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Plant License Renewal - April 29, 1999

                       UNITED STATES OF AMERICA
                     NUCLEAR REGULATORY COMMISSION
                                  ***
               ADVISORY COMMITTEE ON REACTOR SAFEGUARDS
                                  ***
                    MEETING:  PLANT LICENSE RENEWAL
     
                        U.S. Nuclear Regulatory Commission
                        11545 Rockville Pike
                                           Room T-2B3
                        Rockville, Maryland
                        
                        Thursday, April 29, 1999
     
         The subcommittee met, pursuant to notice, at 8:30 a.m.
     
     MEMBERS PRESENT:
     MARIO H. FONTANA, Chairman, ACRS
     MARIO V. BONACA, Member, ACRS
     THOMAS KRESS, Member, ACRS
     DON W. MILLER, Member, ACRS
     ROBERT L. SEALE, Member, ACRS
     WILLIAM J. SHACK, Member, ACRS
     ROBERT E. UHRIG, Member, ACRS.                         P R O C E E D I N G S
                                                      [8:30 a.m.]
         DR. FONTANA:  The meeting will now come to order.  This is
     the second day of the meeting of the ACRS Subcommittee on Plant License
     Renewal.
         I am Mario Fontana, Chairman of the Subcommittee for Plant
     License Renewal.  The ACRS members in attendance are Mario Bonaca,
     Thomas Kress, Don Miller, Robert Seale, William Shack, Robert Uhrig.
         The purpose of the meeting is for the subcommittee to review
     the NRC staff's safety evaluation report concerning Calvert Cliffs'
     plant license renewal application and related matters.
         The subcommittee will gather information, analyze relevant
     issues and facts, and formulate proposed positions and actions as
     appropriate, for deliberation by the full committee.
         Noel Dudley is the cognizant ACRS staff engineer for this
     meeting.
         The rules for participation in today's meeting have been
     announced as part of the notice of this meeting previously published in
     the Federal Register on April 5, 1999.  A transcript of the meeting is
     being kept and will be made available as stated in the Federal Register
     notice.
         It is requested that the speakers first identify themselves
     and speak with sufficient clarity and volume so that they can be readily
     heard.
         We have received no written comments or requests for time to
     make oral statements from members of the public.
         Today, we're going to hear from staff on a presentation of
     their safety evaluation report.  Now, Noel has given the ACRS members a
     list of the SER chapters and a list of issues, with member assignments. 
     Please get your comments to Noel, who will collect them.  These are
     needed by the full meeting next week so that we can incorporate them
     into the interim letter.
         Also, if you have any questions from the staff regarding the
     sections that are assigned to you or any additional areas of interest,
     raise them before the end of the day so that we can receive their
     replies in time for drafting of our letter next week.
         We will proceed with the meeting and I call upon Mr.
     Christopher Gratton.
         MR. GRATTON:  Yes.
         DR. FONTANA:  To proceed.
         MR. GRATTON:  Thank you.  I'm not quite sure whether or not
     I can speak loudly enough or clearly enough to be heard, but my name is
     Chris Gratton.  I'm the divisional coordinator for license renewal
     activities in the Division of Systems Safety Analysis, and I was also a
     reviewer for the Calvert Cliffs license renewal project.
         My presentation will be on the scoping and screening portion
     of the safety evaluation report.  During my presentation, I'm going to
     cover the implementation of scoping requirements, the implementation of
     the screening requirements, how we handle structures and commodities,
     open items pertaining to scoping and screening, confirmatory items
     pertaining to scoping and screening, and the license renewal issues
     pertaining to scoping and screening.
         The staff's goal was to have reasonable assurance that the
     applicant identified all the structures and components subject to aging
     management review.  In order to get this reasonable assurance, we
     performed the following reviews to scope the systems, structures and
     components.
         The first thing that we did was we took a complete list of
     the systems and structures at Calvert Cliffs from Table 3.1 in the
     application and identified those systems and structures that had license
     renewal application reports contained in the application.
         From those systems and structures, without reports of
     application, we sampled several systems to determine whether they had
     intended functions, then we've included them within the scope of license
     renewal.  We've used the FSAR to determine whether the systems had any
     intended functions.
         So our focus was on those systems that were not included in
     the license renewal application, since the other ones were already in
     and evaluated.
         We did identify some systems and structures that did not
     have reports in the application, but upon further investigation and
     through the RAI process, we have satisfactory responses from the
     licensee that the components that perform intended functions were, in
     fact, in the license renewal applications in other sections, such as the
     commodities sections.
         From this review, the staff obtained reasonable assurance
     that all of the systems and the structures with intended functions were
     identified in the license renewal application.
         The second review that we performed, we asked ourselves what
     portion of the within-scope systems and structures are required to
     perform intended functions.  For each of the -- I believe there were 66
     systems and structures in the application, 35 of which are broken out
     into individual SERs in our safety evaluation report.
         We compared the simplified drawings that were provided by
     the applicant to the flow diagrams in the FSAR or other docketed
     diagrams or drawings of the system.  We focused on those portions of the
     system that were not within the scope of license renewal, to ensure that
     they did not have any intended functions to complete system level
     intended functions.  We used the FSAR to identify the intended functions
     along with the list of intended functions provided by the application.
         Special consideration was given to the boundary valves or
     boundary points to ensure that they were properly accounted for within
     the scope of license renewal.
         Next, we identified the within-scope components that were in
     those portions of the systems that were within the scope of license
     renewal.  For each system and structure within scope, Calvert Cliffs
     provided a list of these components that were within the scope of
     license renewal.  Using the flow diagrams, we validated those lists
     component by component.  We found some emissions, but in interaction
     with the licensee, we clarified those emissions as either not required
     to be within the scope of license renewal or the applicant agreed that
     the characterization of the system boundaries was incorrect and they
     included those components within the scope of license renewal.
         At this point, we had boundaries for our systems and we had
     a list of components that we had reasonable assurance constituted the
     entire group of components that were within the scope of license renewal
     and we went on to our screening portion.
         This consisted of an active/passive determination and a
     long-lived/short-lived determination.  The staff compared the list of
     components within the scope of license renewal to those subject to an
     aging management review and focused on the applicant's justification for
     removing items from the second list.  The applicant actually provided
     two lists; one within the scope of license renewal, and a second subject
     to an aging management review.
         The difference between those two lists were removed for one
     of two reasons, either an active/passive determination or a
     long-lived/short-lived determination.  That's what the staff focused on,
     to see whether or not that determination was made properly.
         What remained from this second -- from this screening
     process was a list of structures and components subject to an aging
     management review.  Now, I sort of mixed components and structures
     together and that's because the evaluations were done similarly,
     although a structure is not a system.  The structures were identified
     individually and broken down into their components and the same process
     was performed as it was within the system.  We identified those portions
     that perform intended functions.  We focused on any portions of a
     building or a structure that was -- and if it is not within the scope of
     license renewal, to see if it performed any intended function.
         Then we ensured that the list of components was complete and
     that the components, subject to an aging management review, was also
     complete.  For commodity groups, the structures and components were
     assembled in a different manner.  The commodity groups, being several
     different systems, and the staff performed a review of the following
     type.
         The applicant stated that the commodities associated with
     the within-scope portions of the system were also within scope.  In the
     commodities section, the applicant listed the systems contained in that
     commodity and the staff verified that the list was accurate by sampling
     the systems not included on the commodity list.
         So in the commodities section, a table was provided of those
     systems that contained that particular commodity.  If it was electrical
     equipment, it was electrical equipment.  If the commodity group was
     component supports, it was component supports.
         Using the boundaries that we had validated in the systems
     portion, if, say, the feedwater system was listed on there as having a
     component support, those portions that were within scope, including any
     piping and structural components that extended beyond the last boundary
     valve, that were used for structural support for seismic considerations,
     weren't within scope.
         This was true for the commodity groups.  This is the same
     way that we evaluated this.  The commodity groups were instrument lines
     and cables.  Cranes and fuel handling was reviewed in an individual
     section.  It didn't span different groups and fire protection system was
     evaluated as a single system.
         As far as open and confirmatory items, we still have four
     open items.  The first one has to do with the station blackout diesel
     building.  It was not included within the scope of license renewal and
     it was erected in close proximity of the seismic Category 1 EDG
     building, and there were questions in the staff about whether or not the
     design of the building brings it within the scope of license renewal. 
     The words in the final safety evaluation report, final safety analysis
     report, that say that its failure could impact the ability of the EDG
     building to perform its safety-related function, but the staff is
     considering, as you will see in the portion on license renewal issues,
     cascading issues, and that is how far out and what sort of boundaries do
     we place on scoping and items that do not itself perform safety-related
     functions or non-safety-related functions whose failure can affect a
     safety-related piece of equipment.
         The second open item.  There are several nozzles in the
     charcoal filter beds that were not scoped within the scope of license
     renewal.  The licensee had indicated that up to the isolation valve for
     these nozzles, there's a short section of piping and then a spray
     nozzle.  The fire protection staff in DSSA believes that this section of
     piping, these nozzles are required by 10 CFR 50.48, and we're trying to
     address that with the licensee staff.
         The third issue also is a cascading sort of issue.  It has
     to do with the ductwork that provides cooling to certain rooms within
     the containment that provide the basis for environmental qualification
     calculations.  Without this ductwork or failure of this ductwork, the EQ
     requirements may not be maintained.  The assumptions that were made in
     the calculations would not be maintained, and the staff is trying to
     address how to handle these secondary issues, failure of a
     non-safety-related piece of equipment and its effect on a piece of
     safety-related equipment.
         The final open item is just sort of an editorial type of
     thing.  We noticed that there were some inconsistencies between the
     referencing of individual system electrical commodities and the
     electrical commodity list.  So an open item was issued to make sure that
     those two sections -- well, not those two sections -- the electrical
     commodities list, which contains the table of all the systems that have
     electrical commodities in them and the systems themselves, that they
     cross-reference each properly, because right now we've found several
     errors in that relationship.
         As far as the confirmatory items go, we have two.  Staff has
     been talking with the licensee about the tendon galleries and their
     exclusion and we're waiting for resolution on that issue, as well as
     certain solenoid valves in the containment spray.  The information I had
     on these valves is that they're air-operated valves and they do not
     contact process systems.
         So it's just a matter of identifying the type of valve to
     see whether or not they would be within scope or not.
         Finally, the license renewal issues, there were three in the
     DSSA section.  They covered consumables, which was not addressed in the
     BG&E application.  Consumables, the staff just issued a position on the
     20th of April covering structural steel and grease, component filters,
     system filters, fire hoses, fire extinguishers and air packs.
         Staff plans to use that position.  It's calling for comments
     at this time.
         Fuses, there was a -- staff put out a position that fuses
     were active components and BG&E countered that the fuses were, in fact,
     passive and the -- I'm sorry.  Just the opposite.
         The staff believed that the fuses were passive and BG&E
     thought they were active.
         The final one is this cascading issue that I addressed
     earlier, and that is systems that are non-safety-related or relied upon
     in calculations; you know, should their failures be considered within
     the scope of license renewal when performing your scoping.
         Thank you.
         DR. FONTANA:  The cascading failures, how do you go about
     analyzing those?  Do you track them from first principles or does it go
     back to the PRA or something like that?
         MR. GRATTON:  It was pre-deterministic.  For this SBO
     failure, it was in the FSAR for another reason and the description of
     the failure was in the FSAR itself and 10 CFR 54.4, the B criteria,
     non-safety-related, whose failure could affect a safety-related piece of
     equipment, the EDG structure being the safety-related piece of
     equipment, it was a direct deterministic evaluation.
         DR. FONTANA:  Okay.  Thank you.  Ready to move on?
         MR. GRATTON:  Yes.
         DR. SEALE:  When you did these deterministic calculations,
     were they, in some cases, replications of the calculations that you had
     done or had been done back when the license was first granted, the
     bounding kind of calculation that is used in the licensing basis?
         MR. GRATTON:  No calculations were actually done.  The
     current licensing basis actually carried forward into the license
     renewal period.  That was one of the bases for performing this review. 
     This was a scoping review, where we tried to bring the design basis
     events onto the systems and determine which portion of the systems were
     actually performing the system level intended functions that were
     described in the FSAR.  
         DR. SEALE:  So you made no attempt to confirm that you could
     replicate those calculations.
         MR. GRATTON:  No.
         DR. SEALE:  The laws of physics haven't changed, but --
         MR. GRATTON:  Not that I know of.
         DR. SEALE:  -- there may be other things that have changed
     in the interval that would make that calculation somewhat difficult at
     this point, I'm afraid.
         DR. FONTANA:  Anything else?
         MR. GRATTON:  Thank you.
         DR. FONTANA:  Who is next here?
         MR. GRIMES:  Dr. Seale, this is Chris Grimes, Chief of the
     License Renewal and Standardization Branch.
         I would like to point out that it is our expectation that we
     may end up going back and looking at the structural analysis for the
     non-safety-related station blackout diesel building and, using that
     assessment, to make a determination about whether or not failure of that
     building and its impact on the safety-related diesel generator building
     is an appropriate failure to consider for this purpose.
         So we may end up going back into that analysis and looking
     at the conservatisms or the nature of the failure modes.
         DR. SEALE:  That analysis wasn't in the original licensing
     basis, was it?
         MR. GRIMES:  When the station blackout -- no, not in the
     original licensing basis, but when the station blackout diesel was
     added, it became a part of the licensing basis.
         DR. SEALE:  Yes.  And you may confirm that.
         MR. GRIMES:  I expect that we will end up reviewing that
     analysis to make a final determination on this particular open item.
         DR. SEALE:  I think we'd be interested in what you find out
     there.
         DR. FONTANA:  Okay.
         MR. MUNSON:  My name is Cliff Munson.  I put together
     Section 3.1, common aging management programs, of the SER.  These are
     programs that appear throughout the -- that are used in the different
     structures and systems, in a variety of structures and systems.
         The first one is the fatigue monitoring program, the second
     one is the chemistry program, and then the third is structure and system
     walkdowns, boric acid inspection program, corrective actions program,
     and the age-related degradation inspection program, ARDI.
         So we'll start with the fatigue monitoring program.  This
     program monitors and tracks low cycle fatigue usage caused by pressure
     or thermal transients for components in the nuclear steam supply system
     and steam generator welds, and the cumulative usage factor is used to
     quantify the fatigue damage resulting from each transient.
         The design limit for the CUF is one and corrective actions
     are to be implemented before this CUF reaches one.
         DR. KRESS:  It's easy to measure the pressure variations,
     but thermal variations, you need thermocouples stuck around everywhere.
         MR. FAIR:  I'm John Fair, the reviewer on this.  What they
     mean by that is they're measuring process temperatures as heat-ups and
     cool-downs occur.
         DR. KRESS:  Okay.  And then they --
         MR. FAIR:  In some cases, they do have some more detailed
     thermal measurements in certain locations.
         DR. KRESS:  But they just measure the temperature of the
     fluid.
         MR. FAIR:  Right.
         MR. MUNSON:  The fatigue monitoring program is applied to
     these different systems that I've listed here.  As of right now, there
     are no open items or confirmatory items or license renewal issues for
     the fatigue monitoring program.
         DR. SHACK:  How does that handle GSI-190?
         MR. FAIR:  We separated, in the SER, the monitoring program
     by itself as a program that just tracks the fatigue from the issues
     related to fatigue in the other sections, and we discussed the GSI-190
     in Section 3.2.
         MR. MUNSON:  The next common aging management program is the
     chemistry program.  The chemistry programs primarily manage the
     corrosive action of water for systems containing primary, secondary
     water, component cooling, and service water.  The ARDMS managed by the
     water chemistry programs include various types of corrosion, from
     crevice corrosion, galvanic, to general corrosion, pitting,
     intergranular attack, stress corrosion cracking, intergranular stress
     corrosion cracking, primary water stress corrosion cracking,
     microbiologically-induced corrosion, selective leaching, and degradation
     of elastomers.
         For the systems containing primary water, these are a list
     of the systems containing primary water, and the aging effects that
     apply to these systems that are managed by the chemistry program.
         These are the secondary -- systems that contain secondary
     water, excuse me, and a list of their aging effects.
         DR. SHACK:  I assume that this really works -- I mean, they
     reference EPRI guidelines for primary and secondary water chemistry. 
     What is the commitment, that if EPRI revises those guidelines, what does
     Calvert Cliffs do?
         MR. PARCZEWSKI:  Usually, the plants keep abreast of any
     changes which are made in the guidelines.
         DR. FONTANA:  Please identify yourself for the transcript.
         MR. PARCZEWSKI:  Kris Parczewski, from Material Engineering
     Branch, NRR.
         DR. SHACK:  But there is no commitment then to --
         MR. PARCZEWSKI:  There is no specific commitment in the
     submittal.
         DR. MILLER:  A question.  Several of those systems do
     involve -- have some radiation.  Is there synergistic effects between
     the chemistry and the radiation effects?  Is that addressed in the
     guidelines?  I'm not familiar with the guidelines.
         MR. PARCZEWSKI:  Those guidelines don't address any
     radiation effects.
         DR. MILLER:  Is there any -- I don't know.  Bill, do you
     know about that?  Is there synergistic effect from those chemistry --
     I'm not a chemist, so I don't know, but some of the systems do involve
     some level of radiation.
         MR. MEDOFF:  I'm Jim Medoff, with the Materials and Chemical
     Engineering Branch.  I've done chemistry inspections of plants in Region
     I.  Calvert Cliffs has been one of the plants I have inspected.
         Typically, these plants do monitor both the cold chemistry
     of the reactor coolant system and the radioactive nuclides in their
     reactor coolant system.  In addition to meeting the EPRI guidelines, the
     plants typically set administrative limits that are more conservative
     than the EPRI guidelines, because they typically don't want to get to
     the levels or the limits set by the EPRI guidelines.
         So the chemistry departments typically try to maintain the
     water chemistry to levels that would be consistent or better than would
     be dictated by the limits set by EPRI.
         So from what I have found from my chemistry inspections, the
     industry has been implementing their chemistry control programs in
     accordance with the guidelines and, actually, they've been doing such a
     good job of it, this was one of the reasons they took the chemistry
     inspections out of the core curriculum.
         So I think that the licensees do address chemistry quite
     well.
         DR. KRESS:  The answer to the question that he asked is no,
     that the radiation levels in the cooling system are so small, that it
     doesn't enter into the chemistry very much.
         DR. MILLER:  What's the limits on the radiation for that?
         DR. KRESS:  It's the iodine.
         DR. SEALE:  Your other question, I mean, the radiation
     certainly does affect the water chemistry.  That's basically why you
     have a hydrogen over-pressure, to make sure that you don't generate
     undesirable species because of the radiolysis.  You suppress that as
     part of the water chemistry.
         DR. KRESS:  Yes, but it's so low that it wouldn't matter
     anyway.
     DR. SEALE:  Not the radiolysis product you generate in the core.  When
     you're in a BWR and you're not suppressing, you get a very different
     chemistry.  Not in your concern, but in the corrosion person's concern,
     it generates a very different corrosive environment, depending on
     whether he can or cannot suppress those radiolysis products in a PWR.
         DR. MILLER:  So in a PWR, it's not a concern.  In a BWR, it
     might be a different situation.
         MR. PARCZEWSKI:  Actually, the iodine, radioactive iodine,
     which is dissolved in the sump, can be controlled by keeping pH in the
     sump water about seven, because then the iodine is kept in ionic state
     and, of course, then it's not released.  So there is a control of
     iodine, radioactive iodine in the water.
         DR. KRESS:  Yes.  But that has little to do with the
     corrosion issue.
         DR. SEALE:  It's a different issue.
         DR. KRESS:  It's a different issue.
         MR. MUNSON:  Continuing with chemistry programs for
     component cooling and service water systems.  These are the aging
     effects listed here.  For the chemistry programs, there are no open
     items, no confirmatory items or license renewal issues.
         DR. SHACK:  Can I just go back to the fatigue program for a
     second?  When they're monitoring fatigue, they're monitoring these
     components for some sort of bounding.  I mean, they're not monitoring
     every location, obviously, so they pick bounding locations.
         Are these bounding locations for the things that were
     considered in their original design analysis or have they incorporated
     industry experience that you're getting fatigue, for example, in
     feedwater lines that you really didn't anticipate in the original
     fatigue analysis?  Are you bounding those, also?
         MR. FAIR:  Both are handled.  The answer is correct.  Most
     of the locations are based on the original fatigue analysis.  However,
     there were some additional items added, one of them being steam
     generator nozzles that were a product of industry experience, and they
     did some fairly detailed monitoring at the plant to come up with their
     analysis of those nozzles.
         DR. SHACK:  So they think they've bounded all those
     locations then with the components.
         MR. FAIR:  Yes.  They think they've bounded the worst case. 
     The monitoring program, as you say, is a sampling program and it relies
     on picking the worst cases for the sampling.
         DR. SEALE:  Let me make sure I understand what we're saying
     and the code words that we're using and all.
         I recognize this may not be within the narrow scope of the
     review of the BG&E application.  But nonetheless, there are pilot
     studies that have been ongoing having to do with in-service inspection
     that are related to fatigue problems in piping and stress corrosion.
         And there are presently applications before the Commission
     to go to a risk-informed inspection program where the sites of the
     inspections are picked on the basis of experience with previous problems
     with systems.
         If I read your comments correctly, I gather that the
     positions that you have identified or that the applicant has identified
     here as the places where they're doing their fatigue analysis encompass
     not only the kinds of fatigue locations that were in their original
     in-service inspection, but also at least some selection of the results
     of the experience that has been gained over the years of other locations
     where fatigue has, in fact, been observed.
         Now, that doesn't mean that BG&E is asking to go to a
     risk-informed in-service inspection program, but they are using some of
     those results in picking the sites for doing their fatigue monitoring. 
     Is that correct?
         MR. FAIR:  I believe they're using the experience of past
     problems to pick some of their selected sites.  I don't know that risk
     was factored into any of those decisions.
         MR. DOROSHUK:  This is Barth Doroshuk, from BGE.  We
     incorporate operating experience into locations that we have in our
     fatigue program either as an ongoing monitoring point or special
     analysis.  I'm not sure that we care if it's a risk-informed location. 
     We're more concerned about suspicion that there is damage occurring.
         So we do not use a risk-informed type of approach when we
     think there is something going wrong.  The locations in the fatigue
     program would not be removed from the program as a result of using a
     risk-informed approach.  If there was to be a removal of a point in the
     monitoring program, it would have to be reviewed against 50.59
     requirements to ensure that the design basis requirements were still
     being met.
         So even though we are supportive of using risk-informed ISI,
     we do not use that type of insight to remove locations from the
     monitoring without proper evaluation.
         DR. SEALE:  If I may make a comment.  The obverse of that
     coin is that if the ISI -- if the risk-informed ISI programs -- that is,
     the programs that are based on some sort of risk analysis -- don't pick
     up the, quote, experience identified areas of concern that you have
     selected to add to your program, then there is something wrong with that
     risk-informed analysis.  That's the first point.
         The second point is that I assume that whatever we're doing
     in no way prejudices your option down the road to come in and request a
     modification of your licensing basis to allow you to go to a
     risk-informed in-service inspection program.
         But that's completely removed from and independent of
     whatever the concerns are that we have right here.
         MR. DOROSHUK:  I agree with you.
         DR. SEALE:  Okay.
         MR. DOROSHUK:  Maintaining the configuration and being able
     to maintain the flexibility to change as you get insight is an
     appropriate thing to do and we would -- we believe the commitments that
     are being put in the application as part of the licensing basis would be
     modifiable if we did gain the flip-side, which is positive experience,
     as well.
         So we don't think we're handcuffing ourselves at this point.
         DR. SEALE:  It isn't your intent to do so.
         MR. DOROSHUK:  No, sir.
         MR. STROSNIDER:  This is Jack Strosnider, Director of
     Division of Engineering.  I'd just like to confirm that, number one, I
     agree completely with what you said with regard to risk-informed
     inspection programs.  Our expectation, as you're aware, we're working
     through these pilots now, is that when done properly, they would
     identify the more likely locations of failure, that that's part of the
     consideration there.
         So we would expect that that would be the outcome of a
     risk-informed program.
         Secondly, yes, but nothing that's happening in this
     amendment is going to preclude someone from proposing a risk-informed
     inspection program down the road.
         The final comment I want to make, which I just think might
     help in this -- in understanding this section, is to recognize that
     going through a number of programs here and if we talk about a chemistry
     program, for example, when you get to a particular system, you may not
     be relying solely on that chemistry program to manage degradation.
         In this case, this fatigue monitoring is really monitoring
     to compare to the design basis, the usage factor type consideration. 
     For certain systems, there will also be, on top of that, some Section 11
     or other inspections that are performed.
         So I think it's important to recognize that when you talk
     about fatigue monitoring, this is not solely what's being relied on to
     manage the aging mechanisms.
         Like I said, when you get into the specific systems, you'll
     see that, well, yeah, you credit chemistry, you credit perhaps
     in-service inspection or whatever the appropriate combinations are that
     will effectively manage the mechanism.
         MR. MUNSON:  The next common aging management program is
     entitled structure and system walkdowns.  These are walkdowns of
     structures and systems and components so that any abnormal or degraded
     condition will be identified and documented, with the goal that
     corrective actions are to be taken before abnormal or degraded
     conditions proceed to the failure of the system or structure.
         Corrective actions are taken in accordance with the
     licensee's corrective action program, which is QL2, and at a minimum,
     these walkdowns should occur at least once every six years for every
     structure and system.
         The walkdowns are to be performed on these following
     structures and systems, component supports, primary containment
     structures, all the way through to safety injection systems, instrument
     lines.  I won't go through the whole list.
         DR. SEALE:  Here, again, you talk about what's going to
     happen in the future.  It's the "going to be".  What about the "has
     been?" I mean, you haven't been boycotting the inside of the plant for
     the last 20 years.  You've been walking around in there up till now and
     if you found any water on the floor or whatever the expression might be,
     you've identified the problem and you've taken corrective action.
         And I would assume that there would be some corporate memory
     so that those actions would show up in this program, too.
         MR. HEIBEL:  This is Dick Heibel, Baltimore Gas & Electric. 
     You're exactly correct.  After every outage, the system engineers
     perform system walkdowns to ensure that the systems are ready to start
     up.  There's also PMs that require walkdowns at this six-year frequency
     specifically to look at degradation of the system.  But all of these
     systems will get a walkdown by the system engineer at least every two
     years.
         Additionally, the operators have to perform valve lineups
     after every outage and which valve lineups they do and don't perform is
     controlled by a procedure that we require them, at a minimum, every two
     cycles, to do an entire valve lineup.
         DR. SEALE:  But in addition to that, if you've had any
     experience in the past, I would assume that somehow you've factored that
     into your assessment.
         MR. HEIBEL:  Exactly correct.
         MR. STROSNIDER:  This is Jack Strosnider.  Just to add,
     again, part of the staff's review is to look at operating experience. 
     We asked questions in that area and the submittal included information
     on prior experience.  So that is taken into consideration with regard to
     what you might expect in the future or what corrective actions have been
     taken that might need to continue.  So that is a specific part of the
     review.
         DR. UHRIG:  In other words, that's just a continuation of
     the existing program as far as walkdowns are concerned.
         MR. GRIMES:  This is Chris Grimes.  Except to the extent
     that we look at whether or not the walkdown is addressing a particular
     aging effect of concern.  I think some of the walkdowns have increased
     their scope or increased -- or changed the guidance to the plant
     personnel who are going to be looking for particular kinds of
     degradation.
         DR. SHACK:  That's the 101 modified procedures we saw
     yesterday or something like that.
         MR. STROSNIDER:  In the broader context, the question is
     what's the operating experience not just for this unit, but even
     industry-wide, and does your program, whether it's a walkdown program or
     whatever, does it have the right attributes in it to address that
     experience.
         Part of this gets into identifying what are the plausible
     aging mechanisms based on looking at experience.
         DR. FONTANA:  How many walkdowns have been done on six-year
     intervals so far?  The question that I'm getting at is, does six years
     appear to be a good number.
         MR. DOROSHUK:  This is Barth Doroshuk, from BGE.  The six
     years is for structures only.  As Dick Heibel pointed out, these
     walkdowns occur when you get down at a system level.  Each system
     engineer is required to walk down all or part of his system on a monthly
     basis, unless it's negotiated differently with his supervisor.
         So this is a much more frequent activity than is represented
     here, from a detail standpoint.  In addition, these activities -- these
     walkdowns have been formally in place for over ten years, that these
     procedures or guidelines have been in place and have been, of course,
     maturing with the results of the inspections.
         So the short answer is yes, we do think it's effective, and,
     of course, we'll continue to refine the program as we conduct the
     walkdowns.  And it has been refined for license renewal in particular,
     as Mr. Grimes pointed out.
         DR. BONACA:  Just a question.  Operating experience is also
     used to reduce the number of components which are within the aging
     management program, correct?  For example, I was looking at the
     instrument lines, where an evaluation of the failures that have occurred
     over 25 years, and because of the categorization that these are due to
     poor, inadequate maintenance, a lot of this lining is removed from the
     list because we haven't seen aging issues affecting the lines.  Is it
     correct?
         MR. GRIMES:  This is Chris Grimes.  I believe that the
     characterization is in terms of whether or not there is a reason to
     believe that there is an aging effect that needs to be managed for those
     lines.
         DR. BONACA:  I understand that.
         MR. GRIMES:  As opposed to removing it, it was more is there
     a class of instrument line that requires particular attention and an
     aging management program.
         DR. BONACA:  Exactly.  So I understood that correctly.  The
     question I had is that clearly we -- this is projecting that the future
     will be like has been for the past 25 years.  There may be some
     incipient aging effect we haven't seen yet, either because we go to
     extended life or because there are some phenomena that don't manifest
     themselves -- haven't manifest themselves yet.
         How do we -- how do the programs address these issues? 
     Where you don't have -- when looking at certain areas because your
     program doesn't lead you to do that, you're waiting for the failure of
     the component or -- I'm trying to understand how does this get done.
         MR. STROSNIDER:  Operating experience is one part of the
     review, but it is not considered, in and of itself, sufficient to define
     whether you need a program in the future.
         You also look, based from your knowledge of the type of
     degradation mechanisms that might be anticipated, you look at research
     results and then you -- so you look at the potential basically, I guess,
     just from an engineering or scientific basis of what potential
     mechanisms might show up and you look for programs to address those.
         But there are things that are covered in these programs that
     have not been observed in operating reactors, but there is an
     anticipation they could come about.  So you look at them.
         So I think the important point is, yes, operating experience
     is considered, but it's not the sole basis for defining the program.
         DR. BONACA:  Since we're not looking at risk issues or risk
     importance of components in this program, so there could be some
     component there that because we haven't seen any aging effect, is not
     being inspected specifically or looked at.  Yet, it is risk significant.
         Is it possible that we have the combination there?
         MR. GRIMES:  We went back to look to see whether or not
     there were any risk-significant components that were passive that
     weren't otherwise captured by the deterministic basis.  So that's a
     feature of the review, is to determine whether or not the aging
     management programs are sufficiently comprehensive.
         I'd also like to add to what Jack said, that you mentioned
     the potential that there might be incipient aging effects that have not
     yet been manifest.  The concept about having the current licensing basis
     and the existing regulatory process carry over is a recognition that as
     we learn things in the future and if we identify a new aging effect, and
     we would like to think that's unlikely because we did a -- we've got
     about 15 years worth of research that's looked at what are plausible
     aging effects, what are applicable aging effects, and we've been
     reasonably conservative and the applicant has been reasonably
     conservative about attaching aging effects to things for which, as Jack
     mentioned, haven't been observed yet, but in anticipation, they might
     occur, we'll make sure that inspection and maintenance are appropriate.
         DR. BONACA:  But you see what I was going at.  So you have
     comfort in your review that the programs they have implemented will
     allow for early detection of degradation in certain components which are
     passive, but are not part of what is recognized today as being under an
     aging program.
         MR. STROSNIDER:  Correct.  And I think we have to
     acknowledge, we don't have a crystal ball, there's been a lot of
     research done.  We're addressing those issues that we consider
     plausible, things that could happen that we need to look at.    
         But the other important thing is that these walkdowns and
     the plant programs, you heard the sort of frequency, there are
     indicators of -- if new problems show up, these program walkdowns and
     other inspection activities and stuff will show that that's occurring.
         Then we do gain through operating experience and we'd have
     to factor that in as new issues show up.
         So when you go into the renewal period, some of the same
     programs and mechanisms that you use today for identifying unexpected
     problems will carry forward into the renewal period.
         But the attempt here is to address as much of what you think
     is plausible as you can.
         DR. BONACA:  I had a question yesterday.  I said that once
     the license is granted, it's a process that continues.  There is no
     further review, and then they accept that.
         The only question I had on the part of the staff is how is
     the staff planning to monitor, in the next 15 years, not only for this
     plant, but for the other plants, and see if what they thought was a
     sufficient basis for the license ten years from now is still going to be
     good, what have we learned from this process.
         I'm trying to understand how you guys are going to do that.
         MR. GRIMES:  We would intend to do it better than we have in
     the past, actually, in terms of the programs that we have to change the
     oversight process, that looks at plant performance relative to its
     licensing basis on a day-to-day basis, and to constantly challenge
     whether or not the licensing basis is adequately addressing safety.
         We have now developed a program that's going to look at
     plant performance indicators relative to our expectations about plant
     performance and that includes program attributes, whether or not the
     programs are effective, are the events that are occurring -- do they
     indicate that there is some weakness in either the design or the
     operation of the facility.
         So to get back to your original question, we're working
     towards a conclusion that is based on comfort that actions have been or
     will be taken, using the language in 54.29, about the Commission's
     decision basis, that includes a continuation of feedback mechanism that
     learns from experience, adjusts as new information comes along, but is
     constantly looking in areas that are risk-significant or materially
     significant; that is, like fatigue, looking at potential damage
     locations.
         So we're confident that the processes will work to carry
     forward these conclusions and continually challenge them.
         DR. BONACA:  And I appreciate that.  I'm only saying that
     this is a rule which has a special opportunity for being tested before
     it really goes into play, and that it will be many years before this
     plant achieves its 40-year life and walks into the life extension.
         I think because of that, there has to be a sensitivity and
     monitoring almost itself as a rule, because certainly ten years from
     now, you're going to find that the presumptions which were in the rule
     and in this review were pretty much correct.  We haven't learned
     anything else that said we really didn't have our act together.
         So that's an important point, I think, that there should be
     some strategy at the NRC level to learn these lessons and monitor.
         MR. GRIMES:  We agree.
         DR. BONACA:  And that would give the comfort also to the
     public and everybody else that these programs are thorough and have a
     foundation.  So there is an opportunity.
         MR. MUNSON:  For the structure and systems walkdown, there
     is one confirmatory item.  The walkdowns have been amended to detect the
     aging effects of reinforced concrete structures.  Previously, that was
     overlooked.
         The next aging management program is the boric acid
     inspection program.  This program manages the general corrosion of the
     carbon and alloy steels exposed to concentrated boric acid.  The program
     involves periodic walkdowns of borated systems to look for leakage and
     subsequent corrective actions to mitigate the effects of the
     concentrated boric acid corrosion.
         This program also manages general corrosion,
     erosion/corrosion, where, and stress corrosion cracking of various
     carbon steel reactor pressure vessel components and the program also
     manages, in part, primary water stress corrosion cracking of alloy-600
     components.
         The program is applied to the following list of systems and
     structures.
         The open item for this boric acid inspection program is it
     does not provide for removing interference; thus, some internal portions
     of the reactor vessel cooling shroud that harbor pockets of liquid may
     be inaccessible for visual inspection.
         The confirmatory item is that the inspection scope is to be
     expanded to include reactor vessel cooling shroud anchorage to reactor
     vessel head and reactor vessel cooling shroud structural support
     members.
         DR. SEALE:  I don't quite understand your open item.  You
     recognize that some areas are not accessible for inspection as they are
     presently configured.
         MS. COFFIN:  That's right.  This is Stephanie Coffin.
         DR. SEALE:  You're going to live with that or are you doing
     something to --
         MS. COFFIN:  No.  It's an open item for the applicant to
     address.
         DR. SEALE:  I see.  So they're going to come up with
     something which you will then assess for its adequacy to remedy that.
         MS. COFFIN:  That's right.
         DR. SEALE:  Okay.
         MR. MUNSON:  The next common aging management program is the
     corrective action program and this corrective action -- the program is
     really one of four phases of the maintenance strategy used by BG&E to
     manage the effects of aging.  The four phases are discovery, assessment
     analysis, corrective action, and confirmation document.
         The current licensing basis provides for the assessment,
     analysis and corrective action and confirmation documentation phases
     through the implementation of their corrective action program, which is
     the QL2 corrective action program.
         The processes and activities encompassed by QL2 are
     conducted pursuant to the requirements of Appendix B to 10 CFR Part 50
     and cover all structures and components subject to aging management
     review, and the staff determined that this approach is acceptable to
     address the population of safety-related structures and components
     subject to aging management review.
         There are no open items for the corrective actions program.
         There is a confirmatory item, a description should be
     included in the UFSAR supplement and for the applicant's -- and/or the
     applicant's quality assurance policy for the Calvert Cliffs nuclear
     power plant to confirm that BG&E Appendix B program also applies to
     non-safety-related structures and components that are subject to aging
     management review for license renewal, so that these programs can be
     controlled.
         DR. UHRIG:  Is this an expansion of QA program?
         MR. SOLORIO:  This is Dave Solorio.  I'm sorry.  When you
     say expansion of the QA program.  This is an existing program.  It's a
     very mature program that BG&E has had.
         DR. UHRIG:  But it's going out to new components, is it not?
         MR. SOLORIO:  Well, you're shaking your head, Barth, but
     before I -- so correct me if I'm wrong, but there are certain components
     that BG&E has said are subject to an AMR that were not safety-related
     and I believe BG&E will say that some of those components have always
     been part of their QL2 program.
         But the staff's concern was that the documentation, either
     the QL2 program or the UFSAR, did not specifically call out those
     components, non-safety-related components, to be within the scope of the
     QL2 program.  Therefore, the staff is just asking for that to be
     committed to.
         MR. DOROSHUK:  This is Barth Doroshuk, from Baltimore Gas &
     Electric.  This is not an expansion of the quality assurance program. 
     All the components on-site, whether they be safety-related or
     non-safety-related, are subject to the corrective action program and
     controls of Appendix B.
         What this confirmatory item does -- so in other words, if we
     find something wrong, we write an issue report and we walk through the
     licensing basis checks to check operability issues, irregardless of its
     classification.
         But what this is going to do is recognize that there is an
     aging dimension that may be needed to be clarified just for -- I guess
     we talked here yesterday about the culture and changing behaviors, just
     to make sure that that's captured.
         DR. UHRIG:  Thank you.
         MR. HEIBEL:  This is Dick Heibel.  To put a little more
     definition.  We would consider it an expansion to the program if it's
     being subject to QL2, the corrective action program would change a
     component from being non-safety-related to safety-related.  We don't
     intend to change the designation from non-safety-related to
     safety-related.  But it will still be subject to the -- the entire plant
     is subject to the corrective action program.
         MR. MUNSON:  The final common aging management program is
     the ARDI program.  These are one-time inspections to verify that an
     age-related degradation mechanism does not need to be managed for the
     period of extended operation or to verify the effectiveness of an
     existing separate preventive or mitigative type program.
         The ARDI is applied to a number of different systems.
         DR. SEALE:  That's a pretty long list.  Basically, you're
     hoping that plants don't develop post-40-year geriatric diseases, like
     arthritis and some of these other things that some of us have.
         MR. DOROSHUK:  Yes, sir.  We agree with you.  This probably
     goes right to the question earlier on are we trying -- do we have a
     crystal ball.
         These aging effects that this program is being employed on
     are on the periphery of -- we haven't seen them yet, but, again, we set
     the thresholds very low and we're going to go out and do these
     confirmations.  So hopefully these types of activities do try to take
     into account Mr. Bonaca's concern.
         DR. SEALE:  Well, when you come up with your crystal ball,
     maybe someone will come up with a silver bullet to take care of some of
     our other problems, too.
         MR. MUNSON:  The open item for ARDI is the staff has
     identified some age-related degradation mechanisms that we feel require
     periodic regular inspections and such as for the verification of
     acceptable condition of codings and verification that corrosion is not
     occurring due to leakage.
         So there were some differences that we had with the licensee
     with respect to whether ARDI should be applied to different systems.
         DR. SEALE:  So basically, you moved them into a more
     disciplined or scheduled inspection mode, right?
         MS. COFFIN:  If we thought that a one-time inspection wasn't
     enough, then we asked them to do something more regular.
         DR. SHACK:  How many of these ARDIs are open to question
     now?
         MS. COFFIN:  I don't understand what you mean.
         DR. SHACK:  I assume that -- it says that they're not
     acceptable for some of these.
         MS. COFFIN:  That probably affects about -- I'd have to
     check -- about three to five systems.
         DR. SHACK:  Three to five.
         MS. COFFIN:  Out of --
         DR. SEALE:  That 15.
         MS. COFFIN:  Yes.
         DR. FONTANA:  What specifically?  Is there one or two that
     you can --
         MS. COFFIN:  You want an example?
         DR. FONTANA:  Yes.
         MS. COFFIN:  One example that the staff identified was for
     the saltwater system, they are going to rely on ARDI to verify corrosion
     of carbon steel components due to leakage through the system and the
     staff believes that since leakage can happen anytime throughout the
     remainder of the plant's life, doing a one-time inspection really is not
     going to work for that aging effect, and that's something that should be
     going into the system walkdown kind of a procedure.
         Actually, the applicant has decided that that's how they're
     going to do it and that's more of a confirmatory item for that
     particular system that I gave you an example.
         DR. SHACK:  How about the service water?  That's like a
     long-shot for a one-shot inspection.
         MS. COFFIN:  I'd have to look at the application to look at
     specifically what kind of aging effect they're particularly addressing. 
     A lot of these things, the applicant gave us a lot of information on the
     design and the environment.  That made the staff feel very comfortable
     that if there is an aging effect, it's going to be very minimal, and
     they planned on doing these inspections to verify that assumption, and,
     of course, if that assumption is incorrect, they're going to be
     implementing their corrective action program.
         MR. MUNSON:  That's the conclusion of Section 3.1.
         DR. FONTANA:  Thank you.  Any additional questions on this
     section?
         [No response.]
         DR. FONTANA:  We'll go on to the next one.
         DR. SHACK:  John, just before you leave.  Have you decided
     what happens if, in fact, they can't manage to keep something below the
     line?
         MR. FAIR:  I'm not leaving.  But if you were excusing me,
     I'll be glad to go.
         DR. SEALE:  No.  In a word.
         MR. FAIR:  Yes.  They would have to write a problem
     identification report and we had a discussion of this, which they
     haven't -- there is no specific action they can determine ahead of time,
     other than it would probably require a look at an expanded scope of
     components, since this is a sampling procedure, and they have several
     options for corrective actions; either do some more analyses, propose
     some additional inspections, or maybe go as far as replacement of the
     component.
         MS. COFFIN:  I just want to point out that all these common
     programs that Cliff just went over today, you're going to be seeing them
     again and again throughout the presentations, and I don't think most of
     the presenters are planning to spend a lot of time on all those common
     programs, since we already went over them.
         MR. ELLIOT:  My name is Barry Elliot.  I'm with the
     Materials and Chemical Engineering Branch of NRR, Division of
     Engineering.  I'm going to be discussing our review of the reactor
     vessel, the internals and the reactor coolant system.
         The applicant has 19 programs to manage the aging effects of
     the reactor vessel, the internals and the reactor coolant system.  Nine
     are existing programs, five are modified -- are existing programs that
     have been modified, and five are new programs.
         I don't intend to go through all 19 programs.  I'm just
     going to take and highlight what I consider the most important ones. 
     Some of them I just listened to and I heard a lot of discussion.  So
     you're going to only hear a brief description of the program.
         The first program is the water chemistry program.  For the
     reactor coolant system, it established limits on impurities, such as
     fluorides, chlorides, hydrogen and dissolved oxygen.  It measures
     primary coolant parameters, such as conductivity and pH.
         The water chemistry program is used to assure the reactor
     coolant system will not be subject to corrosion.  It's an existing
     program and will continue into the license renewal term.
         The next program is the eddy current examination program for
     the steam generator tubing.  It's an existing program and also will
     continue into the license renewal stage.  It's used to detect denting,
     where stress corrosion cracking and pitting.
         The third program is the in-service inspection program and
     it picked -- the inspection is a non-destructive examination and a
     pressure test to determine critical locations and components to manage
     the effects or where erosion, corrosion and cracking.
         This is an existing program.  However, as part of our
     review, based on operating experience, based on knowledge of aging
     mechanisms, we have recommended additions to these programs and
     modifications to these programs.
         I'll be talking about, later on, the modifications to the
     ISI program for the internals and the open issues, in particular, there
     is a series of modifications we are recommending be included or at least
     right now are open items that might need -- we might need to make
     adjustments to the ISI program.
         DR. SEALE:  Barry, just out of curiosity, are all the cooper
     components gone or copper alloy components gone from their secondary
     system, so they can truly optimize their water chemistry?
         MR. ELLIOT:  I don't have an answer to that.
         MS. COLLINS:  Especially as it affects steam generator
     tubes.
         MR. ELLIOT:  The next program I'm going to talk about is the
     reactor vessel material surveillance program.  This program is an
     interesting one for Calvert Cliffs, because they have one of the best
     programs in the United States.
         In this program, generally, materials are removed from
     capsules and periodically tested to monitor the effect of neutron
     radiation in the environment.  In the case of Calvert Cliffs, they
     started with six capsules in their vessel.  They've tested -- each
     vessel.  They have tested two from each vessel.  So they have four
     capsules remaining from their original program.
         They have gone out and added to this program.  They have
     added supplementary capsules that they got material from Shoreham.  It
     turns out Shoreham welds were some of the critical welds in Calvert
     Cliffs Unit 1, also.
         In addition, it turns out that McGuire also has material
     that is related to Calvert Cliffs, so that using the McGuire data to
     monitor and calculate the neutron irradiation embrittlement for the
     Calvert Cliffs vessel.
         As far as the license renewal -- that's the existing
     program.  We are concerned about two things, generically, in license
     renewal for vessel surveillance programs.  First, that the data bound
     the neutron fluence for the license renewal period and the second thing
     is that the data that is gathered, and, in many cases, it could be
     gathered before the license renewal period ever begins, that it be
     applicable to the operation of the plant during the license renewal
     period.
         In this case, I don't think it will be a problem for
     Calvert, because although we've explained this to them, that if they
     take -- there are two things they have to do.  They have to modify their
     program.
     First, they have to extend the surveillance schedule to include capsules
     out to the neutron fluence at the end of the license renewal period. 
     Second, if they have early withdrawal of capsules, they must establish
     limits on their operations as far as temperature, flux, spectrum --
     that's about all I can think of right now -- that they must operate the
     plant to and that the surveillance data is useful for.
         If they go outside that bound, then they would have to come
     back to us and either restart the surveillance program, make adjustments
     to the surveillance program, or tell us how they're going to adjust
     their irradiation embrittlement estimates.
         But I don't think this will be a problem for Calvert.  They
     have a lot of capsules and they should be able to monitor the radiation. 
     That's neutron irradiation embrittlement.
         The next is thermal embrittlement, cast stainless steel
     components.
         DR. SHACK:  Just a quick question.  On that one, do they
     have lots of margin on their PTS?
         MR. ELLIOT:  Yes.  Well, it's not that they have -- they
     have -- but I could tell you, the PTS values, they're below the
     screening criteria at end of license and they're committed, as part of
     the regulations, to monitor this.  In fact, six months ago, they
     submitted a new estimate and they're still -- and their estimate
     included the license renewal period and they're significantly below the
     screening criteria for both units.
         DR. SHACK:  I take it that they're even still at 50 foot
     pounds for the --
         MR. ELLIOT:  Fifty foot pounds upper shelf energy.  They did
     an analysis that shows that at the end of the license renewal period,
     they'll be just above 50 foot pounds, like 51 or something like that. 
     This will be monitored as part of the vessel surveillance program.
         The thermal embrittlement portion is a new program, the cast
     austenitic stainless steel program, and this program is to identify cast
     stainless steel materials that are susceptible to thermal embrittlement
     based on the percentage of ferrite, the amount of molibnimum, and the
     casting methodology.
         The criterion-associated analyses are documented in EPRI
     topical report 106-092.  The criteria was developed using measured and
     saturation lower bound JR curves.  The saturation lower bound curves
     were developed by Argonne Laboratory from tests on age, cast stainless
     steel material.  In all cases, the Argonne prediction curves were
     equivalent or conservative compared to the measured values.
         Staff reviewed the topical report and submitted an
     evaluation, I think, to NEI and we've discussed it with Calvert Cliffs. 
     There are some modifications that are necessary to the program.  A few
     of the -- one criteria has to be changed.  The method of calculating
     ferrite has to be a particular way and the inspection method of --
     should we be recommending that it be qualified to Appendix 8, if they
     can develop techniques that can qualify this.
         This materially is very hard to ultrasonically inspect, but
     we're hoping that the industry will put an effort here and be able to
     qualify an inspection procedure for this type of material.
         DR. SHACK:  I'm curious about that, because it had comments
     about niobium in the stainless.
         MR. ELLIOT:  Yes.  One of the things we said is that if
     there's any niobium in the cast stainless -- these are part of the
     limits.  We modified the limit on -- we modify a ferrite limit for high
     molibnimum, but if there is any niobium in the cast stainless steel,
     then this criteria would not apply, and the material would have to be
     inspected.
         DR. SHACK:  Did they really have enough foresight to analyze
     for niobium in their cast stainless?
         MR. ELLIOT:  They said they're going to look into it.
         MR. BALDWIN:  Marvin Baldwin, with Baltimore Gas & Electric. 
     Cast was one of the areas we looked at very closely.  We reviewed the
     certified material test reports that we got from Combustion Engineering,
     from fabrication, and determined that we have no niobium.  Niobium was
     neither specified in the fabrication of any of the cast components that
     are in the RCS pressure boundary.
         DR. SHACK:  I'm sure it wasn't specified, but was it
     analyzed to find out if it got in some other way?
         MR. BALDWIN:  I recall seeing niobium on the data sheets for
     some of the CMTRs.  I can't say that I saw them for all, but what I did
     was I -- I'm not a metallurgist, but I know how to look at documentation
     to see what's there, and I did see NB or, I think it was called
     something different before, I forget what it was, and I did see those on
     some, where there were blanks or no numbers.
         DR. SEALE:  I'm not sure I understand where this niobium is
     supposed to be.  What if you went to a different cladding material?
         MR. ELLIOT:  Excuse me.  This is not cladding.  This is cast
     austenitic stainless steel.
         DR. SEALE:  That's what I said.  I didn't know where the
     niobium was supposed to be.  So you've answered my question.
         MR. ELLIOT:  Okay.
         DR. SHACK:  It's not supposed to be there.
         MR. ELLIOT:  Yes, it's not supposed to be there.
     DR. SEALE:  I know, but if we talk about high burn-up fuels and the
     possibility of modifying cladding.
         MR. ELLIOT:  This issue, you could -- I mean, Bill knows a
     lot about this.
         DR. SEALE:  I'm sure he does.
         MR. ELLIOT:  I think the French reactors, I think, specified
     niobium.
         DR. SHACK:  No, they didn't, but they got it.
         MR. ELLIOT:  They got it.  And so that's why this was a
     concern that was raised and specifically if there is niobium, then all
     the criteria don't apply and the materials would have to be inspected.
         The next program is a modification to the ISI program.  It's
     the internals inspection.  It's the internals program.  I was listening
     before about here is a case where the licensee says really there is no
     problem, but the staff has decided that there is a potential problem in
     the future.
         In this case, the internals are subject to high radiation
     and what we're concerned about here is radiation-assisted stress
     corrosion cracking as well as just general embrittlement of the
     stainless steel.
         Another part of this is that we also have the cast stainless
     components also in this internals.  So not only are they going to have
     the neutron embrittlement, but they're also going to have the thermal
     embrittlement of those components.
         At the moment, there is very limited data available for
     neutron embrittlement of stainless steel.  The applicant is
     participating in an industry program to develop that data.
         However, until that data has gotten analyzed, we have
     decided that the ISI program needs to be enhanced.  The current program
     is to do a VT-3.  Our experience with boiling water reactors is that a
     VT-3 will not discover the type of cracks that you can get from IASEC
     and, therefore, an enhanced VT-1 examination is going to be required for
     the limiting component or limiting locations in the internals.
         The licensee has taken this to heart, finally, and they have
     identified the inside surface of the re-entrant corners of the core
     barrel as a location that is going to be VT-1 -- enhanced VT-1
     inspected.  That has the highest combination of stresses, because it's a
     welded corner.  It's the closest to the core and it also has high
     temperatures.  On one side, it has the hot leg temperature; the other
     side, the cold leg temperature.
         That takes care -- that's the stainless steel and welds. 
     Now, we're also concerned about the cast stainless steel components. 
     There are two cast stainless steel components.  The CE shroud assembly
     tubes and the core support columns.
         In this case, we are concerned about two things; thermal
     embrittlement, like I said, and the neutron embrittlement.  There is no
     data available for this type of problem.  So, again, we asked the
     licensee to do an analysis or to do the VT-1 inspection, enhanced VT-1
     inspection of these components.
         Now, the analysis is -- this is how we're running the --
     this is how we're doing -- we asked them to do the analysis.  We
     established criteria for neutron fluents; that is, ten to the 17th
     neutrons per centimeter squared.
         If the fluents receive, at the end of the license period,
     for any of these components, are above that criteria, it would be
     considered a high radiation area for the program and the only way the
     components would not be inspected would be if VT-3 -- would return to a
     VT-3 -- is if they could demonstrate that the loads on this thing during
     all ASME -- all accident conditions is either compressive or very low. 
     Otherwise, if it has a high fluence, it would get an enhanced VT-1
     examination.
         The second part of the criteria is for low fluents
     components.  If it turns out they have low fluents; that is, lower than
     ten to the 17th.  In that case, we would think that the neutron
     irradiation embrittlement would not be a factor.  The only factor to be
     considered then would be the thermal embrittlement.
         There, they can go -- they would have to show that they meet
     the thermal embrittlement criteria we talked about and we modified for
     the cast austenitic stainless steels.  If they could show that, then the
     inspection could be reduced to a VT-3.
         That's our modification there.
         The next program is the alloy-600 program.  This is for the
     primary system.  The alloy-600 program is a program to manage primary
     water stress corrosion cracking for pressure boundary components and it
     looks like the most susceptible, most safety-significant components.
         This is an existing program.  It basically ranks the
     alloy-600 components based upon the residual and operating stresses,
     operating time, and material heat treatment.  It turned out, as part of
     this review, that in Unit 1, the most susceptible component is the vapor
     space instrument nozzle in the pressurizer -- four vapor space
     instrument nozzles in the pressurizer heads, and they will be replaced
     during the -- with alloy-690 during the 2000-year outage.
         In Unit 2, it turned out that the limiting, most susceptible
     material was the pressurizer heater sleeves, and these materials were
     replaced with 690 in the 1989-1990.
         The alloy-600 program has not identified any other -- at
     this time, any other materials that need replacement.  The alloy-600
     program, we use VT-1 and VT-2 to detect leakage and to determine whether
     there is a problem with the alloy-600 -- the other alloy-600 components.
         The fourth, the last program I was going to talk about,
     which we discussed already, was the fatigue management program for the
     primary system.  The fatigue monitoring program tracks the low cycle
     fatigue usage of critical reactor coolant system components.
         The program has been modified to include reactor coolant
     pumps, motor-operated valves, some pressurizer components, control of
     drive mechanisms, reactor vessel level monitoring system components.
         DR. SHACK:  The other slide said there were no open issues.
         MR. ELLIOT:  I know.  That's not true.
         MR. FAIR:  Could I help you with that?  It's just the way
     that the -- we constructed the SE.  As far as the program itself, we
     didn't have a problem with the way it was being implemented, and that
     is, tracking the worst components and taking corrective actions.
         In terms of the open items in this section, they haven't
     completely evaluated all the components to determine if there were other
     locations that needed to be monitored.  So that's one of the open items.
         MR. ELLIOT:  We have several open items.  Some of these may
     require modifications to the in-service inspection program.  The first
     one is that -- this is not a modification, but that the applicant should
     credit tech spec limits of steam generator leakage as part of its aging
     management program.  That's just we think that that should be done.
         We think there is a program needed to manage stress
     corrosion cracking of the reactor pressure vessel head closure seal
     leakage detection line.  This line has had, in the past, stress
     corrosion cracking.
         We think there is a program needed to manage the cracking of
     pressurizer heads and shelves, in particular, the cladding.  We've had
     cracking in the cladding that has gone through the cladding into the
     base metal in Haddam Neck, around the -- and the area that needs to be
     looked at is the cladding around the surge nozzle and the heater welds. 
     Those are areas that have high thermal fatigue.
         DR. SHACK:  When we say this, does this mean you want them
     to add to this to the fatigue monitoring program?
         MR. ELLIOT:  No.
         DR. SHACK:  Is that what is implied here?
         MR. ELLIOT:  No.  In this case, we were negotiating what
     kind of inspection they can do to look and see whether or not we get any
     of the stress corrosion cracking of the clad in this region or thermal
     fatigue cracking of the clad in these regions.
         The program that might need modification would be the ISI
     program.
         Again, an ISI program is needed to manage cracking on the
     inside surface of small bore piping, including Inconel material.  The
     applicant must document their inspection methods to detect where, before
     it begins to compromise the function of the hold-down rings.
         DR. SHACK:  Again, the small bore piping, that's piping that
     now escapes Section 11 because of its size.  Is that the --
         MR. ELLIOT:  It doesn't escape it.  It has just a surface
     examination.  It doesn't have a volumetric, and so we don't see the
     inside surface.  So we need something more.
         We have a few confirmatory items.  The applicant is to
     revise the cast austenitic stainless steel program to include the
     criteria and methods of examination recommended by the staff.  The
     applicant is to revise the RPV materials surveillance program to include
     data and establish operating conditions for a period of extended
     operation, as I discussed.
         The applicant is to confirm the applicability of the
     alloy-600 CEDM program through the period of extended operation.  They
     have done the analysis for 40 years and now they have to confirm that
     the analysis is bounded for the 60 years.
         The applicant should document their conclusion that the
     control element shroud bolts do not perform a safety function, as
     described in 10 CFR 50.4, and, therefore, not subject to aging
     management review.  And the applicant is to document the operating
     stress for hold-down ring, to demonstrate that the hold-down ring is not
     subject to stress relaxation.
         The final thing is you talked about fatigue.  We have this
     as a confirmatory item.  This is the environmental effects as related to
     GSI-190 and the applicant must resolve the environmental fatigue issue
     for the period of extended operation, if the issue is not resolved
     generically prior to the end of the current license term.
         To summarize the license renewal issues that are critical
     for the vessel internals and reactor coolant system or internals
     embrittlement, which I discussed.  Thermal aging of cast austenitic
     stainless steel, which I discussed.  Vessel surveillance, which I
     discussed, the materials surveillance program, and fatigue is the
     fatigue monitoring program.
         That concludes my discussion.
         DR. FONTANA:  Thank you.
         DR. SHACK:  I guess I didn't quite -- is the implication of
     the bullet on the fatigue really that that one can stay open for a long
     time yet and you don't really need to resolve it until the end of the
     current license?
         MR. FAIR:  Yes, that's correct.  What we're relying on in
     that is we did the evaluation for current operating license, the 40-year
     evaluation, and we presented a finding that we didn't think we needed to
     backfit anything for the current operating license.
         The open issue was whether we could extend that conclusion
     into the renewed period of operation and we thought we needed additional
     work in order to make some safety conclusion in the renewed period.
         MR. GRIMES:  I'd like to add.  The treatment of this generic
     safety issue is the same approach that was used during the operating
     license stage in terms of the treatment of generic safety issues and
     recognizing that we weren't making a licensing decision at this point,
     with a pending issue unresolved.
         It is our expectation that the work that the Office of
     Research is doing is going to identify a resolution of this issue well
     before the plant reaches the end of the 40 years.
         It is a unique generic safety issue in that respect because
     we didn't have any other generic safety issues that bifurcated between
     40 years and the period of extended operation.
         But we've also recognized that we could tackle it on a
     plant-specific basis in much the same way that Barry described the way
     that we addressed these generic renewal issues for embrittlement and
     CASS and other things, on a plant-specific basis.
         But at this point, we're just trying to reconcile what it's
     going to take to resolve the generic safety issue is where the NRC staff
     thinks it ought to be expending its energy rather than trying to resolve
     it on a plant-by-plant basis.
         DR. FONTANA:  Any additional questions, comments?
         [No response.]
         DR. FONTANA:  Well, we're scheduled for a break now.  Thank
     you very much.  Let's be back here at 10:20.
         [Recess.]
         DR. FONTANA:  We will resume the meeting.  You had a
     20-minute break instead of a 15-minute break, so we're going to make it
     up later.
         MS. COFFIN:  Bill, I just wanted to get back to you; later
     today, when we go over the cooling systems, you're going to hear a lot
     more about the aging management programs, for example, for the service
     water system.  You'll see that ARDI is actually a very small component
     of the programs in effect for that system.
         My name is Stephanie Coffin.  I will be going over with you
     the engineered safety feature systems, which consist of the following
     three systems; the containment isolation group, the containment spray
     system, and the safety injection system.
         Just very quickly, the containment isolation group functions
     to prevent uncontrolled or unmonitored releases.  The containment spray
     system limits pressure -- the primary function is to limit pressure and
     temperature in the containment following an accident.  The safety
     injection system, the primary function is to supply emergency core
     cooling following a LOCA.
         Most of these programs you've seen before, because they are
     the common aging management programs that Cliff went over today.  But
     very briefly, all three systems have some carbon steel, no alloy steel
     components, and because they're located in containment, they could
     potentially be exposed to concentrated boric acid.  So to mitigate
     general corrosion of those components, and this is -- the applicant
     relies on its boric acid corrosion inspection program and we went over
     that earlier today.
         With regard to the internals of these components, the
     containment isolation group has a variety of internal environments,
     including treated water, well water and gaseous waste, and because of
     the design of the system and the internal environments, the applicant
     presented information that the corrosion effects are expected to be
     minimal and they're relying on ARDI and supplemented by some local leak
     rate testing of some valves in their programs to verify that, for the
     management of aging effects.  That would be crevice corrosion pitting,
     general corrosion.
         DR. SHACK:  What size is this piping that we're talking
     about here?
         MS. COFFIN:  I would have to look at the application.  It
     probably varies.  For the containment spray system, it's exposed
     internally to treated water and we're relying primarily on the
     applicant's chemistry program to mitigate the corrosive effects of that
     environment.
     Because there are some stagnant conditions in the system, because it's
     in a standby mode most of the time, the applicant has committed also to
     doing some age-related degradation inspection, the ARDI inspections, to
     check specifically in those areas.
         For the safety injection system, again, this system is
     exposed internally to treated water, and we're relying primarily on
     their chemistry controls to prevent corrosion of the internal services.
         There are some local leak rate tests and pumps and valves in
     their IST program that they also rely on to detect any degradation
     that's going on, supplemented by ARDI in some various portions of the
     system.
     One aging effect that's actually not on this chart is elastomer
     degradation and that's for a perimeter seal on their refueling water
     tank, and the -- because it's exposed to the element, the applicant
     identified some degradation that is possible for that seal and they're
     relying on their structure and system walkdowns to identify that.
         There are some modifications that they need to make to that
     program that I'm going to talk about in the next slide, because those
     are confirmatory items.
         For the safety injection system, there is something unique
     in that system in that they have experienced, at this plant, stress
     corrosion cracking of the refueling water tank penetrations at the
     penetration welds and they've discovered that through their walkdowns. 
     They plan on continuing that program to monitor -- manage that aging
     effect, although they're going to do some additional engineering
     evaluation, that, again, I'm going to put off just for a moment, because
     it's part of our confirmatory items with respect to that aging effect.
         Lastly, fatigue, this system is included in their fatigue
     monitoring program and, once again, there is going to be a modification
     to that.  The applicant is going to be doing some additional information
     relative to fatigue that I will talk to right now.
         DR. SHACK:  Would this thing see cycles or is this some sort
     of leakage kind of induced fatigue?
         MR. FAIR:  What they're monitoring right now is the safety
     injection nozzle, which does see thermal cycles during shutdown cooling
     initiation.  They're also taking a look further in the line, certain
     sections of the line for potential stratification effects, which they
     haven't completed yet.
         MS. COFFIN:  There aren't any open items with respect to
     these three systems and the confirmatory items are, one, to modify the
     structure and system walkdowns and specifically what they're planning to
     do is explicitly add to the scope the inspections of the refueling water
     tank for the safety injection system.  They're also going to add into
     the procedure inspection criteria for the perimeter seal for the RWT and
     for the RWT penetrations, penetration welds.
         The applicant committed to doing an engineering evaluation
     of stress corrosion cracking at their RWT penetrations and they want to
     reach the conclusion that they feel satisfied that the walkdowns are
     sufficient to detect stress corrosion cracking before there is a loss of
     intended function.  If they can't reach that conclusion to their
     satisfaction, then they're going to implement an ARDI-type inspection
     program for that particular aging effect.
         Do you want to add something Barth?
         MR. DOROSHUK:  I want to make one comment.  This is Barth
     Doroshuk, from BGE.  Yesterday I referred to this engineering evaluation
     of SEC as a leak-before-break analysis, and I misspoke.  That is an
     engineering evaluation, not a leak-before-break.  So for the record.
         MS. COFFIN:  And the last confirmatory item, John spoke to
     this a minute ago, is that the applicant is right now reviewing industry
     reports, particularly with respect to thermal stratification for some
     portion of this system and to see if and how the fatigue monitoring
     program needs to be modified, particularly for this system, to ensure
     that fatigue is managed for the safety injection system.
         With that, that takes care of these systems.
         DR. UHRIG:  Could you expand a little bit on -- I think it's
     called thermal fatigue.
         MS. COFFIN:  I would love to.  John?
         MR. FAIR:  What did you want me to explain?
         DR. UHRIG:  The thing that I'm most familiar with is stress.
         MR. FAIR:  Yes, and that's what is being monitored.
         DR. UHRIG:  This is just basically thermal cycling reduces
     stress, but now you're talking about thermal stratification, and this
     has got me confused.
         MR. FAIR:  Well, there's an issue that came up with
     potential stratification in lines due to leakage through check valves
     and there was a bulletin issued on it, it was Bulletin 88-08.
         A lot of licensees have gone back to look and see if they
     have this problem in any of the systems in their plant and the
     stratification problem is a combination of stratified flow and cycling
     flow due to leakage and circulation in certain parts of these systems.
         They do cause alternating stresses, quite a number of cycles
     of these alternating stresses and can result in cracking and eventual
     leakage.
         DR. UHRIG:  I had an associated stratification fatigue.
         MR. FAIR:  It oscillates.
         DR. UHRIG:  I see.  All right.
         MR. FAIR:  The stratification can cause other problems.
         MR. PATNAIK:  I'm Pat Patnaik.  In answer to your question,
     Bill, about the size of injection containment spray piping, they're all
     six inches.  They're over four inches and they're up to 12 inches
     diameter, stainless steel.
         DR. FONTANA:  Okay.  Anymore questions, comments?
         [No response.]
         DR. FONTANA:  Thank you.
         MR. HOU:  My name is Shou-Nein Hou, NRR.  I'm the reviewer
     on Section 3.4.  That covers three areas; the chemical boron control
     system, the compressed air system, and fire protection.
         For the chemical and boron control systems, the major
     component consists of piping, accumulator, strainer, tank, flow,
     temperature, heat exchanger, and various kinds of valves.
         The material, essentially it's stainless steel inside; on
     the inside.  That means the contact of process flow.  Outside, they do
     have carbon steel, alloy or stainless steel.
         Another is compressed air.  The material, it's carbon steel,
     and inside is the compressed air.  That is enclosed instrument air,
     plant air, and standby saltwater air.
         The major components, as you can see, are piping,
     accumulator, air compressor, and various valves.  Now, another area is
     about fire protection.  In the license review, there are 66 systems and
     components, and 42 of them relate to the fire protection function.
         In these 42 systems, 26 are safety-related structures and
     systems, such as the pressure boundary system and the structures to
     perform the fire barrier functions, and also some electrical equipment.
         So in this section, we're only talking about the remaining
     16 systems.  Now, in these 16 remaining systems, nine -- part is
     safety-related and part is non-safety-related.  But for safety-related,
     there is also another 26 I just mentioned, all be addressed separately
     in other sections about the aging management.
         So for this particular review, only those non-safety-related
     portions of these 16 systems.
         First, we talk about the chemical boron control system.  Not
     because we have that operated as it inside the component, so there is a
     generic corrosion concern.  So water chemistry program is very
     essential.  I think that's one of the common improvements that we have
     discussed this morning and that essentially is just a program to
     identify the perimeters need to be monitored and also the frequency and
     also what's the acceptance limit.  If you're beyond the limit and what
     kind of action need to be taken.
         So that would take care of that generic corrosion inside
     those components, contact with the borated acid.
         Now, in case if there is a leak, because the fastener is --
     it's carbon steel and alloy, which are subject to corrosion effects to
     the borated acid.  In that, they have borated acid corrosion inspection
     program.  That's also been discussed in this morning.
         Now, the plant also -- this system also has a unique concern
     is about using the heat trace to maintain the temperature of the systems
     above their limit to avoid saturation of the borated acid.  That's about
     the stress corrosion cracking, stress corrosion cracking caused by the
     heat tracing.  Because it contains hydrogen, which is a corrosive
     element.
         Now, the licensee have a plant modification to remove this. 
     That program being started in '91 to replace it with a non-corrosive
     one, and the program is still ongoing, and we were told that it would be
     completed by the end of the current licensing period.
         I think that will take care of the stress corrosion cracking
     concerns.
         Now, there are various valves.  The valve seat and the disk
     is subject to wear, because it's normal operation.  For that, they have
     a leak rate testing and that's a part of the plant surveillance test
     procedure.
         So attention to all this.  Now, they also supplement by an
     ARDI program.  The ARDI program for these particular system, it try to
     verify no severe previous corrosion impeding internals of the components
     contacting the boric water and the shear side of the heat exchanger. 
     That essentially is kind of walkdown process and it's been discussed in
     the morning.
         Another is no significant vibration fatigue.  That, I had to
     go back to the slide in here, talk about CVCS fatigue, the problem. 
     Now, we know fatigue is a problem.  It has two kind of concerns.  One is
     low cycle fatigue, one is the high cycle fatigue.
         The low cycle fatigue is about the thermal transients and
     the cause of stress, fluctuation, and they have the fatigue monitoring
     program and we know this program, as present earlier, and that program
     is not complete yet.  The place, the location for the monitoring,
     critical locations, has not been finalized.
         Also, there are generic concerns also being discussed, the
     GSI-190, how to categorically qualify operating plant for the 60 years. 
     Use the statistical approach, not risk-informed, to pick up sample from
     five PWR and the two BWR plants and perform an analysis using the
     modified curve generated by Argonne.
         Now, besides that, now, there is a concern about the
     charging pump.  The charging pump has created the operational vibration
     and that caused the cracking of the pump or block and also the suction
     side of the piping, as well.  That has been -- that problem is being
     identified and also they have plant modifications in the design and also
     improve the pump operating practice.  So the problem essentially is
     resolved and we're told about all this resolution and we agree with it,
     except for that information not yet being shown in the application.
         So the application needs to be modified to incorporate that
     information.  That essentially covers one of the confirmatory items.
         DR. MILLER:  When you say that problem is resolved, how do
     you reach that conclusion?
         MR. FAIR:  This is John Fair, again.  What occurred on the
     CVCS system is early in operation, they had some vibration problems on
     the suction side that led to some failures.  They went in and corrected
     the design, changed the design, changed the thickness of the piping, did
     some monitoring of the system, determined that they had an adequate fix
     for the --
         DR. MILLER:  How did they determine that?
         MR. FAIR:  That they didn't have significant vibration.
         DR. MILLER:  Do they have on-line vibration monitoring now?
         MR. DOROSHUK:  This is Barth Doroshuk, from BGE.  We do have
     a maintenance condition monitoring program.  That is a vibration
     monitoring program.  It monitors systems throughout the plant.  That
     program was most likely used in the verification corrective action
     follow-up after these modifications were done to the supports and to the
     piping to make sure that vibration was insignificant, as well as
     understanding or not seeing any additional failures or degradation in
     the system.  We concluded that vibration was not plausible for this
     system.
         DR. MILLER:  How did you determine it was not plausible?
         MR. DOROSHUK:  Vibration, we believed that vibration is a
     result of an installation or design defect and the design defect or
     installation defect was corrected here through a plant modification and
     then verified through follow-up monitoring.
         DR. MILLER:  Okay.
         MR. DOROSHUK:  So in this particular location, vibration, we
     believe, is not an aging effect.
         DR. MILLER:  When was this done?  I've looked at your SER,
     but it doesn't tell me a timeframe.
         MR. DOROSHUK:  Fifteen to 20 years ago.
         DR. MILLER:  So you've got that much experience.
         MR. DOROSHUK:  Yes, sir.
         MR. FAIR:  Just to clarify what the issue was on this. 
     Originally, they proposed to do an ARDI on this piping to verify they
     had no vibration fatigue damage.  There was a question as to how an ARDI
     was going to verify this and after some discussions, it was determined
     that since they had so much operating experience on the system as
     modified, that it really wasn't plausible at this time.
         DR. MILLER:  Part of this is response to Generic Letter
     88-14.  Is that what I'm reading here?
         MR. FAIR:  I don't believe so.  Where are you reading?
         DR. MILLER:  I'm just reading the SER, on the overall
     problem that came up.
         MR. HOU:  You mean Generic Letter 88-14?
         DR. MILLER:  Right, Generic Letter 88-14.
         MR. HOU:  I'm going to talk about that later.
         DR. MILLER:  You're going to talk about that one.
         MR. HOU:  Yes, right.
         DR. MILLER:  That relates to instrument air, which
     apparently --
         MR. HOU:  That's right.
         DR. MILLER:  -- stimulated -- did that stimulate the
     vibrations?
         MR. HOU:  That is not a vibration problem.
         DR. MILLER:  Okay.
         MR. HOU:  Not a vibration problem.  That's a -- well, I'm
     going to talk about it.  Are you finished?
         MR. FAIR:  Yes.
         MR. HOU:  About the compressed air system, the inside is
     compressed air.  Now, the material is carbon steel.  That carbon steel
     can only cause corrosion concern if the air has some problems; for
     instance, it contains the moisture.  So they have a preventive
     maintenance program.  That program is going to check the air quality. 
     But that program is later on being in place after it caused the piping
     failure problem and the failure is caused by the corrosion.
         Because of that -- well, this is not only the plant problem,
     it also is the industry-wide problem.  So the NRC issued Generic Letter
     88-14.  Because of this letter, they modified the plant and also changed
     the maintenance procedures and also they put in place the checklist to
     ensure that the air quality inside the instrumentation is dry and free
     of oil, free of the particulates, particles.
         DR. MILLER:  So there is a monitoring system for that.
         MR. HOU:  A monitoring system.
         DR. MILLER:  Generic Letter 88-14 spoke to that.
         MR. HOU:  88-14 probably -- it's asking for some actions,
     but also providing information.  This is an information letter.  But
     with that, they performed a corrective action to try to resolve the
     problem, and this is what they do.  So the problem no more exists.
         And as for the plant air, and others, like saltwater, they
     do not have the air quality control, but, however, due to their
     preventive maintenance procedures, they look at more frequently and also
     they do have certain filters, dryers, to make the air quality good.  But
     -- except they do not have to monitor it.  Quality monitor the
     instrument air.
         But recently they have looked on those plants and see how
     the condition look like and find out those lines are in very good shape. 
     So it look like it's not much a concern.
         Now, talk about fire protection.  Now, the fire protection,
     they actually -- they perform a certain way procedures, try to manage
     the aging problem.  The first, in the updated FSAR, it has to be
     reviewed by the staff and we accept that, there is a fire protection
     program in there.
         That contains certain systems and the components to ensure
     they have -- maintain its function and for the fire-fighting -- for the
     fire protection purpose.
         And if -- for the non-safety-related components of the 16
     systems fell into this category and there is not a problem.  Now, in
     particular, what -- for example, that includes the feedwater, auxiliary
     feedwater and also the plant drain and also something, I guess,
     sprinklers and also hose stations.
         Now, another screening, there's about a structural system,
     actually it's a monitoring the operating conditions of the system and
     component and that's by walkdown, periodic walkdown, and also by
     monitoring their performance during the plant operations.
         So if have this covered, we know there is no problem because
     the operating condition for those system and components actually -- the
     fire-fighting capability, because in the safety-related components, we
     have -- now, there are other concerns, like LOCA, like seismic, but for
     this non-safety-related, they do not have -- for the operating loading
     is already large enough.
         So if the operating condition is good, we know their
     fire-fighting capability is maintained.
         Now, that kind system, for example, component cooling and
     compressed air system.  Now, another approach they're taking is those
     systems -- now, they have part of it is safety-related, but also another
     portion is non-safety-related.  Now, for safety-related, we know they
     have aging management programs defined, but in a non-safety-related,
     they have the same material, subject to the same environment.
         So if they apply the safety-related aging management, the
     program, to this non-safety-related portion, that will take care of the
     aging concern.  So this is that their third approach.
         Now, with all of these three approaches, they also, they
     have supplemented by an ARDI.  The ARDI program is one-time inspection,
     just to verify those fire protection non-safety-related portions, there
     is no significant general corrosion.
         Now, with all these three approaches taken, that covers the
     15 of the 16 remaining issues just mentioned, the non-safety issue, but
     there is one remaining one.  It's the condensate system.  The condensate
     system, the non-safety-related portion, the makeup line is downstream of
     a normally closed manual isolation valve.  But that can take care of by
     the ARDI.
         Now, talk about open items.  Now, earlier, in my discussion
     on the component -- the CVCS, I mentioned about there is a concern on
     the stress corrosion cracking and the caused by the heat trace adhesive
     and they going to replace it with a new material.
         But this replacement, it is started in 1991 and they said
     they're going to conclude it by end of the current licensing period. 
     That means more than ten years away.  If we know this is a concern and
     also we know that there is a way to fix it and also it's being started,
     so why take so long to finish, and that's one of our open items.  We
     want to have reasons.
         Another one of concern is within -- for this program,
     because it takes so long, and also because of the replacement, but we
     have to know what is the situation of the piping, would it already have
     a crack or they may generate cracks during the ten years period of time.
         So we'd like the program also to consider the inspections to
     ensure that the condition of the piping.  That's another open item.
         Now, the third open item is about the fatigue.  The fatigue,
     about in the -- in the low cycle fatigue, they have some -- they monitor
     the thermal transient and they perform analysis based on monitor of the
     results.  But the analysis, the evaluation scope, it also include heat
     exchanger and thermal, is what they indicate in application.  But in the
     application does not provide a detail about the process how to conduct
     this evaluation.  So this is the third open item.
         That concludes my presentation.
         DR. FONTANA:  Any comments?  I guess one question for BG&E,
     which I guess they don't really need to answer, is when you get asked
     for what's taking you so long, what kind of answer do you give?
         MR. HEIBEL:  This is Dick Heibel, from Baltimore Gas &
     Electric.  What we were doing with the installation on the boric -- the
     heat tracing on the boric acid, we're replacing it as components are
     pulled out for maintenance and on a catch-as-catch-can basis.  It's a
     type of modification that, quite frankly, on its face, did not merit a
     -- it's very expensive program to undertake.
         So what we have is stocks of this different type of heat
     tracing and when we pull pumps, valves, and do work on sections of pipe,
     replace it on a catch-as-catch-can basis, or if the heat tracing fails.
         DR. FONTANA:  All right.  Thank you.
         MR. HOU:  Do you have anything to say about it?
         MS. COFFIN:  I would just add the comment that the
     application has seen stress corrosion cracking of these tanks due to the
     heat and that's why identified the problem, and I'm sure they have an
     engineering evaluation of why they can wait, but the staff hasn't seen
     that yet.
         DR. FONTANA:  Okay.  Who's next?
         DR. SEALE:  Dr. Powers will probably be here the next time
     you talk about fire protection, so you may have a few questions to come
     up at that time.  You're not off the hook.
         MR. GEORGIEV:  Good morning.  My name is George Georgiev,
     and I'm with the Materials and Chemical Engineering Branch, with the
     Division of Engineering, and I will be doing the presentation of Section
     3.5.
         Section 3.5 includes four systems; component cooling
     systems, saltwater system, service water system, and the spent fuel pool
     cooling system.  All these systems have in common, in general, the low
     temperature and as the name implies, they provide cooling to various
     equipment components within the plant.
         The license application reported that several operating
     problems have occurred with those systems and with all fairness, they
     are all normal kind of problems that have been in other plants.  An
     example of those problems, they had a leaky valve, valves in the
     component cooling system, they got some degradation of cement in the
     saltwater system, some high cycle fatigue in the spent fuel systems, and
     all these problems have been addressed and the repaired and there
     haven't been any other problems.
         The materials of all this system are various because they
     all operate under various conditions.  They include carbon steel,
     stainless steel, carbon-nickel, you've got various type of linings,
     rubber linings, cement lining, and all this is necessary to do the
     operation.
         To address the problems and to take care of various
     degradation mechanisms, the application reports aging effects and for
     the purpose of this presentation, if you see here in the first where it
     says corrosion, that includes various type of corrosion.  It includes
     crevice corrosion, pitting corrosion, galvanic corrosion, general
     corrosion, and the microbiological induced corrosion.
         Also, there are other specific for these systems,
     degradation mechanism like wear, selective leaching, elastomer and
     rubber degradation, mortar, cement lining degradation, and sulfur.
         DR. SHACK:  A question.  I thought yesterday they said they
     had rubber-lined systems, and you say cement.
         MR. GEORGIEV:  Yes, they do have both.  They do have
     above-ground piping, cement lined.  In fact, they have reported some
     leakage with this.  I believe it has been replaced.  But one has to
     address all these effects, the licensee has identified aging management
     program and most of them are existing programs.  They are either site
     director procedures, programs to -- maintenance program items, and in
     some cases, they had to modify to address the aging effects.
         And the only problem for this particular four system is the
     ARDI program, which is the inspection program that they'll do to look
     specifically for aging degradation, for these systems.
         And as far as having open items, we don't have any open
     items and we don't have any licensing issues.
         That concludes my presentation.
         DR. FONTANA:  Any questions, comments?
         [No response.]
         DR. FONTANA:  Very good.  Let's move on then to --
         MR. GEORGIEV:  Give my time for somebody else.
         DR. SEALE:  That's generous.
         DR. FONTANA:  Get out the heating ventilation and air
     conditioning systems.
         MR. CHENG:  My name is Tom Cheng, with the Mechanical and
     Civil Engineering Branch.  Today I'm going to discuss something about
     Section 3.6, the HVAC systems.
         My presentation is going to cover three systems, which are
     the auxiliary building heating and ventilation system, primary
     containment heating and ventilation system, and the control room HVAC
     system.
         Before I start my presentation, I would like to highlight
     some operating experience identified at the site.  Some cracking has
     been discovered at the HVAC ducting due to vibration-induced fatigue. 
     Some losing fasteners has been experienced because of the dynamic
     loading.  The control room air conditioning unit was placed out of
     service to repair the broken damper linkages.  Also, during the
     performance period, the elastomer degradation being identified.
         BG&E, based on their operating experience and the review of
     industry documents, so identified those five aging-related degradations
     can cause possible aging effects, which is corrosion and elastomer
     degradation, effect of dynamic loads, and the wear of valves and
     radiation damages to the non-metallic material.
         BG&E uses five aging management programs, as are listed in
     my viewgraphs.  The first one is the structure and system walkdown
     procedures.  I think that Dr. Munson already presented. Also, the ARDI,
     and he presented also.
         Structure and system walkdown procedures, which is existing,
     the ARDI is a new one.  In addition to those, BG&E also uses containment
     leakage rate testing program.  This program would be used to discover
     and manage the leakage of surface wear and also the leakage of crevice
     corrosion, due to crevice corrosion, general corrosion, degradation.
         Also, preventive maintenance program, which is existing
     program, to be used to discover and manage the effect of corrosion
     problem.
         The third -- the fourth one is the administrative procedure
     -- I'm sorry.  Excuse me.  The chemistry program procedure, CP-206, to
     be used to identify the corrosion.  I have to apologize.  I forgot to
     list this one on my viewgraph.
         BG&E has demonstrated in their application that the
     combination application of this aging management programs can provide a
     reasonable approach to inspect and assess the condition of the systems
     such that any degradation condition will be identified and documented
     and corrective action can be taken before the degradation proceeds to
     failure to perform the intended function.
         The staff who reviewed BG&E's application drew the following
     conclusions.  BG&E's approach for determination of possible aging effect
     and approach to identify possible aging effect are reasonable and
     acceptable.
         The combination application of this aging effect program,
     management program, meets the ten elements of the SRP.  I did not
     identify any open items, except one confirmatory item.
         According to the application, the two new diesel generator
     buildings and also associated HVAC are placed into operating in 1995. 
     Because the aging of the existing control room HVAC system equipment is
     some 20 years ahead of the aging of those located in the diesel
     generator building and also because the new equipment is just at the
     beginning of its design life and the system have the design life of 45
     years, BG&E concludes that the aging management of the new equipment can
     be deferred.
         BG&E's conclusion is acceptable, providing BG&E needs to
     confirm that, the environmental conditions such that the moisture
     contents in the air, temperatures and so forth in the two diesel
     generator buildings are similar to the conditions in the control room
     and that the material and hardware configuration of the HVAC system
     located in the new building are similar to those in the control room.
         This concludes my presentation.
         DR. SHACK:  What's the nature of the dynamic loading?  This
     is the vibration-induced?
         MR. CHENG:  That's just, for example, like accumulators in a
     location and create a vibration, like a fan, those things.
         DR. UHRIG:  Imbalance.
         MR. CHENG:  Imbalance, correct.
         DR. FONTANA:  Any additional comments?
         [No response.]
         DR. FONTANA:  Thank you very much.  We'll move on to
     emergency diesel generator systems.
         MR. GEORGIEV:  Hello again.  Since we are formally
     introduced already, I'll skip the first slide and go to the second one. 
     The emergency diesel generator system actually includes two systems, the
     diesel generator itself and the diesel fuel oil system.
         In general, the diesel has been operating adequately and
     several problems have been reported, but all of them have been addressed
     and resolved by BG&E.
         The operating condition for the diesel basically is external
     environment, which is plant quality type of air, and internal
     environment, it's either water, tritiated water, or oil, or exhaust
     gases coming when the diesel is operated.
         To address the degradation mechanism associated with diesel
     fuel oil, the application basically divide the problem into external
     piping and buried piping, and materials involve the carbon steel
     materials and for the buried piping, the buried piping has been wrapped
     with protective coating and they also use cathodic protections to
     protect the buried piping.
         For the external service of the piping, they are protected
     by paint.  In essence, what BG&E reports to do to address the
     degradation mechanisms, which are corrosion, weathering, fatigue, and
     wear, they have existing plant programs and also are creating four other
     new programs, which are a program which is catching all type of problem,
     the program to inspect the buried pipe, and a program to inspect the
     balance for the fuel oil storage tanks and they also have created a new
     program for caulking around the storage fuel oil tank.  The reason being
     to prevent water and other material to seeps and effect the metal.
         We have, in essence, agreed with BG&E's proposal to manage
     the aging effects.  However, we do identify one open item and this open
     item pertains to BG&E has classified the cathodic protection as not
     being needed for aging management of buried piping.  The staff disagrees
     with this.  We believe that they do need both.  They do need the
     protective wrapping measures and also the cathodic protections.
         License renewal issues, we don't have any.  We have no
     confirmatory items.
         That, in essence, concludes my presentations.
         DR. FONTANA:  Any comments?
         DR. UHRIG:  Does the cathodic protection --
         MR. DAVIS:  It's a compressed current system, but it acts
     the same way.
         DR. FONTANA:  Thank you.  I guess we can go on to the next
     item before lunch.  It looks like it's fairly long, but we scheduled 20
     minutes for it.
         Moving on to the steam and power conversion systems.
         MR. PARCZEWSKI:  My name is Kris Parczewski.  I am a member
     of staff of Material and Chemical Engineering staff, in the Division of
     Engineering.
         I'm going to present to you a review, staff's review of
     steam and power conversion systems.  The steam and power conversion
     systems included in the license application, license renewal application
     consist of six systems; auxiliary feedwater system, feedwater system,
     main steam system, steam generator blowdown system, extraction steam
     system, which, by the way, is inoperable, and nitrogen/hydrogen systems.
         Now, the system, the material, the materials of the system
     are mainly carbon steel, but some of the systems have some additional
     material.  For auxiliary feedwater system has, in addition to carbon
     steel, alloy steel, bronze, brass, cast iron, and elastomers.  It is
     exposed to an environment of chemically treated water at temperatures
     just below 200 degrees Fahrenheit.
         DR. FONTANA:  Excuse me.  Could you push that other
     microphone out of the way?  Thank you.
         MR. PARCZEWSKI:  The feedwater system, in addition of carbon
     steel, has chrome alloy steel.  It is exposed to an environment of
     chemically treated water, the secondary water, basically, at a higher
     temperature, up to 475 degrees Fahrenheit.
         Main steam system, in addition to carbon, has alloy steel
     and some stainless steel, and the orifice is made out of stainless
     steel.  It's exposed to an environment of wet steel and two-phase fluid
     in the drain line when the condensation occurs.
         The steam generator blowdown system has, in addition to
     carbon steel, stainless steel, brass and cast iron.  It is exposed to an
     environment, two-phase fluid on the side of the heat exchanger and the
     component cooling water on the tube side of the heat exchanger.
         The extraction of steel is made strictly from carbon steel
     and it's exposed to the moist air.  It's empty, because it's not being
     used presently.  The nitrogen and hydrogen system is made out of carbon
     steel and it is exposed to an environment of very, very dry gases, with
     dew point minus 40 degrees Fahrenheit, which is extremely dry.  But
     still it might have some corrosion, so the applicant included it in the
     review.
         There are several different aging mechanisms, aging effects. 
     The most prevalent definitely is the corrosion and there are several
     managing -- aging management programs for different systems, depending
     on the operating conditions and the type of material and so on.
         There are really two types of aging management programs. 
     One is a preventive program and the other one is monitoring.  The
     preventive program, in most cases, as you can see here, is controlled
     with secondary water, there's pH, oxygen consideration, some iron,
     boron, if there is boron in the system, and so on.
         DR. SHACK:  What do they use for their pH control agent?
         MR. PARCZEWSKI:  They use -- for pH control, they use the
     hydrogen, which, of course, is composed in the heat exchanger, the high
     temperature.  You generate some ammonia, which keeps pH.
         In the auxiliary feedwater system, in addition to secondary
     water, there is a buried pipe inspection program, which is -- pipe are
     exposed to MIC, microbiologically influenced corrosion, and there is no
     way to control it.  The only way to prevent it, the only way is just
     inspecting it.
         The second one is, of course, preventing maintenance. 
     Corrosion inspection, this is a new program, ARDI program, they do
     corrosion inspection.
         In feedwater, again, there is a corrosion inspection
     program, which is the new ARDI program.  In water, main steam line, main
     steam system, the secondary water, to some extent, prevents some
     corrosion.  This is the only way we can do it.
         DR. SHACK:  In the feedwater system, what is the ARDI
     looking for here?
         MR. PARCZEWSKI:  The ARDI is looking for damage due to
     corrosion, inspection.
         DR. SHACK:  So there is no regular erosion/corrosion
     checkmate type program.
         MR. PARCZEWSKI:  There will be another point in my
     presentation on erosion/corrosion.  It's a specific type of corrosion,
     which is not included in the corrosion.  We did it separately because
     there is slightly different control of this particular mechanism.  It's
     the next slide.
         In the steam generator blowdown system, we have already
     secondary water chemistry.  Then there is, of course, another component,
     cooling water, which controls the chemistry of the cooling water in the
     heat exchanger, the one which goes through the tubes, and there is an
     additional corrosion inspection ARDI program.
         In extraction steam, there is an ARDI program for control --
     for inspecting the corrosion in this extraction system, which I
     indicated really has only moist air.  In nitrogen/hydrogen system, you
     have motion control, which is really inspecting, but if there is any
     corrosion, it's extremely small, because the gases are kept in a very,
     very dry condition.
         Now, erosion/corrosion.  Erosion/corrosion is a very, very
     significant aging mechanism and this is why we looked at it as a
     separate item.  It is, to some extent, controlled -- prevented by
     controlling secondary water.  However, there is a problem there. 
     Usually to reduce corrosion, you keep oxygen down as much as you can. 
     It is not true erosion/corrosion.
         To optimize, you have to go up to a certain point.  You
     cannot go completely -- usually, you should keep above about 40 ppb.  Of
     course, you cannot do this.  So really, in order to control corrosion,
     you cannot optimize erosion/corrosion system.  Therefore, prevention
     using secondary water is somehow limited.
         So we have, in addition to inspection programs, monitoring
     programs.  One of them -- we have the chemistry -- we have a monitoring
     program which uses a program developed by EPRI and they have a check --
     I have experience with that, an excellent program, and what it does, it
     predicts which components are susceptible to corrosion and in addition,
     it predicts when they're going to fail.
         The program has to be, so to speak, calibrated, which means
     some of the components have to be measured, the effect of
     erosion/corrosion, by using the either ultrasonics or radiography, and
     then input into the code.  This calibrated code then can predict some
     other components which are not measured, when they're going to fail,
     when they have to be replaced.
         It's being used by practically all the licensees, because it
     does a very good job.
         In addition, there is an ARDI program for inspection which
     basically is an extension of this monitoring program, using the same
     program, but it adds additional components which originally were not
     included in the program.  So basically, it's an extension of the E/C
     program.
         This is for -- in main steam line, again, you have secondary
     water chemistry monitoring, basically the same programs as for water --
     in feedwater.
         The same applies to steam generator blowdown.  Again, you
     have the same program.  So all those three systems have the same
     program.
         In addition, cavitation is another mechanism which, of
     course, is not a chemical.  It doesn't involve corrosion.  It's
     hydrodynamic phenomenon, and there is an -- there is going to be
     established an ARDI program for inspecting cavitation damage.  There is
     no way to mitigate -- to prevent it.  Just the only thing is to inspect
     it.
         This same applies to the wear program.  ARDI inspects the
     control of seats and plugs of steam atmospheric valves and sterite
     carbon steel borders and MSIVs.  So this program will be limited to
     those components.
         Now, the steam generator blowdown system would have a
     leaching mechanism.  There are some components made out of cast iron or
     made out of brass.  In those components, the environment, corrosive
     environment removes selectively materials in case of cast iron to remove
     the ferrite phase.  In the case of brass, it removes zinc.  So this is
     the corrosion mechanism.
         Again, there is no -- you can control, to some degree,
     through secondary chemistry, but it still needs to be inspected and
     there is inspection program, ARDI inspection that is going to take care
     of it.
         Now, elastomers, there are two programs addressing the
     elastomer degradation.  One program, which is the sealant inspection
     program, will take care -- again, you cannot prevent the program.  The
     only thing is to inspect it.
         The sealant inspection program, which inspects the sealant
     around the condensate storage tank, which might be affected by the
     environment.  ARDI elastomer program, which will address the inspection
     of solenoid operated valve made of ethylene, propylene, and subject to
     wear.  So that's the programs.
         The final is fatigue.  In some of the piping in feedwater,
     you have stratification of fluid in the pipe and this stratification
     would produce thermal stresses which will obviously produce some fatigue
     of the piping.  So this is the final program I will be discussing here.
         DR. SHACK:  John, just a question on that fatigue.  You need
     a horizontal run of piping to have that problem, don't you?
         MR. FAIR:  Yes.  As a matter of fact, that's why they
     selected this section of the pipe, right near the nozzle.  We asked a
     question as to why it wasn't a concern anywhere else and it was because
     there is a vertical riser coming up to that horizontal run of pipe.
         DR. SHACK:  So there's just one sort of small segment of
     horizontal piping here.
         MR. FAIR:  Yes, and this is an area where they have a fairly
     detailed monitoring of the thermal temperatures in the area to do a
     detailed fatigue analysis.
         DR. FONTANA:  Any additional comments?
         [No response.]
         DR. FONTANA:  Thank you very much.  I think we'll move on to
     the next topic, sampling and monitoring systems.
         MR. PATNAIK:  I'm Pat Patnaik, from the Division of
     Engineering.  I've been asked -- I compiled the sampling and monitoring
     system Section 3.9.  This sampling and monitoring system comprises of
     nuclear steam supply sampling system, radiation monitoring system, and
     the instrument lines.
         Mine is going to be a snapshot of the SER.  The nuclear
     steam supply, NSSS sampling system provides for sampling of liquids,
     steam gases, radioactive and chemical control of plant fluids, and this
     has five subsystems, which is reactor coolant sampling, steam generator
     blowdown sampling, radioactive waste sampling, gas analyzing sampling,
     and post-accident sampling.
         The general categories of equipment are accumulators, air
     drives, piping, valves, valve operated panels, instruments, sample
     vessels, and pumps.  The materials for these components are stainless
     steel or carbon steel.
         These are compatible with the medium inside the pressure
     boundary, which is either borated water or chemically treated water.
         The components in this NSSS sampling system that we
     evaluated had the intended functions of maintaining the pressure
     boundary.  It provides containment actuation of the nuclear steam supply
     sampling system during a LOCA.  It also provides capability to sample
     gaseous fluid during an accident.
         The RMS, which is the release and monitoring system, detects
     an increasing radiation level or an abnormal radioactivity concentration
     at selected points in the plant.  It provides indication of such
     conditions to operating personnel and the system monitors also the
     discharge of radioactive fluids from the plant and provides a signal to
     isolate components in the event of abnormal conditions, to prevent
     uncontrolled release to the environment.
         Again, the RMS comprises of piping, tubing, pumps, valves,
     filters, instrumentation, and the materials are either stainless steel
     or carbon steel, and which are compatible with the internal environment
     which is either air, borated water, or chemically treated water.
         They had intended functions of maintaining the pressure
     boundary.  It provides containment isolation, radiation signal to the
     engineered safety feature actuation system for containment isolation and
     radiological release control.
         DR. SEALE:  Would you help me?  I've got a block.  What's
     the BACI, again?
         MR. PATNAIK:  That's the boric acid corrosion inspection
     program that you heard in the earlier presentation.
         DR. SEALE:  Okay.  I knew I had heard it, but I had
     forgotten what it was.  Somehow or another, I didn't feel comfortable.
         MR. PATNAIK:  This is the program that the in-service
     inspection personnel perform right after the outage and walk down the
     system.
         DR. SEALE:  Yes, okay.
         MR. PATNAIK:  Now, moving on.  The instrument lines are
     associated with all plant systems.  Therefore, the applicant evaluated
     this as a commodity.  And for the purpose of instrument line, the
     evaluation is from the -- looks at from the process line down to the
     first hand valve or route valve.  Then it went line-up to the
     instrument.  In other words, it's defined as the components located
     downstream of the first hand valve off the main process line or the
     vessel, which is called the route valve, and the instrument lines are
     all piping, tubing, fittings, hand valves.
         The materials are stainless steel, carbon steel, copper,
     depending on the environment inside, which could be borated water,
     chemically treated water, oil, air.  The components that we evaluated
     had the intended functions of maintaining pressure boundary integrity.
         Corrosion manifests as general corrosion of external, which
     is due to leakage of borated water from piping or joints.  As the
     previous speakers well stated, the ARDI program is -- the licensee has
     taken credit for the ARDI program and the BACI program, boric acid
     corrosion inspection program, on the nuclear steam supply system
     sampling lines.
         And for radiation monitoring system, also, ARDI program has
     been taken credit and on the instrument lines, again, we have ARDI
     program.  Structures and systems walkdown, which you've heard.
         Then there are two other programs that the licensee has
     taken credit for, which is control of shift activities and ownership of
     plant operating spaces.
         I want to walk you through these last two, because you
     haven't heard anything of these two.
         Under control of shift activities, operators perform the
     walkdowns, plant operators.  They inspect accessible operating spaces
     during each shift and when the containment -- when the -- during an
     outage, they also perform these walkdowns inside the containment, once
     per shift.
         This program provides for discovery of conditions that could
     allow general corrosion to progress for the instrument line supports, by
     performing visual inspections.
         The inspection items related to aging management include
     vibrations and effects that may have caused by this age-related
     degradation mechanism, such as damaged piping, instrument tubing, or
     leakage of fluids.
         Also, this program would also detect leakage of fluids,
     which is as a result of conditions progressing from the age-related
     degradation mechanism.  And the licensee also has the corrective actions
     program which will take care of any of these aging effects noticed
     during the inspections.
         The other program is the ownership of plant operating
     spaces.  Under this program, the plant operating spaces, they have
     owners identified within each space who would provide a point of contact
     for any individual who finds deficiencies or any concern with the space,
     and the responsible individuals are required to periodically inspect
     their assigned spaces for housekeeping, cleanliness, material
     conditions, and radiological deficiencies.
         This program provides for discovery of general corrosion of
     the instrument line supports by performing visual inspection in plant
     operating areas.
         Again, the inspection items related with this aging
     management include items related to specific age-related degradation
     mechanisms, such as corrosion; item two is effects that may have been
     caused by age-related degradation mechanisms, such as loose lines or
     loose fasteners, because of fluids, and the conditions of pipes, loose
     fasteners, conditions that would allow progression of age-related
     degradation mechanisms, such as unbracketed lines and pipes.
         Again, they have the corrective action program which takes
     care of any deficiencies that they identify.
         That's the general corrosion.
         Next, we have this crevice corrosion and pitting.  For the
     nuclear steam system, we have the ARDI program and then we have the
     other programs like specification and surveillance of the system,
     component cooling, service water, secondary chemistry program.
         These are all the chemistry programs, which the licensee is
     taking credit for, as mitigation.  Then the third is the local leak rate
     test of penetrations.  Actual, this local leak rate test of penetrations
     is identifying where in the control valves, but the staff didn't
     evaluate aging management on the valve internals because the valve
     internals perform their intended function with moving parts and changes
     in the configuration, which is not subject to aging management review.
         DR. SHACK:  Would this local leak rate give you a thermal
     cycling problem and a fatigue problem?
         MR. PATNAIK:  Local leak rate --
         DR. SHACK:  Through the valve.  Is this a hot/cold -- hot
     fluid going to a cold fluid kind of thing?
         MR. PATNAIK:  No.  I'm talking about Appendix C test -- I
     mean, Appendix J, Type C test.
         DR. SEALE:  Okay.  Which is --
         MR. PATNAIK:  Which is different.
         I guess I have one more slide.  Lastly, the low cycle
     thermal fatigue is one of the possible plausible age-related degradation
     mechanisms on the nuclear steam supply sampling system.  Anytime you
     draw a sample, you go through a thermal cycling, and what the licensee
     has used fatigue monitoring program.
         We have an open item on this, like many other fatigue items,
     items on fatigue, this item involves -- there are 11 locations in the
     RCS that are being monitored for fatigue and our staff thought that the
     applicant should provide validation to demonstrate that the low cycle
     fatigue uses of piping and valves in the RCS hot leg sampling is bounded
     by monitoring of those 11 fatigue critical locations.  That was the only
     open item.
     There is one other item, age-related degradation, elastomer degradation. 
     The internals of check valves in the past, the post-accident sampling
     system gas return line tot he containment, and some of the supports in
     the instrument line.  They contain the elastomer materials that are
     susceptible to age-related degradation.
         The staff determined that the applicant's ARDI program will
     effectively manage this age-related degradation mechanism.  So the staff
     concluded the applicant has demonstrated that the aging effects
     associated with the sampling and monitoring systems are adequately
     managed, such that there is reasonable assurance that the systems will
     perform their intended functions in accordance with the current
     licensing basis.
         So this is a nutshell of what we presented of the ACR.
         DR. FONTANA:  Any additional comments?
         [No response.]
         DR. FONTANA:  Well, thank you very much.  The next item is a
     fairly long one, so I think we ought to break for lunch now.  Since
     we're ahead of time, I guess we can show up at 1:00.
         MR. GRIMES:  That would be acceptable to the staff.  As a
     matter of fact, we would prefer that, since the folks that are supposed
     to be here for the afternoon session might not otherwise know when to
     show up.  So if we could reconvene at one, that would be our target.
         DR. FONTANA:  That's fine.  Okay.  We'll come back at 1:00.
         [Whereupon, at 11:53 a.m., the meeting was recessed, to
     reconvene at 1:00 p.m., this same day.].             A F T E R N O O N  S E S S I O N
                                               [1:00 p.m.]
         DR. FONTANA:  The meeting will resume.  We'll move into the
     presentation on building structures.  David Jeng.
         MR. JENG:  Yes.
         MR. GRIMES:  Dr. Fontana, before we continue with the staff
     presentation, I would like to mention that I just provided a copy of a
     staff position that was issued yesterday to NEI on fuses, which
     concludes that aging management review for fuses is not necessary.
         Assuming that NEI does not object to the conclusion in that
     position or that we otherwise don't receive critical comments on the
     basis for arriving at that decision, that will address one of the open
     items in the Calvert Cliffs review.
         That letter also illustrates the process by which we're
     going through and defining these generic renewal issues and addressing
     the resolution and then documenting the results.
         It describes the nature of the guidance that we would add to
     the standard review plan.  So we offer that also to the subcommittee as
     an illustration of how the process is working.
         DR. FONTANA:  Thank you.
         MR. JENG:  Good afternoon.  My name is David Jeng.  I am
     with the Mechanical and Chemical Engineering Branch of the Division of
     Engineering.
         Today, I am going to report to you our review findings of
     the building structures, which is covered in the ACR Section 3.10. 
     Please go to page 75.
         Building structures of BG&E include the following five
     items; primary containment structure, turbine building, intake
     structure, miscellaneous tank involved, auxiliary building, and
     safety-related diesel generator building structures.
         The basic approach of BG&E in achieving aging effect
     management for their structures are as follows.  They, first, identified
     all the structures and component types, such as the concrete structure
     components or steel structure components, and matching these types to
     the potential aging-related degradation mechanisms, such as the
     corrosion of the steel, cracking of the concrete, and corrosion of the
     stainless steel liners in the spent fuel pool.
         By matching these two concepts, the component types, with
     the potential age degradation mechanisms, they come up with some ten
     structure and component types such aging type categories and I am going
     to report to you how these ten categories are identified and how their
     aging management programs are proposed to be handled.
         Going to page 76.  The first item is the corrosion of
     tendons in pre-stressing losses.  BG&E, in this evaluation, determined
     that their aging management program for this item should include
     mitigation -- periodic tendon surveillance program and implementation of
     a long-term corrective action program, which was established after their
     discovery of the earlier degradations in the tendons group.
         Going to the second item on the same page.  Concrete
     reinforcing degradations.  BG&E determined that the aging effect of
     freeze/thaw, leaching, aggressive chemical attack, groundwater, boric
     acid, and flow-in water do not apply to their concrete structures,
     except for the intake structure, which is submerged into a bay water, a
     more aggressive environment type water.
         The reason for their judging that these effect do not apply
     because the concrete they provided is a very high quality concrete and
     their aggregate are tested to standards and also the design is such that
     they are consistent with the ACI process and they are going to ensure
     such effect would not prevail.
         Please go to page 77.
         DR. FONTANA:  Are they also inspected at some point to make
     sure that that kind of construction standard really does -- those kind
     of construction standards really does provide concrete that is that
     good?
         MR. JENG:  Yes.  As I said in the slide, in the curing,
     which covers the good quality construction practices and the
     post-construction curing of the concrete.
         Going to page 77.  Weathering of the caulking, sealants and
     expansion joints.  BG&E's aging management program items include for the
     fire barriers in the auxiliary building and adjacent rooms, they are
     going to implement an existing fire barrier program.  For the other
     caulking and sealants which are non-fire barrier functioning, they are
     going to propose a new program to perform inspection.
         But BG&E did not adequately cover the potential aging effect
     of radiation temperature on the non-metallic portion of the penetration
     assemblies, such as the cable installation, sealants for their
     penetration, and this item remains open, and this is listed in the open
     items later.
         Please go to page 78.  The corrosion of containment wall and
     dome liners.  BG&E's evaluation decided that the program should include
     use of a protective coating to minimize corrosion effects,
     implementation of visual inspections.  They are using STP-M-665 1/2 on
     the two plants, respectively.
         And the last item that BG&E indicated that the -- based on
     their past experience, their inspection program has been shown to be
     quite effective.
         Please go to page 79.
         DR. SHACK:  What is the nature of the periodic inspection?
         MR. JENG:  Okay.  The most inspection is the type of
     inspection -- for instance, the containment liner inspection, which is
     based on the ASME IEW/IWL provision, as well as the Reg Guide 1.35, and
     they are done on every refueling outage.
         DR. SHACK:  But is that a visual inspection?
         MR. JENG:  Basically, visual inspections.
         We are on page 79.  Corrosion of steel.  The aging
     management program lists item includes use of protective coatings to
     minimize corrosion.  Again, implementation of a periodic visual
     inspection program.  But for the containment emergency sump cover and
     screen, which is sort of unique, it was not specifically covered in the
     earlier BG&E maintenance program and they are proposing a new inspection
     program, number STP-M-661.   
         Going to the lower part of the page, corrosion of the
     refueling spent fuel pool liners and cavity sealing ring, but in 1995,
     BG&E did inspect the fuel transfer canal and ensured that there was no
     indication of damage or corrosion.
         So for this item management, BG&E indicated that the concern
     is the potential IGSCC, which may be applicable to the stainless steel
     liners and the PCSR and for this item management, BG&E proposes to use a
     periodic walkdown, that's MN-1-319, to manage the aging effects.
         Please go to page 80.  The next item in the category is
     degradation of intake structure containing concrete walls, sluice gates,
     and steel subject to aggressive chemical attack.
         The aging management program proposed by BG&E for this
     category include use of a preventive coating to minimize steel
     components corrosion, implementation of periodic inspection, and
     performance of structure and system walkdowns.
         The lower portion of the page, corrosion of steel components
     inside miscellaneous tanks involve enclosures.  For this particular
     category, BG&E proposes to use preventive coating to minimize corrosion,
     implementation of periodic walkdowns, and through application of these
     programs, they intend to manage the corrosion of CST tank number 12,
     FOST tank number 21, and the auxiliary feedwater valve enclosure.
         Please go to page 81.
         DR. UHRIG:  You said they propose to use.  They presently
     have preventive coating, do they not?
         MR. JENG:  They do, but they are making it official
     commitment for some enhancement of the content of the program.
         DR. UHRIG:  Thank you.
         MR. JENG:  Please go to page 81.  Weathering of vertical
     tendons.  BG&E did discover some degradation in the vertical tendons. 
     For this category, it proposes to include implementation of periodic
     inspection and to perform needed engineering evaluation and take
     whatever needed corrective actions.  The staff finds this to be
     acceptable.
         Go to the lower portion of the page.  The evaluation of
     neutron absorbing materials.  For this particular consideration, BG&E
     proposes to perform periodic sampling of the neutron absorbing materials
     and also to implement the EGP 86-03R title, analogies of neutron
     absorbing material in spent fuel storage racks.
         Please go to page 82.  Besides the about ten items I
     discussed, BG&E also looked into the potential effect of foundation
     settlement and it concluded, and the staff agreed to their conclusion,
     that because of the following three reasons, the foundation settlement
     is not a plausible concern for the BG&E structural foundations.
         The number one basis is the design is such that the building
     capacity of the foundation material is so high, with a margin of more
     than ten.  Secondly, there is the underground drainage system in place
     right now which would tend to control groundwater levels.  And the third
     reason is the -- after all these years, the settlement, if any, should
     be mostly in the uniform settlement and the settlement normally do not
     effect the structure performance.
         For the intake structure, BG&E did also maintain that the
     first and third reason alone should be able to justify that there will
     be no settlement concerns for intake structures.  Incidentally, the
     intake structure of the underground drainage system.
         I have covered the major, some ten component category aging
     effects and the BG&E proposed management programs.  The staff did review
     all these proposed programs in great details and except for the open
     item which we have three items later, we have come to conclusion that
     they have done adequate evaluation job and proposed adequate scope of
     programs to achieve the needed management of aging effects of BG&E
     building structures.
         Please go to page 83.  There are three open items.  The
     first one is pertaining to the tendon force trending analysis. Because
     of the major difficulties experienced in the tendon areas, and the staff
     asked BG&E to show some trending of the existing forces in the tendons
     to stay above the minimum requirements called for by the design, at the
     end of the 60 years or 20 years extended period, and this is the first
     open item.
         The second one pertain to the concern of the groundwater
     effect on the intake structure from the embedded surface areas and the
     BG&E presented some chemical analysis of the groundwater for the plant. 
     In fact, they provided three reports.  One of the three testing show
     very high -- concern on the degradation of the concrete surfaces.
         So for this reason, the staff asked BG&E to commit to
     perform at least some portion of the inspection on the outside exterior
     surfaces of the intake structures before the starting of the license
     renewal period at least one time, and this is the second open item.
         The third open item pertain to the BG&E need to further
     address the effect of aging due to irradiation and temperature on the
     cover, O-ring and other known metallic materials for the electrical
     penetrations.
         Please go to page 84.  There are two confirmatory items. 
     The first one pertain to the BG&E commitment to perform inspection
     before year 2002 of the containment domes.  There have been some
     freeze/thaw induced degradation observed on the top of the containment
     and BG&E maintains that -- but the staff wants to make sure, you do this
     inspect one before year 2002, and they consented.
         The second item pertain to the BG&E commitment to further
     enhance the guidance on their MN-1-319, which is quite often used in
     many of the programs.  The enhanced area covers, number one, to provide
     much more detailed guidance on how to judge the functionality of the
     structures and components.
         The second item is to further enhance the guidance on how
     they can change -- the authority to change the programs, scoping
     decision criteria, and how to change the schedule of inspection.
         So these two item BG&E has committed enhance in their
     program MN-1-319.       There are six -- page 85, please.  There are six
     license renewal issues.  Most of these issues are not germane to BG&E
     because they already provided information specific to their plant and
     one item -- two items that staff has yet to develop their own position.
         So I am reporting to you that the license renewal issue does
     not pertain to BG&E application.
         With this, I am concluding my presentation and if you have
     any questions, I would be pleased to answer your question.
         DR. FONTANA:  Let me take time to look at these just for a
     second here.
         DR. UHRIG:  These issues will be resolved before -- these
     six issues.
         MR. JENG:  The six issues are not germane to BG&E's
     situation.
         DR. UHRIG:  Okay.
         DR. FONTANA:  Any comments?  Any additional comments?
         [No response.]
         DR. FONTANA:  Well, thank you very much.
         MR. JENG:  Thank you.
         DR. FONTANA:  Thank you.  We'll move on to component
     support, cranes and electrical commodities.
         MS. LI:  I'm Renee Li, from Mechanical Engineering Branch,
     in Division of Engineering.  The section I'm going to talk about is
     Section 3.11, which covers component supports, cranes and electrical
     commodities.
         For component support, the component support is defined as
     the connection between a system or a component within a system and the
     structure member.  All component support type that provide support to
     system and the components which are within the scope of license renewal
     are also considered to be within the license renewal.
         The component support including piping supports, cable
     raceway support, HVAC ducting support, and equipment support.  The
     support section also include the piping segments that provide structure
     support.
         These piping segments include piping segments beyond the
     safety and the non-safety-related boundary to the first seismic
     restraint and they perform the intended passive function of providing
     structure support to the safety-related piping.
         The crane section include fuel handling equipment and other
     heavy load handling cranes.  This section covers the evaluation of, A,
     components involved in fuel handling and transfer and, B, cranes that
     routinely lift heavy loads over safety-related components that are
     associated with fire systems, spent fuel storage, refueling pool,
     elevator fuel handling and the cranes.
         The last section I'm going to talk about is the electrical
     commodity.  The electrical commodity include the structure enclosure for
     electrical equipment which provides support and protection of the
     electrical equipment located within them.
     The electrical commodity include miscellaneous panels, motor control
     center cabinets, switch gear, disconnected cabinet, bus cabinets,
     circuit breaker cabinet, local control station panel, battery terminals,
     and the charger cabinet, and inverter cabinet.
         The following three slides will show the applicant proposed
     aging management program to manage the aging effects and which will also
     show which components that -- component support that those aging
     management are credited for.
         Our review is to ensure that the applicant's proposed aging
     management program will manage the aging mechanism and the effects in
     such a way that the intended function of the component supports will be
     maintained in accordance with the current licensing basis during the
     period of extended operation.
         As you see, the aging management program for general
     corrosion of steel, which has combination of numerous program, and the
     most of the program have been addressed earlier.  I think the only one
     maybe is the snubber visual inspection surveillance program, and that's
     the tech spec snubber surveillance program, which has a table that will
     determine the frequency and also the sample size of each inspection.
         The other have been covered, except addition of baseline
     walkdown, which is to pick up those component supports that are not
     covered by the original baseline inspection.
         Preventive maintenance checklist.  Usually, the PM checklist
     or the task is for a specific component or component support.  For
     example, there is a preventive maintenance checklist that's a modified
     version of the existing program and it's credited for aging management
     of the metal spring isolator and the fixed basis component supports,
     such as containment air cooler fan.
         The same program for the general corrosion of steel are used
     for managing the effects of loading due to hydraulic vibration or water
     hammer.
         The next slide shows the aging effects of loading due to
     some extension of piping and the component, and aging management program
     basically are very similar to the previous one.  The first one is the
     structure and the system walkdown.  The second one is the control of
     shift activity.  The third one is the ownership of plant operating
     spaces and also the section 11 ISI program.
         The same program is also used to manage the aging effects of
     loading due to rotating machinery.  The last slide for the component
     supports has to do with aging effect of elastomer hardening and the
     program -- the aging management program, the three programs we already
     discussed, plus the plant modification program, the plant modification
     program is a new program and that's credited for the modification of
     control room HVAC air handler support to replace elastomer isolator with
     the spring-type isolator.
         The last aging effect is the stress corrosion cracking of
     high strength bolts and the aging management program that is credited
     for ISI and addition of baseline walkdown.
         And for the piping segment that provides structure support,
     in the application, BG&E states that the same aging effect for the
     safety-related portion of the piping will apply to these piping segment
     beyond the safety and the non-safety-related boundary.  Therefore, the
     aging management program that credits for managing the aging effects of
     safety-related portion of piping are also applicable to those piping
     segments.
         The next two slides are for fuel handling equipment and
     other heavy load handling cranes.  Again, our review is to ensure that
     the applicant's proposed aging management program will manage the aging
     effects in such a way that the intended functions of the components will
     be maintained in accordance with the current licensing basis during the
     period of extended operation.
         BG&E has proposed numerous evaluation programs, procedures,
     instructions, and including PM tasks, and those programs have been used
     for different combinations of aging effects and the fuel handling
     equipment or the heavy load handling crane.
         The aging effects they cover has general corrosion,
     oxidation, fatigue, and wear.
         The next slide will show the mechanical degradation,
     distortion, and also corrosion due to boric acid.  I will not go into
     the detail of the various PM programs.
         This is the slide for the mechanical degradation,
     distortion, and also corrosion due to the boric acid.
     Most of the programs that I just showed, they are existing programs. 
     Just a few are the modified programs and the programs generally provide
     requirements for inspection.  Most of the inspections are visual
     inspections, but they have some NDE, and each program is credited for
     discovery and management of certain aging effects for a specific group
     of components.
         I think one of the programs, that is the boric acid
     corrosion inspection, this morning has been discussed and there are some
     specific concerns of that program.
         DR. SHACK:  Is the snubber considered a passive support or
     are you --
         MS. LI:  The snubber itself is active.  But between the
     snubber and the structure, the portion we consider as a support to the
     snubber, is passive.  So that is the one that's inside scope.
         DR. SHACK:  But the active function of the snubber is
     checked.
         MS. LI:  Is checked per the tech spec.
         DR. SHACK:  Under the tech spec.
         MS. LI:  That's right.  The next two slides are for the
     electrical commodity.  The applicant has identified the aging effects of
     fatigue and electrical stressor and the wear, also general corrosion and
     the dynamic loading on the motor panels.
         As far as the aging management program, for the fatigue, the
     licensee credits the PM checklist, I think the name is reactor trip
     circuit breaker inspection, and that has a requirement of every 48
     weeks, they do a visual inspection and also require that if any fatigue
     degradation is detected, it should be reported and they evaluate per
     site corrective procedures, and operating experience showed that this
     has been very effective.
         Also, the program, ARDI is also credited for these aging
     effects.
         For the electrical stressors, the PM procedure, MN-1-102, is
     credited and in accordance with the PM procedure, repetitive tasks are
     performed, train, inspect, and calibrate the electrical commodity, and
     if there is any degradation, it will be reported and they evaluate and
     correct action taken.  Also, the ARDI program is credited for this aging
     effects and I think for the other two, for maintenance procedure and the
     ARDI, the dynamic load -- yes.  The dynamic loading on the motor control
     center panel are the one that nearby the emergency diesel generator and
     the concern is the vibration.
         The staff's review, we do not identify any open item or
     confirmatory item and also there is no license renewal issue in this
     area.
         Based on the information provided by the applicant, we are
     able to conclude that the aging management program will be adequate to
     manage the aging effects identified by the applicant and we believe that
     there is a reasonable assurance that component support, fuel handling
     elements, heavy load handling cranes and the electrical commodity will
     perform their intended function in accordance with the current licensing
     basis during the period of extended operation.
         That concludes my presentation.
         DR. FONTANA:  Any comments?
         [No response.]
         DR. FONTANA:  Thank you very much.
         DR. SEALE:  Drinking with a fire hose.
         DR. FONTANA:  Pardon?
         DR. SEALE:  Drinking with a fire hose.
         DR. FONTANA:  The next area -- is it one presenter for the
     remaining areas?
         MR. SHEMANSKI:  Yes.  I've got the next four sections.
         DR. FONTANA:  Okay.
         MR. SHEMANSKI:  I may need some help, though.
         DR. FONTANA:  All right.
         MR. SHEMANSKI:  Good afternoon.  My name is Paul Shemanski. 
     I'm with the Electrical Instrumentation and Control Branch, Division of
     Engineering.  I will be making presentations on the four remaining
     sections; Section 3.12, 3.13, 4.1 and 4.0.
         Starting with Section 3.12, which is entitled electrical
     components.  This section is devoted primarily to not EQ cables. 
     Electrical cables are long-lived, passive components that are within
     scope and subject to an AMR and cables that are associated basically
     with every plant system.
         At Calvert Cliffs, there are approximately 30,000 cables and
     of the 30,000 cables, 29,000 are non-EQ cables and 1,000 are EQ cables.
         Again, this section deals primarily with the non-EQ cables. 
     Because of the large population, BGE decided to treat cables, the non-EQ
     cables as a commodity and for efficiency, the 29,000 non-EQ cables, they
     were divided up into six groups, as indicated on the slide.
         The first two groups are located in the main steam
     penetration room.  The first group consists of cables and power control
     servers routed without maintained spacing, whereas the second group
     consists of cables and power servers which are routed with maintained
     spacing.
         The reason group number two has maintained spacing is that
     these cables are designed to carry larger currents, so they have to be
     spaced a certain number of cable diameters away from each other, so that
     you don't suffer the thermal effects of self-heating, due to ohmic
     heating.
         DR. MILLER:  So the spacing requirements are strictly the
     ohmic heating.
         MR. SHEMANSKI:  It's the ohmic heating and the spacing is
     determined by the actual -- I guess they go through and do the thermal
     calculations and determine how many cable diameters away form each other
     they must be spaced.  It's a function of the cable loading, the current
     it's carrying.
         DR. MILLER:  Are any of these cables -- are there any in
     radiation areas?  I notice you have -- I'm looking at the LRA right now
     and you have a lot of discussion of cables that are in radiation areas
     and how you're going to handle those through calibration and so forth.
         MR. SHEMANSKI:  These particular cables are located in the
     main steam penetration room and I do not believe -- Carl, is that
     correct?  I think they're only subject to thermal.
         DR. MILLER:  These probably aren't in radiation areas.
         MR. SHEMANSKI:  I don't believe these are.
         MR. YODER:  My name is Carl Yoder.  Those cables in the
     first two groups are outside containment.  They are in the aux building,
     not just the main steam pen room, but throughout the aux building.
         MR. SHEMANSKI:  Now, group three, cables and power servers,
     those are located in containment and they are subject to synergistic
     thermal and radiation aging and the max temperature in containment is
     120 degrees F.
         Group four, cables in the four KV power service, those
     cables are subject to thermal aging and they are used for the four KV
     pump motors in the saltwater system.
         Group number five, those cables are located in
     instrumentation service and they are subject to thermal aging resulting
     from a reduction of insulation resistance.
         DR. MILLER:  So those are subject to degradation.
         MR. SHEMANSKI:  Yes, they are.  Instrumentation cables tend
     to be smaller and more susceptible because of their physical dimensions,
     more susceptible to thermal degradation, and those particular ones, they
     manage the aging through instrument calibration program.  They
     periodically calibrate the instrumentation circuitry and they can, in
     essence, tell if they're getting degradation due to calibration errors
     or whatever -- not calibration errors, but changes in calibration.
         DR. MILLER:  So the concept -- I'm reading this section
     right now in the LRA.  The concept there is you have -- starting at
     excessive drifting, for example.  You're going to attribute those to
     cabling or --
         MR. SHEMANSKI:  You start by doing a root cause analysis and
     it may lead you to a determination that the cable insulation may be
     degrading, resulting in the increase in -- or I should say reduction in
     insulation resistance and that would effect the calibration of the
     instrumentation circuits.
         DR. MILLER:  And all those cables are accessible, so they
     can replace them.
         MR. SHEMANSKI:  I believe so.  And the last group are cable
     sin the four KV power service.  They're also used for the four KV pump
     motors in the saltwater system, but they're -- well, they looked to see
     if they were susceptible to a degradation mechanisms called treeing. 
     Treeing is a form -- it's a high voltage induced degradation.  It
     results in kind of a tree-like pattern in the cable insulation and its
     degradation that provides hollow microchannels in the cable to grow.
         And as those microchannels grow, I guess, the cable becomes
     -- you have changes in the dielectric material, dielectric
     characteristics of the insulation.  However, they did do an ARDI and
     found that there was no evidence of any treeing in those high voltage
     cables.
         DR. MILLER:  And none of those cables -- are those cables in
     radiation areas?
         MR. SHEMANSKI:  No.  They're in the -- they're used for the
     four KV pump motors.  They are subject to thermal degradation.
         DR. MILLER:  So the only cables really in the radiation
     areas are instrumentation cables.  Is that right?
         MR. SHEMANSKI:  No.  There are cables in power service in
     containment, group three.
         DR. MILLER:  I'm sorry.  You're right.
         MR. SHEMANSKI:  And those, of course, are subject to
     synergistic thermal and radiation aging.
         DR. MILLER:  So how are -- I can probably read it here and
     find it.  How are they going to handle those effects in case --
     instrumentation, I can see they're going to do surveillance.  On the
     power service, how are they going to do those, if there is any
     degradation?  Since we know that degradation of instrumentation cables
     -- I mean, there are different insulators and so forth, I'm certain
     there are.
         MR. SHEMANSKI:  Group three was subjected to an ARDI.  As a
     matter of fact, all six groups were subjected to ARDIs and the ARDIs,
     the age-related degradation inspections, have been completed. 
     Specifically, for group three, BGE is telling us that any power cables
     that satisfy the following criteria, if they're inside containment, if
     they use EPR, which is ethylene, propylene, rubber or cross-link
     polyethylene, if they're not environmentally qualified, which these are
     non-EQ cables, they're saying that these are considered to be subject to
     plausible synergistic radiation and thermal aging.  So they will --
     those are plausible aging mechanisms, so they will periodically have to
     look and see if they are getting any type of degradation.
         DR. MILLER:  Is that by visual inspection?
         MR. SHEMANSKI:  Well, one way.  They do have monitors,
     radiation temperature monitors.  They know what the threshold levels are
     of the cable insulation material.  Carl, I believe, wants to amplify.
         MR. YODER:  I just want to clarify.  With regard to those
     cables we have determined to be subject to plausible aging, except for
     the instrumentation cables, which will be subject to loop calibrations
     that include the cables, the rest of those, we've committed to replace.
         DR. MILLER:  So they're all accessible for replacement, in
     other words.
         MR. YODER:  Well, we'll probably end up re-running them.  We
     won't pull all the cables out.
         DR. MILLER:  So you pull the old ones out and you'll
     re-route them if you can't route them --
         MR. YODER:  We normally would not pull an old cable out
     because it would probably damage surrounding cables.  So we'd run new
     ones.
         DR. MILLER:  I see.
         MR. SHEMANSKI:  This particular slide shows the various
     aging effects which cables are subject to, embrittlement, cracking,
     reduced mechanical integrity, swelling and so forth, insulation
     resistance reduction.  And we mentioned the ARDI program, which has been
     completed for these cables.
         I also talked about the instrument calibration program.
         As a result of our review of these non-EQ cables, we did not
     identify any open items or license renewal issues.
         DR. MILLER:  Now, somewhere I saw that, of course, there is
     a generic issue 168 on cables.  How do we get around that?  That's not
     been fully reconciled yet.
         MR. SHEMANSKI:  This particular section is on non-EQ cables.
         DR. MILLER:  That's non-EQ, you're right.  I'll wait for
     that.    
         MR. SHEMANSKI:  My last presentation will be on EQ.  168,
     GSI-168 is devoted to environmental qualification.
         DR. MILLER:  We'll wait.
         MR. SHEMANSKI:  This is not the section, 3.13.  This is
     confusing.  Let me explain how we arrived at putting this section in the
     SER.
         If you look in the license renewal rule, EQ appears twice. 
     It appears once under scoping, where the five regulated events are
     listed, ATWS, fire protection, PTS, so EQ is listed under scoping.  Then
     it appears again in the EQ rule -- I mean, in the renewal rule as a
     TLAA.
         This particular section, when BGE generated their
     application, they wanted to address the scoping aspect of EQ, which
     requires that you look at passive, long-lived components.  So what they
     did was they took the EQ master list and they only looked at the
     long-lived, passive components on the EQ master list, where there may be
     intended functions of these components that are not managed by the EQ
     program, and because the EQ program focuses primarily on radiation and
     temperature.  Those are the main parameters.
         However, if you look at some of these components, such as
     the containment penetration assembly, that is subject to general
     corrosion.  Well, that general corrosion is not handled by the EQ
     program.  So BGE identified four components here, the containment
     penetration assemblies, core exit thermocouples, they're subject to
     crevice corrosion and pitting, solenoid valves, they're subject to
     crevice corrosion and pitting, and the reactor level vessel monitoring
     in core assembly, which is subject to crevice corrosion and pitting.
         For those particular aging effects, they identified the
     following programs.  For the specific class of EQ components, the ones I
     just mentioned, general corrosion, crevice corrosion and pitting, those
     are handled by the chemistry control program in PEG-7, which I believe
     is a walkdown type program.
         Kapton-unique aging, that one is dealing with the insulated
     wires on Valcor solenoid valves.  It turns out that Kapton, it's not an
     extruded insulation material.  It's sort of wrapped and, as such, it's
     more susceptible to absorbing moisture and under hot high moisture
     conditions, hot temperature and high moisture conditions, the Kapton can
     absorb water and then it becomes very brittle.
         It really should only be used in an environment less than 40
     percent.  So that's sort of a unique aging effect for a particular type
     of solenoid valve that BGE is using.
         There were no open items or confirmatory items or license
     renewal issues associated with this subset of EQ components that I just
     discussed.
         DR. UHRIG:  Are any of the Kapton-unique components used in
     safety systems?
         MR. SHEMANSKI:  I believe so.  They're used as solenoid
     valves and I believe the answer is yes, they are in safety-related
     systems.  They are on the EQ master list.
         DR. UHRIG:  So anything that's EQ would be on a safety
     system.
         MR. SHEMANSKI:  Right.  Although it is possible, on the EQ
     master list, there are some non-safety-related components that may have
     to be qualified.  But probably 95 percent of the components on the EQ
     master list are safety-related electrical components.
         DR. MILLER:  The idea here is they've already been
     qualified.
         MR. SHEMANSKI:  They've already been qualified.
         DR. MILLER:  Tested at least.
         MR. SHEMANSKI:  Right.  They've been qualified through LOCA
     testing.
         DR. MILLER:  And somebody has agreed that a short-term LOCA
     type test is equivalent to a long-term -- you have the same number of
     rads over long-term and it's the same number of a short-term.
         MR. SHEMANSKI:  Well, basically, you're trying to -- in a
     LOCA chamber, you're trying to simulate LOCA and they go through and
     make a calculation of what the expected pressure and temperature is. 
     They try to simulate that in the LOCA chamber and then they add in the
     accident dose that you would expect, typically 150 mega-rads.  So it's,
     in essence, trying to simulate LOCA conditions.
         How long you test it in the LOCA chamber is a function of
     how long the equipment is required to operate post-LOCA, and that varies
     depending on the plant CLV.  Some plants have a 30-day operability time,
     others go up to, I believe, one year.  It's a function of when the plant
     was licensed.
         DR. MILLER:  Of course, that's not a synergistic test. 
     Temperature and radiation is not the same thing.
         MR. SHEMANSKI:  Well, you do get a -- there is a synergistic
     effect.  You get added degradation when you combine radiation and
     temperature.
         DR. MILLER:  They just aren't done at the same time.
         MR. SHEMANSKI:  Right.  Are there any additional questions
     on cables?  Because the next presentation will be on TLAAs.
         DR. MILLER:  The generic issue, are you going to address
     that here sometime?
         MR. SHEMANSKI:  Yes.  The next presentation --
         MR. SOLORIO:  Paul, can I interrupt something?  Before you
     go on, Paul.  BG&E pointed out to me something related to an earlier
     presentation the staff has made on Section 3.11.  With respect to the
     electrical commodities, BG&E has changed their commitment to use ARDI as
     one of their aging management programs and they're going to use
     electrical penetrations.  That was a recent change and the staff is
     reviewing that against the SER, because it's currently not reflected in
     the staff's SER.
         However, I don't anticipate there being any significant
     changes, because we're really talking about going to -- the nature of
     the program probably is going to be very similar and it's probably going
     to be even more frequent.
         As opposed to a one-time inspection, it's going to be a
     periodic type of inspection.  So I don't see a significant change in
     that area.
         MR. SHEMANSKI:  Okay.  The next section in the SER, Section
     4.1, is the identification of time-limited aging analyses, TLAAs.  BGE
     has identified each TLAA with its aging effect and its disposition,
     demonstrating that the analyses either remain valid for the period of
     extended operation, the analyses have been projected through the end of
     the period of extended operation, or the effects of aging on the
     intended functions will be adequately managed for the period of extended
     operation.
         In my next presentation, I'll go into a little more detail
     on EQ, because you haven't heard anything about that yet.  However, for
     the other TLAAs, which appear on this slide and the next slide, this is
     a total list of TLAAs.
         Do you have any specific questions on those?  You heard most
     of the discussion regarding fatigue monitoring program and I believe
     most of these, if not all, have been covered by previous speakers.  So
     if you do have any specific questions on any of these TLAAs, we have
     several staff members that probably would be in a better position to
     answer them.
         Basically, what I've given you here is the list of the TLAAs
     that have been identified by BGE.  I'll just run through them one by
     one.  The heat-up and cool-down curves, the aging effect is radiation
     embrittlement and the aging management program relies on the G and H, 10
     CFR 50 Appendices G and H curves, and data from the surveillance
     capsules.
         DR. FONTANA:  TLAA involves equipment that whose lifetime
     originally -- let me see if I understand this properly.  It's equipment
     whose lifetime originally could have gone past 40 years, but if you're
     going to extend a license, it can go -- the equipment will have to
     operate beyond what may have been its design life.  Is that correct,
     basically?  And you have to analyze that it's going to be able to
     perform its function during this additional time period, is that
     correct?
         MR. SHEMANSKI:  Right.
         DR. FONTANA:  Now, the analysis then is done, like the
     heat-up and cool-down curves on radiation embrittlement, the analysis is
     obviously quantitative.  You have models and predictions and that sort
     of thing.
         They're not referenced here.  I guess if you look at the
     BG&E report and you track the references all the way through, they
     should take you to the models and data and uncertainties and everything
     else.  Is that correct?
         MR. SHEMANSKI:  Well, they should, yes.  Right.
         DR. FONTANA:  Well, do they?
         MR. GRIMES:  Dr. Fontana, if I could.  The simplest way to
     describe time-limited aging analysis is basically a design analysis
     that, in some way, incorporates 40 years in the design calculation.  So
     for example, the PTS analysis has a plant life assumption it.  Fatigue
     has a certain number of cycles assumed in it.
         And this, the aging management aspect of time-limited aging
     analysis is either that you show that the -- you state the analysis has
     already been updated for a 60-year life, you -- it either already
     exists, it has been updated to 60 years, or it will be managed in some
     way.
         DR. FONTANA:  Well, how do you know it's any good?
         MR. GRIMES:  We review the analysis results.  We've either
     done it -- as Barry mentioned earlier, we've already done a safety
     evaluation related to embrittlement for a 60-year life.  In other cases,
     there are analyses that we've seen before.  So by sampling a typical
     analysis, we have confidence that simply redoing the analysis with a
     different assumption is all right, or there is an aging management
     aspect associated.  There is a process aspect that we can refer to.
         MR. ELLIOT:  I'm Barry Elliot.  The pressure temperature
     limits curves are developed from the requirements in Appendix G and the
     requirements in Appendix H is the surveillance program.  That's just to
     confirm that the embrittlement we used for the curve is what we think it
     is.
         Now, the embrittlement -- the non-embrittled portion of the
     analysis is in the ASME code.  It's a specified way of calculating
     pressure temperature limits.  The part that's age-related degradation is
     the embrittlement portion and that is -- we have regulatory guide, Reg
     Guide 1.99, Rev 2, which describes how you are to calculate the amount
     of embrittlement which goes into these pressure temperature limits. 
     What we do is if a new pressure temperature limit comes in, we review
     the surveillance data, we review the methodology of calculating the
     embrittlement to make sure it complies with what's in the regulatory
     guide.
         So this is time-limited aging.  It happens to be, for this
     particular plant, they gave us a 48 effective full power year curve
     already and so they've already done -- for the equivalent fluence of 48
     effective full power years, for Unit 1.  For Unit 2, I think they have
     only a 30 effective full power years.
         So sometime in the future, before 30 effective full power
     years, they have to give us another curve that applies to 48 effective
     full power years.  But they would be following the guidance in the --
     the requirements of Appendices G and H and the regulatory guidance in
     Reg Guide 1.99 to calculate those curves.
         DR. FONTANA:  Okay.  Thanks.
         MR. SHEMANSKI:  Okay.  The next two TLAAs involve fatigue
     analysis for RCS piping, steam generator pressurizer, pressurizer
     auxiliary spray line, and pressurizer surge line.  The next one is the
     fatigue analysis for main steam supply lines for turbine-driven aux feed
     pumps, and those are both managed by the fatigue monitoring program.
         In addition, the next TLAA is also managed by the fatigue
     monitoring program, fatigue analysis for the containment liner plate. 
     The next TLAA is the pre-stress loss calculations on containment
     tendons.  That particular TLAA has been deferred by Baltimore Gas &
     Electric to the year 2012.
         Another TLAA is the spent fuel pool criticality calculation,
     the aging effect is loss of neutron absorption and the coupon
     surveillance program is used as the aging management program for that.
         DR. FONTANA:  I'm just curious.  How do you go about
     measuring the tension in the tendon?
         MR. SHEMANSKI:  They've got a lift-off test which is in the
     tech specs and I forget the parameter, 2000 KIPS or some -- I don't
     recall the exact number, but they have kind of a jack and they're able
     to measure the lift-off force with the tendons, and that's really not my
     area.
         DR. FONTANA:  Okay.
         MR. SOLORIO:  The NRC staff reviewer who evaluated that
     isn't here at the moment, but I believe someone from BG&E has some
     information they can provide.
         DR. FONTANA:  I'm sure you know how to do it.  I was just
     curious.
         MR. WARD:  I'm Don Ward.  It's sort of backing out of the
     way they're installed initially.  The tendons are installed with shims
     under both ends, so that you wind up with stretching the wire in order
     to get the tension in there.
         When you do the lift-off test, you put a ram back on one end
     or a jack, a thousand-ton -- I'm sorry -- a 500-ton jack, pull on it,
     and measure the force.  There are gauges on the jack that you can
     measure the force with.
         DR. FONTANA:  Five hundred ton jack.
         MR. WARD:  Yes.  They carry about 700,000 pounds each.
         DR. FONTANA:  Thanks.
         DR. SHACK:  What does it mean when the program is deferred
     to 2012?
         MR. PATNAIK:  This is Pat Patnaik.  What we got from the
     applicant, that they would provide us the curves, the loss of stress,
     pre-stress loss, on the tendons, calculated to the new values.  That
     will be covered in the tech specs.  Those are in the tech specs.
         MR. WARD:  Don Ward again.  The part that was in the tech
     specs, that you will now remember being in the tech specs, was recently
     moved to chapter 15 of the FSAR, but it's the same sort of thing.  It's
     these curves plot on semilog paper as a straight line.  We were just
     looking to see if there are any nuances and so it's being deferred a
     bit, particularly until we decide what we're doing with the vertical
     tendons.
         MR. SOLORIO:  This is Dave Solorio.  I just wanted to point
     out also that there is an open item associated with this.  Page 109.
         MR. SHEMANSKI:  It's open item 4.1.3-2, deferral of the
     re-calculation of loss of pre-stress on containment tendons, to the year
     2000.  Since we're on open items.
         There is also an open item on the addition of the upper
     shelf energy evaluation as a TLAA.  The staff has concluded that this is
     a TLAA and should be treated as such.  The third open item is the
     addition of metal fatigue of B-31-7 Class 2 and Class 3 piping as a
     TLAA.  Apparently, BGE did not -- I'm sorry -- BGE did consider the
     number of cycles in the evaluation of Class 2 and Class 3 piping.
         Therefore, the staff feels that this is a TLAA, should be
     treated as a TLAA.  There is one confirmatory item regarding
     documentation of containment liner plate fatigue analysis.  Basically,
     BGE needs to document the evaluation which demonstrates that the current
     analysis remains valid for the period of extended operation.
         We list one license renewal issue, 98-0048, elevated
     temperature of pre-stress in tendons.  This, I believe, was previously
     discussed in Section 3.10 of the staff SER on building structures.
         Are there any additional questions regarding TLAAs?
         [No response.]
         DR. FONTANA:  I guess not.
         MR. SHEMANSKI:  If not, then I'll go to the final TLAA,
     which is EQ, environment qualification of electrical equipment.  BGE
     identified the 10 CFR 50.49 program, that's the EQ rule, 50.49.  BGE
     identified that as a TLAA for license renewal.
         Now, it's important to note that when the staff evaluated
     the BGE TLAA for EQ, we focused on the program elements and process, and
     I will repeat that again.  We focused on the program elements and
     process provided by BGE.
         They are using standard approved EQ methodology and
     acceptance criteria in accordance with the 10 CFR 50.49 EQ rule.
         Basically, the way BGE is treating it, for all of the
     long-lived active and passive, this TLAA is unique, it includes -- this
     is the only TLAA, the only place in the application you'll see where we
     have active components in license renewal.
         It just so happens that the EQ rule 50.49, when you look the
     EQ master list, it consists of active and passive components.
         DR. MILLER:  Did they do that just for convenience?
         MR. SHEMANSKI:  No.  I mean, that was the way the EQ rule
     initially was developed.  You had to list or include all of the
     electrical components that --
         DR. MILLER:  All safety-related.
         MR. SHEMANSKI:  All safety-related electrical components
     that are, number one, subjected to a LOCA or main steam line break or
     high energy line break; that is, subjected to a harsh environment, and
     then required to mitigate that particular DBE.
         You look at the list, it includes, as you could see, motors,
     transmitters, pressure switches, all of which are active.  But for this
     particular TLAA, we do include both active and passive long-lived
     components.
         DR. MILLER:  But it wasn't required to do that.  Is it
     required to do that by the rule?
         MR. SHEMANSKI:  Which rule are you referring to?
         DR. MILLER:  By the rule, the license renewal rule.
         MR. SHEMANSKI:  The focus of the Part 54 rule is on
     long-lived --
         DR. MILLER:  Passive.
         MR. SHEMANSKI:  -- passive components.  However, it does
     list five regulated events.  It lists -- in paragraph 54.3, it lists
     fire protection EQ, ATWS, PTS, and station blackout.  And by picking up
     the EQ rule, you automatically pick up the EQ rule master list, which
     has active components.
         DR. MILLER:  So by including EQ, you automatically pick it
     up.
         MR. SHEMANSKI:  You automatically pick these up.  So there
     -- and basically the aging management program for EQ is the 50.49
     program.
         DR. MILLER:  In a way, the rule 54 picks up through EQ the
     active components.
         MR. SHEMANSKI:  Right.
         DR. MILLER:  The EQ program then covers you.
         MR. SHEMANSKI:  That's correct.
         DR. MILLER:  That's a simple way to put it.
         MR. SHEMANSKI:  And the way BGE approaches the qualification
     of these particular components is prior to the end of an equipment's
     qualified life, the equipment will be replaced, unless it can be --
     unless the qualified life can be extended through reevaluation,
     primarily re-analysis.  So they tell us that sufficiently in advance,
     prior to the expiration of a component's qualified life, they will go
     through and determine whether or not that component needs to be replaced
     or whether or not they could extend the qualified life based on
     re-analysis or some type of reevaluation.
         Now, we reviewed the methodology that BGE is using in their
     current EQ program, and keep in mind that they do have an approved 50.49
     program.  They've got an SER issued by the staff in the mid '80s which
     finds their EQ program in compliance with 50.49.  So they're solid for
     the first 40 years.
         And as equipments on the EQ master list approach the end of
     their qualified life, they will be re-assessed ten years from now just
     as they are today.  They will be using the same methodology.
         So we looked at how they extend their component qualified
     life and we evaluated or looked at the acceptance criteria they apply,
     what type of corrective actions they use, how they go about
     refurbishing.
         We looked very closely at how they would be applying
     re-analysis, how they treat the thermal and radiation environments, and
     what effect any plant environmental changes would have on the
     qualification status.  So we took a pretty in-depth look at their
     existing program, basically doing a process type evaluation, and are
     satisfied that 50.49 is an acceptable aging management program.
         DR. MILLER:  So 50.49 covers everything that we've talked
     about all day today.
         MR. SHEMANSKI:  Well, 50.49 focuses primarily on electrical
     components in a harsh environment.  The key stressors they are subjected
     to are thermal and radiation and if they happen to be subject to spray
     from the ECCS system, caustic spray, then, of course, they --
         DR. MILLER:  Boron -- boric spray.
         MR. SHEMANSKI:  Right, they've got to simulate that in the
     LOCA chamber, that is part of the qualification process.
         This slide shows the aging effects due to thermal and
     radiation primarily, and those aging effects are managed by the
     qualification process, which is utilized in the 50.49 program.
         DR. MILLER:  So were all the things like all the sensors and
     so forth excluded and all the rest of the program, now we've got
     pressure and flow transmitters all included at this point for these --
     if they're EQ.
         MR. SHEMANSKI:  Right.
         DR. MILLER:  And we assume an environmental qualification
     covers all the issues we talked about.
         MR. SHEMANSKI:  Well, it does not cover things like crevice
     corrosion or general corrosion.  It turns out that some of these
     components on here, electrical penetration assemblies, solenoid valves,
     they have a license renewal intended function, for example, to maintain
     pressure boundary and that particular function is really not -- it's not
     evaluated in the EQ program.  That was why BGE, when I went through
     Section 3.13, they looked to see are there -- they went through these --
     this entire EQ master list and they said are there any of these
     components that have intended functions such as pressure boundary that
     are not covered by the EQ program, and they did find four, I believe.
         DR. MILLER:  Solenoid valves were addressed separately in
     there.
         MR. SHEMANSKI:  Right.  So they are subject to general
     corrosion or pitting and, of course, those aging effects are not managed
     by the EQ program, but they're managed by other programs, I believe the
     chemistry control program.
         So the bottom line is I think they've got all the -- all of
     the plausible aging effects have a management program.
         DR. MILLER:  In that list, there's, of course, a whole bunch
     of passive components.  They've already been covered under the other
     program, as well as this one.
         MR. SHEMANSKI:  Right.
         DR. MILLER:  So the only questionable one would be
     components such as flow transmitters and pressure transmitters and level
     transmitters.  Those might be the only ones that might be falling
     through the crack, so to speak.
         MR. SHEMANSKI:  I don't believe they have fallen through the
     crack, because I don't think those particular ones have any license
     renewal intended functions that are not being managed by the EQ program.
         DR. MILLER:  I'm not saying they did.  I'm saying they could
     have.
         MR. SHEMANSKI:  They could have.  We did look and I don't
     believe --
         DR. MILLER:  Based on the fact that we spent maybe five or
     ten hours on this, everybody else has spent many more than that.  I just
     looked at it from a superficial viewpoint and I would say, gee, did we
     cover everything of those active components that weren't covered under
     all the other programs, does EQ cover everything under those.
         MR. GRIMES:  Dr. Miller, I looked at --
         DR. MILLER:  Am I asking a question that makes any sense?
         MR. GRIMES:  Yes, and I'd like to attack your question in a
     slightly different way.
         DR. MILLER:  Don't attack it.  Address.
         MR. GRIMES:  Address.  Okay.  First of all, I want to
     clarify, time-limited aging analysis don't care about the license
     renewal scope.  They're a time-limited aging analysis.  There is a
     qualified life.  EQ just happens to be the biggest qualified life
     question we've tackled and for -- to the extent that managing the
     environmental qualification time-limited aging analysis relies upon the
     50.49 program, regardless of whether or not you've got a piece of
     equipment that's active, passive, long-lived, short-lived, whatever it
     is, if it's got an EQ qualified life of a year, 40 years or 1,000 years,
     the 50.49 process will sort that out.
         To get back to your other question about what do we do with
     GSI-168, to the extent that information comes out of that research that
     challenges the qualified life of any particular cable, then that same
     compliance with 50.59 process, about making decisions about replacing,
     refurbishing, re-analyzing or re-testing, we rely on that process to
     address GSI-168 until the research identifies something different to do.
         But to the extent that EQ stuff is also captured as -- in
     4.13 of the -- I'm sorry -- 3.13 of the safety evaluation, where we also
     look at it from the standpoint of are there other aging effects that are
     not explicitly addressed by this qualified life process, like crevice
     corrosion or fatigue or other thing, then we address that specifically
     for passive components.
         For active components, all of those things are excluded for
     the same reason we excluded active equipment and that's basically we're
     looking at reliability under the maintenance program as the means to
     manage aging effects for active components.
         DR. MILLER:  I think I'm visually seeing everything fitting
     together.  I'm now seeing the cracks are closing.
         MR. GRIMES:  The EQ was particularly troublesome for us, as
     well, because even though it's a well established and well regulated
     program, it's got this overlapping area of responsibility and so that's
     why we ended up with one section of the safety evaluation that treats
     aging effects and aging management programs and then time-limited aging
     analysis also has an aging management aspect of it, as well, but it
     really gets back to the process question.
         MR. SHEMANSKI:  My last slide, there are no open items or no
     confirmatory items regarding EQ.  However, we did have one license
     renewal issue, 98-0014, which basically asked the question whether or
     not 10 CFR 50.49 is an adequate aging management program under the
     license renewal rule.  And basically, the answer is yes, and we
     concluded in the BGE SER that 10 CFR 50.49 is an acceptable aging
     management program under 10 CFR 54.21.
         MR. GRIMES:  Paul, if I may.  I would like to clarify that
     this particular generic renewal issue has now blossomed into what we
     call the credit for existing programs issue, which was forwarded to the
     Commission and I believe that the ACRS received a copy when we forwarded
     the NEI letter.
         We're developing a Commission paper that addresses the
     extent to which the staff can conduct a license renewal review without
     challenging the adequacy of these existing programs.
         So you will be hearing more about that, but for the purpose
     of this review, we challenged the existing programs.  We went digging
     into, for example, environmental qualification and compliance with
     50.49.  The means of compliance as it relates to managing aging.
         So you will be hearing some more about that issue, but it's
     really more relevant to treating future applications.
         DR. FONTANA:  The future applications, these license renewal
     issues that are resolved now, are they assumed to be resolved for all
     future applications?
         MR. GRIMES:  To the extent that we would add guidance to the
     standard review plan or that NEI would add guidance to the NEI 95-10
     guide on preparing an application, yes, we consider them resolved for
     future applications, too.
         DR. FONTANA:  We're a little overdue on our break.  Any
     questions on this area here?
         MR. WESSMAN:  Before we go on a break.  I'm Dick Wessman,
     with the staff.  A minor housekeeping item.  On page 108 of the
     viewgraphs, we had an erroneous entry there and I wanted to clarify
     that.  If you look at that, you will see a couple of entries, one of
     them dealing with fatigue analysis for the containment liner and another
     one at the bottom dealing with Class 2 and 3 piping.
         Those two activities are not covered by the fatigue
     monitoring program, per se, but they are addressed by analysis
     activities done by the applicant.
         DR. FONTANA:  Thank you.
         MR. WESSMAN:  Yes, sir.  That's all.
         DR. FONTANA:  Let's take a break.  Let's see.  When we come
     back, we'd like to discuss what will be presented at the May full ACRS
     meeting, some topics for an ACRS interim letter, and possibly what would
     be appropriate for additional staff presentations and maybe for future
     meetings.  So you all may want to be giving some thought to those items.
         So let's come back at 20 of.
         [Recess.]
         DR. FONTANA:  The meeting will come back into session.  The
     first thing that we would like to discuss with you is what should be
     included in a presentation for the full ACRS meeting the first week in
     May.  You have an hour and a half, and that's on the first day, I think,
     Wednesday.  Will you be making most of the presentation?
         MR. GRIMES:  Were you addressing me personally or the staff?
         DR. FONTANA:  You.
         MR. GRIMES:  We'll do -- actually, we do almost anything you
     want.  We can do a summary overview.  We can just have a very high level
     with Dave giving his overview presentation and maybe putting together
     some summaries or if there are particular topic areas, Mr. Wessman was
     graciously supporting us and we could get particular staff to come talk
     about topical interests.
         DR. FONTANA:  Well, the full committee I don't believe has
     received a presentation from you in this area, in my memory at least, I
     don't think.  So I think it's probably appropriate to start from the top
     and give a -- because I'm sure that two or three of them that are not
     here and some that are here don't understand the whole philosophy of
     this license renewal, which is really rather esoteric, just coming off
     the street and listening to it.
         So I think an overview of the philosophy basically that you
     as the staff are working within the constraints of Part 54 and whereas
     we on the committee aren't necessarily.  But with regard to what you're
     doing, I think you probably should quickly overview what Part 54 is
     constraining you to do.
         DR. SEALE:  How long do we have?
         DR. FONTANA:  An hour and a half.  But I think maybe taking
     about ten minutes to get everybody on the same page is probably going to
     be worthwhile, because questions that are going to arise are how do you
     determine what's in scope and what's not in scope, and the concept of
     TLAA is rather esoteric, so you may want to say -- just like you said
     about 20 minutes ago, perfect.
         Then the area of issues, I'm sure there is going to be some
     confusion about what are generic license renewal issues compared to the
     other list of GSIs, and you may want to identify what the difference is,
     and how you -- the basis for the prioritization of the issues, the fact
     we now have 105 of them, when I think there's --
         MR. GRIMES:  It's 109.
         DR. FONTANA:  It's 109, and I forget how many are on the
     priority one list.  In fact, you would allow some issues to go into --
         DR. SEALE:  Sixty years.
         DR. FONTANA:  To go beyond the end of the current license,
     and I'm sure you're going to get asked about that.
         With respect to the SER, I think we'd like an overview of
     it, relating most of the key agreements and what the key issues left are
     and what the key confirmatory things are.  There aren't many of them
     left, as far as I could see.
         DR. SEALE:  Could we get some words from BG&E?
         MR. DOROSHUK:  Yes, sir, we could support that.  Is there
     any specific area?
         DR. SEALE:  Well, in your presentation you made, of course,
     there's a lot of it that's background and all, but the material and the
     scope, your perception of what the scope is, and then the IPA process
     you went through, and then maybe a summary of some sort.
         MR. DOROSHUK:  Yes, sir.
         DR. SEALE:  I think that would be very helpful to the
     committee, because it -- I won't call it a bottoms-up approach, but it
     is the applicant now working with the process as opposed to the
     regulator's perception of what the process ought to come up with, and I
     think that's very important.
         DR. FONTANA:  Those two diagrams.  You have the IPA flow
     diagram, I think that's useful and very valuable.
         DR. SEALE:  Yes.
         MR. GRIMES:  You could start about the IPA flow diagram and
     end up about the last pie chart, and it's that chunk in the middle
     there.
         DR. FONTANA:  How much time do you think BG&E should have
     out of this hour and a half?
         DR. UHRIG:  Twenty, 30 minutes.
         DR. SEALE:  Yes.  Something like that.
         DR. FONTANA:  Something like that.  And I guess you will
     start it, the staff will start it, and you determine between yourselves
     where to break into it, I guess.
         MR. WESSMAN:  I think it would be constructive for the staff
     to do that introduction and overview of the philosophy, then go to BG&E
     with their discussion of how they did the submittal and then come back
     to our SER and we'll pick the specifics that you want us to. That's how
     to handle three 30-minute segments, for lack of a better term.
         DR. SEALE:  Exactly.  Recognizing that you're going to get
     interruptions.
         MR. WESSMAN:  Of course.  Especially by people who are not
     here.  At least we know who they are.
         DR. FONTANA:  Any additional thoughts on what ought to be
     covered in the meeting?
         DR. SEALE:  I could facetiously say that if you don't want
     to get too many interruptions, you might not say anything about fire
     protection, but I guess that --
         DR. FONTANA:  Or risk-based.
         MR. WESSMAN:  That's right, George will be here.  We could
     use, as a clue from you all, as to the specific areas that you think, as
     we try to characterize the SER, that you want us to spend time on.  I
     think there's been a lot of interest in fatigue and we probably need to
     offer that up.  But if you could give us some other specific areas that
     you think are areas of interest.
         DR. MILLER:  I'm not certain this -- this is something I
     need to look at for my own edification, but I'd like to have more
     information on the environmental qualification program and how that all
     fits together, the things we hit near the end.
         Now, again, that may not be generic enough for the
     committee, though.
         DR. FONTANA:  Well, first of all, you want to get --
         DR. SEALE:  We're down to an hour here, guys.
         DR. MILLER:  I know, that's what I say, an hour and a half,
     we won't have enough time for any of these specialty areas.
         DR. FONTANA:  When you get to the SER, an important idea to
     get across, whichever way you do it, is the extreme depth.  The thing
     was actually exhausting to --
         DR. SEALE:  I think the run-through from the first day
     viewgraphs are a good way to state it.  Your presentation, basically.
         DR. KRESS:  David's.
         DR. SEALE:  Yes.  Then the question is do you try to
     cherry-pick somewhere through the rest of the 110.
         DR. MILLER:  Certainly, we've got 30 minutes to go through
     the other 110 slides, and which ones are we going to pick.
         DR. SHACK:  You'll vote for EQ, I'll vote for Barry's part,
     and everybody will pick the part that interests them.
         DR. KRESS:  I would pick the steam generators.
         DR. SEALE:  I think just to get across the idea that you're
     putting a very heavy reliance on inspection, that that's really the tool
     that this process, this whole process relies on.
         DR. UHRIG:  I also think it would be useful to convey the
     concept that this is really using existing programs to the maximum
     extent possible, with modifications where necessary.  Only when this was
     not appropriate did you go to new programs.
         DR. FONTANA:  I guess you ought to do something for common
     aging management programs.
         DR. SEALE:  Yes.
         DR. FONTANA:  This category.  Because I think that's
     important.
         DR. UHRIG:  There were some numbers given about what
     percentage of the -- how many new procedures, how many existing
     procedures, how many modified procedures.  I don't remember the exact
     numbers, but it was --
         MR. GRIMES:  Out of the 430, there were 329 --
         DR. UHRIG:  Those kind of numbers.  I think that gives you a
     picture.
         MR. GRIMES:  Yes, 11 new, 101 modified, something like that.
         MR. DOROSHUK:  We'll make sure we have those slides for that
     particular part of the presentation.
         DR. MILLER:  I guess we're looking at kind of a condensed
     version of what we heard yesterday, right?  Mostly.
         DR. FONTANA:  Bill Shack, do you think one of the things
     that should be touched on is the Section 3.2, vessels internals and
     reactor coolant system?  That's what Barry Elliot covered.
         DR. SHACK:  Well, after you go through the big overview, I
     don't know whether we should -- the 3.1, the aging management review of
     the common management programs maybe should be the big sweep.  Even
     there, I don't think we -- you know, we can't go through it in the
     detail that you went here, but somehow you've got to, out of this thing,
     grab that chunk out.
         I think that will probably chew up --
         DR. MILLER:  You've got an hour and a half right there.
         DR. SHACK:  -- most of the time.  Between those two
     presentations, it's sort of gone.
         DR. FONTANA:  It sounds like we really can't get into much
     of the specific areas.
         DR. SHACK:  I don't see how we can get into the specific
     areas.
         DR. FONTANA:  Unless the question pops up.
         MR. DUDLEY:  There is an alternative.  For the three people
     who are not here, provide them a copy of the slides, where they can see
     what programs are or what systems are evaluated in each chapter.
         DR. KRESS:  Those three people will have also read part of
     the SER and they can come prepared to ask questions.  So we'll make it
     known that if they have an issue with some of that SER, that they need
     to ask.
         DR. UHRIG:  But you could easily send them the slides that
     were used today.
         MR. SOLORIO:  I would like to ask that if you'd let us know
     what areas they've read, so we can prepare the staff.
         MR. WESSMAN:  Yes.  I hate to muster 20 people over here,
     even though it's only an hour and a half.  If there is any way we can
     focus it down to a smaller number of key players.  They're busy working
     on Oconee.
         DR. FONTANA:  It seems to me that you three guys will be
     able to cover it at the level we're talking about.
         DR. SEALE:  Why don't we ask them who they can best do -- I
     mean, the rest of the guys.
         MR. GRIMES:  I'd also like to suggest you -- we've got a
     head start this time.  To the extent that two and a half of us anyhow
     can try and get through as many of the common programs and the basic
     stuff and address broad questions about aging management, as much of
     that as we could accomplish in an hour and a half we're going to have
     next week, we could do that, and then we've still got open items to
     resolve.  We could -- we're going to come back to the committee at least
     once more.
         So we could -- maybe we could get a sense next week about
     what particular areas you'd like to explore further and we could just
     make a commitment that we'll address those in a future meeting.
         To the extent that we can dispose of as much as you can
     dispose of and focus down on particular areas of interest.
         DR. UHRIG:  I think in the preparation of the letter, this
     will be brought to a focus.
         DR. FONTANA:  Will that give you enough to go on?
         MR. GRIMES:  We're going to -- in the hour and a half, we're
     going to devote about 30 minutes to a broad overview of Part 54,
     terminology, the basic elements, what are the time-limited aging
     analysis, basically a day's presentation in a half an hour for BG&E, and
     then a half-hour for the safety evaluation overview, which means three
     15-minute prepared presentations.  Does that pretty well cover it?
         DR. FONTANA:  So that the need for additional staff
     presentations, I think we're saying we will need them, but what's going
     to be included probably will come out of the things that are not going
     to be covered next week, right?
         MR. GRIMES:  Right.
         DR. FONTANA:  So these guys can work up --
         MR. GRIMES:  We'll make commitments next week to address
     particular questions and basically frame an agenda for a future meeting.
         MR. WESSMAN:  We can bring a few of the key people.  I think
     Stephanie Coffin did a lot of work on the ARDI and we'll have her here
     and that may eliminate some of that area of questioning.  So it isn't
     like it will just be the three of us, but I just don't want to muster
     all 20.
         DR. FONTANA:  Any additional ideas, questions?  No?  If not,
     are we done?
         DR. SEALE:  I think so.
         DR. FONTANA:  I'd like to thank the staff and BG&E.  These
     were really well organized response of talks, they were to the point,
     good presentations.  They reflect a tremendous amount of work and we
     appreciate the considerable amount of work you did preparing for this
     meeting, which I'm sure is significant, particularly considering all the
     other things you've got to do.
         So, again, thank you very much, on behalf of the committee,
     the subcommittee.  We appreciate it, and we'll see you next week.
         This meeting is over.
         [Whereupon, at 2:58 p.m., the meeting was concluded.]
Page Last Reviewed/Updated Wednesday, February 12, 2014