get to the 8 startup testing program, I hope you do go into a fair amount 9 of detail on the experience, including ESF actuations and what 10 we know about them at this time. I thought the Staff's paper 11 they sent down last week at least highlighted the problem, but 12 it was awfully cryptic, so I would like to hear some more 13 detail about that.

14 MR. STAROSTECKI: We are prepared to go into each 15 one, if you .like, and we have the right people.

16 COMMISSIONER ASSELSTINE: Okay.

17 MR. STAROSTECKI: When we say inspection history 18 favorable, we are talking from the standpoint of 12,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> 19 of inspection at Hope Creek, of which 8000 were really devoted 20 to construction. That compares equally with most of the other l

21 construction plants in the region. The enforcement history l

22 has been very favorable and the SALP results indicate a very l

23 responsive utility management.

24 The quality assurance program has been strong. As 25 we noted in our readiness assessment report of April, the

. 43 1 quality assurance, quality control program in particular we 2 view as a strength. Interesting to note that they have had 3 very low quality control reject rates, which means that when 4 the QC inspector goes in there, they find the work was done 5 right the first time, and I think that is a true indication of 6 quality. Do it right the first time and don't rely on the 7 inspector to reject it to have it redone.

8 COMMISSIONER ASSELSTINE: In those two areas, was 9 the experience with Hope Creek comparable to the experience 10 with Salem or was there a learning curve such that you saw a 11 better performance and better experience with Hope Creek?

12 MR. STAROSTECKI: I obviously wasn't there when they 13 were building Salem. My own personal observation from what 14 little I know is the inspection program is so much different, 15 we look at so much more today and we have a stronger emphasis 16 on direct management control in the last four or five years, 17 and I really couldn't speak to Salem.

18 Let me ask if -- We don't have anybody. The people 19 who were involved in the construction inspection of Salem, j 20 some of them I have talked to in the past, and quite frankly, t

21 I would not want to draw any parallels.

22 The quality assurance organization also set up an i 23 allegation management system known as SAFE Team at Hope Creek

) 24 a few years ago, and they have been interviewing people before f

25 they exit site. We have inspected that and found that it was

. 44 1 working successfully.

2 COMMISSIONER ASSELSTINE: I take it when you 3 inspected it you looked at the qualifications of the people 4 conducting the interviews and doing the reviews and you found 5 that those were technically qualified, experienced people?

6 MR. STAROSTECKI: Yes, and there are several ways of 7 doing that, but more important to me was not only that, but 8 when they got the information, did they relate it generically, 9 and if there was a problem, did they go back and fix the ,

10 underlying problem in other areas; not just because somebody 11 found one procedure, if it was a procedure generation problem, 12 they looked at it across the board, and we were happy and 13 satisfied with that.

14 There were some weaknesses, but basically it was not 15 just a band-aid approach.

16 COMMISSIONER ASSELSTINE: Okay. So even though they 17 bought the SAFE Team concept, they didn't make the same 18 mistakes that Detroit Edison made.

19 MR. STI.ROSTECKI: I'm not aware of the mistakes --

20 I'm sorry -- at Detroit Edison.

21 COMMISSIONER ASSELSTINE: You are not? Jim?

22 MR. TAYLOR: I think they didn't make the same 23 mistakes as Detroit Edison did.

24 COMMISSIONER ASSELSTINE: Good. Thank you.

25 MR. STAROSTECKI: The Augmented Independent Design

45 1 Verification involved three separate systems that were looked 2 at by Sargent & Lundy. The hardware and design was not 3 affected. Obviously, there were a few problems, but it went 4 satisfactory and that was documented and overviewed by both 5 NRR and IE, and the Region with some involvement.

6 Team inspections, as I mentioned, give us a lot of 7 confidence that what we have done in terms of sending both 8 resident inspectors and region-based people to the site has 9 verified what we expected to see.

10 MR. TAYLOR: I might say a couple of words about 11 that IDVP. They hired Sargent & Lundy to overview Bechtel's 12 work. We did three in-depth inspection reviews at Bechtel and 13 of Sargent & Lundy's work. They did three systems and they 14 did a very thorough job. The Staff was impressed with the 15 work done by Sargent & Lundy. Sargent & Lundy put their best 16 people on it.

17 There were issues in documentation, but as a result 18 of that, there were no design changes as such that had to be 19 made, nor were there any hardware changes, three major safety 20 systems.

21 COMMISSIONER ASSELSTINE: Was that done fairly 22 recently? I take it after those became more of a voluntary 23 effort, so that it's really something of their own initiative.

24 MR. STAROSTECKI: There were two activities that 25 were done in response to the Public Advocate of the State of 1

l

=

46 1 New Jersey. The Public Advocate basically said, look, why go 2 to hearing, I would rather get something useful out of 3 this. So they had a management audit done by Ted Barry and 4 Associates in response to the suggestion from the State of New 5 Jersey and this augmented IDVP. So this was done in response 6 to that and a settlement was reached, so they did not have 7 hearings, as a result.

8 MR. TAYLOR: It was finished last year.

9 MR. STAROSTECKI: Can I have Slide 13?

10 [ Slide.]

11 One of the discussion points I would like to talk 12 about is what we refer to as preoperational test exceptions.

13 The reason I am bringing this up is preoperational tests 14 normally involve an integrated system operation, and normally 15 there are a few items that need to be taken up after the fact, 16 such as an indicator or a sensor that may not be working at 17 the time so it doesn't get tested with the rest of the 18 system. When these preoperational tests are done properly, we 19 can even take credit and utilities do take credit for 20 surveillance testing so they don't redo the tests later on 21 when they do the surveillance tests. So that is the 22 importance of talking about preoperational tests.

23 Test exceptions mean just that. They didn't get to 24 test all the pieces of the hardware in an integrated sense.

25 There may have been a pump, a valve, a component that wasn't

l

. 47 1 ready to be tested, and this results in an exception. Each 2 exception is reviewed by the utility, and the Region, 3 consequently, follows up on the review of those because they 4 are normally dispositioned after all the individual tests have 5 been done separately.

6 So this approach taken by the utility resulted in 7 some deferrals of some component tests and, consequently, did 8 not give you a fully integrated test. This satisfies our need 9 based on the exceptions we saw for verifying that the hardware 10 worked.

11 The integration of all this, we said, and the 12 utility agreed, would best be done by specifically redoing the 13 integrated tests when they did the surveillance tests. So we 14 have had both preoperational tests for hardware, and it is 15 focused more.on components, and the integrated verification 16 through the surveillance testing program.

17 CHAIRMAN ZECH: But all the equipment is tested. It i 18 is just not all tested as a system; is that what you are 19 saying?

i

) 20 MR. STAROSTECKI: All the equipment has been tested i

21 during the preoperational phase, and, in fact, has 22 subsequently been tested as a system when they did the

, 23 surveillance tests.

l 24 CHAIRMAN ZECH: Fine.

l 25 MR. STAROSTECKI: So it has caused some work for the i

.- 48 1 utility and the Staff, and I just wanted to clarify that 2 nothing was bypassed.

3 CHAIRMAN ZECH: Fine. Go ahead.

4 MR. STAROSTECKI: The scram reduction effort is a 5 proactive effort by this utility. They, in fact, have gone 6 out and looked at specific problems at other plants. We have 7 seen them working with INPO in identifying industry experience 8 where they, in fact, have already made a large number of 9 changes to procedures and hardware to avoid some of these 10 spurious trips that sister plants have experienced.

11 I would like to go to Slide 14.

12 (Slide]

13 Startup testing was started shortly after the lower 14 power license was issued April lith. I will be mentioning the 15 Perry facility because Perry was issued a low power license on 16 March 18th, so it gives a benchmark as to how they fared. As 17 indicated on the slide, the fuel loading did go smoothly. We 18 had no difficulties. The fuel loading was done in 16 days.

19 The Perry plant took 37 days, and it was interesting that fuel 20 load at Hope Creek was finished on April 27th and at Perry on 21 April 24th, further giving us a better reference mark.

22 Initial criticality at both Hope Creek and Perry 23 took approximately the same amount of time and it was done in 24 a structured approach. It was about 78 days after license 25 issuance for Hope Creek, and 80 days for Perry.

• • 49 l One of the things that comes out of the startup i l

2 testing program is the fact that there have been some 3 interesting LERs, as Commissioner Asselstine has indicated, to h

4 talk about ESF system actuations, but I think it is of I

i 5 interest to recognize that the internal evaluation process 6 that Public Service uses at Hope Creek has identified about 75 7 different types of problems that we in the Region follow, of j 8 which about half, or 34, have been LERs.

i 9 We met with Public Service Electric and Gas very I

j 10 early on in early May after they had had a number of these 11 LERs that related to ESF actuations. Of the 34 LERs that we 3

l 12 have seen so far, I would say 14 have been due to personnel

{

13 error. A significant point to recognize, however, is that the <

1 i 14 LERS are not out of line and, in fact, compare very favorably 15 with other plants. This is a fairly low number of LERS for an l

16 NTOL facility, and because of that, it has allowed us to focus 17 on some of these more specific problems.

18 We have not, obviously, had an opportunity to talk 19 much about startup testing in the power ascension phase to 5 i

l 20 percent power because activities have only recently been 21 occurring that way, and they expect to be doing some mora 1

22 testing in the next week.

23 COMMISSIONER BERNTHAL: Rich, if I might ask a 24 question at this point because it seems appropriate. In all 25 of this startup testing, I notice that you have deferred i

50 1 certain required tests of pumps and valves, apparently, for up 2 to two years? I don't know whether it is you or somebody else 3 here at the tabic, but my understanding is that the licensee 4 was granted relief from certain tests in the SSER for up to 5 two years, and I'm just curious why that was done or what the 6 special circumstance was there.

7 MR. STAROSTECKI: To help maybe clarify your 8 question, there are two issues at hand. Maybe it's the IST 9 program, and also the General Electric initiative to 10 streamline the preoperational startup testing program.

11 COMMISSIONER BERNTHAL: It is in the fourth SSER.

12 MR. BERNERO: Yes, I think it's the IST program we 13 are talking about. This plant has the truncated started test 14 program, but that doesn't give you two-year 15 postponements. That gives you just less redundant testing, a 16 shorter test program.

17 MR. STAROSTECKI: I'm not aware of any tests being 18 deferred. I have to agree with Bob it most probably is the 19 in-service testing program, or they may baseline como of their 20 components at a later point in time.

21 MR. TAYLOR: Mr. Lainas, do you have the answer to 22 that?

23 CHAIRMAN ZECH: Would you identify yourself and come 24 to the microphone, please?

25 MR. LAINAS

My name is Gus Lainas. I'm with the l

l

._ - -___.~_--- _ - . . . _ _ .

4

^*

51 1 Division of Boiling Water Reactors. I think what you are 2 referring to is the condition number 4 in your handout. This .

3 is the IST program. I think a lot of this is because they 4 have asked for a deferment but we haven't finished our review 5 of what their request was. So I don't think there is anything 6 that is really significant with respect to this particular 7 issue. It's a question of us finishing our review.

8 COMMISSIONER BERNTHAL: Okay.

9 CHAIRMAN ZECH: All right. Proceed.

10 MR. STAROSTECKI: I didn't have any other points on l 11 the startup testing program other than the LERs to date. As 12 of July 3rd, we have had 34, and that is a fairly low number 13 ccmparing it with some other plants. Limerick, for example, 14 for the first three months had 59, almost double. So when I 15 refer back to Limerick, we had a concern at Limerick with the 16 knowledge of the operators with their tech specs and the 17 administrative procedures, and this eventually was manifested 18 in the LERs and that eventually'got straightened out.

19 We don't have that kind of problem with operator \

20 knowledge. We have had some personnel errors. Fourteen of 34 21 were due to personnel. We have not had a large number due to 22 equipment failure and design inadequacies. Only about ten.

23 And the lingering problem that does stick out from the LERs is 24 the ESF actuations, and I will talk about that shortly.

25 COMMISSIONER ASSELSTINE: You are going to talk

o 52 1 about the six scrams also?

2 MR. STAROSTECKI: If you would like.

3 COMMISSIONER ASSELSTINE: Please.

4 MR. STAROSTECKI: Slide 15, please.

5 (Slide]

6 The control room discipline and professionalism --

7 and at this point, I would also like the senior resident 8 inspector to make a comment as to his observations, but my own 9 personal view has been that the operators there are 10 controlling the situation. They have established a specific 11 mechanism for keeping people out of the control room to 12 minimize noise and confusion in the control room. They are on 13 five-shift rotation and find that five-shift rotation gives 14 them more flexibility to control things like overtime, and 15 they have got more people on shift than the minimum required.

16 So when we talk about overtime, you have to talk 17 about workload and the ability to do things on backshifts or 18 do you have to bring people in. With the additional manning 19 on each shift for five shifts, they claim that they can get 20 more work done. They have the people to man six shifts; they 21 just don't see that as giving them as much flexibility.

22 The STAS, as mentioned, are qualified as SROs, and 23 people do not stand STA watches unless they have an SRO 24 license.

25 They have a very strong commitment to training with

,_. . ~ . . _ . - .

53 1 Public Service Electric and Gas. Salem has all ten areas 2 accredited by INPO. They intend to have Hope Creek going up 3 next year, and they have had a plant-specific simulator for 4 both Salem and Hope Creek in operation. The Hope Creek 5 simulator was operational in February 1985, so I think that is 6 a very positive sign, having it operational in advance of a 7 license.

8 They have a very strong program for non-licensed 9 operators. As I think NRR mentioned, they have got programs 10 for technicians and other crafts that include fully-equipped 11 laboratories, shops for chemistry, and health physics people 12 get included. All in all, a very strong training commitment 13 and including a strong commitment to supervisory training, 14 which I think is one of the stronger lessons learned from the 15 Salem ATWS event.

16 The number of SRO people that are qualified and RO 17 qualified is as indicated. The examination failure rates and 18 pass rates, I should say, showed no anomalies. The Region I 19 experience for pass rates this fiscal year has been 80 percent 20 for SROs and 79 percent for ROs. That is based on 260, 270 21 examinations. Twenty-nine of approximately 36 people passed 22 the SRO exam, and a total of 19 ROs similarly experienced 23 about an 80 percent pass rate.

24 So we have no unusual insights as to weaknesses in 25 the training program.

54 1 The low power operating experience, I have to say, 2 has been somewhat limited because of the initial criticality 3 coming fairly late. The few challenges that the operators 4 have had have been handled well.

5 The ESF actuations is what I would like to dwell on 6 now unless you would like to hear a little bit more about 7 control room demeanor.

8 COMMISSIONER ASSELSTINE: One quick question on 9 overtime. What would be the worst case for an operator, 10 either in a weekly period or in a two-day period, in terms of 11 the amount of overtime that one would work?

12 MR. STAROSTECKI: By policy?

13 COMMISSIONER ASSELSTINE: No, in terms of actual 14 experience given the five shifts. Anything like the 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> 15 in a two-day. period or the 80 or 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> in a week that we 16 have seen at --

17 MR. STAROSTECKI: This is Bill Borchardt, the senior 18 resident inspector. I would like him to answer.

19 MR. BORCHARDT: Good morning. We have seen that 20 overtime for operators has been limited to less than ten hours 21 a week.

22 COMMISSIONER ASSELSTINE: Great. Thanks.

23 CHAIRMAN ZECH: Proceed.

24 MR STAROSTECKI: The ESF actuation since the 25 license was issued have included 17, and in the first month of

l 55 1 operations we had five of unknown cause. What we are talking

, 2 about here is the high pressure coolant injection system 3 transactuating. There are really three possibilities of these r

4 things occurring. One is an actual transient that occurred 5 that necessitated these transactuatings. Two, some electrical 6 or electronic signal. Obviously, when we heard about the 7 Bailey logic, we thought is there some correlation with that?

8 And third is some kind of hydraulic perturbation.

9 We had a meeting with the Utility in May to discuss 10 this. They had established a task force. They are 11 aggressively pursuing it. We expect to meet with them next 12 week to discuss further the results of some of their looking 13 into this program.

14 What we really see as a potential issue is the fact 15 that on a boiling water reactor, most of your signals are 16 generated based on reactor vessel level. At Hope Creek there 17 are really two unique features. Each train -- and there are 18 four trains -- has reference legs, and one reference leg 19 having a perturbation on it indicating an erroneous level 20 could initiate that train. So it is basically one out of one 21 logic for ESF actuation.

22 Two, there are a number of systems that use these 23 common sensing lines and reference lines, so opening a valve 24 improperly, people working in the spaces bumping against these 25 lines, bumping against these sensors can cause hydraulic 1

. -- -----,. . -.- - - - , - . , . . , . . , , , , n.. ,- - . - - - - - - .

56 1 perturbations. We have seen that at Shoreham. Shoreham has 2 had 20 ESF actuations since they have had a low power 3 license. So 17 makes it look more like a Shoreham-type 4 problem.

5 So we tend to believe it is becoming more of an 6 issue of workers in the spaces and the fact that the boiling 7 water reactors do rely much more heavily on sensing reactor 8 vessel level, which means you have both the reference leg and 9 the sensing line that you have to worry about. On a 10 pressurized water reactor, you obviously don't have this 11 problem. You are sensing steam generators, you are sensing 12 pressurizers, you are sensing feed system, a lot of other 13 parameters, and you don't have this common line using one 14 reference leg or one sensing line.

15 Some utilities have eventually gone forward and 16 created dedicated sensing lines for each train to avoid this 17 perturbation.

18 At Hope Creek, there are some differences. They do 19 not have the same kind of logic for these ESF effectuations 20 that other GE plants do. They also, because of that, they 21 have a different logic for initiation of a single train.

22 We know the utility has recognized the concern. We 23 are not sure that we have the answer. We don't intend to make 24 any recommendations to NRR until we are satisfied there is an 25 answer and the utility has gotten to the bottom of the

57 1 problem.

2 We are fairly confident that it is not a logic 3 problem, but in fact relates more to hydraulic perturbation.

4 The key here is it is entire system actuations and not 5 component actuations.

6 Would you want,any more discussion on the ESF 7 actuations?

8 COMMISSIONER ASSELSTINE: How did Shoreham fix their 9 problem or have they fixed it yet?

10 MR. STAROSTECKI: They have not done the long term 11 fix. There are two fixes. The short term fixes get people 12 out of the work spaces so they don't bang against these 13 lines. The long term fixes come up for a plant like Shoreham, 4

14 they have two logic trains coming off one level sensor.

15 Shoreham's long term solution is to split up the trains, but 16 they have a different logic, which is not going to be 17 applicable necessarily to Hope Creek, if this is the source of 18 the problem.

19 COMMISSIONER ASSELSTINE: I take it what you would 20 be focusing on for Hope Creek before the staff issues a full 21 power license would be identifying the root cause and at least i

22 putting into place the short term or interim corrections, if 23 it a hydraulic perturbation problem. It would be controlling 24 workers in the work spaces.

25 MR. STAROSTECKI: Correct, which means controlling

, _ - _ - _ - _ - - _ , _ _ _ _ - ,_. . 2-

58 1 workers and upgrading the procedures to have more management -

2 and supervisory oversight when they are working in sensitive 3 areas. You can do that through procedures like cautioning 4 people that these are the kinds of hazards that can develop.

5 They also are putting physical barriers around some 6- of these devices so people can't reach them. You see that an 7 awful lot in these boiling water reactors, with these wired 8 cages around the sensitive instruments.

9 COMMISSIONER ASSELSTINE: For the longer term, I 10 take it you look at some other change or modification?

11 MR. STAROSTECKI: It is interesting because for the .

12 longer term, it depends on whether you have a repeat of these 13 kinds of situations. If you can really correlate and 14 understand the root cause, that may be sufficient.

15 COMMISSIONER ASSELSTINE: Did Susquehanna and 16 Limerick have these kinds of problems?

17 MR. STAROSTECKI: To some extent; yes. My 18 recollection is that Susquehanna had it also and their 4

19 solution was to split up the logic to have dedicated reference 20 legs and sensing legs for each train and not have shared 21 legs. Limerick, I don't think had as large a number as 22 Shoreham and Hope Creek.

23 CHAIRMAN ZECH: Unless there are other questions, 24 I'd like you to wind up as soon as you can. We have to bring 25 the licensee up here. We want to give you time to finish your

59 1 presentation, but we would like to get the licensee up here 2 fairly soon, too.

3 MR. STAR;STECKI: Mr. Chairman, I have no other 4 slides that I would want to present. I would like to offer 5 the Senior Resident Inspector's views on his observations of 6 how they have been handling the scrams, the kinds of scrams 7 they have dealt with, and the adequacy of their post-trip 8 review process.

9 CHAIRMAN ZECH: Fine. We would like to hear that.

10 We would like to hear it briefly, please.

11 MR. BORCHARDT: Yes, sir; I'll try. .

12 As a matter of our normal routine inspection 13 program, we reviewed scrams real time as they happen and 14 attend the licensee's post-trip review meetings. I agree uith 15 the determination for cause of the scram. Also, later on, 16 reviewed the scram as it was presented to us in the LER i 17 format.

18 To date, there have been six scrams, three of them I l

19 would like to point out there were scram signals but no rod 20 motion because it was either during fuel motion or fuel i

21 movement into the reactor vessel or previous to that time.

22 There have been three at power. Two have been caused by i

23 personnel error as a result of down ranging the wrong IRM and j 24 providing a scram signal. One other was due to having a half 25 scram inserted, due to a failed instrument, and then in an f

I l

l

. . . _ , . , _ _ , _ . _ _ . ., _.m, _ _ *_._..

s' 60 1 unrelated event, an APRM failed and because of a 2 conservatively high gain adjustment factor set into the 3 instrument, that resulted in the other half scram, and they 4 got a scram out of that.

5 We found their post-scram reviews had been very 6 thorough and the decisions made as a result of that, coming 7 out of it and approaching the next start have been 8 conservative.

9 CHAIRMAN ZECH: Thank you very much.

10 MR. ROE: That brings the staff's presentation to a 11 conclusion. .

12 CHAIRMAN ZECH: Are you going to give me a 13 conclusion from the staff?

14 MR. ROE: Yes, sir.

15 COMMISSIONER BERNTHAL: May I ask one question 16 before you give a conclusion? Why it is that we haven't -

17 finished all the items in the in-service testing program? We 18 have had the package for a year; haven't we?

19 MR. WAGNER: It's really not that unusual to offer 20 relief like this. In the case of Hope Creek, we granted the 21 relief via the license.

22 COMMISSIONER BERNTHAL: It is not that unusual to 23 take a year though to review the submittal?

24 MR. WAGNER: No, sir. It's a rather complex 25 submittal. What we do, we do a short review, trying to hit

..' 61 1 upon some major points and if those look like they are in ~

2 order and.the utility did request relief, we do grant it.

3 That's what has been done.

4 MR. VOLLMER: One of the other reasons, 5 Mr. Commissioner, is the fact that the items that have to be

~

6 done under this program are usually later on in the operation 7 and they are done for a number of years. You don't really 8 heavily impact them in that particular by being late a few 9 years after license issuance.

10 COMMISSIONER ASSELSTINE: I have one other question 11 as well before the staff gives its conclusion. It has to do 12 with the 24 inch feedwater check valve. The Supplement 2 to 13 the SER says that -- I guess the original SER indicated that 14 the outer and inner valve body surfaces for these two check 15 valves must be inspected at the first refueling outage and at 16 other times when a valve is disassembled for maintenance, and 17 then the supplement references a letter from the licensee or

{

, 18 the applicant, that indicates that they do the inspection 19 program at the first refueling outage.

20 Does that mean they are not doing as much -- they t

21 are not committing to do the inspection if they disassembled 22 the valve prior to the refueling outage, and if so, why is 23 that satisfactory to the staff?

, 24 MR. WAGNER: Would you repeat that, the last part?

i 25 COMMISSIONER ASSELSTINE: It seems like their

. - - . _ _ _ _ _ . -. ,, _ ~ - . . _ _ . _ _ _ _ _ . . . , . _ . . _ _ _ . , . _ . . - . _

62 1 commitment isn't as strong as what you asked for. What you 2 said in the earlier SER was you are going to disassemble these 3 valves either at the first refueling outage or if you 4 disassemble the valves before, then you will do the inspection 5 then.

6 It sounds like the commitment from the applicant is, 7 we will do it at the first refueling outage. Is that weaker 8 than what you asked for or are they committing to do it if 9 they disassemble the valves?

10 MR. WAGNER: We find what they are doing is 11 acceptable. Other boilers have done the same types of 12 examinations on feedwater check valves. This is a result of ,

13 GDC-51 review regarding fracture prevention.

14 COMMISSIONER ASSELSTINE: Because the valve bcdies 15 may have cracked some?

16 MR. WAGNER: That's right.

17 CCMMISSIONER ASSELSTINE: Are they going to do the 18 inspection early on if they disassemble the valves or not? Is 19 it only going to be at the inspection outage? The refueling i

20 outage.

21 MR. WAGNER: As far as I know, the refueling.

22 COMMISSIONER ASSELSTINE: The staff has bought off 23 on that, even though what they had asked for earlier was 24 something stronger?

25 CHAIRMAN ZECH: Apparently, they have. I presume

63 1 you have reason for that. ~

2 COMMISSIONER ASSELSTINE: At some point, I would 3 like to know why you are satisfied with something less 4 stringent than what you asked for before.

5 CHAIRMAN ZECH: Yes; follow through on that, if you 6 would please. Thank you.

7 MR. VOLLMER: Mr. Chairman, in response to your 8 question, again, the last slide, we conclude that the licensee.

9 does satisfy all requirements for issuance of a full power 10 license and subject to your approval and the things that were 11 mentioned from the regions that still need to be cleaned up, 12 we would be able to proceed with that issuance. ,

13 CHAIRMAN ZECH: Your conclusion is based on the 14 provision for completing the items you mentioned?

15 MR..VOLLMER: Yes, sir, mentioned here today.

16 CHAIRMAN ZECH: Fine. Thank you very much. Will 17 the licensee come forward, please? Please introduce yourself 18 and your colleague for the record and proceed.

19 MR. FERLAND: I will, Mr. Chairman. Good morning, 20 gentlemen. My name is Jim Ferland. I am the Chairman and 21 President of Public Service Electric and Gas Company. With me 22 this morr.ing is Mr. Corbin McNeill, our Vice President of 23 Nuclear Operations. We appreciate this opportunity to make 24 just a few comments.

25 This turns out is the second time within the past

N

. 64 1 twelve months that I have had the opptrtunity to sit at this 2 table, seeking authorization of a full power license. On 3 November 25, 1985, I appeared here as President of Northeast 4 Utilities, seeking in a similar fashion a full power license 5 for Millstone-3. That unit has completed a very successful 6 power extension test program and is now in commercial 7 operation.

8 During my tenure with Northeast Utilities, I had 9 extensive involvement with the company's nuclear program. I 10 have had a senior reactor operator's license and was for 11 several yea,rs superintendent of the Millstone nuclear complex.

12 Prior to accepting my current position with Public 13 Service Electric and Gas, I assessed the company's nuclear 14 activities and became convinced they were of high quality and 15 getting better. The management and directors of Public 16 Service Electric displayed considerable respect for the 17 attention required to properly manage this technology. I have 18 little doubt that my nuclear background wasn't a important 19 determinant in my selection as Chairman and Chief Executive 20 Officer.

21 I recognize the great responsibility with

, 22 accompanies your authorization to operate nuclear facilities.

23 I will assure you that proper management attention and 24 adequate resources will be given and applied to this most 1 25 demanding activity, i

1

. 65 1 -

Mr. McNeill brings extensive nuclear experience to 2 his position as Vice President of Nuclear Operations, as 3 Mr. Starostecki pointed out, Mr. McNeill came to Public 4 Service from the New York Power Authority, where he served as 5 Senior Vice President, Nuclear Generation and prior to that, 6 as Resident Manager of the James A. Fitzpatrick nuclear power 7 station, the boiling water reactor.

8 Mr. McNeill served in the U.S. Navy where he 9 commanded a nuclear submarine and was Commanding Officer of a 10 Navy Nuclear Power School.

11 . His office as well as the entire 1,800 employee 12 organization is located at Artificial Island, the site of the 13 Salem and Hope Creek stations, where he directly supervises 14 all engineering and operating activities for these units.

15 Accompanying Mr. McNeill and me this morning are i

I 16 Mr. Richard Eckert, the company's Senior Vice President of 17 Engineering and Nuclear Activities as well as other members of l 18 the company's nuclear organization. Mr. Eckert and i

19 Mr. McNeill have mapped out a comprehensive program to assure l

L 20 that Hope Creek is safely brought into service and is safely 21 and reliably operated over its lifetime. We are here tot,y to I 22 assure the Commission that we are ready in every respect to 23 receive the full power license that we need to move into our 24 power extension program.

l 25 The power extension test program will be conducted i

l i

6G

- 1 in a deliberate, cautious and in a very thorough manner.

2 I would like to ask Mr. McNeill if he would maybe 3 respond to what I think is an open question on how it turns 4 out a standby liquid program system has automatic initiation 5 and following that, we would be glad to respond to any other 6 questions you may have.

7 MR. McNEILL: Thank you. At the time the Commission 8 was considering the various options for ATWS mitigation, the 9 issue of automated injection of the standby liquid control 10 system had not been determined. Public Service had reached 1,1 that point in the design where we had to make a decision as to 12 whether we would go with automatic injection or with manual 13 injection. We took what we thought was the conservative 14 approach, to avoid any replication of effort later on or 15 design changes and did in fact take the approach to an 16 automatic-injection.

17 I would point out we have through analysis managed 18 to delay the period from the initiation signal until the 19 automated initiation takes place to allow the operators time 20 to interrupt that if the spurious signal does initiate the 21 standby liquid control.

22 CHAIRMAN ZECH: Any other questions from my fellow 23 Commissioners?

24 COMMISSIONER BERNTHAL: I wanted to give you a crack 25 at this question, it is the logic modules again. I know ue

..- 67 1 discussed that extensively way back whenever it was. My 2 memory probably isn't as good as it should be.

3 Would you explain to me why on something that one 4 would expect Bailey must have had a good deal of experience by 5 now, we are still worrying about things like humidity and RF 6 leakage in the system?

7 MR. McNEILL: Different reasons for both issues that f

8 came up. In fact, the RF interference issue is a cabling RF 9 interference issue rather than a module RF interference 10 issue. In retrospect, it would have been better to have 11 installed shielded cable on the signal cables in the plant.

12 COMMISSIONER BERNTHAL: All right.

13 MR. McNEILL: When we had the option of either 14 re-wiring all the cabling in a plant or putting input 15 filtering and buffering on the modules, it was much simpler 16 and most cost effective to do that and that was the approach 17 for correction that we took.

18 On the second issue, the humidity, we really didn't 19 find this problem until we started to do some of the equipment 20 qualification issues where we raised the humidity levels 21 higher than are normally experienced in similar applications j 22 in other applications of the Bailey system, which is both 23 shipboard and on some fossil stations.

24 It was only when we got the humidity values up 25 around 60 percent that we found two pins that were in these l

68 1 modules were too closely spaced and the high humidity would 2 cause the interference and we had to re-design that section of 3 the board.

4 I'm not sure whether Bailey had ever seen that 5 problem before. To our knowledge, it only showed up in some 6 high humidity conditions that we did experience in the plant 7 plus the EQ testing that was done on those modules at some 8 point in time.

9 COMMISSIONER BERNTHAL: That was a single failure 10 there, where you had arcing --

11 MR. MC NEILL: Yes.

12 COMMISSIONER BERNTHAL: And the RF problem was more 13 you were piping them into the RF?

14 MR. MC NEILL: Yes, they were all going into the 15 module, rather than being picked up in the module itself.

16 COMMISSIONER BERNTHAL: I recall that now.

l 17 A general question, though. Maybe the Staff needs

18 to answer this privately later on, but I'd be curious as to 19 your opinion on this broader question of the use of solid i

l 20 state components, so-called solid state components. Most t

l 21 people don't use much else anymore, in other applications.

22 It must be very common on northern Europe -- I've 23 been through enough of those plants -- to see that kind of 24 utilization. Are we -- I don't know how to put this. Are we 25 in the same league with them, in our application of these I

69 1 technologies? Or are we behind? Is the NRC the problem, or 2 what's going on here?

3 MR. MC NEILL: I would express personal opinion at 4 this point, and I think the issue is that in the case of Hope 5 Creek, we did not buy a fully integrated single design plant.

6 one of the issues that was brought up by the Staff was that we 7 had been deeply involved in both the engineering and 8 construction.

9 We made many independent or owner considerations of 10 how we would put all of the electronics and relay systems of 11 this plant together. We took certain elements from General 12 Electric. We took certain elements of Bailey -- which had 13 some history within public service. We had used Bailey at 14 Salem Station. We had used Bailey and there were reasons for 15 doing that. .

16 We did not go and buy a single integrated electronic 17 system for the plant. I would think that what you see, 18 knowing the Swedish plants with a single designer, that they 19 probably have a formatted modular approach to that kind of 20 design.

21 That doesn't exist under the same conditions in 22 which we built Hope Creek.

23 COMMISSIONER BERNTHAL: It sounds like we are a bit 24 behind them in that respect.

25 MR. MC NEILL: I believe that that's the case. We

m. - _ , . _ _

s-_ _ , . _ . _ , _

--7,,, , _, .,_ ,_p., , , , , , . . , , , , . _ -

p

70 1 are behind Navy plant in that particular respect, even though 2 they are much smaller.

3 COMMISSIONER BERNTHAL: Well, I was suspicious that 4 that was the case.

5 CHAIRMAN ZECH: Jim?

6 COMMISSIONER ASSELSTINE: I don't have any 7 questions. I've got a few comments before we vote.

8 CHAIRHAN ZECH: Please, go ahead.

9 COMMISSIONER ASSELSTINE: I was up at the plant, as 10 Mr. McNeill knows, just a few weeks ago. And I saw a number 11 of things that I was quite pleased with. I think what we 12 heard from the Staff about looking at the experience of other 13 plants, both in this country and abroad, I was very impressed 14 with that and very pleased to see that.

15 I think that's something of a new approach for this 16 company and quite frankly, I saw a number of differences this 17 visit over the time when I visited Salem a couple of years ago 18 and I was very pleased to see those changes.

19 I sensed a new attitude and a new positive approach 20 by the management of the company and by the people at the 21 plant, and I was very pleased to see that.

22 The visit to Sweden, I think, is something that this 23 company is really to be commended for. And particularly, 24 sending working level people from the plants, not just the 25 senior managers or executives. That's good, but sending the

71 1 working level people, I think, gives you some direct 2 experience and knowledge at the working level that's quite 3 beneficial.

4 I was in Sweden fairly shortly after the visit, and 5 I heard very positive things from the people in Sweden, 6 particularly the people at the plants, about the exchange of 7 information and ideas and the enthusiasm which the Hope Creek 8 people brought to their visit.

9 And I was particularly pleased, when I visited Hope 10 Creek, to see not only that you'd done that but you'd also 11 profited from the experience and that you were making a number 12 of improvements or additions to your program at Hope Creek, 13 including things like radiation control, to get occupational

, 14 exposures down, and maintenance and equipment reliability.

15 And particularly I was impressed with the valve performance 16 efforts that you have underway to increase reliability of 17 valves.

18 I think that's a positive step that shows a forward 19 looking approach, a willingness to learn from the experience 20 of others, that I think is commendable.

t 21 I was very impressed, also, with the training 22 program. They've got a very nice training facility and 23 particularly for areas like maintenance and I&C work. I was

24 very impressed. I don't think I've seen another training i

25 facility that has better features than yours did. You've got

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72 1 your simulator already in operation, and I think the company's 2 been out front on the accreditation effort. Your schedule for 3 accreditation on Hope Creek is very aggressive, when I compare 4 it to other NTOL's. l 5 The post-scram review. I was very pleased to hear l

6 the Staff's comments on your post-scram review efforts at Hope l 7 Creek and I think that's another good sign of a positive 8 change from what we saw at Salem a few years ago. I was 9 pleased to see that.

10 Design features, I am pleased to see the -- moving 11 towards the four train approach, the secondary containment and 12 automating the standby liquid control system. I think, again, 13 that's a forward looking approach. Building in that safeguard 14 to let the operators stop the injection if it's not 15 appropriate -- if you have a spurious actuation -- I think is 16 a smart thing to do. And quite frankly, I'd like to see other 17 new boilers follow that kind of an approach. I think it's a 18 good forward looking approach.

19 Two others items, Jim, that you mentioned. Locating l 20 your nuclear operation at the site, I think, is a very 21 positive step and I credit that with some of the change in 22 improvement in performance over the past couple of years. I 23 wish some other utilities would follow that kind of an 24 approach. It's sort of a hassle and a traumatic experience 25 for people to start with, but I rhink the payoffs will be very

+

73 1 1 big down the road. It's a tough decision and I think the l 2 company should be commended for making that decision and 3 making that change.

4 I guess the last item I would mention is fitness for 5 duty. I think you've got a first-rate fitness for duty 6 program. It stands out as an example that the industry, as a 7 whole, ought to follow and I was very pleased, on my visit, to 8 see that you're having good experience with it and that the 9 many problems and objections that we hear from others just 10 don't seem to be materializing, so I think that's a final item 11 that you're to be commended for.

12 The one thing I'd raise a question about is these 13 ESF actuations and I trust that both you and staff are 14 committed to finding out the cause of those problems and to 15 getting them, fixed before you go above five percent operation.

16 MR. MC NEILL: There have been some recent events 17 that were not related here, which we have discussed with the 18 ' region. And without getting into technical details, I would 19 point out that I think we have really localized some of the 20 root causes and they are amenable to very short term 21 correction of the problems.

22 COMMISSIONER ASSELSTINE: Good. Those are the only 23 comments I wanted to make, Lando.

24 COMMISSIONER BERNTHAL: I would just make a comment 25 that Commissioner Asselstine has displayed considerable

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s 74 1 courage here and I want to commend him for that.

2 [ Laughter.)

3 COMMISSIONER BERNTHAL: We've not always had the 4 best experience when we're in the process of praising good 5 performance, but I want to second much of what Jim said.

6 I have, for a long time, wished that we would take 7 more advantage of the obvious abilities and changes and 8 improvements that our European counterparts have made and I 9 know that you've done that. I would urge you to keep on the 10 path that you've started on and don't let the compliments go 11 to your head.

12 COMMISSIONER ASSELSTINE: That's right. I thought 13 about that.

14 MR. MC NEILL: Well, let me tell you, they won't.

15 But we do intend to make ourselves the best operating nuclear 16 utility in the world. So, it's going to take us some time, 17 but we'll get there.

18 CHAIRMAN ZECH: Well, let me just say very briefly 19 then that, first of all, I too agree with essentially the 20 assessment that Commissioner Asselstine and Commissioner 21 Bernthal have brought forward.

22 My visit to the plant, as well as my review of the 23 entire record performance led me to believe not only the 24 specifics that have been mentioned by Commissioner Asselstine, 25 but overall the key management involvement that you have

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75 1 throughout your organization and apparently a strong awareness 2 that we're involved in a demanding technology and it does 3 require attention to detail and discipline and formality and 4 then things that I personally thing are absolutely necessary 5 to operate our plants reliably and safely.

6 So I, too, think that you have certainly taken the 7 right approach. I think it gives me a certain degree of 8 confidence that you're going to operate that plant not only 9 safely but in an effort to provide excellence throughout and I 10 expect you to be one of the leaders in our country. You've 11 got a start in that direction, but it's not easy. It requires 12 constant vigilance and attention to detail.

13 And I think you're going through the transition 14 period now from construction operations. It seems to me 15 you've demonstrated perhaps a stronger awareness of the 16 challenge in that regard than other plants have. But I would 17 only caution you that if your full power license is granted 18 that you continue to try to do things right the first time and i

19 continue to do everything you can to inspire your entire team 20 to be vigilant to improvements, and also to competent 21 performance throughout, i 22 It's not easy, but those are the things that must be 23 done. You look like you are off to certainly the right start 24 in the right direction, but I just want to say we expect you 25 to operate it safely. We expect it. And I'll be very i

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o 76 1 disappointed if you don't have a very fine record of 2 performance.

3 Unless there are any other comments, I presume my 4 fellow Commissioners are ready to vote.

5 Those Commissioners who approve the Staff's 6 recommendation to authorize full power operation of the Hope 7 Creek Generating Station by Public Service Electric and Gas, 8 please signify by saying aye.

9 [A chorus of ayes.]

10 CHAIRMAN ZECH: Those opposed.

, 11 [No response.]

12 CHAIRMAN ZECH: The vote is 4-0 and the meeting is 13 adjourned. Congratulations.

14 [Whereupon, at 11:50 a.m., the meeting was 15 adjourned.]

16 17 18 19 20 4

21 22 23 24 25

J .

1 2 REPORTER'S CERTIFICATE 3

4 This is to certify that the attached events of a 5 meeting of the U.S. Nuclear Regulatory Commission entitled:

6 7 TITLE OF MEETING: Discussicn/Possible Vote on Full Power Operating License for Hope Creek (Public Meeting) 8 PLACE OF MEETING: Washington, D.C.

9 DATE OF MEETING: Monday, July 21, 1986 10 11 were held as herein appears, and that this is the original 12 transcript thereof for the file of the Commission taken 13 stenographically by me, thereafter reduced to typewriting by 14 me or under the direction of the court reporting company, and 15 that the transcript is a true and accurate record of the 16 foregoing events.

, 17 /

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, COMMISSION BRIEFING HOPE CREEK GENERATING STATION

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JULY 21, 1986 I

i FULL POWER OPERATING LICENSE t

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DAVID H. WAGNER 49-29418 4

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. PRESENTATION OUTLINE 1

LICENSEE / PLANT BACKGROUND UNIQUE DESIGN FEATURES MAJOR REVIEW ISSUES SHIFT STAFFING INSPECTION PROGRAM CONCLUSION i:

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LICENSEE / PLANT BACKGROUND MULTIPLE OWNERS FOR HOPE CREEK

- PUBLIC SERVICE ELECTRIC 8 GAS COMPANY (95%)

- ATLANTIC CITY ELECTRIC COMPANY (5%)

PUBLIC SERVICE ELECTRIC & GAS COMPANY OPERATOR AND AGENT FOR OWNERS PLANT DESIGN

- GENERAL ELECTRIC BOILING WATER REACTOR AND TURBINE

- 1067 MEGAWATT ELECTRICAL OUTPUT

- MARK I CONTAINMENT DESIGN

- CONSTRUCTION COMMENCED 1976 SITE

- ORIGINALLY S,ITED AT NEWBOLD ISLAND, NEW JERSEY, A DENSELY POPULATED AREA

- LOCATED IN LOWER ALLOWAYS CREEK TOWNSHIP, SALEM COUNTY, NEW JERSEY ADJACENT TO SALEM FACILITY

- NEAREST CITY: SALEM, NJ (8 MILES); POPULATION: 7,000 (1980)

- NEAREST DENSELY POPULATED CENTER OF 25,000 PERSONS OR MORE:

NEWARK, DELAWARE (18 MILES)

STARTUP j - LOW POWER LICENSE ISSUED APRIL 11, 1986

- INITIAL CRITICALITY ACHIEVED JUNE 28, 1986

- AUTHORIZATION FOR 5% POWER EXCEEDANCE REQUIRED JULY 30, 1986 l

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UNIQUE DESIGN FEATURES SECONDARY CONTAINMENT REINFORCED CONCRETE

- MINIMUM THICKNESS 18 INCHES

- 3 PSI DIFFERENTIAL DESIGN PRESSURE

- 4,000,000 FT5 VOLUME

- CYLINDRICAL WITH TORISPHERICAL DOME MAIN STEAM ISOLATION VALVE SEALING SYSTEM INBOARD AND OUTBOARD SYSTEMS POSITIVE PRESSURE SYSTEM STATION AUXILIARY; COOLING SYSTEM CLOSED CIRCUIT C'00 LING LOOP EXCHANGES HEAT FROM PLAN 7 LOADS TO SERVICE WATER SYSTEM

t MAJOR REVIEW ISSUES SOLID STATE LOGIC MODULES REPRESENTS A COMMON MANUAL AND AUTOMATIC ACTUATION PATH INCORRECT ACTUATIONS OF SSLMS DURING PRE 0P TESTING RELIABILITY OF SSLMS TURBINE OVERSPEED ACRS RECOMMENDED TURBINE OVERSPEED PROTECTION BE REEVALUATED TURBINE OVERSPEED PROTECTION MEETS STAFF CRITERIA CONTROL ROOM VENTILATION SYSTEM FAILURE ACRS RECOMMENDED INVESTIGATING EFFECTS OF CONTROL ROOM HEATUP DUE TO LOSS OF HVAC CONCERN INVOLV,ES EFFECTS OF HEATUP ON CONTROL ROOM INSTRUMENTATION CONCERN IS BEING REVIEWED UNDER GENERIC ISSUE 83 CONTAINMENT DESIGN MARK I CONTAINMENT PLANT UNIQUE ANALYSIS DONE FOR CONTAINMENT HYDRODYNAMIC LOADS

,_ . . , . _ . _ .___,.m _ ._

TRAINING FORMAL SHIFT TRAINING COMMENCED IN MAY 1984 1ST COLD LICENSING EXAMS GIVEN JULY 1985 THOSE THAT PASSED EXAMS HAVE CONTINED IN CREWS i

IMPLEMENTED REQUALIFICATION PROGRAM IN OCTOBER 1985 AND CONTINUED WITH TEAM TRAINING CONCEPT THROUGHOUT REQUALIFICATION PROGRAM OPERA' TORS HAVE BEEN TRAINED FROM SYSTEM-BASED EMERGENCY OPERATING PROCEDURE EACH SHIFT HAS AT LEAST 1 PREVIOUSLY LICENSED BWR OPERATOR ALL CREWS HAVE HAD AT LEAST 6 MONTHS WORKING TOGETHER ON THE SHIFT TO PHICH THEY ARE CURRENTLY ASSIGNED l

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5 ELEMENTS FOR BWR CONTAINMENT IN SEVERE ACCIDENTS ,

1. HYDR 0 GEN

2. SPRAYS

3. PRESSURE

4. CORE DEBRIS

5. TRAINING AND PROCEDURES O

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HOPE CREEK GENERATING STATION l

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HOPE CREEK AND ACCIDENT OCCURRENCE ATWS CHALLENGE REDUCED BY IMPLEMENTING ATWS RULE RECIRCULATION PUMP TRIP ALTERNATE R0D INSERTION STANDBY LIQUID CONTROL SYSTEM (AUTOMATIC)

STATION BLACK 0UT CHALLENGES REDUCED BY TURBINE-DRIVEN HIGH PRESSURE COOLANT INJECTION (HPCI)

SYSTEM TURBINE-DRIVEN REACTOR CORE INJECTION COOLING (RCIC)

SYSTEM 4 STANDBY DIESEL GENERATORS 4 HOUR CAPACITY CLASS 1E BATTERIES TRANSIENT RESPONSE AIDED BY

- OPERATOR TRAINING (EMERGENCY PROCEDURE GUIDELINES, REV. 3)

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HOPE CREEK AND THE 5 ELEMENTS

1. HYDR 0 GEN

- INERTED CONTAINMENT, FULL COMPLIANCE WITH 50,44

2. SPRAYS

- RHR/ SPRAYS OPERABLE, FURTHER STUDIES UNDERWAY

3. PRESSURE

- HAVE IMPLEMENTED EPG REV, 3 VENTING PROCEDURES

4. DEBRIS

- UNDER STUDY 5.

TR41NING

- HAVE IMPLEMENTED EPG, REV, 3 1

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SHIFT STAFFING FIVE 8-HOUR SHIFTS

- 4 SHIFTS - 6 DAYS ON/2 DAYS OFF

- STH SHIFT IN TRAINING /REQUALIFICATION DUAL ROLE STA/SR0 ON ALL 5 SHIFTS MEETS REQUIREMENTS FOR ENGINEERING EXPERIENCE AND OPERATING EXPERIENCE ON SHIFT SHIFT MANNING TECH SPEC REQUIREMENT PER SHIFT TOTAL PRESENT STAFF SR. NUCLEAR SHIFT 1 5 6 SUPERVISOR (SRO)

NUCLEAR SHIFT ,. 1 5 12 SUPERVISOR (SRO)* ',

NUCLEAR CONTROL 2 10 19 OPERATOR (RO)

STA 1 5 9'

'6 0F THESE ARE ALSO SROS

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INSPECTION PROGRAM CONSTRUCTION PRE 0PERATIONAL TESTING STARTUP TESTING OPERATIONS L:

2 CONSTRUCTION REGION I INITIAL OPERATING LICENSE REVIEW DATED APRIL 11, 1986 INSPECTION HISTORY FAVORABLE QUALITY ASSURANCE PROGRAM STRONG 1

AUGMENTED INDEPENDENT DESIGN VERIFICATION TEAM INSPECTIONS 1

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PREOPERATIONAL TESTING j PRE 0P TEST EXCEPTIONS PSE8G APPROACH PORTIONS OF TESTS DEFERRED NECESSITATED TECHNICAL REVIEWS SURVEILLANCE TESTING INTEGRATED SYSTEM TESTS SCRAM REDUCTION EFFORT REVIEW 0F INDUSTRY EXPERIENCE PROCEDURES MODIFIED DESIGN CHANGES i

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4 STARTUP TESTING LOW POWER LICENSE - 4/11/86 FUEL LOADING - WELL PLANNED, COORDINATED AND CONDUCTED WITHOUT INCIDENT (4/15/86 - 4/27/86)

INITIAL CRITICALITY - 6/28/86 LICENSEE EVENT REPORTS / INTERNAL EVALUATION PROCESS REPORTS POWER dSd,ENSION TEST PROCEDURES - VERY GOOD QUALITY SIMULATOR USED FOR PROCEDURE VALIDATION I

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,o OPERATIONS CONTROL R00M DISCIPLINE AND PROFESSIONALISM COMMITMENT TO TRAINING LICENSED OPERATORS (SHIFT PERSONNEL) 18 SR0 QUALIFIED AND CURRENT 19 RO QUALIFIED AND CURRENT L0w P0hE'8 OPERATING EXPERIENCE

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CONCLUSION THE STAFF CONCLUDES THAT THE LICENSEES SATISFY ALL REQUIREMENTS FOR ISSUANCE OF A FULL POWER LICENSE FOR HOPE CREEK i:

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