ML20202J021

Forwards Description of Reactor Operations Improvement Plan, Per 850910 Meeting Re Performance Corrective Actions

ML20202J021
Person / Time
Site:	Fermi
Issue date:	10/10/1985
From:	Jens W DETROIT EDISON CO.
To:	James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
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References
FOIA-86-244 VP-85-0198, VP-85-198, NUDOCS 8607170011
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          $lE7df' t..nr C.wr o*:                                              ENCLOSURE 1.B etroit       ~                                                                   i 640". M-- he +r4 4.

j*Q".[.q;aad6W Nuclear operations October 10, 1985 VP-05-0198 pattRW f, Mr. James G. Keppler -f Regional Administrator '

                                                                  \   3 Region III                                                   (;o          4 U. S. Nuclear Regulatory Commission                           , s. - s 799 Roosevelt Road                                             N 'I'        n Glen Ellyn, Illinois            60137                                  g g(gud-

Dear Mr. Keppler:

Referenc.** . Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43

Subject:

Reactor Operations Imorovement Plan On September 10, 1985, we met with you and your staff to discuss recent operational occurrences and to let you know that we were also disappointed with our performance. We wanted to describe the corrective actions which we had implemented to assure ourselves that these events were behind us and would not recur. In response to the decisions made at that meeting, we have attached herewith, in both outline and narrative form, a description of our Reactor Operations Improvement Plan. Our analysis identified the problem areas that we needed to resolve before we could improve our performance. The action which we have aircady taken in the plant addresses these problems. Furthermore, we have made it clear to all our levels of management that we will not be satisfied with poor performance in any activity conducted at Fermi 2. Our coamitment to excellence demands nothing less. l I have given my full support to the Reactor Operations Improvement Plan which we are now implementing. On the strength of this plan and our people, I firmly believe thac our performance has already improved and will get even better. 8607170011 860709 PDR FOIA PUNTENNB6-244 PDR

    ,,                                                                         'h

Mr. James G. Keppler October 10, 1985 VP-85-0198 Page 2 Our plan and actions described in these Attachments are essentially the same as those presented at the September 10 meeting. Elements of our action plan were implemented prior to that meeting and the NRC Resident Inspectors have had an opportunity to observe associated improvements. I am confident that this program will reduce the number of operational occurrences and Technical Specification violations at Fermi 2. I remain committed to this end. Based on this improvement program, I would like to return to operation from the planned October outage without restriction and am ready to work closely with the NRC toward that goal. Sincerely,

                                            , '/         f I               .

cc: Mr. P. M. Byron Mr. M. David Lynch Mr. G. C. Wright USNRC Document Control Desk Washington, D.C. 20555 l l I t w-,

Mr. James G. Keppler October 10, 1985 VP-85-0198 Page 3 bec: F. E. Agosti L. P. Bregni W. F. Colbert J. E. Conen J. H. Flynn E. P. Griffing W. H. Jens R. S. Lenart L. Lessor S. H. Noetzel G. R. Overbeck A. Papadopoulos o T. D. Phillips T. Randazzo G. M. Trahey A. E. Wegele R. L. Woolley Approval Control Region III Chron File NRC Follow-up Book /NRC File Secretary's Office (2412 WCB) Licensing File: e- w

VP-85-0198 Attachment 1 Page 1 of 4 REACTOR OPERATIONS IMPROVEMENT PLAN I. PROBLEMS A. Operational Occurrences B. Technical Specification Violations II. ROOT CAUSES A. Inadequate definition of the responsibilities of operating staff and available support for the operating staff. B. Excessive number of plant modifications and equipment repairs which were being approved by the Shift Supervisor for implementation. C. Weakness in the implementation of the evaluation and corrective action process. Note: Inefficient and administratively burdensome procedures have been identified as overshadowing each of these Root Causes. III. CORRECTIVE ACTIONS A. Increased management support and operating staff effectiveness in Control Room. l l B. Improved communication practices. C. Improved administrative procedures and systems. D. Improved effectiveness of incident evaluation and corrective action process. E. Increased awareness of consequences of errors and strengthened accountability. F. Reduced number of equipment repairs and modifications being worked on at any one time. IV. CORRECTIVE ACTION IMPLEMENTATION A. Increased management Support and operating staff effectiveness in Control Room.

VP-85-0198 Attachment 1 Page 2 of 4

1. Simulator training is being focused upon normal plant operations (emphasize log entries, marking charts, i.e.,

good Control Room practices).

2. Plant Manager or Superintendent-Operations is having one-on-one meetings with each NSS, NASS, and Shift Operating Advisor (SOA) to review and emphasize responsibilities and authorities.

3. The quality of Control Room logs has been and will continue to be upgraded.

4. Operations Engineer or Assistant Operations Engineer reviews NSS and Nuclear Shift Operator (NSO) logs daily.

l 5. Superintendent-Operations reviews NSS and NSO logs periodically.

6. NASS has been assigned to Control Room to supervise significant Control Room activities.

l 7. All advisor roles have been clarified and the SOA has been moved to the Control Room with the STA. The Shift Technical Advisor (STA) has been assigned the additional task of investigating and resolving persistent nuisance alarms and annunciators.

8. Operations Engineer reviews performance of shift activities against plans.

9. NSS involved in planning for plant evolutions.

B. Improved communication practices.

1. Superintendent-Operations randomly observes shift operation, provides feedback to the Nuclear Shift Supervisor (NSS) and documents these observations.

2. Advisor to Plant Manager conducts regular surveillances of Control Room operations and provides feedback to Plant Manager.

3. NSS or Nuclear Assistant Shift Supervisor (NASS) conducts briefings for shift operating personnel following turnover.

4. Nuclear Training highlights differences between simulator and plant during operator training.

j 5. Operating staff personnel conduct on-shift training on significant plant and procedure changes. l l l

f VP-85-0198 Attachment 1 Page 3 of 4

6. NSS requires briefing prior to significant test activities and plant evolutions.

7. Operators have been given supplemental training on Control Rod manipulations.

C. Improved administrative procedures / systems.

1. Interim status chart is being used to track LCOs on equipment required by Technical Specifications affecting l shift activities.

e

2. Work order, tagging and equipment status systems modified to more clearly specify post-maintenance test requirements and indicate documents which require revision.

3. As a long-term corrective action, plant administrative procedures will be reviewed to consider revisions which will make these procedures less burdensome on the plant staff.

. D. Improved effectiveness of ir.cident evaluation and corrective I action process.

1. LERs are being tracked and trended.

2. Enhanced corrective action process.

E. Increased awareness of consequences of errors and strengthened accountability.

1. Employes are being reminded they will be held accountable for adherence to procedures.

2. Meetings have been held down to first line supervisor level to discuss plant status, NRC actions and emphasize employe performance.

F. Reduce number of equipment repairs and modifications being , worked on at any one time.

1. NSS has been given authority to control work by setting priorities and work load.

i

2. Instituted a daily schedule meeting in order to have NSS plan upcoming work and set priorities for the day. j l

3. Non-emergency work is being scheduled on Plan of the Day l (POD).

j VP-85-0198 Attachment 1 Page 4 of 4

4. The Plant Support Engineer is reviewing Engineering Evaluation Requests (EERs) and Engineering Design Packages (EDPs) to minimize changes.

5. The NSS is conducting status meetings at 0600, 1800 and 0100 to monitor progress and changes in work activity.

V. CRITERIA POR MEASURI?7G EPPECTIVENESS A. Minimize number of open PN-21s (work orders). B. Minimize number of Engineering Design Packages which remain open after work in the field has been completed. C. Minimize number of inoperable or continuously alarming annunciators in Control Room. D. Perform surveillances on time without using grace period. E. Minimize the number of outstanding, time sensitive LCOs. F. Minimize number of reportable operational occurrences. VI. I?DEPE?DE?C VERIPICATION OF IMPLEME?EATIOIT A.-Quality Assurance to monitor implementation and effectiveness. 1

                                                      -e              .-

VP-85-0198 Attachment 2 Page 1 of 8 REACTOR OPERATIONS IMPROVEMENT PLAN I. PROBLEMS Between March 20 and September 5, 1985, Detroit Edison has had 62 operational occurrences that required reports to be submitted to the NRC pursuant to 10CFR50.73 or because of the interest generated by the occurrence. Two occurrences, the premature criticality incident of July 1-2 and a transient which resulted

    - in temporarily exceeding 5% power on July 24, did not meet the               '

10CFR50.73 criteria but have received considerable attention. Sixteen of these occurrences involved Technical Specification violations. II. ROOT CAUSES Detroit Edison has pursued several lines of investigation to identify root causes. Detroit Edison has studied the weaknesses identified by NRC inspectors and reviewed other relevant industry experience. Also, Detroit Edison has completed a review of the 62 operational occurrences discussed above. The 62 occurrences have been categorized as follows: 24 of the 62 occurrences have been attributed to equipment / design shortcomings; 5 are due to inadequacies in procedures; 29 were caused by personnel error; and the remaining 4 were due to a combination of the above Causes. The occurrences traced to personnel errors are of particular concern. Personnel errors include failure to follow procedures and/or Technical Specifications, mis-communication, and lack of familiarity with equipment. Detroit Edison requested the Institute of Nuclear Power Operations (INPO) to perform an independeat inves'tigation of Fermi 2 operating activities and communications in the plant. The INPO team observed Permi 2 Control Room and operations management activities during the week of August 12 and made recommendations for improvements to Detroit Edison management. Detroit Edison also obtained an assessment of Fermi 2 plant management from Management Analysis Company (MAC). This assessment took place during the period of August 19 through August 30, 1985. The MAC assessment focused on the management aspects of operations and complements the work performed by INPO.

l i VP-85-0198 Attachment 2 Page 2 of 8 , In addition, problem solving task forces, comprised of i appropriate knowledgeable representatives of the Nuclear Operations organization were established to conduct systematic analysis of Licensee Event Report (LER) occurrences, to identify cause and to recommend corrective action to prevent or minimize the likelihood of recurrence. In summary, these investigations revealed a situation in the Control Room which inhibited the operating staff from exercising proper control over the plant status and operations. This situation was caused by a failure to define in sufficient detail the responsibilities of the Control Room shift team, the lack of support by the staff, and by attempting to conduct a wide variety of activities related to equipment repair and modification orders. The large number of somewhat burdensome procedures is an overlaying problem. III. CORRECTIVE ACTIONS To function effectively, the Control Room staff must exhibit a high degree of teamwork, effectively utilize the many resources available on the shift and in the operating organization, and carry out its command and control function in a careful and

professional manner. Weaknesses in these areas have contributed to operational occurrences and Technical Specification violations which might otherwise have been prevented. Improvements which 4

strengthen each of these areas are expected to lead to both feuer i operational occurrences an3 Technical Specification violations. Improvements are necessary in on-shift, shift-to-shift, and Control Room-to-support organization communication practices. 1 The effectiveness of the remaining corrective actions will be i i limited by the capability of the operating authority to communicate its problems, needs, and priorities to those organizational units which are responsible for addressing them.

;         Also, timely and accurate feedback from support functions is necessary for the. Control Room staff to understand the plant status.

j Adding further support to improve Control Room operating

;         performance, greater emphasis is being placed on the current

{ understanding of plant operating status. Current dated LCOs are displayed in hard copy. The DOT system of flagging control board system and component abnormal conditions is being made more visible and meaningful in correlation with the outstanding work 4 orders. Tagging and work orders are being modified to more i clearly specify post-maintenance test requirements and indicate which documents require revision. As a long-term action, administrative work procedures will be simplified or clarified to consistency.

VP-85-0198 Attachment 2 Page 3 of 8 Prompt and thorough evaluation of incidents provides a means to prevent recurrence. If the evaluation is not timely or the evaluation not thorough, the cause may not be determined and the opportunity to avoid recurrence is lost. Likewise, if the corrective action is not timely or appropriate, similar incidents

,                      may be expected.

Nuclear Operations personnel have been advised to consider the consequences of taking even the simplest of actions. Technical Specification violations and unplanned occurrences have resulted from such seemingly simple actions as opening a valve or lifting an electrical lead. If after taking such a deliberate approach i an unexpected error occurs, personnel have been advised that it

is equally important that the error be communicated so that i

 )

appropriate operating staff or management action can take place in a timely manner. The reduction of open work items and increased control by the

!                      operating staff over open work items will reduce the number of unexpected operational occurrences and violations.

IV. CORRECTIVE ACTION IMPLEMENTATION A. Increased management support and operating staff effectiveness i in Control Room. The Nuclear Training organization is developing and, when ' possible, modifying existing scenarios to exercise the requalification classes on routine plant startup and operation. Emphasis is being placed on normal system line-up, operation and responses required. This includes expected

,                         alarms and indications. The importance of logging activities on charts at shift turnover, system startup and transient initiation is stressed as is evaluation of plant conditions using the Sequence of Events Recorder.

To strengthen shift management techniques, the Plant Manager or the Superintendent-Operations are meeting individually with each NSS, NASS and Shift Operating Advisor (SOA). Subjects covered at these meetings include: communications at all levels; relationships between operating staff positions; the significance of actions and need for attention to every detail; the need for prompt investigation of anomalies; the consequences of errors; plant safety concerns; the role of the SOA; and a reminder of each person's responsibilities and the accountability for his actions.

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VP-85-0198 i Attachment 2 Page 4 of 8 I l ) To improve the quality of Control Room operations logc, l j entries into the Nuclear Supervising Operator's (NSO) log are l i being made by the NASS as an interim measure. This is to I i assure that adequate logs are being kept while the NSOs gain ! fa:tiliarity with good logging practices. The Operations i Engineer or designee is reviewing the NSS and NSO logs at i least daily, except weekends, to assure that they are being . kept properly and that the proper entries are being recorded

;                                       as the plant is being operated.

1 Also the Superintendent-Operations is reviewing the NSS and NSO logs on a periodic basis to provide feedback to the NSS and the Operations Engineer. The NASS has been assigned to the Control Room proper as a permanent duty station on shift. The NASS has been placed in charge at the controls area of the Control Room during planned reactivity manipulations, plant startups and shutdowns, j multiple plant testing activities and outage periods when significant maintenance is in progress. The role of_the Control Room NSO has been clarified to assist the NASS or NSS in directing plant activities. The duty station of the SOA is now the Control Room. As such, . the SOA is directly involved in Control -Room activities. The SOA utilizes previous BUR operating experience to provide assistance and advice to the NSS, NASS and NSO, as required. j In order for such assistance and advice to be timely, it is , necessary for the SOA to be cognizant of the details of plant i operations. For this reason, the SOAs have increased their i l involvement in activities in the Control Room. l Through coordination with the on-shift Plant Support Engineer, j the Shift Technical Advisor (STA) monitors for hardware-related problems associated with Control Room equipment which may not otherwise be identified or tracked. 1 The STA is concerned with resolving Control Room problems like i nuisance annunciators and alarms in addition to normal duties. The Reactor' Engineer has increased participation in reactor j operations and is closely following, analyzing and reviewing i significant reactor evolutions. Similarly, the Operations Engineer has increased involvement in operations by following i and reviewing performance of shift activities against established plans and checking the quality of Control Room l logs. , l 1 l ' I i l l _ - _ . , . - . - - . _ _ _ . - _ . . . ~ _ _ _ . - . _ _ - , _ _ . , . . _ . _ - . .

                                              +

VP-85-0198 i y Attachment 2 Page 5 of 8 The NSS has'b'een give'n ths authority to control work in the plant by setting priorities and work load. This is accomplished through interface with the plant Outage l Management organization and through direct involvement in work planning meetings. This ensures that the NSS retains the l ability >to direct and supervise the operation of the plant by

            , establishing a' manageable work plan that is consistent with such operations.'

B. [mproved'communicationpractices. To streng5 hen on-shift work process precision and

            ' effectiveness, the Superintendent-Operations periodically and without prior notice has been observing shift operation
   .         activities. The Superintendent-Operations gives feedback to the Nuclear Shift Supervisor (NSS) or Nuclear Assistant Shift Supervisor (NASS) . and-documents any. observations. The Superintendent-Operations observations include actual plant j            operations and the review of operations administrative activities such.as shift turnover, log review and plant status system updates.

The advisor to the Plant Manager is conducting more frequent, j regular surveilla'nces of Control Room operations. The advisor observes the performance of the Control Room crew, reads the log kept by the Shift Operating Advisor (SOA), discusses any 1 problems with.the'SOA, reads the log kept by the NSS and, occasionally, the51og kept by the Nuclear Supervising Operator (MSO). In addition, the advisor observes plant parameters and

,           annunciators and provides his observations to the Plant l

Manager. Following turnover from the off-going NSS, the NSS conducts a briefing of shift operating personnel. The briefing is held in the Control Room and covers the following items at a minimun: a) Present plant status, b) Upcoming shift activities such as power changes, system manipulations and evolutions, surveillance

;                 tests, startup tests, special tests, etc.,

i i c) A summafy of the'important objectives to be met by j the end of the shift, and d) A discussion giving a broad overview of plant direction relative to the overall schedule and any relatedcmanagement items with emphasis on how the on-shift complement fits into the plans. i ,

VP-85-0198 Attachment 2 Page 6 of 8 s Supplemental training on the current requirements for control rod. manipulations, including the reduced notch worth pull concept, has been conducted with all six shifts of plant operators. Recognizing that there will always be situations requiring plant / simulator differences, Training is emphasizing the important ' differences between the plant and the simulator during training. Similarly, the operations staff is providing on-shift training regarding significant plant and procedure changes. C. Improved administrative procedures and systems. An interim status chart has been implemented to track i LCOs on equipment required by Technical Specifications . which a#fect shift activities. Also, the work order, taggint! and equipment status system has been modified to more clearly specify post-maintenance test requirements. Human factors me hods are being applied to the administrative procedures to make them more streamlined and more user oriented. s D. Improved. effectiveness of incident evaluation and corrective action process. LERs are being tracked and trended so that symptoms of potential problems can be diagnosed early to prevent. recurrence. Emerging trends and selected LERs are being evaluated utilizing proven, systematic problem-solving methods to identify cause and remedial as well as preventive corrective action. Corrective action taken is being tracked to completion and evaluated'for ' effectiveness. The corrective action process is being further enhanced by refinement of procedures associated with the process and structured training for personnel involved in the evaluation and review phases of the process. Procedures have been issued for implementation. Formal training for selected personnel is scheduled to begin the week of November 4th. These actions, coupled with actions previously initiated by the QA organization, will improve the timeliness and overall effectiveness of the corrective action process. l ,

VP-85-0198 Attachment 2 Page 7 of 8 E. Increased awareness of consequences of errors and strengthened accountability. In each one-on-one session between the Plant Manager or l the Superintendent-Operations and the NSS, NASS, and SOA,  ! employes are reminded of their responsibilitiest  : delegated authority and accountabilities; of their  ; expected job performance and of their relationship with  ; other shift members. Meetings with employes down to.the- ' group supervisor level were held during the week of September 17 to discuss the status of the plant, the status of NRC/ DECO interactions and to remind'each empicye of his part in improving the performance of Fermi 2. F. Reduced number of equipment repairs and modifications being worked at any one time. The NSS is responsible for ensuring that the ability to provide proper direction is not compromised by an excess of work or testing. For this reason, the NSS is controlling work in the plant by determining priority and amounts of work for the shift. Work in the plant is identified and scheduled on a Plan of the Day. This daily plan is prepared by Outage Management through input received on status of activities and on tasks which are to be added of deleted from the schedule. Each working cay, a planning meeting is held with the day shift NSS in vttendance. The NSS provides input relative to anticipated plant operations over the next few days so that tasks can be identified and prioritized on the schedule accordingly. Organizations are given the opportunity to ask questions of the NSS or request that certain jobs be added to the schedule. The NSS establishes work priority and provides i direction as to the amount of work to be scheduled. The Plant Support Engineer revieus Engineering Evaluation Requests (EERs) and Engineering Design Packages (EDPs) to reduce plant changes to only thoce nece::ary for safe plant operation. This change reduces the number of changes implemented at any given time se only those that are essential are undertaken. , l The NSS conducts status meetings at 0600, 1800, and 0100 hours. These meetings are held with representatives from the various work groups to monitor progress on important items as well as to allow additions to the work schedule or review changes in course as directed by the NSS.

VP-85-0198 Attachment 2 Page 8 of 8 V. CRITERIA FOR MEASURING EFFECTIVENESS Goals have been established for certain key operational activities. In addition, Detroit Edison has established objective monitoring criteria to deteraine the overall effectiveness of the Reactor Operations Improvement Plan. These criteria are indicative of a well operating organization. Detroit Edison organizational units have been assigned responsibility to track and trend performance with respect to each of these criteria. Management will be monitoring this performance so that adjustments can be made, if necessary. The results of this monitoring are available for your review. Detroit Edison expects improved performance with time for each of these criteria, especially directed toward minimizing the number of reportable operational occurrences. VI. INDEPENDENT VERIFICATION OF IMPLEMENTATION The Nuclear Quality Assurance organization of Nuclear Operations will provide independent verification of. effective implementation of the program utilizing audits and/or surveillance methods. Results will be reported to Nuclear Production and Nuclear Operations Management. m

                                                                      )

I

ENCLOSURE 1.C NOV 8 1985 x Docket No. 50-341 The Detroit Edison Company ATTN: Wayne H. Jens  ! Vice President ' Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 Gentlemen: Thank you for your letter dated October 10, 1985, describing your Reactor Operations Improvement Plan. We have reviewed your proposed course of action and conclude that it contains the appropriate attributes which, if properly implemented, should achieve the desired results. We do note, however, that you did not provide any quantitative criteria for measuring Improvement Plan effectiveness or a time table for achieving your goals. To allow both Detroit Edison and the NRC to monitor the plan's effectiveness, we request that this information be provided to the NRC Region III Office. As stated during our September 10, 1985, meeting, the NRC feels it would not be appropriate to lift the 5% power limitation prior to observing that your corrective actions are having a positive effect on plant operations. To that end I plan on an augmented restart inspection program to observe plant operations, after the present outage is completed, to assess the effectiveness of your Plan. At the conclusion of this assessment a datennination with respect to the 5% power limitation will be made. Sincerely, Orl:_insi sig.:ed by

                                                ..u.s  G. Kc; per James G. Keppler Regional Administrator cc: See Distribution
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The Detroit Edison Company - I'- v : erd Distribution: L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DCS/RSB (RIDS) Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voigt, Esq. Nuclear Facilities and Environmental Monitoring Section Monroe County Office of Civil Preparedness 1 i

l 1 cor.na I vm ,, ,. ENCLOSURE 1.D h ase Ceresens pe=*a seco na oi. **gr-e, m a u c.e,-esiu g 913) W ito

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• I November 27, 1985

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Mr. James G. Eeppler Regional Administrator Region III

   -                        W.S. Nuclear Regulatory Commission 799 Roosevelt Road
                           , Glen Ellyn Illinois 60137 4

Reference:

1) Fermi 2 NBC Docket No. 50-341 -

NRC Docket No. 50-341 NBC License No. EFF-43

2) Detroit Edison to NRC letter, " Reactor Operations Improvement Plan". TP-854198, October 18, 1985

3) NEC to Detroit Edison letter, "Reguesting quantitative Criteria for Measuring i Improvement Plan Effectiveness", November 8, 1985 Sahject: Additional Inforn.etion Regarding the Ranctor Oserations Introvement Finn In response to your letter 'of November 8,1985 reguesting quantitative criteria for monitoring the Reactor Operations Improvement Plan, Attschment 1 is provided herewith for your information. The goals identified in this plan are ones which are indicative of a nature operating plant. Positive treads indicating that Fermi 2 is approaching these goals can he observed la attachment 1. Management f aspects these positive treads to contisse and will nomitor them on a

_ periodic basis. Amy deviations away from the desired tread or goal will prompt management review and corrective action, as appropriate, , to assure that progress toward the objectives of the Reactor Improvement Plan costianos. It is anticipated that sa the Fermi 2 l operating experience increases, we will move even closer to these j goals.

i l l l l Mr. James C. Esppler

              .m.      November 27. 1985 TF-85-0219 1* , ,.     .

Fase 2 . ,..:4

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4 ". It is important to note that these goals may reguire adjustment. l either up or down, shonid management deternise that the gosta are too limiting or are otherwise not achieving the desired results.. As an  ; example, during the course of the recent estage to complete the 3L panel installation and Igulpment Qualification work, trends were observed away from the desired direction. This was not only planned but also expected so that tasks could be completed prior to return to service. r since these trends have been shown to be E'the positive direction and because management will continue to apalter to assure progress is the positive direction, Detroit Edison regnests that it be allowed to operate Fermi 2 at levels la eacess of M pesar. If you have any guestions regardias this matter, please contact me. Sincera1y. l cc: Mr. F. M. Byron l Mr. M. David Lynch 1 Mr. G. C. Wright USNRC Document Control Desk Washington, D.C. 20555 e

ATTACHMENT 1 Page 1 of 6

• OAL A:

p Minimize number of ODen PN-21's (Work Orders) ectives

                   ~ -
            ~

TOTAL - 150 Management Attention Level i

                .           TOTAL                                     -

110 Expected I  ; l l B #.p _ . 1 I OUTAGE 85-01 g P 1 I 400 1 I I  ! 1 l 381-371 l t  ! I 3% g 66 g t i I 33 l I l ) 300 l  !  ! ' I I I 3 250 , l 12s J6 1224 r 200 I , 1 87 i > 1 17s I I mo t I_ _ _ _____l unoaesenot_kooticoLard1_J t l 9 I l 3 _.. . _ _ _ 200 j _ _ _ _ _ _ _ _ _ l _ _ 110_ w I

• 1 I I

I I I -

                             !                                  I                                                            I t                             i                                  I                                                            I                      -

1 0 l I I I I I I I I I I I I I I I I I I I I l . 5 22 29 06 13 20 27 03 10 17 24 01 Septernber October Novernbar Dec E a . _ _ . . .t; . . * " ~ . IDTE: Includes plant system related PN-21's (work orders) only. During an )uttgo greater than one week in duration, total numbers can be increased by  ; i fcctor of 2.5.

                +.

1 l

i Page 2 of 6 icAL 3: Minimize number of EDP's which remain open after work has baen comoleted, i.e. fleid conclete.  : Objective - EDP's open 30 days - 15 Management Attention Level after field work 7 Expected complete

   .     .. __ ... .                                          ..                           .                                      . 4 I

200 I I ISO l Nuzbor I of - 160 1 --- Fiold l

@c::plete                 140 i EDP'O                              I 120 I                                  ..

100 i open i Pact 80 1 30 l _...-..... 70 70s Daya 60 1 3 g .. . 40 1 45 1

      -                    20 1                                                                                                                            -~      ~~

t _ _ _ _ . _ _ Z Z _ _ _ _ ; _ _%oteesa t. ./J.tentass_Te:rJ_ _ _ _ _ _ _ _ __ _ _ _ _ 10 l l-------------------M------------------------- -7 01 I I I I I I I I I I I I I I I I I I I I september i October i November l December l

            .                                          1. - ~                                  _ . . _ _ _ _

                                                 - = ~ . . - - .         . n.    . .

_ _ _ ~____ Page 3 of 6 . 10AL C: Minimize in Control number Room. of inoperable or continuously alarming annunciators i Objective - Number of lighted, non-functional annunciators 15 Management Attention Level 10 Expected i I i I l 100 l  ! 1 90 I utstanding I 80 l Csntrol l 70 i Roo3 1 60 1 Prebico

• I _J6 57 50 l h5'4 inunclotors i 44

                                                         /                               6-47 36 30 1 I

20 I l--------------- MaiwwLthiterttisx1Jea 10 l--------------------- DD8 Sit 4.--------l---------------- 15 I ---------------- 10 l 1 1 I I I I I I I l September I I I I i 1 1 I I I l October i November l December l Problem logic, etc.annunciators are all inoperable, nuisance, setpoint, related annunciators.

                                                                                                                                                                                                                                             ' ~ -                                '                           -

Page 4 of 6 - GOAL D -Perform Surveillances on time minimizino usino crace Obiectiv_e_ .

                           -~

Surveillances including grace completed periodon time - 994 Management Attention L 100% expected

                                   ~~

the grace periodSurveillances not completed within 24 hours of reach 7/ week Management Attention Level 5/ week Expected i 101 l l Brvoillances l 100 1110 100 Comp 1cted l - 100--400 A00-100 Expected - 100 99 l - -

                                                                                                                                                                                                   .7 on Time                                                                   i                                                                                                            -Management Attention Level                                                                             .

Ss I {, Incltding l - j 97 I teco Porlod I 96.5 . 96 I i (t)  ;: { 95 l

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I I I I I I I I I I I I I l September I i 1 1 I l October l November i 1 December I i 10 1 tvoillances I , , . . ~"~ Bot 11

omoloted Uithin 6 I---------------- h G O M W D W81---------------

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                                                                                                                                                                                                                                                                      - 7 14 Ecurs Cntoring 4                                                              1 l---------------------------- ----- M Y------------

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                                                                                                                                             /

1 September I VI I I I 1 1 1 I I i October l I i November i December l _ _ , , - - - . , , . _ _ - - . . ~ - _ _ _ - - _ . , ,. - . . - - _ . _ - , . - _ _ . . . . , ~ _ , _ _ _ _ _ _ _ - .-,,__,-,-.-.._,,._._.__-...._,._..--m. _ - . . _ . , , , , . , , _ _ . . - , , , , - - - - - .

                                                                                 ~                              -   --

p. - _. .._ ._ _-

      .                                                                                          Page 5 of 6 N)AL En              minimine the number of outstandina. time sensitive Lco's                                                 -

Objective --- Number of dated - 5 Management Attention Level LCO's outstanding 3 Expected .. I I 10 1 I 9I I Ru bar 8I I of 7l l DatGd 6I i s I ---------------------- MM*"*01 B*9 S-"L*l---------- 5 Leo'o I 4I I Mtotending 3 l--------._------ -- ---------- U N---------------- 3 . . . 2l 2 I 11 1 14 o-o i I 1 1 1

                                        /I          I  I i   1    1     I   I   I    I    I   I      I I   I l     September           i October     l    November l           December       i l

l l l l

                                                                                                                                                                         -----7
    ,                                                                                                                                 Page 6 of 6 IOAL F:                     Minimize the numher of reoortable operational occurrences *                                                                                         .

Objective - Number of Licensee - 2/ week Management Attention Level Event Reports (LER's) 1.5/ week Acceptable

                 }
                 -                   I
            . 4. ....       5 I                         5                                      .

I i 1 4I I I Nurbar l 3l . 3 3-3 I I

   'f 21       2----+- ----2----- --- ?IS - EI Elt80IlWl

• El----- - 2.0 I

g___ . . ___ ___ ___ __ ____ __ __ _Msueteds-------------- - 1. 5 LER'O I 11 1-1 l - I eI o - 41

                                    .1_J_ I            I   I  I   I  I  I  I  I       I     I   I               I                I                 I            I I I    september            l October   i November i                            December                                       l

__ A . . . . . . Note: Reportable Operational Occurrences do not include Security-related LERs.

wene, J. uccerthy J,. ENCLOSURE 1.E cna e-a oone sw

. _ . -       _ _ .                                                                                                     ==w

b. it .

cdison ,= s.,-- .... .mur-January 29, 1986 YP-86-0008 i i Mr. James G. Reppler - Regional Administrator Region III U. S. Nuclear Regulatory Commission 799 Roosevelt Road - Glen Ellyn. Illinois 60137

Reference:

1) Fermi 2 NRC Docket No. 50-341 ERC License No. NPT-43

2) NRC to Detroit Edison Letter. -- - .

                                                             " Requesting Information Pursuant to 10CFR50.54(f)". December 24, 1985

3) Detroit Edison to NRC Letter.

                                                             " Reactor Operations Improvement Plan". VP-85-0198 October 10, 1995

Subject:

Response to Request for Information Pursuant to 10CFR50.54(f)

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

This letter is submitted in r e s p o'n's'e-to th e7u cl e a r -- I Regulatory Commission's request for information pursuant to 10CFR50.54(f) which is cited as Reference 2 above. Detroit Edison is committed to the highest standards for both managing and operating the Fermi 2 facility. Enhancement of management and management practices is essential to attain the operating and performance goals set for Fermi 2. We understand what needs to be done to improve regulatory and operational performance and are prepared to take the actions necessary to effect such improvements. The following three secticos address the issues identified in Reference 2 above Jkt7% 30 /[ $ M ,

                                                                                                                            . -    e          l Mr. James C. Reppler January 29, 1986                                                                    ,,                    ,

YP-86-0008 ...- Fage 2

1. ADEQUACY OF MANAGEMENT, MANAGEMENT STRUCTURES AND EYsTEMS Detroit Edison management needs to strengthen the

_ sensitivity, discipline and responstveness of the

                        ; unclear Operations creanization._ In this regard, Nuclear Operations management is developing a Nuclear

, Operations Improvement Plan which addresses planning, accountability, attitude, communications, teamwork, f ollow-up and training in the entire organization. By developing a plan directed toward eliminating

                         'o e z i c a . ; ; i : :  4-   *k=   -
                                                                  ;re..,      imy.wv...uss can be expectec au wvosmit managenenc_, in sne a b il i cT TT recognize and respond to problems which could affect plant safety and in controls to assure improved regulatory, operating, engineering, maintenance and security performance.                      A =1==   i: '=ine         dow=1aasd and
          ~     -
                         ' mill         k=  ---ia_wed in detail hy             an        Overview Ca==ittee__

prior to implementation. The plan will be initiated no

                          -lacer snan May 1, 198T'and fully implemented by July 1, 1986. The role of the overview committee is more fully l                          described below.

Manneenent Detroit Edison is evaluating the key management personnel at Termi 2 to assess performance and

                  ~ ~ ~ - ~4T f e c t i v e n e s s r--A isan a gem ent -ch an g e -w i414 e -ma de -en .           . _ .

February 1, 1986 to accommodate the retirement of Wayne l Jens, Vice-President. Nuclear Operations. Frank Agosti, i Manager-Nuclear Operations will sbeceed Wayne Jens as ! Vic e-P r e s id en t beginning on that date. Further. I recognize that additional strengthening of the Termi 2 management is appropriate. Consequently, I am seeking additional officer candidates with nuclear operating experience from outside the Company to provide additional management which I feel is required to achieve the goal of operating excellence. These individuals will be charged with completing reviews of the existing Termi 2 management and making such changes as deemed desireable. Mr. Agosti will report directly to me until the above officers have been selected. I have directed the Fresident and Chief Operating Of fic er of Detroit Edison, Charles M. Beidel, to assist me in monitoring the performance of the Nuclear Operations organization. The Nuclear _ Anality Assurance organisation wil' renort 'a W'- B e t A m 1__- The President will also assura that any other corporate resources are

                                                                                                     .---n               ..       . _-_ _

r i . Mr. James G. Keppler January 29, 1986 - VF-86-0008 Fage 3 provided which are necessary to support or audit ,the Nuclear Operations organisation. This change in control will enhance the use of Quality Assurance as a management tool to improve regulatory and operating performance. In addition, three other Detroit Edison of fic ers will provide independent overview of the Fermi 2 Engineering, Security and Administrative organizations. These three of ficers will report to the President in this matter. Further, to assist in this effort, we formed the Fermi 2 _,

              +  Inaepencent Overview Committee wnicn is comprised of y    recognized nuclear industry consultants. This committee will provide Detroit Edison management with a critique dJYgc '

h of the present Fermi 2 management. The Overview

 .#g d /[
 ?               Committee has already conducted interviews with v#g bchhf    management personnel from both the site and corporate
 'gc p   f       organisations. A preliminary report has been presented
    ,            by the Overview Committee to a committee of the Board of y              Directors, the Board Nuclear Review Committee.

Attachment 1 explains the role and schedule of the Overview Committee. Detroit Edison will strongly consider the Committee's recommendations for management improvement. Mannemment Structure The concept, structiire a nTTu n c t a o n s ox M e 1ucieur - - - - - - - - - - - Operations organisation have been reviewed by independent management consultants and many of their reconcendations are being implemented. In addition, the Company has been seeking other ways of improving and the following are some examples. Nuclear Operations is currently working with a professional organisation and management consultant from the Detroit Edison Corporate Of fic e to improve the interface between Nuclear Engineering and Nuclear Production. Nuclear Engineering and Buclear Production are conducting joint sessions to clarify responsibilities,~ agree on work priorities and to improve communications. In July, 1985, engineering for the Fermi plant was reorganised to consolidate engineering re s p on s ib ilit ie s in the Nuclear Operations organisation under the leadership of an Assistant Manager. The present engineering organisation has assumed full control of engineering and is augmented by a single architect / engineer with a dedicated staff on site. Since engineering problems have occurred during this

Mr. James G. Keppler January-29, 1986 VF-86-0008 Page 4

                                                                                                       )

l l transition period, the effectiveness of the present engineering organisation and its procedures are being l reviewed by management. The architect / engineer will review the procedures currently being used by the Nuclear Engineering organisation to assure that proper control of the engineering process is maintained. The office of the Manager-Nuclear Operations was temporarily moved to the plant office building near the i Flant Manager. The purpose of this move was to permit the Manager to monitor day-to-day work to insure that the Engineering organization. the Regulation and Compliance organization and Nuclear Operations Service 4 organizations are being responsive to the needs of the j plant. This effort has reinforced the operating l authority of the Flant Manager and focused all nuclear i operations resources toward support of Nuclear Production. I intend to have Trank Agosti as Vice-President continue to occupy that office-for an-l interim period. i The Termi 2 Independent Overview Committee will continue l to examine the management structure and personnel to ) identify further improvements which would enhance regulatory and operating performance. Each , j recommendation will be considered by management for j implementation. Manneseent Evatoes and Practicas 4 j After the success of the Fall 85-01 Outage, it becsee evident that a similar planning and controls effort to plan, coordinate and follow-up is necessary not only for I outage work but also for day-to-day work activities. Each organisation will be evaluated to assess the planning, coordination and completion of its activities. Where improvement needs are identified, these will be included in the Nuclear Operations Improvement Plan. I An evaluation of Nuclear Security was conducted to identify areas for improvement in regulatory performance. As a result. Nuclear Operations management l and Nuclear Security developed a Security Improvement Plan to address the inordinate number of security plan violations which occurred in the last quarter of 1985. The major elements of the Security Improvement Plan were presented to the NRC staff on January 17 and included aggressive immediate actions. long-term corrective I l

                                                                                                                                                )

l Mr. James C. Keppler January 29, 1986 TP-86-0008 Page 5 actions, time frames for accomplishment and performance indicators. That Plan will be discussed with the NRC in a separate meeting. The Security Improvement Plan will incorporate recommendations from the Independent Overview Committee where appropriate. _An evaluation of plant maintenance activities showed.,two _ areas for improvemega.which would enhance regulatory and

                       ~ operating performance. These two areas are post-maintenance test requirements and techniques for

[ removing and placing into service critical plant equipzent. The work order process has been moctried to more clea'rly state the post-maintenance requirements and additional documentation requirements that must be met i before the shift operating authority can accept a component or system for service. These improved management controls have resulted in better control over work and documentation for all maintenance activities. The procedures by which instrument repair technicians remove and place equipment back into service have undergone significant revision. In addition, instrument repair technicians have taken additional training and on-the-job instruction regarding the proper techniques to be used. These efforts will reduce the chance of I mak in g errors and thereby reduce the impact maintenance activities might have on plant operations. The need for continuous attention to management ~_ practices for improved regu1st ory perTormanc e ~1r

                                                                                                                              - - ~ - " - -

i recognized. The Detroit Edison corporate organisation and management development consultant has been directed to work with Fermi 2 management to focus attention on their management practices within Nuclear Operations. As part of this effort, a survey on organisational climate and management practices has been conducted. The results of this survey will provide data to guide both individual and group management practice improvements. The sensitivity of the Company and Nuclear Operations. l specifically, to potentially significant conditions has been substantially heightened as a result of the  : premature criticality incident. Nuclear Operations  ! asnagement recognizes the need to communicate certain events regardless of the reportability requirements. Recognizing that communication and response improvements between Detroit Edison and the NRC are as important as recognizing significant conditions, a Nuclear Operations Directive has been prepared which prescribes policy

   . _ . . . _ . _ _   __      . _ , _          _ _ . _ _ _ . _ _ _ _ . _ . _ _ _ . _ _ _     ________._____._._c..._,_....,.               _-.

Mr. James C. Reppler i January 29, 1986 VF-86-0008 Page 6 4 supporting.a more effective dialogue between the two organisations. In addition, Detroit Edison has contracted with a consulting company to conduct a series l of workshops with various management levels to improve r ' their sensitivity to issues and responsiveness to the NRC. The consultants have already conducted interviews with site personnel as the first phase of developing the j workshop. Subsequent phases of this workshop will involve the operating staff where reportability concerns and issues will be addressed to improve sensitivity.

)

l To enhance awareness of, and thereby sensitivity to, i nuclear activities on the part of corporate management j and the entire Nuclear Operations organisation, a prof es sional communic ations unit has been active on-site since August 1, 1985. This unit produces three publications which provide information to the site and corporate organisations. These publications include the I i monthly Moderator, the Weekiv Moderator and daily I " Management Update" messages distributed using the site computer communications system to generate a bulletin , board newsletter. In addition, banners and other posters have been displayed at the site entrance and

exit to remind all personnel of their key role in i

atlaining the regulatory and operating performance goals set for Termi 2.

         ~ ~ ~2 .                                   ET AD T1tESS -70R -1E =S T ART --AND POWER ISCALATIDEI,_                                                    _ _ _    __                 ,.

j Detroit Edison has concentrated on correcting errors that have been made in its operations and is committed l l to continue the Reactor Operations Improvement Plan. l The Reactor Operations Improvement Flan was developed i and implemented to improve operating performance of Fermi 2. That plan was directed at reducing the l frequency of operational occurrences and technical i specification violations. The positive trends which i have been schieved since this program was implemented l are expected to continue. The performance to date and j ind ic a t o r s for the Reactor Operations Improvement Plan are shown in Attachment 2. Any startup decision will require verification that satisfactory trends are i continuing. The Independent Overview Committee will be reviewing or ner.. .;! .?  : pip;;t ; Mupport re...rt [ seediness and subsequent moles or operstaan. The progress on, and l resolution Df, *'^r: ~

7;;-- . f 0;uipment problems which i

are impediments to startup, or f or which the progress or i i *

                                                                                                                                   .-_j--_...--_.,-..._.-_.__-_-,,_-m..~  - - - . - _ - _ _

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

l l Mr. James G. Keppler l January 29 1986 ! YP-86-0008 Page 7 i i resolution is expected to result in better operating and regulatory performance are presented in Attachment 3. The last startup at Fermi 2 on October 3 1985 was successful and it is intended that similar steps and procedures be followed in preparation for the next , startup. The operators who will be responsible for reactor startup will have recently conducted reactor

!                       startup evolutions on the simulator. Attachment 4 describes the actions the plant staff will take to prepare the plant for startup.

The actions that will occur after startup but prior to Test Condition 1 are covered in Attachment 5. The additional tests illustrate the retesting to verify j performance before moving to the next Test Condition. The tests required at other power ascension conditions are delineated in the FSAR and the Startup Phase Test i Program. The six Test Conditions have been established as hold points to assess overall plant performance. Before i startup and before proceeding to any subsequent Test

!                       Condition, approvals will be required from plant

management and Corporate management after receiving a ,

review and recommendation from the Independent Overview 1

;                        Committee.

Overall plant performance will be assessed utilising the 1 following: 1 1 A. Reactor Operations Improvement Plan, to assess . ! , plant operations; B. Stat tup Test Phase results, to assess plant equ.pment performance;

!                                       C.                 Independent Overview Committee, to assess overall performance.

l The Overview Committee will make a recommendation to me l and the Board Nuclear Review Committee regarding movement to the next Test Condition. My approval and review by the Board Nuclear Review Committee are required before the plant can proceed. i j 3. IMPROVED REGULATORY AND OPERATIONAL PERFORMANCE i The plans identified in this response represent Detroit Rdison's commitment to improving the regulatory performance, operating performance and management

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

Mr. James C. Keppler January 29, 1986 VF-86-0008 Page 8 performance at Fermi 2. These plans will be monitored to assure that the improvements have been effective. Should it become evident that these plans need modification to effect further regulatory or operating performance improvements, such changes will be made. As an example, any development needs or weaknesses in the radiological controls area vill be addressed by the Radiological Improvement Flan. Changes may immediately occur from the commitment to consider each recommendation received from the Independent Overview Comeittee. Detroit Edison established a program called SAFETEAM in 1983. This program was a first for the commercial nuclear power industry in that it provided a method by which anyone who is currently working or had worked on the Fermi project could anonymously have any of their concerns ebout the plant or its operation investigated. This program has been directed by the Detroit Edison Auditor and operated by Detroit Edison personnel. The program has worked well. However, it is our plan to provide additional independence from the Company by transferring direction of the program to another company. A Detroit Edison Company subsidiary, SYNDECO, is currently operating similar programs at four other nuclear power plant sites. It is our intent to contract with them to conduct this program at the Fermi site. It is understood that' nuclear plants with h . availability, small numbers of both forced outages and personnel errors, few unplanned scrams, few recurring events, and low personnel radiation exposures are generally well-managed overall. Such plants are more reliable and can be expected to have higher margins of safety. Detroit Edison is committed to such attributes

        -                          for Fermi 2 and has adopted certain Institute of Nuclear l                                   Fower Operations (INFO) Performance Indicators as an aid in monitoring plant performance. Performance against these criteria has been tracked where applicable during the startup phase of operations. Additional ind ic a t o r s will be added to help identify areas needing corrective action as appropriate.

l The equipment problems and personnel errors have been indicative of less-than-acceptable performance. We acknowledge that and we regret it. Although these problems and errors have not jeopardised the health and safety of the public, we nevertheless are committed to

Mr. James C. Reppler January 29, 1986 VF-86-0008 Page 9 correct the trends which could lead to safety concerns if left uncorrected. Detroit Edison believes that'with the continued success of the Reactor Operations Improvement Plan, the implementation of the Security t Improvement Flan, and the actions taken as specified in Attachment 3 and Attachment 4 the plant will be ready to ressee operation up to 52 power. Detroit Edison will meet with the NRC staff to discuss its overall performance and readiness to proceed above 52 power. It is my intent to maintain oversight and review by the Independent Overview Committee, the Detroit Edison Board Nuclear Review Committee, and myself until we are i satisfied that this plant with its new management, its plant operators, and its support staffs have demonstrated satisfactory performance as measured

 ;                           against other plants and INFO performance criteria.

Fermi 2 will only be operated in a manner which ensures the public health and safety. For this reason. Detroit 1 Edison believes that the Farmi 2 license does not need to be suspended, revoked or otherwise modified. , l Very truly yours.

                                                                                                                                                                              \,                                                         -

J Attachments cc: Mr.. F. M. Byron

;                                                   Mr. M. David Lynch Mr. G. C. Wright USNRC Document Control Desk Washington. D. C. 20555 i

i

   . _ _ _ . _ . _ . _ . . .   . _ _ _ . . . _ _ . _ _ _ . _ _ . . . _ . _ _ _ _ . _ . _ _ _ _ _ . _ . _ _ .      . _ _ _ . . _ _   . _ _ . . _ . _ _ . . . . _ _ , , _ _ . .    . . _ . _ . _ _ . . . _ _ _ _ _ _ . _ , _ , . . . _ . - +__...

Mr. James C. Keppler January 29 1986 TF-86-0008 Page 10 i j OATH AND AFFIRMATION l To the best of my knowledge and belief the statements contained herein are true and correct. In some respects '

these statements are not based on my parsonal knowledge

,           but upon information furnished by other Detroit Edison employes.              Such information has been reviewed in accordance with Company practica and I believe it to be reliable.

t q 1 o 4 I ) Walter J. hc C a r t'h y , Jr.  !

                                                          ._ - Cha i rma n _o f i.t.ha _Baa rd _ . ..._ . - - .

Detroit Edison i i ~ SUBSCRIBED and SWO to before me this ay of h/h6 19 6 C/ f I MM Notary Public MARCIA BUCX l Notary Public. Washtenaw County, MI Wy Commission Empires Dec.514 h ?% -

                                                                                                     'I i

TABLR OF ATTACBENTS liLla Iass i Attachment 1 1-1 Fermi 2 Independent Overview Coazittee Attachment 2 2-1 Resctor Operations Improvement Program Indicators

 ?

Attachment 3 3-1 System & Equipment Problem Resolution or Progress Attachment 4 4-1 Actions to Insure Readiness for Reactor Restart Attachment 5 5-1 Actions to be Completed Af ter Restart Prior to Test Condition 1 1 I

       .n                                                                                              l

AIIAgBMENT 1 Ferri 2 Indeenndent Overview Committee Recognising that an introspective self-examination is by its very nature a limited undertaking. Detroit Edison has sought an independent, unbiased review of its management, j organization and improvement programs. A group of recognized nuclear industry experts with a broad range of management and operating experience has been retained to operate as an Independent Overview Committee. This Overview Committee has an initial management assessment role and then a follow-up assessment and approval role for power ascension. The charter for this Overview is provided herein. l' The committee has a specific charge from the Chief Executive Officer to report findings and make recommendations regarding the management of Termi 2. r

                                      **~                                                                       .- .-                                                                                    __ _

1-1

                                                                                      \

l l CBAEIZE i FERPI 2 TNDEFENDENT OVERVIEW COMMITTEE i PURPOSE l The purpose of the Committee is to provide corporate management and

 !     the Board of Directors of Detroit Edison an overview evaluation of the operation of Fermi i and the performance of Nuclear Operations management. The Comnittee will provide advice concerning changes in            i management management systems or structures and in the operation of Ferzi 2 that will asstre its safe operation.

WEEEERSFIP Jack Calhoun. General Physics Corporation. Chairman Barry J. Green. Consultant  ; i Leo C. Lessor. Managnment Analysis Company l Salomon Levy. S. Levy. Inc. Murray E. Miles. Basic Energy Technology Associates. Inc. James V. Neely. Nuclear Power Consultants. Inc. 3 1EPORTING The Committee will report its findings and recommendations to the l Chief Executive Of ficer of Detroit Edison. The President of Detroit Edison will be available to participate in the deliberations of the 1 . couaittee when required. The Scard Nuclear Review Committee will j attend some of the deilngs othe committee anifTall remain ~ cognizant " ~~ ~ l i of its findings and recommendaticis. i C00RDIKATION OF THE COMMITTEE'S Q?IVITIES The Assistant Manager. Regulation & Compliance. Nuclear Operations. Detroit Edison, or his designee, will coordinate and assist where necessary in the activities of the Courittee. He will provide any , reports, memoranda, and letters the Ctumittee requires and will  ! arrange for meetings, interviews, visirs to the plant. trips, etc., required by the Committee. He will act as contract administrator for all contracts required to carry out the Committee's activities. ANTICIPATED MEETING SCHEDULE I' Week of January 6 - 11 Week of January 27 - 31 Week of February 24 - 28

One Jay per month for the remainder of 1986 1-2

CRARTER Fermi 2 Independent Overview Committee Page 2 l i i 1G11

!                     Manne.aert tvatumelon Tank I                      Frepare a report which identifies, evaluates , and analyses any management, management structure, and system problems and root causes of these problems. This report should specifically address Item 1 Page 2. of the December 24. 1985 Nuclear Regulatory Commission letter from James C. Keppler to Wayne B. Jens.

Present the Overview Committee report to Detroit Edison senior management, and representatives of the Detroit Edison Board of Directors in a meeting to be held on February 7.1986 or soon thereafter.

;                      Review the Improvement Flan prepared by the Nuclear Operations management staf f in response to the problems identified by the Overview Committee.

Monitor during 1986 the actions required in meeting the Nuclear Operations Improvement Plan and recommend modifications to the plan as j appropriate. 1

!                       Remeter Deermelena lawlev Review the Reactor Operations Improvement Plan presented to the NRC in 4

letters dated October 10. 1985, and November 27. 1985, and any future i

        ~
                      ~ mod'ififatIons 't(~Ehls plan. Norass specifies 11                7 wr plans to -restatt - - - - -

the plant in February. Review the performance of the plant and organisation during the restart of the plant af ter the Fall and Winter i 1985 outage. Based on this review. recommend further action required for increasing reactor power beyond 52 to the next power plateau. The committee will review and comment on Detroit Edison's response to the December 24, 1985 letter. Specifically, the committee should evaluate whether the plans presented in this letter adequately cover the necessary conditions that should be met prior to resuming operation. Since the management evaluation task may have uncovered i management deficiencies that should be corrected prior to restart, we would like to have those pointed out to us in your response and comments to our draf t letter. The committee will review and provide any necessary advice concerning each test condition up to and including commercial operation, warranty test and full power operation. This power escalation program will be submitted to the NRC in response to the December 24, 1985 letter. 1-3

l 1 I l

                      ~

ATTACHMENT 2 Remetor Deerations Teprovement Pl an S t a.typ The Reactor Operations Improvement Plan was subritted to the NRC on October 18, 1985. Included herein is a status report on the commitments contained in that letter. Sixty-one of the sixty-four commitments have been implemented. Monitoring information is also provided berein to demenstrate the effect the Plan has had on plant operations. The;3cels identified in'this plan are ones which are indicative of a mature operatirg plant. Management expects positive trends to continue and will continue to monitor them. Any deviations away from the desired tren! or goal will prompt management reviev and corrective' action, as appropriate, to assure that progress toward the objectives of the Plan continues. It is anticipated char, as the Fermi 2 operating experience increaser, we will move even closer to these goals. It is important to note that these goals may require adjustment, either up or down, should management determine that the l goals are too limiting or are otherwise not achieving the I desired results. Progress on the Plan will be reviewed with the Independent Over Committee.

                        ' ~        ***
                                                                                        ..s l

I - 2-1 i e r --- -- - , . . - - . _ . . _ , __ _ , . _ _ _ , _ _ _, , __ __ e_ _ _

s REACTOR OPERATIONS IMPROVDtENT PLAN Commitment Status Ac t i on I t ee

• Status

1. Current dated LCOs are displayed in hard copy. Complete

2. The DOT system of flagging control board syster and Incomplete component abnormal conditions is being made more (QST issued) visible and meaningful in correlation with the outstanding work orders.

3. a. Tagging and work orders are being modified to Complete more clearly specify post-maintenance test re-quirements.

b. Indicate which documents require revision. Complete

4. As a long-term action, ad=inistrative work procedures Partially Comp.

will be simplified or clarified to consistency. (Training Reg'd.)

5. Item 5 Deleted. N/A

6. Nuclear Operations personnel have been advised to Complete consider the consequences of taking even the simplest actions.

7. Personnel have been advised that it is equally Complete important that the error be communicated so that appropriste operating staf f or management actico can take place in a timely manner.

8. The reducticn of open work items and increased Complete control byte cperating vtaff ever-epen-week-4tems- - - - _ . _ . _. .

will reduce the number of unexper.ted operational occurrences and violations.

9. The Nuclear Training organization is developing , complete and, when possible, modifying existing scenarios to exercise the requalification classes oa routine plant startup and operation.

10. Emphasis is being placed on normal system line-up. Complet e operation and responses required.

11. The importance of logging activities on charts at Complete shift turnover, system startup and transient initiation is stressed as is evaluation of plant conditions using the Sequence of Events Recorder.

 *EDII: All " Completes" have been verified by Nulcear Quality Assurance 2-2

12. Tha Flant M:n gst cr th2 53 pari:to;dcnt-0percticns Complete oro 00ctisg individ: ally eith occh NSS. NASS cnd shift Operating Advisor (SOA).

13. To improve the quality of Control Room operations Complete logs, entries into the Nuclear Supervising Operator's (550) los are being made by the NASS as an interin measure.

14. The Operaticos Engineer or designee is reviewing Comple t e ,

the MSS and NSO logs at least daily, except week- I ends, to assure that they are being kept properly f and that the proper entries are being recorded as ' the plant is being operated.

15. Superintendent-Operations is reviewing the NSS and Complete NSO logs on a periodic basis to provide feedback to the RSS and the Operations Engineer.

16. The NASS has been assigned to the Control Room Conplete proper as a permanent duty station on shif t.

17. The NASS has been placed in charge at the controls Complete area of the Control Room during planned reactivity manipulations, plant startups and shutdowns , multiple plant testing activities and outage periods when sign-ificant maintenance is in progress.

18. The role ~of the Control Room NSO has been clarified Complete to assist the NASS or NSS in directing plant act-ivities.

19. The duty station of the SOA is now the Control Room. Complete

20. SOAs have increased their involvement in activities Complete in the Control Room.

21. Shif t Technical Advisor (STA) sonitors for hardware- Complete related problems associated with Control Room equip-ment which may not otherwise be identified or tracked.

22. The STA is concerned with resolving Control Rooe Complete problems like nuisance annunciators and alarms in addition to normal duties.

23. The Reactor Engineer has increased participation in Complete I reactor operations and is closely following, analyzing and reviewing significant reactor evolutions.

24. Operations Engineer has increased involvement in Complete operations by following and reviewing performance of i shift activities against established plans and checking the quality of Control Room logs.

25. The NSS has been given the authority to control work Complete in the plant by setting priorities and work load.

2-3

26. Item 25 is accomplish:d through intorfcco uith the plcnt complete Outage Management organisation and through direct involvement in work planning meetings.

27. The Superintendent-Operations periodically and without Complete notice has been observing shif t operation activities.

28. The Superintendent-Operations gives feedback to the Complete Nuclear Shift Supervisor (NSS) or Ruclear Assistant l Shift Supervisor (NASS) and documents any observations.

29. The Superintendent-operations observations include Complete actual plant operations and the review of operations administrative activities such as shift turnover. log review and plant status system updates.

30. The advisor to the Plant Manager is conducting more Complete frequent, regular surveillances of Control Room operations.

31. The advisor observes the performance of the Control Complete Room crew, reads the log kept by the Shif t Operating Advisor (SOA), discusses any problems with the SOA reads the log kept by the Ruclear Supervising Operator (N50).

32. In addition, the advisor observes plant parameters Complete and provides his observations to the Plant Manager.

33. Following turnover fro = the off-going NSS, the NSS Complete conducts a briefing of shift operating personnel.

34. Supplemental training on the current requirements for Complete control rod manipulations, including the reduced notch worth pull concept, has been conducted with all six shif ts of plant operators.

35. Training is emphasizing .the impcrtant dif ferences complete between the plant and the simulator during training.

36. The operations staff is providing on-shift training Complete regarding significant plant and procedure changes.

37. An interim status chart has been implemented to Complete track LCOs on equipment required by Technical Specifications which aff ect shift activities.

38. The work order, tagging and equipment status system Complete has been modified to more clearly specify post-maintenance test requirements.

39. Numan factors methods are being applied to the Partially administrative procedures to make them more Complete.

streamlined and more user oriented. (Training Reg'd) l 2-4 I

40. LERs cro being:

a. Tracked. Complete

b. Trended so that symptoms of po'tential problems Complete can be diagnosed early to prevent recurrence.

41. Emerging trends and selected LERs are being evaluated Complete utilizing proven, systematic problem-solving methods to identify causes and remedial as well as preventive corrective action.

42. Corrective action taken is being:

a. Tracked to Completion. Complete

b. evaluated for effectiveness. Complete

43. The corrective action process is being further enhanced by:

a. Refinement of procedures associated with the Complete proc es s .

b. Structured training for personnel involved in the Complete evaluation and review phases of the process.

44. Corrective Action Procedures have been issued for Complete implementation.

45. Corrective Action formal training for selected Complete personnel is scheduled to begin the week of November 4th.

46. Actions previously initiated by QA organization, will Complete improve the timeliness and overall effectiveness of the corrective action process.

47. a . In each one-on-one session between the Plant Complete Manager or the Superintendent-Operations and the NSS, NASS, and SOA, employes are reminded of their responsibilities; delegated authority and account-abilities; of their expected job performances and of their relationship with other shift members.

b. Meetings with employes down to the group super- Complete visor level were held during the week of September 17 to discuss the status of the plant, the status of NRC/ DECO interactions and to remind each employe of his part in improving the performance of Fermi 2.

48. The NSS is responsible for ensuring that the ability Complete to provide proper direction is not compromised by an excess of work or testing.

i 1 2-5  :

• l l

49. For this rococn (Item 48), th? NSS is ccatrolling cork in the Complete plant by determining priority and amounts of work for the shift.

50. Work in the plant is identified and, scheduled on a Complete Plan of the Day.

51. Each working day, a planning meeting is held with the Complete day shift RSS in attendance.

52. The NSS provides input relative to anticipated plant complete operations over the next few days so that tasks can be identified and prioritized on the schedule accordingly.

53. The NSS establishes work priority and provides Complete direction as to the amount of work to be scheduled.

54. The Plant Support Engineers review Engineering Complete Evaluation Requests (EERs) and Engineering Design Packages (EDPs) to reduce plant changes to only those necessary for safe plant operation.

55. The NSS conducts status meetings at 0600, 1800, and Complete 0100 hours.

56. These meetings (Item 55) are held with representatives from complete the various work groups to monitor progress on important items as well as to allow additions to the work schedule or review changes in course as directed by the NSS.

57. Coals have been established for certain key Complete operational activities.

_58 Detroit Edi_s,on _has, established ebjective monitoring Complete

          . criteria to determine _ _t'he overall-'eYfectiveness vf ---

the Reactor Operations Improvement Plan.

59. Detroit Edison organizational units have been Complete assigned responsibility to track and trend perform-ance with respect to each of these criteria.

60. Management will be acnitoring this performance so Complete that adjustments can be made, if necessary.

61. The Nuclear Quality Assurance organization of Nuclear complete ,

Operations will provide independent verification of l effective implementation of the program utilizing ] audits and/or surveillance methods.

62. Results will be reported to Nuclear Production and Complete Nuclear Operations Management.

2-6 i

   ,                 . _ . _ , , - -                    -.                             ,.O,

l i Remeter Onermeinna Teerevement Freerar Indienters Coal A o The goal is to minimize the number of open work orders. l o The dotted line represents the expected while the solid line represents the actual results. o As of January 26, 1986 there were 173 open work orders. Comi E: o The goal is to minimize the number of field complete (F.C.) EDP's open for greater than 30 days not yet closed and signed off by the Plant Manager. I I o As of January 26, 1986 there were 41 open F.C. EDP's. Cent c o The goal is to minimize the number of outstanding Control Room problem annuncistors. o The dotted line represents the expected range. The solid line represents the actual results. A specific breakdown between engineering and broke /fix annunciators is also pr e s en t ed . o As of January 26, 1986 there were a total of 39 outstanding Control Room problem annunciators. Coni D o The goal is to perform all surveillance procedures on time, including the grace period and to minimize the number requiring use of the grace period. o-- ToF Usi week en3ing January-26.-1986 there wre 100% --- -- - - - - - - ---- - surveillances completed on time including the grace period and there was one (1) surveillance not completed within 24 hours of entering the grace period. Coal E: o The goal is to minimize the number of outstanding, time-sensitive LCO's. o As of January 26, 1986 there were zero (0) outstanding, time-sensitive LCO's. Coal F: o The goal is to minimize the number of Reportable Operational Occurrences. o For the week ending January 26, 1986 there were zero (0) LER's. o The four week rolling average as of January 26, 1986 was 0.25. 2-7

C0AL A Minimize number of enen PN-21's (Verk Orderal Ob4ectiven: TOTAL - 150 Management Attention Level TOTAL - 110 Expected N l U l M 400 1 B i E l R l 1 0 300 l P l E l 1 N I 219 W 200 l\ O l 171 173 R l%15d6 - -

                                              - - - / - - - - - - - - - - - - - - - - 15 0 MA L E          1             144           145
                                         \         '

l 121y37 O 100 1------- ----------------- 110 R l Expected D l E I , R l s o I l I I I I I I I I I I I I I I I I I l December l January February 1 ' March 'l ~~ " - 1 6 15 22 29 5 12 19 26 2 9 16 23 2 9 16 23 30 6

30TE: Includes plant system related PN-21's (work orders) only.

During an Outage greater than one week in duration, total numbers can be increased by a factor of 2.5. Because the trend is above the Management Attention Level, an inquiry was prompted to identify the source for the increasing trend. The trend is above the Management Attention Level due to a controlled, deliberate increase in known work items to support reactor restart. 2-8 i

COAL 3: Minimise number of DP's which remain open after work has bene ceryleted. (.... field enentete.

  .iective:              D P's open 30 days       - 15 Management Attention Level after field work         -   7 Expected complete                                                                             ,

l l 200 I l 100 I Ull% O r l ~ of 150 l ield l nrlete 140 l DP's l 120 l l 100 I coen l Pact E0 1 30 l is 60 l I O 41 40 j % s3., 37-33Ss'4 r 20 l - l-------------------------------- --------------------- 15 'I'A

           -- - 1 -                                         _ _ _ _   _ _ _ _                          _

l------------------------------------------------------ 7 0 ! 2x aac;2; I I -- I I I I I I I I I I I I i 1 1 I l l Decer.ber l .7 e nua r;' l Februtry l  !!a r ch l 1 P. 1522795 32 19 26 7 9 15 23 7 a Ir 23 3r G l NOTE: This trend remains above the Management Attention Level. A management inquiry has revealed that the rate of closure has remained relatively constant due to the large number of EQ DPs closed out during the 85-01 Outage. l 2-9 l l

COAL C: Misioise cunbar of 12cperable er centinuously claruirg annunciators in Contrel Room inetive: - 15 Management Attention Level

                         -   10 Expected 100 I I                                               Engineering Fixes = 23 I                                               Other Fixes         = 16 9C l                                                Total               - 39 I

I 80 l I Total Number of Annunciators = 1224 1 70 l I utstanding l EC 1 Contrcl i I Roon 50 51 1 Problon

• l 40 l J1'46 4'\

 >nnunciators         I                                  39 38 m3 5 1     3 6'3 ^/

Paquiring 30 l l

    .neering          i                              g -23 20 I Fi::              I i _ _ _ _ _ _ _ _ _ _ _ _________________________________1,..,1,

_ _ _ _ _ _ _ _ Li I 5 . I

            -----e  q__--       ---

________________________._..__2a l ~ : ,:-:: :- J. I OI I I I I _I I I I I I __I I I I I I I I I I tecender l .7anua y l Februtry I "orcP

                                                                                     .          l 12 19 2G 2         15 ?3 2     "  16 23 30 '

1 3 15 22 29 5 P BOTE: Froblem annunciators are all inoperable, nuisance, setpoint. logic, etc. related annunciators. Management has requested a schedule and plan for the engineering items. Additional attention is being directed to expedite resolution of the other fixes required. 2-10 l

I l COAL D: Perfere Survei11=neca en ties ninfririne usine armee meriod j 4ective: Surveillances completed on time including grace period: 99% Management Attentien Level

                                - 100% Expected Surveillances not completed within 24 hosts of reaching the grace period:

7/ week Management Attention Level 5/ week Expected i 101 1 I furvoillances i 100 1-100-100-100-100-100-100 Comploted I 99 l on Time 1 98 1 Including I 97 1 3raco Period l 96 I (t) l 15 1 - 1 I I I I I I I I I I I I I I I I I I I l December i January l February l March l 1 8 15 22 29 5 12 19 26 2 9 16 23 2 9 1623306 l 10 1 3urvo111ances 1 -- Not 8 l Completed 1------------------------------------------------------ 7 MAL Within 6 1 24 Hours l------------------------------------------------------ 5 af entoring 4 l Expected the Grace  ! Poriod (No./ Week) 2 1ly g -1 2 1 2g -I g 1 0 I I I I I I I O I I I I I I I I I I I December l January l February i March 1 1 8 15 22 29 5 12 19 26 2 9 16 23 2 9 16 23 30 6 2-11 1

                                                                                         -                         -~ ~~

C0AL E: Finielre the nii-her of nutstandine. time sensitive Leo ' a-jective: Number of dated - 5 Management Attention Level LCO's outstanding - 3 Expected I 10 1 I 9 l l Number 8l 1 of 7I I Dated 6I I 5 l------------------------------------------------------ 5 MAL r,co'o I 4I I Butetanding 3 ^- 3 l--------------------------------------------------- i Expected 2l 2 1 2 __.2

                                                    \                            --               - - -      - - -
                                                     \

23\l 0! \ 0-0 0-0 I l I I I I I I I I I I I I I I I I I l December l January i February l March l 1 8 15 22 29 5 12 19 26 2 9 16 23 2 9 16 23 30 6 2-12 (

l l-COAL 7: Minieine the nueber of reeeremble neerational neenrrences .._ . _ . . _ . ___ . _ _ _ _ _ Sjective: Number of Licensee - 2/wcek Management Attention Level Event Reports (LER's) 1.5/ week Expected I 5l l l 1 I 4I . I I irnbar 1 3I I I 2 - Mgmt. of l Attention

                       ---------2-------------------------------------------- Level I

i ------ - ------------------------------------------- 1.5 8R's/wk l Expected 11 1 1 I I oI o 0- 0-0 1 1 1 1 1 I 1 I i i i i i i 1 -1 1 1 1 l December l January l February l March i 1 8 15 22 29 5 12 19 26 2 9 16 23 2 9 16 23 30 6 3i ~~ - ~- Our i I eok 2l l Lr l . Q - -- - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - 1. 5 - Mg t . 9111ng 1.25 1.25-1.25 Attention Level 11------------\-------------------------------------------------1.0-----Expected l .75 75 sorage i N.5# ,\5-25 oi l l I I I I I I I I I l l l 1 I I I I

@R'c/wk)              l      December                  l   January l         February l                   March                        l 1    8     15 22 29 5                 12 19 26 2         9    16 23 2           9     16 23 30 6 NOTE:    Reportable Operational Occurrences do not include Security-related events.

2-13

ATTACRMENT 3 Evater and Enuinment Probl em Remetut inn er Froereas The information berein identifies the status of system and equipment problems which were identified as restraints to restart or which were addressed to improve regulatory and operating performance:

1. Equipment Environmental Qualific tic: M:difi:::ic:: .

2. Installation of an Alternate Shutdown Panel

3. Main Steam Bypass Line Replacement

4. South Reactor Feed Pump Turbine

5. High Pressure Coolant Injection (HPCI) Pump

6. Emergency Diesel Generator Repairs

7. Residual Beat Removal Pump "B" Motor Replacement B. ~7eactor Auxiliary Building Embedded Plates - - - -

9. Traversing In-Core Probe (TIP) Nitrogen Purge Line Isolation a

10. Reactor Water Clean-Up System Modifications l

  ~
                             * * -      * ~ ~ * -

3-1

1. Eeuinment Envienn= ental Dualifientien Modifientiona In order to comply with the requirements of 10CTR49 and Generic Letter 85-15. an evaluation was made of all safety-related equipment to determine its environmental qualification (EQ). The Fermi 2 EQ submittal to the NRC identified which safety-related equipment in a harsh environment would require relocation or replacement. During the Fall 85-01 Outage, all equipment delineated in the submittal was relocated or replaced.

2. Installmeien of Alt ernate Shu t d own Panel During the 85-01 outage en alternate shutdown panel

 ,                              was installed to provide additional shutdown capability to satisfy License Condition 2.c.9.d. in the event of a damaging fire in the Control Center. A
   -                            final design and operating procedure review was conducted in parallel with construction. Three design deficiencies were identified and are being corrected.

3. Main Steme Evemma Line Benimesment On September 15,1985. cracks in the pipe wall of the east main steam bypass line were discovered. Similar cracks were found in the west bypass line upon further i investigation. The cracks developed at attachment points as a result of high frequency, flow-induced vibra t ion. New bypass lines have been installed which incorporate heavier wall pipe to reduce stress. reduce pipe attachment stress concentration and pressure breakdown orifices to stage the pressure and reduce velocity in tO pipe. Vib'rTtTon and strain - -- -

instrumentation has been installed on the lines to

provide empirical design verification after the lines are in operation. A safety evaluation has been completed to ensure the system capacity meets the l valuer stated in the Fermi 2 PSAR.

i l .

4. South Remeter Feed Pu=n Turb in e (SRFPT)

The SRFPT failed in June.1985. The vibration on the machine was not detected in the Control Room due to inaccurate instrument indication. The extent of the i damage required the complete disessembly and repair or l replacement af the turbine rotor, bearing pedestal. and miscellaneous bearings, seals and tria piping. Additional instrumentation has been added and the turbine is ready for operation when reactor steam is ava il ab le. A piping modification was made on the 31sad seal system to reduce air in leakage' to the c ondenser. 3-2

5. Eigh Preasure Coolant Ininetion (RPCI) Pumn Initial operation of the Righ Pressure Coolant Injection (BPCI) Fump. under load, evidenced moderate vib ra t ion . During the Fall 85-01 Outage, cold alignment checks and realignment was made on the pump. l No defects were found upon inspection of the booster l pump internals. l J

Modifications to the governor and overspeed trip  ! device were made to ensure proper operation in the future. Installation of alignment devices for hot alignment of the unit were completed. The unit is ready for testing when steam is available upon restart.

6. *-areenev Diesel Cenerator Renmira The diesels have undergone extensive analysis to determine the cause for the bearing problems experienced to date. Contributing causes include misalignment. long-term storage environment, misassembly, lack of pre-lube. and particulate in the oil . Several corrective actions have been taken to address the contributing causes. In addition, a slow-start feature has been added. A reliability demonstration is planned for two diesels. A presentation was made to the ERC itaff on January '24 -

1986, outlining this program. A formal submittal of the program will be made to the NRC.

7. Residum' Best Memovm1 Firen 'B' Motor Renlac===nt On November 25, 1985 RRR pump motor 'B" failed during operation in The uburdown cuo Mug w de. N ertiIntiun shows the failure to be caused by lack of process

control during manuf acture followed by low-amplitude, cyclic stress during operation. A replacement motor has been obtained from the Browns Ferry plant and is now installed. Another motor is being investigated to assure that this was an isolated failure.

8. Reme t er Anv il i a ry Buildine *=hedded Pinten l i

Standard embedded plates were incorporated in the design of the Reactor Building as a means to anchor loads to the concrete structure. Generic load capacities were established for these embedments with the intention of performing specific load reconciliation after construction completion to ensure no overloading. 3-3 )

 =

a

A cesservctiva caolysis h:d base parformed to idaatify ~ ~ ~ ~ those embedments which potentially could be - - - - - -

                                                                                                          --- -i overloaded. However, subsequent detailed review of                                                     l the potentially overloaded embedments.

9. Traversing In-Core Probe (TIP) Nitrogen Purge Line  ;

Isolation Recent correspondence from the NRC reveals the TIP nitrogen purge line should conform to General Design Criteria 56 (GDC56). An interim design to meet the intent of CDC56 is being implemented which  ; incorporates two QAI seismically-sounted ball valves outside containment. This change will be installed prior to starting from the present outage.

10. Reacter Water cleanne Evstem Modifications During initial operations, numerous unnecessary Reactor Water Cleanup System (RWCU) isolations I

oc curred . These isolations have been attributed primarily to the Steam Leak Detection Syster and to the differential flow (Leak Detection) isolation signals. Instrument and control modifications were made on this system to prevent recurrence of the - - - _ problem and to provide the operators Control Room

                                      ~~~                       ~~~         ~

information. W6m em 3 -4

_ . _ _ . _ - ~ _ _ 4 Ac t i on s to Ynaure Readiness for tsacter Restart Following are the items which were completed for the last reactor startup prior to the fall 85-01 Outage. Because this startup was successful, these items will be repeated for the next startup.

1. Lineups and independent verification of lineups will be completed on Engineered Safety Feature (EST) Systems designated by the Operations Engineer within 30 days of the planned reactor startup date.

2. Existing lineups will be reviewed by Operations Supervision for all plant systems. ,

3. The lineups of primary containment manual isolation valves outside the dryvell will be verified and independently reviewed.

4. A random sample of fire barriers will be walked

              ~down and verified -fer templianee with Technical - -         --

Spec if ic a t ion s .

5. Security barriers will be walked down and verified for compliance with the Physical Security Plan.

l 6. The securacy of the " Control Room Status File" will be verified by Operations Supervisor.

7. All required Operational Condition 2 surveillances will be completed.

8. Temporary modifications will be verified for applicability.

Add it ional Ir een Added to Tnsure Readinema for Esatart The following additional items will also be completed to insure readiness for restart:

1. The Reactor Operators responsible for reactor startup will have recently conducted reactor startup evolutions on the simulator.

4-1 l l

Attcchnent 4

2. Outstanding Technical Specification change requests will be reviewed by Operations Supervision to ensure full compliance with Technical Specifications.

3. The Technical Engineer will review Deviation Event Reports identified by Nuclear Production i

management to ensure that they are closed or, if not closed, that they have been determined ,to not contribute to repetitive events.

4. Nuclear Quality Assurance will ensure that actions assigned as a result of Licensee Event Reports (LER) are completed or adequately planned.

5. The Reactor Operations Improvement Plan (ROIP) goals listed below are either being met or show a trend toward the established goal. These gosis are:

a. Minimize the number of Control Room nuisance alarms.

b. Minimize the number cf Engineering Design Packages (EDP) which are field complete for greater Ehan~30 ~3ays but require paperwork - - -

closure.

c. Minimize the number of time-sensitive Limiting Conditions for Operation (LCO).

d. Minimize the number of " signed on" active work orders (PN-21's).

e. Complete all surveillances within the grace period and minimize the use of the grace period.

f. Minimize the number of Licensee Event Reports (LER).

6. Operational Assurance will conduct an audit or surveillance of committed reactor startup readiness tasks within 30 days of the planned reactor startup date.

4-2 i I

ATTACRMENT 5 ,

                                                                                  ~

Actions To Be Completed After Restart Prior to Test Condition I The following listing are the items which must be completed prior to exceeding 51 power. These items are either the completion of testing which requires the reactor be in operation at low power levels or actions taken to ensure readiness of the facility to support power ascension. Upon successful completion of these items the plant will have met all the technical

• requirements to exceed 51 power and will be ready to commence Test Condition 1.

1. High pressure coolant injection will be retested and declared operable.

2. Reactor Core Isolation Cooling system will be verified operable.

3. The Main Steam Relief Valve and Automatic Depressurisation System will be verified operable.

4. Main Steam bypass line expansion will be monitored during testing.

5. South Rasetor Peed Pump performance will be verified by test.

 ~-
      -- M .--Operation und ywi f.. ace -of-the-Of f -Gee -eystem --   _ - . _ _ _ - - . . _                 _

will be verified by test.

7. Reactor Operations Improvement Plan (101P) goals listed below are being met or show a trend toward the established goals:

a. Minimize the number of Control Room nuisance alarus.

L. ;;LL lse th _ hr :f Eginee-r-isg Design _ , Packages (EDP) which are field complete for greater than 30 days but require paperwork closure.

c. Minimize the number of time-sensitive Limiting Conditions for Operation (LCO).

d. Minimize the number of " signed on" active work orders (PR-21's) .

e. Complete all surveillances within the grace period and minimize the use of the grace period.

f. Minimize the number of Licensee Event Reports (LER).

5-1 1 i i i

Enclosure 2 Augmented Inspection Plan Due to the numerous problems associated with the operations department and operations related activities Region III is implementing an Augmented Inspection Plan (Enclosure 2A) to observe plant activities during startup and until there is sufficient confidence that the licensee is able to effectively manage the plant at power operations. The initial inspection activities will be handled by the resident inspectors. Subsequent observations will be handled by a team comprised of representatives from Region III, and other offices as appropriate. The team will function to observe daily operations, implementation of Detroit Edison's Reactor Operations Improvement Plan (Enclosure IB and ID) and any short term change proposed by the licensee in their response to the 50.54(f) letter (Enclosure IE). DRP envisions that the overall final inspection plan will at a minimum address the following areas during the restart effort: development and implementation of management goals and objectives and how these are understood and implemented. planning and control of routine activities control room as well.as balance of plant attitudes of personnel with respect to nuclear safety and procedural adherence. level of understanding by workers and management of the potential impact of day to day action on nuclear safety. Involvement of DECO Senior management in the day to day operation of the facility. l The effectiveness of direction, guidance and supervision by first line j supervisors. i Lead Responsibility: Region III, DRP 4

DRAFT - ENCLOSURE 2.A November 19, 1985 MEMORANDUM FOR: G. C. Wright, Chief, Reactor Projects Section 2C FROM: P. M. Byron, Senior Resident Inspector, Fermi

SUBJECT:

Fermi 2 Augmented Inspection Plan Fermi 2 has had repeated significant operational problems commencing with the July 1 premature criticality continuing through September. The unit is currently in cold shutdown and has not operated since October 10, 1985. Several meetings have been held to review the licensee

• s actions 7nd the weasures -they-trave-instituted-to minimize --- -- - - - -

or prevent recurrence. The licensee submitted a Reactor Operations Improvement Plan (ROIP) to Region III dated October 10, 1985, which is Enclosure 2 to this plan. Region III believes that it is tppropriate to provide augmented inspection coverage. The augmented inspection plan is contained in Enclosure 1. The inspection plan includes three hold points; 0%, 5%, and 25% power. The third hold point (25%) was chosen to allow the inspectors to perform a more encompassing appraisal of the

DRAf1 licensee's ability to manage and operate the unit. The licensee has f scheduled 31 days for operation between 5 and 25 percent. This is - sufficient time to observe how well the licensee manages the increased operation of equipment and startup testing activities i integrated with routine plant activities. , The following are criteria which must be met before exceeding the I sp2cified power levels.

1. 0%

a. Seismic analysis issue resolved to RIII satisfaction.

t. 3L panel tested and operational. - All procedures approved and in place.

c. EQ modifications complete,

d. EDG #13 problem resolved to RIII satisfaction.

              --- e. ---EDG *14 inspected -and sny -issues -resobed.---                         --- -

2. 5%

a. Actions associated with the ROIP implemented.

b. No LCO violations.

c. No personnel errors.

d. CAT "B" items must be completed.

1 1 2

DRAFT

3. 25% i l

a. No LCO violations,

b. All surveillances completed on time without benefit of

                    " grace" period or provide justification.

c. PM's completed on time or provide justification.

d. No personnel errors.

e. ROIP effective in reducing number of PN-21's.

f. Control of LCO time clocks effective.

g. Startup testing activities effectively integrated into routine plant activities (surveillances, maintenance, rM's).

h. H!d: Open items addressed and backlog reduced.

i. Shift Status / Briefing effective in keeping shifts appraised of ongoing and planned activities.

j. Reduce the number of Control Room related PN-21's to

                    .not more'than twenty.                                     - - - - - - - - -   --

4 l P. M. Byron, SRI, Fermi 2 r 3 - - - _ _ _ - -

DRAFT

Enclosures:

1. RIII/ SRI Inspection Plan

2. DECO ltr VP-850198 dtd October 10, 1985 l

l l l 4

DRAFT Enclosure 1 INSPECTION PLAN The following are items to be inspected prior to exceeding the , listed power levels. A. Zero Percent (0%) RIII 1. Seismic analysis completed. NRR/5RI 2. EQ Mods complete. RIII 3. 3L panel operational- procedures approved and in pl a c e . - - - - - - - - - RIII/NRR 4. EDG-13 repaired & tested--cause of failure determined. SRI /RIII 5. EDG-14 inspected. SRI 6. Simulator training is being focused upon normal plant operations (emphasize log entries, marking charts, i.e., good Control Room practices. l 5

DRAFT SRI 7. Plant Manager or Superintendent-Operations has had one-on-one meetings with each NSS, NASS, and Shift Operating Advisor (50A) to review and emphasize responsibilities and authorities. SRI 8. Operations Engineer or Assistant Operations Engineer reviews NSS and Nuclear Shift Operator (N50) logs daily. SRI 9. Superintendent-Operations reviews NSS and N50 logs periodically. SRI 10. All advisor roles have been clariried and the SOA has been moved to the Control Room with the STA. The Shift Technical Advisor (STA) has been assigned the additional task of investigating and wsolving-persistent-euisance -elams and -- -- -- -- annunciators. SRI / Team 11. Operations Engineer reviews performance of shift activities against plans. l SRI / Team 12. NSS involved in planning for plant evolutions. 1

1 1 DRAFT SRl/ Team 13. Superintendent-Operations randomly observes shift operation, provides feedback to the Nuclear Shift Supervisor (N55) and documents these observations. SRI / Team 14. Advisor to Plant Manager conducts regular surveillances of Control Room Operations and provides feedback to Plant Manager. SRI 15. NSS or Nuclear Assistant Shift Supervisor (NASS) conducts briefings for shift operating personnel following turnover. SRI 16. Operating staff personnel conduct on-shift training on significant plant and procedure changes. i SRI / Team 17. N55 requires briefing prior to significant test activities and plant evolutions. l B. Five Percent (5%) SRI 1. Review Inspection Report 85031 to assure items have been addressed by licensee. ]

                                                         -_7.-,   ._ _        ___                                 _   _

DRAFT 1 SRI 2/ Review Inspection Report 85043 to assure items have been addressed by licensee. SRI /RIII 3. Review licensee response to item F of Inspection Report 85043. RIII 4. Review licensee ROIP effectiveness criteria. Team 5. Review PN-21's applicable to control room.

a. number outstanding

b. significance

c. prioritization SRI 6. Review Preoperational TEDR's (DER conversions)

(justification for not being completed should a be attached). Team 7. Review Maintenance PN-21 backlog (prioritization--take sample, determine agreement / disagreement). i Team / SRI 8. Review Control Room operations. SRI / Team 9. Operations Engineer reviews performance of shift activities against plans. 8 .

DRAFT SRI / Team 10. NSS involved in planning for plant evolutions. SRI / Team 11. Superintendent-Operations randomly observes shift operation, provides feedback to the Nuclear Shift Supervisor (NSS) and documents these observations. SRI / Team 12. Advisor to Plant Manager conducts regular o surveillances of Control Room operations and

                                                            ~

provides feedback to Plant Manager. SRI 13. Operating staff personnel conduct on-shift training on lignificant plant and procedure - - - changes. SRI 14. NSS requires briefing prior to significant test

 ~~

activitits ind piant evoiutions. -- SRI / Team 15. Interim status chart is being used to track LCO's on equipment required by Tet?nical Specifications affecting rai*t ar 'sities. SRI 16. LER's are being tracked and trended. l SRI / Team 17. NSS has been given authority to control work by i setting priorities and work. load. l 9

DRAT 1 Team 18. The N55 is conducting status meetings at 0600, 1800, and 0100 to monitor progress and changes in work activity. s Team 19. Quality Assurance to monitor implementation and effectiveness. C. Twenty-five Percent (25%) SRI / Team 1. Witness startup tests (sample). SRI 2. Witness main generator synchronization. Team /5RI 3. Observe Control Room Operations

a. surveillances b.--Tevei of wrk activity - - - - -- -

                          ~

c. control of out-of-service equipment

d. review occurance of personnel errors and defective procedure events

e. observe licensee's ability to control outstanding PN-21's

f. observe coordination of routine activities with startup testing activities.

g. review / observe maintenance activities for l

l proper closeout of PN-21's. 10 _ -.

I DRAFT

h. observe the licensee's ability to reduce the number of PN-21's applicable to the control room.

SRI / Team 4. Operations Engineer reviews performance of shift activities against plans. I SRI / Team 5. NSS Involved in planning for plant evolutions. SRI / Team 6. Superintendent-Operations randomly observes shift operation, provides feedback to the Nuclear Shift Supervisor (NSS) and documents these observations. --- - - SRI / Team 7. Advisor to Plant Manager conducts regular surveillances of Control Room operations and

  - " - "    -      - - - ~

provides -feedback t -Phmt-Manager --- -- - - -- l SRI / Team 8. NSS or Nuclear Assistant Shift Supervisor (NASS) , conducts briefings for shift operating personnel following turn:ner. SRI 9. Operating staff personnel conduct on-shift training on significant plant and procedure changes. l i 11

                                                                      -  w-- +        4                - - ,,w

DRAFT SRI / Team 10. NSS requires briefing prior to significant test activities and plant evolutions. l SRI / Team II. Interim status chart is being used to track LCO's on equipment required by Technical Specifications affecting shift activities. Team 12. Work order, tagging ano equipment status systems modified to more clearly specify post-maintenance test requirements and indicate documents which require revision. SRI 13. LER's 1 ire being tracked and trended. Team 14. Enchanced corrective action process. 1RI/ Team -- -15. --itSS tasteenWn strthonty -to-control-work-by -- - -- - setting priorities and work load. SRI / Team 16. Non-emergency work is being scheduled on Plan of the Day (POD). Team 17. The Plant Support Engineer is reviewing Engineering Evaluation Requests (EER's) and Engineering Design Packages (EDP's) to minimize changes. l 12

DRAFT Tcam 18. The N55 is conducting status meetings at 0600, 1800, and 0100 to monitor progress and changes in work activity. Team 19. Quality Assurance to monitor implementation and effectiveness. The SRI / Team will provide three shift coverage from the restart through the fifth day of operations at greater than five percent power. The coverage will run from the 6:00 a.m. planning meeting through the night shift briefing. Expanded coverage will be provided through the period until there 1s sufficient confidence - that the licensee is able to effectively manage the plant at power cperations. m -  ;

Enclosure 3 Confinmatory Action Letter In response-to the premature criticality event of July 1,1985, Region III issued a Confirmatory Action Letter (CAL) dated July 16, 1985 (Enclosure 3A). The CAL detailed a number of actions the licensee was to take and placed an agreed upon hold on reactor power to less than or equal to 5% power. The licensee has completed action on all the individual items, and Region III has verified that the actions have been completed, reference Inspection Report No. 50-341/85043 (inclosure 3B). The only remaining item is the 5% power limitation, which cce to subsequent events, remains in force. 9 i Lead Responsibility: Region III, DRP 5 _9. - -

CONF lR*.tTOD MT 10V t ETTE f CC. R111-EE-10 ENCLOSURE 3.A Ju, i6 19.!

                                                                         =

Docket No. 50-341 The Detroit Edison Company ATTh: Wayne H. Jens Vice President huclear Operations 6400 North Dixie Highway hewport, MI 48166 - Gentlemen: This letter confims the conversation on July 16, 1985, between Mr. E. Greenman of my staff and yourself related to the inadvertent criticality which occurred and went unrecognized during the reactor startup on July 2,1985. With regard to the matters discussed, we understand you have taken or will complete the following actions:

1. Provide to NRC Region 111 the results of your evaluation of the inadvertent criticality event of July 2, 1985, including corrective actions you have or will take. Include in your report the bases for not reporting this event to the NRC.

I

   .- 2.      Assure that operations personnel are properly trained and understand the applicable procedure (s) for subsequent control rod manipulations.

3. Assure that all operations personnel are aware of the event and its poten-tial significance.

4 Verify the operability and/or validity of the program for the the Rod Worth Minimizer.

5. Verify that training programs at your simulator are consistent with the current procedures being implemented at the facility.

E. Af ter all actions required above are completed, obtain verbal concurrence from the NRC Region 111 Regional Administrator or his designee prior to exceeding Si reactor power. l

                   <*           'h                 '

CAL-RIII-85-10 The Detroit Edison Company 2 '-- i 125 Please let us know if your understanding differs from that set forth above.

                                                   " Original signed by A. Bert Davis" James G. Keppler Regional Administrator cc: L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DMS/ Document Control Desk (RIDS)

Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voigt. Esq. - Nuclear Facilities and .. Environmental Monitoring Section a RIII RIII RI! RI}g"' L (, RII Chfssotimos/rr afer Norel'us yes Offis/Keppler 07/16/85

                                                                                     /jj,.

1 -

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                                                                                  .pt5
                                                           ~
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i UNITE 3 STATES ENCLOSURE 3.B U c NUCLEAR REGULATORY COMMISSION

 $              e                              REGION lil e              #                         700 ROOSEVELT ROAD b                             OLEN ELLYN, ILLINOIS 90137
      *oa

• NOV 8 1985 l

Docket No. 50-341 The Detroit Edison Company ATTN: Wayne H. Jens Vice President - Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 Gentlemen: This refers to the special operational readiness team inspection conducted by E. G. Greenman, G. C. Wright, A. J. Mendiola, M. E. Parker, and M. J. Jordan of this office on August 18-20 and September 16-20, 1985, of activities at Fenni 2 authorized by Facility Operating License No. NPF-33 and to the discussion of our findings with F. Agosti and R. S. Lenart and other members of your staff at the conclusion of the inspection. The enclosed copy of our inspection report identifies areas examined during the inspection. Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel. No violations of NRC requirements were identified during the course of this inspection. Inspection team findings have been characterized as program strengths, or weaknesses, as appropriate, and are documented in Appendices A and B, respectively, to this letter. A number of the weaknesses, in Appendix B, have been addressed in your " Reactor Operations Improvement Plan" which we are currently reviewing and will address in separate correspondence. Item F of Appendix B is not addressed in the Plan and as such you are requested to respond to this item within thirty (30) days of the receipt of this letter, stating actions taken or planned to improve the weak area. l In accordance with 10 CFR 2.790 of the Comission's regulations, a copy of this letter and the enclosed inspection report will be placed in the NRC's Public Document Room. 1 W MONG 9g' .

The Detroit Edison Company 2 l ' I.' l. * { l We will gladly discuss any questions you have concerning this inspection. Sincerely,  ; un/A. A C. E. Norelius, Director

                                                                     +=q Division of Reactor Projects

Enclosures:

1. Appendix A, Licensee Strengths

2. Appendix B Licensee Weaknesses

3. Inspection Report No. 50-341/85043(DRP) cc w/ enclosures:

L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DCS/RSB (RIDS) Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Comission Harry H. Voigt. Esq. Nuclear Facilities and Environmental Monitoring Section Monroe County Office of Civil Preparedness l l l RII R II RIII RIII RII T Landi n/jlk urg 1ht C s o imos Green $a No s , 10/23/85 Mgf 4

Appendix A LICENSEE STRENGTHS The inspection team noted specific features of the licensee's programs and activities which have been characterized as strengths. A strength is a . positive attribute or feature, which exceeds regulatory requirements, or ] feature, which may contribute to the safety or effectiveness of plant i activities. A. Moving Nuclear Assistant Shift Supervisor (NASS) into the control room giving more direction and supervision in the control room. B. Conmunication from the control room to the plant was considered good at the time of the inspection. C. Nuclear Supervising Operator (NS0) and Nuclear Shift Supervisor (NSS) logs were well written and were complementary to each other rather than being duplicates. l 4 i 1 1 l l l l

l

                                                                 ' Appendix B LICENSEE WEAKNESSES The inspection team has identified items of concern which have been                  "
                                                                                                     )

characterized as weaknesses. A weakness does not constitute a violation  ! with regulatory requirements, rather it is related to effectiveness of a l program, activity, or organization.  : A. The communications from management en current issues were not well j transmitted to the shift to allow for a clear understanding of what j was expected and why. B. The inspectors observed problems with the team effort of the control ! room operating staff. C. The Shift Operating Advisor (SOA) and Shift Technical Advisor (STA) and j the Reactor Engineer need to be integrated into the shift. D. Upper level management review of NSO and NSS logs was not evident. t E. The licensee has no mechanism for trae).ing short term LCO's. F. Shift check sheet needs to be revised to give acceptance values rather j than a checkoff as " SAT". l G. The Control Room Information System (CRIS) does not provide immediately t accessible information or equipment status. The " dots" associated with j the CRIS are difficult to identify on the panels. 1 i 4 i l I

U.S. NUCLEAR REGULATORY CODMISSION REGION III Report No. 50-341/85043(DRP) l

~

Docket No. 50-341 License No. NPF-33 i Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name: Fenni 2 Inspection At: Fermi Site, Newport, MI Inspection Conducted: August 18-20 and September 16-20, 1985 i Insper. tors: G. C. Wright

A. J. Mendiola 1

! M. E. Parker M. J. Jordan i-Approved By: G. C. Wright, Chief Projects Section 2C Date l Inspection Sumary: . Inspection on August 18-20 and September 16-20, 1985 (Inspection Report i No. 50-341/85043LDRP)) Areas Inspected: Special unannounced operational readiness assessment team inspection of the Fermi 2 facility in the areas of Conduct of Operations and corrective actions associated with recent events. The inspection involved 110 hours on site by five inspectors including 20 hours on backshifts. Results: No violations, deviations, or significant safety concerns were identified. ! l i l

l DETAILS i 1. Persons Contacted

                                                                                     \

l Detroit Edison Company  ! ! +*F. Agosti, Manager, Nuclear Operations

     +*R. Lenart, Assistant Manager Nuclear Production        *

, *K. Earle, Engineering Operations ! +*E. Griffing, Assistant Manager Nuclear Operations i

     +*J. Conen, Licensing Engineer
        *R. Woolley, Acting Supervisor, Licensing
;       *W. Miller, Jr. , Supervisor OA, NQA l        *F. Reimann, Rad Assessor i
        *W. Ripley, Assistant to Operations Engineer
     +*G. 0verteck, Superintendent of Operations NRC

! *E. Creenman, Deputy Director, Division of Reactor Projects

        *G. Wright, Chief, Reactor Projects Section 2C
     +*M. Parker, Resident Inspector, Femi
        *D. Jones, Resident Inspector, Femi 1
        *M. Jordan, Senior Resident Inspector, LaSalle l     The inspectors also talked with and interviewed members of the operation,

. maintenance, surveillance, and health physics sections.

,

• Denotes personnel attending exit interview held on August 20, 1985.

     + Denotes personnel attending routine resident inspectors exit interview held on September 30, 1985.

2. Scope The purpose of the Operational Readiness Assessment Team inspection was i

to assess the readiness of the Femi 2 facility for full power operation by evaluating the effectiveness of management controls over operations, conduct of operations, authority / responsibilities defined and understood, observation of shift turnovers, comunication and quality of logs and records. In addition, the Licensee's corrective actions associated with a Confimatory Action Letter dated July 19,1985 were reviewed. The methods of evaluation used included procedure review, personnel interviews at the senior site management and operations staff level, document review. and direct observation of activities. Particular emphasis was focused on > ! the interfaces among the various operations personnel for accomplishment of their assigned tasks.

3. Operations 1

The inspectors spent many hours in the control room observing operations and speaking with the control room staff. The operations staff acted in a professional and knowledgeable manner. Alams were responded to in an  ! appropriate and timely fashion. i 2

The operating crews worked well together with frequent interi:hanges between the Nuclear Shift Supervisor (NSS), Nuclear Assistant Shift l Supervisor (NASS) Nuclear Supervising Operators (NS0s). Nuclear Power ) Plant Operators (NPP0s) and Nuclear Assistant Power Plant Operators (NAPP0s). Also shift meetings were held after the individual shift turnovers for better comunications. Through discussions and observation with the operations staff (Nuclear ' I Shif t Supervisor (NSS), Nuclear Assistant Shift Supervisor (NASS), and l Nuclear Supervising Operators (NS0)) several concerns were raised.  ! I a. The comunications and direction from management on current issQes and operating practices were not transmitted well to the shift to allow for a clear understanding of what was expected and why. 1 Examples of this were:

                 -(1) The NS0s felt unnecessary restrictions were implemented on

! control room operations such as no coffee and soda within the brown area of the control room. l (2) Onshift

there haspersonnel did not in been an increase have a clear audits (NRCunderstanding of why) of INPO, Management t control room functions from prior to licensing as to after receiving the license.

(3) Why it was important for dating and time marking all plant recorders once a shift. (4) The change in adverse personnel actions taken as the result of j an event, from prior to licensing (firing) and after licensing j (retraining) was not understood. The lack of consistent 1 disciplinary action had the operating staff unsure of where j they would stand if they were involved in an incident. It j appeared to the team that the licensee did not have a clear policy in this area. l j (5) The management's action taken on recent events that was { published in the paper was not well understood by the operating i staff. The operation staff felt a definite split between the management and the operation department. Operation's staff often heard of management's decisions through the local papers. l This overall comunication problem will maain as an open item , (341/85043-01)DRP)). 1

b. At times the inspectors observed problems with the team effort of the control room operating staff.

(1) The control room NSO at times was extremely busy and the NASS l did not appear to restrict or redirect the activities in the control room to assist the control room NSO. (2) Alarms as a result of surveillance or maintenance work were acknowledged and cleared by other than the operating shift. This type of performance could result in a separate alars on the same board being acknowledged or cleamd without the NSO being aware of it. n

i ~ f (3) Operator watch relief for meals were not of the same high quality and detail as the shift turnover. . (4) The NASS turnover was accomplished over an hour late. The relief NASS had his phone turned off and the on duty NASS was not able to get in touch with him. i The items discussed above will be tracked as open item i (341/85043-02(DRP)).

,     c. Additional concerns of control room conditions and behavior were i             noted.                                                                           t i            (1) There are infomational dot stickers on certain annunciators in                j the control room which were used during construction to
!                   indicate nuisance alams. They serve no purpose now and should be removed.

(2) The use of magnetic dots in place of out-of-service tags. The dots are small and blended into the colored panels such that l they do not visually highlight the component that needs work.

!                  They are also subject to being moved during plant operations or cleaning of the panels such that the dot may migrate to an improper component.

i (3) Simulator training was geared to casualties and not nomal i plant evolutions. The simulator training did not allow the { crews to complete evolutions (startup/ shutdown) from start to i finish. One crew interviewed had only performed one startup from start to finish and then only because the MSS had requested l it. They showed interest in more training on loss of feed water j events. !' (4) The shift indicated that training at the simulator was ! accomplished by dividing the shift into two sections for l training. This detracts from the team / crew concept of an i integrated shift. t (5) The NSO responds to a problem which required operator action including a review of the procedures. This action seemed to be slow and somewhat hesitant by the NSO to accomplish the procedure. When this was brought to the attention of the NSS, he indicated he was aware of the issue and was trying to get the NSO to act more promptly. The inspectors observed the following shift operations which were good practices: (1) Moving the NASS out of the NSS office and into the " horseshoe" portion of the control room was a good practice. This will provide a greater level of control and knowledge of plant l evolutions and events. 4

(2) Consnunication from the control room to personnel in the plant was good. In most cases, repeat back of actions prior to taking them were transmitted both from the plant to the control room as well as from the control room to the plant. Observations and discussions were also made with the Shift Technical Advisor (STA) and the Shift Operating Advisor (50A). These individuals appear to understand their responsibilities and the communication channel they would take to resolve any problems they may have. A review of the Administrative Procedure 21.000.01,

          " Shift Operating and Control Room", indicated the STO and STA are
          " administratively" men 6ers of the operating shift. Discussions with these individuals indicated they are administratively a menber of the shift as advisors and not a mainstream member of the shift.

Events in July and August 1985, indicate that the licensee has not made effective use of the SOA or the STA. To get the maximum advisory effect from these people they need to be integrated into the mainstream of the shift. When equipment is removed from or returned to service, these individuals should be made aware of it. Any changes in major plant parameter such as reactor vessel level, pressure, that are recognized by NSO as abnormal, should be brought to the attention of the SOA and STA. These individuals should be made aware of all Engineered Safety Features (ESF) actuations so that at all times they have an accurate status of plant conditions and can perfonn the advisory function from a position of knowledge of the plant and plant status in lieu of from a position of gathering knowledge of the plant and plant status. These individuals should be in the control room during all major testing and plant evolutions so that they can perfonn the function of an advisor as they observe a problem starting to occur and not only advise when requested by the NSS or NASS. The team also feels that the above comunents are applicable to the Reactor Engineer during the startup testing phase of operation. Thisitemisconsideredtobeanopenitem(341/85043-03(DRP)).

4. Infonnation Flow Through review of records, observation of control room activities and interviews with onshift personnel an assessment of infonnation flow and adequacy was made.

a. The review of records included log books, out-of-service log, control room infonnation system cards and shift check sheets. Although all the logs were being kept in accordance with applicable procedures, a nus6er of weaknesses were identified as follows:

(1) While the NSO log was routinely reviewed by middle level management there was no evidence that the NSO and NSS logs were reviewed b and above)y upper level management (ie Superintendent-Operations

                                     . n

i (2) While the out-of service log tracked long ters LCO's there appeared to be no mechanism for tracking short tem LCO's. nor is the out-of-service log kept in a location that would provide ready access to onshift control room personnel (3) While the shift check sheet contained good infomation, instances were noted where instead of a value (ie level, pressem, etc) ! the word " SAT" was used. It is felt that where a parameter is l to be verified, a value should be provided. i The above items are considered open items (341/85043-04(DRP))

b. Shift turnovers were observed. The practice of holding one on one j panel walkdowns and information exchange is viewed as a positive

,               aspect of the system. The followup group meeting while appropriate i                could be improved by providing a better description of plant status,
               .and planned activities, including reasons.

c. The Control Room Information System (CRIS) was reviewed for adequacy and implementation. The magnetic " dots" are discussed elsewhere in this report. The other basic concern about the CRIS is that, although providing good information, the infomation is one step removed from the panels. To detemine equipment status the operator must go to the panel, obtain the nusber of the " dot" associated with the equipment, and then go to the " card" file to obtain the

! infonnation. The licensee should review the system for potential j improvement. OpenItem(341/85043-05(DRP)) I

d. The processing of work requests was discussed with onshift personnel.

One potential problem was identified when it was determined that j work requests can be signed by either the NS0 or the NASS. This

situation could lead to one or the other individual being unaware of ongoing work. The licensee should review this situation and i

establish one focal point. OpenItem(341/85043-06(DRP))

5. Confirmatory Action Letter

, As a result of the premature criticality which occurred on July 2, 1985, j a Confinnatory Action Letter, dated July 19, 1985, was issued to the i licensee. The licensee was subsequently requested to complete the following actions: 1 a. Provide to the NRC Region !!! the results of the evaluation of the ! inadvertent criticality event of July 2,1985, including corrective actions that have or will be taken. Include in the report the basis j for not reporting this event to the NRC. The licensee met with NRC Region III on July 23, 1985, to discuss the licensee's evaluation and their corrective actions. As an ' interim measure, the licensee has initiated the following actions.

(1) Required a second qualified member of the unit technical staff

! to verify all rod pulls for Groups 3 and 4 until the Rod Worth j Minimizer (RWM) has been reprogransned. ! 6

i l ! (2) Modified the rod pull sheets to eliminate confusion. i ! (3) Required the use of current rod pull sheets at the simulator. As a result of augmented inspection coverage during the week of i August 5,1985, the resident inspectors observed the md pull to criticality and observed general control room activities. During this time, the inspectors observed licensed operator actions to ' i ensum they were complying with the above connitments. The  ; ) inspectors consider the licensee's interim measures adequate. The i licensee has reprogranned the Rod Worth Minimizer (RWM) to enforce

in Groups 3 and 4. This action was completed per Engineering Design i

Package (EDP) 4224 under PN-21 (Work Order) 552909 on August 23, 1985. The licensee, therefore, is no longer requiring a second qualified member of the unit technical staff to verify all rod pulls for Groups 3 and 4. The licensee's response to the CAL, DECO letter ? RC-LG-85-0017 dated September 5,1985, documented the licensee's j actions and the basis used concerning reporting requirements. , This item is considered closed. J

b. Assure that operations personnel are properly trained and understand the applicable procedure (s) for subsequent control rod manipulations.

i The ifcensee has taken several steps to ensum operations personnel i are properly trained and understand the procedures for control rod '

manipulation. The licensee is implementing the following actions.

(1) Conducting training for operations personnel to assure that the rod pull sheets are understood by those using them.

 ,              (2) Providing a cover sheet / instructions to the rod pull sheets to 4

assure understanding of control rod manipulation. j (3) Conducting training sessions with the mactor operators j concerning the Rod Worth Minimizer, i ! (4) Reviewing the fomat,and layout of the rod pull sheets for hunuin factors consideration. l (5) Providing specific instructions to the operating shift j concerning control rod movement. (6) Conducting training with licensed operators to assure they are trained and undarstand the intent and purpose of reduced notch ! worth pull concept. The Ifcensee has completed training for operations ursonnel to assure that the rod pull sheets are understood by ttose using them. In addition to the trefning, the licensee has provided a cover sheet j to the rod pull sheets which provides additional instructions to the operator and requires documentation of the individual's understanding of the instructions. A review was performed on the i rod pull sheets for human factors consideration. As a result of i this review, the rod pull sheets have been m vised to minimize i I 7 L_____ _ _ . _ ---------C

l confusion. The licensee has also taken advantage of the Alann Typer in modifying the rod pull sheets thereby reducing redundant documentation previously required of the operator. The inspectors have observed control rod manipulations using the new rod pull sheets and consider the licensee has taken appropriate action. This item is considered closed. , l i I c. Assure that all operations personnel are aware of the event and its l potential significance. - l The inspectors through discussions with reactor operators and ^ training instructors have verified that operations personnel, either through special training sessions or nonnal requalification training, have observed the special training film concerning the event and that they have been briefed on the rod pull event and its

;        potential significance. The inspectors have observed control rod                   !

manipulation on several occasions subsequent to the inadvertent criticality event including rod pull to criticality and individual , rod scram time testing, and consider that the licensee is taking

 ;       positive steps. This item is considered closed.

I I j d. Verify the operability and/or validity of the program for the Rod j Worth Minimizer. { As of August 5, 1985, the licensee had recertified the RWM program to ensure that it was operating properly. This included resolving j the Deviation / Event Report No. NP-85-0397 concerning software discrepancy and resolution of the design function of the system. In Deco letter NE-85-1013 dated July 19, 1985, the licensee clarified the design function and recomended changes to the Rim to prevent { recurrence of the inadvertent criticality. The licensee has i reprogra med the RWM to enforce in Groups 3 and 4. This action was i completed per EDP-4224, under PN-21 552909, on August 23, 1985. l The inspectors have since observed control rod manipulations including i a rod pull to criticality on September 13, 1985. The inspectors i have verified that the RWM has been reprogramed and that the

operators are using the upgraded rod pull sheet. This item is considered closed.

e. Verify that training programs at the simulator are consistent with

the current procedures being implemented at the facility.

l

The inspectors have reviewed the licensee's simulator procedures to 1 ensure they have been updated. The inspectors also verified that the rod pull sheets used at the simulator have been updated to reflect current pull sheets. The licensee is currently requiring i periodic audit of these procedures to ensure that only the latest I revision is used. The inspectors were concerned with the use of infomation copies versus controlled copies of procedures at the I

simulator but were informed that these procedures were on controlled distribution thereby ensuring distribution of the latest revision or change. This item is considered closed. 8 -

f. After all actions required above are completed, obtain verbal concurrence from the NRC Region III Regional Administrator or his designee prior to exceeding 5% reactor power.

The licensee has completed action on these items and has met with NRC Region III on September 10, 1985, to discuss their actions taken as a result of the inadvertent criticality and to request lifting of the five percent reactor power restriction. This item remains open pending resolution of the items contained in this report as well as other outstanding issues. Concurrence from NRC Region III to exceed 5% power remains outstanding. Open Item . (341/85043-07(DRP)).

6. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during .

the inspection are discussed in Paragraphs 3, 4 and 5.

7. Exit Interview The inspectors met with licensee representatives listed in Paragraph 1

on August 22, 1985, September 30, 1985, and various other items during the inspection period and sumarized the scope and findings of the inspection. The inspectors also discussed the likely infonnational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection. The licensee did not identify any such documents or processes as proprietary.

I i l 4 9

ENCLOSURE 4.B , s-gs erroit - Edison Min 5A w.L. February 5. 1986 VP-86-0010 PRIORITY ROUTING l First see md i RA QC DRA EIC ql Mr. James C. Keppler Pegional Admiinistrator Tpss , [ et U. S. Nuclear Regulatory Con:eission 3d"4 j{ Region III ggggj}7 799 Roosevelt Road Glen Ellyn. Illinois 60137

Reference:

1) Terri 2 NEC Docket No. 50-341 NPC License No. NPF-43

2) Detroit Edison Letter to NRC. " Emergency Diesel Generator Status". TP-85-0216 dated December 13 1985

                            ~

Subject:

Etiergency Diesel Generator Crankshaft Bearing Reliabilftv Deronstration Test Procrae As committed in Detroit Edison's January 24, 1986 seeting with the KFC staff. Detroit Edison submits the enclosed description of the Crankshaft Bearing Feliability Demonstration Test Program (the Deronstratico Test Prograr) for the Termi-2 emergency diesel generators (EDCs). Detroit Edison is confident that the program described in our January 24, 1986 meeting and docutented in Tnclosure I will confirm the reliability of the Ferzi-2 EDCs. Further. Detroit Edison saintains that the Demonstratfor Test Program provides the basis for the NPC to conclude that the Fermi-2 EDGs are a reliable backup power source. As noted in Enclosure 1. Chronology section. Detroit Edison will provide the NRC a separate submittal with edditionel f pf os sis t ion on the surveillence test history of the Ferri 2 EDCs. In accordance with a February 3. 1986 discussion < vith the NPR Licensing Project Manager, this report will ! also reflect information relevant to the discovery of a segment of en off ring in FDC 12 and air entrained oil in l TDC 11 encountered 4tting iniplesentation of the ! Deronstration Test Program. l . FEB 7 ngg SS ua f Sc 7 t, o S .

l Mr. James C. Keppler P{bruary 5 1986 VPi-86-0010 Page 2 i If ye'u have any questions in this matter, please contact Mr. R. L. Woolley at 313-586-4213. E Sincerely.

                                                                                                              ~       4 H$

i Frank E. Agosti L Vice President

                                                                                  ,                             Nuclear Operations
                                                                                  \

s cc: Mr. P. M. Byron Mr. W. C. Culdemond (RIII) Mr. L. Rulman (NRR) i Fr. M. D. Lynch Pr. G. C. Wright . USNRC Document Control Desk Vashington, D. C. 20555 i t, l i 1

                                                                                                                 ,a   - --

• n,..-a,----, . - - -,. - - . . - - - , - .---

nr. James G. Keppler February 5, 1986 VF-86-0010 Page 3 bec: R. C. Anderson F. E. Agosti i L. F. Bregni W. F. Colbert J. F. Conen

• J.B. Flynn J. R. Green E. F. Griffing i W. B. Jens J. D. Leman R. S. Lenart L. Martin S. R. Noetzel l J.A. Nyquist

C. 1. Ove rb ec k l A. Papadopoulos (NUS)

J. L. Piana I T. Randazzo i G. M. Trahey I A. E. Wegele l R. L. Woolley ! Approval Control NRR Chron File Secretary's Of fic e (2412 WCB) Licensing File - Diesel Generator 1 i 1 f l I l

Enclosure 1 February 5, 1986 VP-86-0010 Page 1 Of 10 l Enclosure 1 Emergency Diesel Generator Crankshaft Bearing Reliability Demonstration Test Program Introduction A meeting with NRC staff was held at the Fermi-2 site on January 24, 1986 to review the history of the Fermi-2 diesels, their performance, and actions taken and planned l by Detroit Edison to restore the EDGs to reliable

operation. An important element of Detroit Edison's i

efforts to confirm the reliability of the EDGs, the 1 Demonstration Test Program, was described in the January 24 l meeting and is documented herein. Additional key points I presented by Detroit Edison are also documented below. l Bandouts presented at the January 24 meeting are provided in Inclosure 2. This report also fulfills Detroit Edison's commitment in its December 13. 1985 letter to provide a followup report 4 on the failure of the bearings in EDG 13. Chronolonv j The history of operation and repair of the Fermi-2 EEGs was presented at the January 24 meeting. This information is summarised in the handouts shown in Enclosure 2. At the 4 NRC's request, additional information on the surveillance test history of the Fermi-2 EDGs will be transmitted to the NRC under separate cover. Highlights of the chronology of the EDGs are summarized below. l In January, 1985. Detroit Edison identified problems with the upper crankshaft bearings of Fermi-2 EDGs 11 and 12. Bearings were examined in all four EDGs to determine the extent of the damage and the root cause of the problem.

,                                Bearings in EDGs 11 and 12 and the upper crankshaft in EDG

' 11 were replaced. The apparent cause of the bearing problems was inadequate lubrication (i.e., lack of

 ;                               prelubrication during repeated fast sterte).

Following this repair, Detroit Edison performed the

;                                vendor-recommended bearing break-in procedure, in addition l                                to a 40 hour seasoning run. Corrective actions were documented in earlie                              sepeste to 11. e E T.C (References 1-5).

The Fermi-2 EDGs completed this demonstration successfully ! in March, 1985.

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Inclosure 1 February 5 1986 VP-86-0010 l Page 2 of 10 In November, 1985. EDG 13 was manually shutdown during i operation when the #3 upper crankline connecting rod and associated #3 main bearings failed. The scope of repairs

 !                             to the engine included replacement of the upper crankshaft and all upper crankshaft bearings. Detroit Edison's investigation of this event indicates that the #3 main bearing failed due to incorrect teeseerb13 sfter tl e January. 1985 inspection. A report on this event 5tt provided to the Commission in Reference 7.

Following a demonstration test run of EDG 13. visual inspection of t l. e u pp + r c. : o pl ? is. t fr. recember 1985 revealed three bearings with surface scoring. Scoring of two of these bearings is attributed to foreign material in the lube oil. Detroit Edison c~onsiders both the damaged bearings and the extensive repairs performed earlier to be the most likely source of the foreign material introduced into the lube'oit system. i When the scored bearings in EDG 13 were found. Detroit i Edison inspected all upper and lower bearings of EDG 14. No scoring was found. Konetheless. Detroit Edison elected to replace all of the upper crankline bearings in EDG 14 to eliminate concerns related to the gray, matted surface appearance of several bearings. i Because of the findings in EDG 13. Detroit Edison elected to inspect the bearings of EDGs 11 and 12 (which are the Division I EDGs). The bearings of EDG 12 were inspected in December. 1985. One lower bearing (13M) was replaced at that time. i j When EDG 11 was opened in early December. Detroit Edison ! found questionable surface conditions on six bearings, and elected to replace all upper bearings. During the process ,' of returning EDG 11 to service, two bearings failed. Subsequent investigation revealed an undesirable upper crankshaft bearing cap alignment pattern. Detroit Edison  ; has since replaced four bearings which showed signs of , surface scoring and performed a detailed realignment of the bearing caps.

l l l Enclosure 1 February 5, 1986 VP-86-0010 Page 3 of 10 i Semeini Concerna Noted in the January 24 Meetine In December, 1985. Detroit Edison's surveillance of the EDCs revealed reduced viscosity of the lube oil in EDG 14. The viscosity returned to its former values after the lube oil was replaced. This leads Detroit Edison to conclude tbat the reduced viscosity resulted from dilution of the lube oil with a small quantity of fuel oil. Fuel cil is used to clean the bearings and may have been introduced ina.tvertently during the bearing repairs and replacements. A trend of decreasing viscosity has also teen identified.in surveillance of the lube oil of EDG 12. This declining viscos ity appears to be the result of a fuel oil leak into the lubricating oil system. Detroit Edison's investigation of this matter is continuing. Meanwhile, regular monitoring of~the lube oil, required by Detroit Edison's surveillance procedures, will ensure that an acceptable lube oil viscosity is maintained. Detroit Edison's investigation of the EDG bearing probicas indicates that the recent observations of declining lube oil viscosity in EDG 12 and reduced viscosity in EDG 14 are not related to the bearing failures. During the Jonuary 24 meeting, a member of the public expressed concerns about potential problems with the alignment of FDC 11 during installation. Detroit Edison's investigation of the bearing problems on EDG 11 does not reveal information to substantiate the concern. Detroit Edison checked .t h e alignment of EDG 11 on its mounting slid in January 1985 and found it to be within tolerances. The alignment of EDGo 11 and 13 was checked in December 1985 and was also within the specified tolerances. The manufacturer indicates that the way the EDCs are mounted on their skids minimites the possibility of distorting the engine block, even if the mounting beams are slightly misaligned. The patterns of wear found on the EDG 11 4 bearings are consistent with the other observations e r s' ii not indicate ttst they are related to the floor neet! alignment of the EDGs.

l Inclosure 1 ) February 5, 1986 VF-86-0010 Page 4 of 10 I i I Purnome of the Demonstration Test Proeram The bearing problems at Termi-2 occurred at a time of heightened NRC concerns about EDG reliability, primarily

because of probicos encountered with Transamerica Delaval, anc. EDGs. The type of EDG employed at Fermi-2, Fairbanks-Morse (F-M), Division of Colt Industries, has a record of high* reliability demonstrated in 49 nuclear applications.

The Demonstration Test Program is intended to restore confidence in the Fermi-2 EDGs as a reliable backup source l of AC power. The Demonstration Test Program will simulate  ! the number of slow starts and fast starts which would be i expected of an EDC over an 18-month fuel cycle, and the run-time that might be needed to assure safe shutdown of the plant, if EDG operation were required following a I Loss-of-Coolant Accident. Eneinea Selected for'the Demonstration

 !           Emergency Diesel Generators 11 and 13 have been selected

for the Demonstration Test. The selection of these tvc EDGs was based on the following considerations:

)

o These EDGs are in separate Divisions. I o Both had bearing failures. 1 o Both have had new upper crankshafts installed. i o EDG 11 experienced problems with the alignment i of the bearing caps and, in general, had the

!                                             most problems of the Fermi-2 IDCs.

i Prenaration 4 Before starting the Demonstration Test. Detroit Edison will complete the following on EDCs 11 and 13: i o A flush of the engine lube oil system will be performed to help remove foreign material from the system (and reduce potential concerns about foreign material that may have been introduced 3 by the bearing failures and crankshaft j replacements in EDGs 11 and 13). i 4 4 l - ._.-. - - . , _ - . . - - - - - - _ , . _ - - -.- - ,.-. . - . - - ., , .

Eaclosuro 1 February 5. 1986 YF-86-0010 Fase 5 of 10 o A new brand of lube oil (Mobil) will be installed in all four EDGs. Detroit Edison surveyed 16 other owners of F-M engines to identify differences between tl t it

engines and Detroit Edison's. Six of the other i

own=rs contacted use Mobil l u"b e oil. To determine whether the brand of lube oil contributes to the bearing differences ctse:ved at Fermi-2. Detroit Edison had (It.cita eo change from Shell lube oil to Mobil lube oil in IDG 13. Subsequent to the January 24, 1986 presentation, it ves decided to use Mcbil in b all Fermi 2 EDGs. o Before the Reliability Demonstration Test is started. EDGs 11 a'n d 13 will be run under load for a minimum of 100 hours to " season" the bearings, per the manufacturer's recommendations. (Subsequent to any future bearing replacements, a 100 hour " seasoning" run will similarly be performed). seer. ' The Demonstration Test will include the following, in the order listed below:

1. Gap check on the upper crankshaft main bearings using a 0.002" feeler gauge between the bearing and the bearing saddle, per the manufacturer's recommendation.

2. Twenty (20) prelubed " slow" starts; after each slow start the EDG will be run under load for a minimum of two (2) hours, including one (1) bour at a load of 2500 to 2600 kW.

3. Gap check on the upper crankshaft main bearings using a 0.002" feeler gauge.

4. Ten (10) prelubed " fast" starts; after each fast start the EDG will be run under load for a 3:inimum of two (2) hours, including one (1) hour at a load of 2500 to 2600 kW.

5. Cap check on the upper crankshaft main bearings using a 0.002" feeler gauge.

6. A seven (7)-day continuous run with the EDG under a load of 2500 to 2600 kW.

Enclosure 1 February 5, 1986 VF-86-0010 Fage 6 of 10 Accentance criterion The Demonstration Test Program will be considered successful when the EDGs complete the twenty " slow" and

• ten

             " fast" starts, and the seven day run. A successful Demonstration Test verifies that the EDGs can reliably perform their intended function. Following completion of the seven-day run. Detroit Edison will perform a gap check on the upper crankshaft main bearings, run the appropriate surveillances required by Technical Specifications, and declare the EDG operable.

Emmin for Reliance en the Can Check For the Demonstration Test Program and subsequent operation of the EDGs, Detroit Edison will rely on tl.e gap check as the primary measure of bearing integrity. A bearing vill be considered as " failed" only if it does not pass the gap check, oi there are other visually obvious signs of significant def ori it j o: dcccge tc the bearing. In the past three months. Detroit Edison removed all EDG bearings for visual examination. Detroit Edison chose to remove the bearings for visual examination in part to satisfy the NRC's requests for information. Detroit Edison's experience confirms the engine manufacturer's recommendations against frequent disassemblies solely to support visual examinations et the bearings. Termi-2 EIC 24 had no bearing problems until the bearings were disassembled for visual examination. In the view of the engine c.anufacturer. Fairbanks-Horse, the risk of damage to the bearings during removal and reinstallation and the potential for system contamination or misasses.bly, eFCeed6 the incremental value of direct visual inspection of the bearing surfaces. The manufacturer's position, as stated in the January 24 seeting with the NRC, is that the gap check provides an adequate indication of becring integrity. The gap check is the accepted method for detecting bearing failure and is used by both nuclear and commercial customers of F-M. Detroit Edison is aware of no other owner of F-M engines who disassembles bearings for visual determination of bearing condition. Detroit Edison agrees with the manufacturer's position and vill rely o,r the gap check as the primary measure of bearing integrity.

D Inclosure 1 February 5. 1986 YP-86-0010 Page 7 of 10 Bearine Failure Errive Dec.onstration Test Proeram Further bearing failures are not expected. However. Edison recognizes the potential for misassembly and other problems created by the recent work on the EDG bearings. If a bearing does not pass the gap check during the Demonstration Test. Detroit Edison will analyze the bearing failure, and will repair or replace the bearing, as necessary. At that time. Detroit Edison will determine the break-in required to " season" the bearing, and will reinitiate the Demonstrar. ion Test on the affected diesel. If Detroit Edison is required to shut down the EDGs because of a problem unrelated to the bearings. Detroit Edison will correct that problem and resume the Demonstration Test on the affected EDG at the point at which the Test was interrupted. , Incornoration of Patte11e Femults l Detroit Edison.cpamitted to have the Battelle Columbus  ! Laboratories analyse *a sample of the failed bearings from I the Fermi-2 EDGs obtained in the November-December, 1985 l inspections. This will provide an independent determination of the cause of the various conditions noted on several bearings. Detroit Edison will evaluate the results of Batte11e's analysis when they become available. Detroit Edison will factor these results into future corrective action, if appropriate. The "Envelone of Accentabiliev" Successful completion of the Demonstration Test Program will define an " envelope of acceptability" within which the reliability of the EDG crankshaft bearings have been demonstrated. This " envelope" will include twenty slow

     .         starts, ten fast starts, and seven days of coetinuous operation. After completing the Demonstration Test Program. Detroit Edison will revise the maintenance procedures for the EDGs to require a gap check of the upper crankshaft main bearings every six months or upon completion of twenty (20) slow starts or ten (10) fast        i starts, whichever occurs first. The limit on fast starts      ;

applies to pre-lubed, non-t re-lub ed , or any combination of l pre-lubed and non-pre-lubed fast starts. The six-month gap check is expected to be the more limiting requirement.

                         .                                         ..-.,.L,

Enclosure 1 i February 5. 1986

VP-86-0010 Page 8 o f 10 4

The limit of ten fast starts was defined, in part, by Edison's experience with the Fermi-2 EDGs. Through January j 1985, the Fermi-2 EDGs experienced an average of 62.5 fast ' starts per engine, with air / oil boost and without manual prelubrication. The design life of the EDG bearin s is based on bearing wear (i.e., minimum thickness of bearing shell). The manufacturer typically experiences over 10.000 hours of operation on its engines before bearing l replacement is required due to wear. Detroit Edison j estimates that normal surveillance and operation will require each EDG to run typically less than 100 hours per year. At this rate, each EDG would be expected to operate between 2000 *nd 4000 hours over the 40-year life of the l P l ant. There.' re. the expected bearing life exceeds the I anticipated houco of operation by a factor of 2.5 to 5. l Detroit Edison believes that the lower limit of ten fast starts provides a conservative criterion for triggering a gap check, wit.hout unduly restricting operability of the EDCs. Detroit E2ison expects that this limit may be relaxed as EDG operating experience confirms the level of reliability. Commitments for EDC Surveillane. As presented at the January 24 meeting, and documented above. Detroit Edison will revise the EDG maintenance procedures to require a gap check of the upper crankshaft main bearings once per six months or upon completion of twenty (20) slow starts or ten (10) fast starts, whichever ' occurs first. 1 i In March. 1985. Detroit Edison proposed more frequent inspection of the EDG lube oil filter as one element of the program intended to detect incipient bearing failures. Subsequent experience has indicated that inspection of the lube oil filter is ineffective in predicting bearing failures. In addition, more frequent inspection of the oil filter increases the likelihood of contaminating the lube oil system. Therefore. Detroit Edison plans to eliminate the oil filter sampling program described in Reference 4. This letter is referenced in paragraph 2.C.(10) of the Fermi-2 Operating License. Accordingly. Detroit Edison ! will seek a license amendment to revise the reference to the March 14. 1985 letter. That request for license amendment will be filed separately. l l l l l -

i Enclosure 1 February 5, 1986 VP-86-0010 Page 9 of 10 Endorsement by Colt Industries and Failure Analvain Asseeintes In the January 24 meeting, the NRC asked representatives of Colt Industries (i.e.. Fairbanks-Morse), and Failure Analysis Associates (FaAA), whether they agreed with the course of action proposed by Detroit Edison to restore confidence in the reliability of the Fermi-2 EDGs. The representatives indicated their approval of the Edison plan presented to the NRC. Detroit Edison later requested that Colt and FaAA put their endorsement in writing for inclusion in this report to the NRC. Copies of their letters of endorsement are provided in Enclosure 3. Conclusion Detroit Edison is confident that the program described in our January 24, 1986 meeting and documented above will confirm the reliability of the Fermi-2 EDGs. The bases for this conclusion include: o , Colt engines have a proven record of reliability. o The Demonstration Test Program will include 30 starts perrengine. This is more than the 23 starts required by Regulatory Guide 1.108 for the initial demonstration of EDG reliability. o The Demonstration Test Program will simulate the total number of starts that would be expected over an 18-month fuel cycle and the run time that would be needed to assure safe shutdown following-a design basis Loss-of-Coolant Accident. l l o Gap checks will be performed at intermediate points in the Demonstration Test Trogram. o Both the engine manufacturer (Colt) and Detroit Edison's consultant (Failure Analysis Associates) stand behind the Fermi-2 Demonstration Test Program. Detroit Edison maintains that the Demonstration Test Program provides the basis for the NRC to conclude that the Fermi-2 EDGs are a reliable backup power source.

Inclosure 1 February 5, 1986 YP-86-0010 Page 10 of 10 References

1. Detroit Edison letter to NRC, NE-85-0329. " Request to Revise Draft Fermi-2 Technical Specifications", dated February 14, 1985.

2. Detroit Edison letter to NRC, NE-85-460, " Additional Information on Diesel Generators", dated March 6, 1985.

3. Detroit Edison letter to NRC, NE-85-0455, " Additional Change to Draft Ferai-2 Technical Specification for Diesel Generators", dated March 9, 1985.

4. Detroit Edison letter to NRC, NE-85-0459, " Clarification of Diesel Generator Commitments", dated March 14, 1985.

5. Detroit Edison letter to NRC, NE-85-0461, " Letter correction", dated March 15, 1985.

6. Detroit Edison letter to NRC, NE-85-0462, " Transmittal of Additional Information Relative to Diesel Generator commitments", dated March 15, 1985.

7. Detroit Edison letter to NRC, VP-85-0216 " Emergency Diesel Generator Status", dated December 13, 1985.

 ~
         . - . -                         ?-  .                       _ _ . . _ -

0 Enclosure 2 l February 5, 1986 VP-86-0010 Copy of Bandouts Presented in January 24, 1986 Meeting with NRC Staff on EDG 5 earings Reliability Demonstration Test Program f e 0 a 9 O

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EDG 11 h I********I Jan 85 1********I Dec 3,85 1********I Dec 27,85I**** I I I I I I I Bearinos 1 X 2 X 3 X o o 4 X 5 X o X 6 X o X 7 8 o 9 o

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I -l 1 I l l l Run Hours 346 125 20 Starts Fast (PLM) 127 25 0 Fast (NPL) 175 1 0 Slow 0 8 10 Total 302 . 34 10 Hours / Start 1.1 3.6 2.0 Notes -Replaced the -Repl aced all -Realigned Caps Upper Crank Upper Bearings -Replaced Failed

                      -Replaced all                                     & Distressed Upper Bearings                                 Bearings
                                                                     -Flush Engine NOTE: THE ASSOCIATED CONNECTING RODS FAILED IN JAN 85.

l PLM= Manual Prelube, NPL=Not Manuall y Prelubed

EDG 12 h l********l Jan 85 1********I Dec 85 l********l i I I i l i Bearinos 1 X 2 X 3 X 4 5 6 7 X 8 X 9 10 11 12 13 o (Lower) 14 l********l l********l l********l i I I I I I Run Hours 292 137 240 starts Fast (PLM) 52 - 23 0 Fast (NPL) 152 1 0 Slow 0 7 8 Total 204 31 8 Hours / Start 1.4 3.6 30 l Notes -Replaced -Replaced upper crank 13M lower bearings

                          -Inspected 14M, 12M, l

• 10M and BM on lower crank

                          -Gap checked all other bearings PLM= Manual Prelube,       NPL=Not Manually Prelubed
        -9

EDG 13 l 1 l********l Jan 85 l********l Nov 85 l********l Dec 85 l**** h I I I I I I I Bearino 1 2 o (Groove) 3 X 4 o (Lower) 5 6 o (Groove) 7 8 9 10 11 12 o o 13 14 l********l l********1 l********l l**** I I i i I I I Hours 214 94 234 Starts Fast (PLM) 25 24 3 Fast (NPL) 134 0 0 51ow 0 . 6 46 Total 159 30 49 Heurs/ Start 1.3 3.1 4.8 Notes -Inspected Upper -Replaced the -Replaced 3M, Crank Bearings Upper Crank 7M & 13M 1-6 -Replaced all -Flushed Engine Upper Bearings -Demonstration

                           -All Other              -Replaced 4M Bearings were            Lower Bearing gap checked I

( l ( PLM= Manual Prelube, NPL=Not Manually Prelubed

I i l EDG 14 Jan 85 l********l Dec 85 l********l Jan 86 i+++* h l********l I I I I I I I Boarinos o 1 2 3 4 5 6 7 8 o 9 10 11 12 o 13 14 l********l l********l l**** l********l I I I I I I I Run Hours 270 117 250 Starts 30 20 0 Fast (PLM) Fast (NPL) 142 2 0 Slow 0 7 8 Total 172 29 8 Hours / Start 1.6 4.0 31.3

                          -Inspected                    -Inspected               -Three Notes                                                                          bearings Bearings 1-6               all upper and lower bearings           reused
                          -Observed some bearings had              -Replaced all a dull matte              upper crank-                              <

line bearings ) partial finish  ! PLM= Manual Prelube, NPL=Not Manuall y Prelubed o

TYPICAL CAUSES OF BEARING FAILURE DIRT OR FORElGN MATERIAL IN OIL INSUFFICIENT LUBRICATION MISASSEMBLY l MISALIGNMENT OVERLOAD CORROSION DESIGN OTHER i l l i m,. -- - - - ~ , - - - , f - , .- y

NO9 EMBER 1985 EDG 13 EVENT: OPERATOR SHUTDOWN EDG 13 DUE TO NOISE CHANGE PROBLEM: BEARINGS 3CR, 3M AND 4M FAILED 13 M HAD BEARING WEAR CAUSE: PRIMARY - BEARING 3CR FAILED DUE TO MISASSEMBLY , IN JANUARY 1985, THE BEARING WAS INSPECTED NO DISCOLORATION = N0 HIGH TEMPERATURE ALUMINUM DID NOT EXPERIENCE A HIGH TEMPERATURE FRETTING ON CONNECTING R0D FACES BENT CONNECTING ROD BOLTS BEARING FRAGMENTED

                         ~

SEC0f0ARY - B ARING 3M FAILED DUE TO DECREASED OIL FLOW TO BEARING FACES BEARING 13M . BEARING TO JOURNAL CONTACT ACTION: o CHECKED ALL OTHER PREVIOUSLY REWORKED BEARINGS. NO OTHERS WERE FOUND TO BE A CONCERN. o REPLACED UPPER CRAN (SHAFT o REPLACED ALL UPPER BEARINGS l l l

- - - JANUARY 1985 EDG 11 EVENT: EDG 11 SHUTDOWN AUTOMAT 1CALLY ON A LOW LUBE OIL PRESSURE SIGNAL

 . PROBLEM: SEVEN FAILED BEARINGS CAUSE:               BEARINGS FAILED DUE TO INADEQUATE LUBRICATION DURING FAST STARTS ACTION:

PRELUBE ALL PLANNED STARTS TEST EDG'S AT PLANT SPECIFIC LOAD LEVELS IMPROVED OIL SAMPLING PROGRAM INAUGURATED OIL FILTER SAMPLING PROGRAM REVISED PROCEDURES REVISED TECHNICAL SPECIFICATIONS INCORPORATE SLOW START FEATURE (DELAYED) (ACTION STEPS APPLIED TO ALL EDG'S) EDG 12 EVENT: GAP CHECK INSPECTION PROBLEM: FIVE FAILED BEARINGS CAUSE: SAME AS EDG 11 ACTION: SAME AS EDG 11 1

DECEMBER EDG 13 EVENT: VISUAL INSPECT 10N OF UPPER BEARINGS FOLLOWING SUCCESSFUL COMPLETION OF DEMONSTRATION ' PROBLEM: BEARINGS 3M, 7M Ato 13M FOUND WITH SURFACE SCORING CAUSE: BEARINGS 3M AND 7M - FOREIGN MATERIAL IN OIL BEARING 13M - BEARING TO JOURNAL CONTACT ACTION: REPLACED THREE BEARINGS 9 e S w- + >-

't NOVEMBER 1985 EDG 14 EVENT: VISUAL INSPECTION OF ALL BEARINGS PROBLEM: NONE CAUSE:( N/A ACTION: REPLACED ALL UPPER CRANK BEARINGS TO ELIMINATE A " DULL ROUGH" SURFACE, APPEARANCE JANUARY 1986 EDG 14 EVENT: SECOND VISUAL INSPECTION PROBLEM: 3 BEARINGS W1TH A TRACE OF SURFACE SCORING CAUSE: BEARING TO JOURNAL CONTACT ACTION: REINSTALLED BEARINGS l l i l

NOVEMBER 1985 EDG 12 i EVENT: VISUAL INSPECTION OF ALL BEARINGS PROBLEM: BEARING 13M LOWER FOUND WITH SURFACE SCORING CAUSE: BEARING TO JOURNAL CONTACT i ACTION: REPLACED BEARING e t O I I

DECEMBER 3, 1985 EDG 11 EVENT: VISUAL INSPECTION OF ALL BEARINGS PROBLEM: BEARINGS 3M, SM, 6M, 8M, 9M, 13M(UPPER AND L0tfR) FOUND WITH SURFACE SCORING CAUSE: BEARING TO JOURNAL CONTACT AGGRAVATED BY ALIGM4ENT ACTION: REPLACED ALL UPPER MAIN BEARINGS AND ONE LOWER BEARING DECEMBER 27, 1985 EDG 11 EVENT: INSPECTION DURING BEARING RUN-IN PROBLEM: TWO FAILED BEARINGS AND TWO BEARINGS WITH SURFACE S CAUSE: BEARING TO JOURNAL CONTACT AGGRAVATED BY ALIGM4ENT ACTION: DETAILED REALIGNMENT OF UPPER BEARING CAPS

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l ENGINE BEARINGS FUNCT10NAL REQUIREMENTS l o PROVIDE LOW-FRICT10N, LOW-WEAR JUNCT10N BETWEEN MAJOR ENGINE 1 COMPONENTS: PISTON - WRIST PIN WRIST PIN - CONNECTING ROD CONNECTING ROD - CRANKSHAFT CRANKSHAFT - ENGINE BLOCK O PROMOTE FORMATION OF LUBRICATING OIL FILM BETMEN BEARING Af0 ADJACENT SHAFT OR JOURfML. O 1. i

ENGINE BEARINGS SPECIFIC REQUIREtENTS o DESIGNED TO CONTROL STRESSES WITHIN PROVEN CAPABILITIES l0 MANUFACTURED TO CLOSE DIMENSIONAL TOLERANCES

  .O      MATERIALS SELECTED TO PROVIDE:           3 LOW FRICTION WITH JOURNAL ABILITY TO ABSORB AND NEUTRALIZE ABRASIVE PARTICULATES
               -    STRENGTH FOR LONG, RELIABLE LIFE
~ ~ ~ ~ ~

COWATIBILITY WITH ENGINE OIL o VIABLE MATERIALS: FOR BEARING PHASE TIN, LEAD, CADMlUM, itOlUM FOR MATRIX PHASE COPPER, ALUMINUM 1 2 l

                                                                                                 ).

ENGINE BEARINGS ~ DESIGN PROCEDURES

1) COMPUTE LOADS IWUTS: HORSEP0kER COMBUSTION PRESSURE FIRING ORDER COMPONENT WEIGHTS COUNTERWEIGHTS GEARS AND ACCESSORIES

2) SELECT SIZES LENGTH AND DIAMETER GROOVES, DIL HOLES '

CLEARANCES

3) SELECT LUBRICANT VISCOSITY AND VISCOSITY INDEX SUPPLY PRESSURE SUPPLY TEMPERATURE 3

1

                                                                                                    .                           5000 lb.
                                  .                                      TDC i

POLAR LOAD DIAGRAM L UPPER MAIN #1 900 rpm / 2850 MW J l 4

ENGINE BEARINGS ANALYTICAL TECHNIQUES UNIT LOAD

                 #1 MAIN BEARING UNIT LOAD    =                          =  1316 P.S.I.

8" X (2.75" .4375") JOURNAL ORB 1T ANALYSIS SOLVES DIFFERENTIAL EDUATIONS OF FLUID FLOW IN BEARING FOR EVERY lo 0F CRANKSHAFT ROTAT10N. OUTPUT: PEAK OIL FILM PRESSURES > MINIMUM OIL FILM THICKNESSES INTERPRETATION:- COMPARISON TO GUIDELINES ESTABLISHED BY THE ANALYSIS OF MANY DIFFERENT ENGINES 5 z

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ENGINE BEARINGS CONCLUSION FOR FAIRBAtKS-MORSE DIESELS AT FERMI II o BEARING STRESSES DUE TO PEAK OIL FILM PRESSURE ARE SAFELY WITHIN CAPABILITY OF ALUMINUM - 6% TIN BEARINGS, P.O.F.P. CAPABILITY = 25000 PSI o OlL FILM THICKNESSES ARE

                               -    GENEROUS IN CONNECTING ROD ACCEPTABLE IN MAIN BEARINGS FOR TYPICAL MEDIUM SPEED DIESEL ENGINES i

OTHER CAUSE BEARING SCORING MOST LIKELY OCCURS o WITH A NEWLY LAPPED JOURNAL At0 NEW

,                                                        BEARINGS PRIOR TO SHAFT SEASONING o      LOW OCCURRENCE PROBABILITY l

i e 9 1 't j

     " ~ ' ' .--- - - - - - - . _ _ - ,,   _ , _    _

SUMMARY

FAILED BEARINGS l INADEQUATE LUBE

                'EDG 11 ALIGINENT EDG 12        INADEQUATE LUBE BEARING CONTACT EDG 13      MISASSEMBLY WORN BEARINGS (VISUAL INSPECTION)

EDG 11 ALIGtNENT EDG 12 BEARING CONTACT EDG 13 , FORElGN MATERI AL BEARING CONTACT EDG 14 TRACE BEARING CONTACT l f

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

i CORRECTIVE ACT10N o REPLACED FAILED AND SCORED BEARINGS EXCEPT 3 ON EDG 14 (TRACE) o CONTINUE OIL SAMPLING PROGRAM o ELIMINATE OIL FILTER SAMPLING PROGRAM f I o FLUSH EDG'S 11 AND 13 WHICH EXPERIENCED BEARING FAILURES o CHANGE OIL TO MOBIL (ONE DIVISION) o SEASON BEARINGS FOLLOWING REPLACEMENT o MINIMlZE DISASSEMBLY o CONTINUE REQUIRED SURVEILLANCES o GAP CHECK BEARINGS EVERY 6 MONTHS j o PROCEED WITH BATTELLE LABS ANALYSIS OF BEARINGS l 0 RESOLVE EDG 12 OIL VISCOSITY PROBLEM

o C0f0UCT A RELIABILITY DEMONSTRATION o SIRJLATE A FUEL CYCLE o 100 HOURS SEASONING RUN o 20 SLOW STARTS o 10 FAST STARTS o RUN FOR 7 DAYS (168 HOURS) 9

SCHEDULE i ALL EDG WORK Af0 TESTING TO BE COMPLETED BY i FEBRUARY 19, 1986 3 1 1 a e 4 i f l i i 4 I e I i l i i l I I l I i l l 0

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

COLT'S POSITION

                        . l.               Long storage time (1975 - 1982) 7 years.

2. Galvanic action as shown by Technimet report. - l

3. Bearings were subjected to large number of fast starts (with quantity not pre-lubed) prior to bearings being conditioned to crankshaft. '

4. As a result of the failures in Unit #11 in January 1985, all units were subjected to disassembly and replacement of bearings in Unit #12.

! 5. Units #13 & 14 - The upper bearings in position 1 thru 6 were removed, i visually accepted and re-assembled. All bearings inspected were good.

6. Unit #13 failed #3 upper conn rod bearing due to improper re-assembly.

As noted in brinnelling of cap & rod fits. l

7. DECO & NRC decided to disassemble all engines to visually inspect 4

bearings. a) Problem - Any disassembly of engine bearings places jeopardy on proper re-assembly. . b) DEC0/NRC replai:ed bearings against Colt's recommendation. Example - i #14 unit upper main bearings. No problems until bearings were replaced. c) Opening crankshaft / bearing assembly introduces debris into bearings

                                                - As noted in #4 & 7 main bearings on #13 unit.

8. Colt recommends imediate stop to disassembling components for visual inspection of bearing surfaces. Inspect bearings with feeler gauge check only.

9. Correct problem with lube oil dilution on Unit #12 & 14.

l 10. Run engine per: a Extended wear in - 40 hours , b Continuous load - 2500/2600 kw - 100 hours l c Check bearings w/ feeler gauge l d Run NRC qualification tests e Re-check bearings with feeler gauge. I l l l

  ...,..__..m_ . . ._ ,        . - , , , , .    , . _ _ , _ . , . _J-_. _ , . _ . _ . . , , , . , . - - , _ - , , . _ . _ _ . , -       **%__  ...-_. . _ . _ _ . _        _,  , , . _ . - , , _ _ _ , _ _ , _ _ _

i

SUMMARY

o USE PROVEN DIESELS o EXTENSIVE DIESEL SURVEILLANCE PROGRAM o HAD SOME BEARING PROBLEMS AND SURFACE INDICATIONS i o IDENTIFIED CAUSES (MISALIGNMENT, STORAGE, MISASSEMBLY, LACK OF PRELUBE, PARTICULATES) o TAKING. APPROPRIATE CORRECTIVE ACTIONS (ALIGNED, CONDITIONING, REASSEMBLED, PRELUBE, FLUSHED) o IMPLEMENTED SLOW START CAPABILITY o BELIEVE DIESELS WILL RELIABLY START AND OPERATE WHEN CALLED UPON o PLAN TO RESTART ABOUT 2/19 AND NEED TO IDENTIFY REGULATORY PROCESS SO THAT OUR ACTION SUPPORT TIME FRAME i t

                                                                         - - - - - - - - - - - - - - - ~ - - - -

Ecciocuro 3 February 5, 1986 YP-86-0010 Endorsemente of Fermi-2 Emergency Diesel Generator Crankshaft Bearing Reliability Demonstration Test Program by Colt Industries and Failure Analysis Associates

1. Memorandum from C. Ankrum to Ed Greene, Colt Industries. Fairbankr, Horse Engine Division. " Detroit

    .             Edison 205981 C o n t r r,c t . Special Engine Run-In Procedure", dated January 30, 1986.

2. Letter from Dr. L. Swanger. Failure Analysis

Associates, to Mr. J. Nyquist. Detroit Edison, "Fairbanks Horse Diesel Engine, FaAA Case No.

WDC17064", dated January 31, 1986. b 8 1

Gtit industries N.e.n ro u Mm'.

               $                                                                                                                                     sowi.wiecorwn assit                                                       I p                                                                                                                                     ...eu.u i ,

interomoe Ed Greene C. Ankrum

   ' #'"                   Detroit Edison 205981 Contract                                                                                     o.i.:          January 30, 1986 Special Engine Run in Procedure This memo is to confirm our verbal agreement with Detroit Edison to formalize the special run-in procedure recommended for the engines at the Enrico Fermi II plant.

All engines are to be run-in per the standard Fairbanks Iforse Service Information letter Volume A. issue 5, sheet I through 3. dated August 13. 1985. Use the column for 900 rpm engine speed referenced in sheet 3. The 110% overload run will not be required. Upon completion of bearing inspection by feeler gauge after engine run-in, the engine will be subjected to the following continuous runs: a 40 hours 9 2000-2200 kw. b 100 hours 9 2500-2600 kw. Upon completion of the 100 hour run, a bearing inspection is to be made with feeler gauge. If units #12 and 14 pass this inspection, these units may be returned to service. - It was agreed in the meeting with DEC0/NRC/ Colt on January 24, 1985 that units

                         #11 and 13 were to receive additional testing per the following:

a ap 20 slow starts b i 10 fast starts ch 168 hour continuous run at 2500-2600 kw. At the completion of these tests, the bearings are to be inspected by feeler  ; gauge and if acceptable, the units can be returned to service. If at any point. 1 a conn rod or main bearing fail the feeler lauge check, only that bearing and I the bearing connected by the oil passage in t1e crankshaft are to be removed for rework. No other bearings are to be disassembled. After rework, the engine should be subjected to the full re-run as originally specified. All scheduled starts, including the fast starts, the enaines are to be pre-lubed priortostartingperpreviousagreementandDetroitEdisonprocedures. - After engines are returned to service, it is understood that for all future surveillance testing, the engines will be slow started and pre-lubed. Utilizing the above procedures should provide the best assurance the engines w eet future demands of their intended service. cc: P. Brown ' T. Skinner G. 51aymaker T. Miller i (

                                                                                                                     .___-,_._.8   ..I _v.. _ _ _

Failure a~oi uana ~o w, tuccicat co~sut, ~,s m%L,e, , - . . . - . . ....., AL.E ANOmeA VAGIN4A 22314 (74316 55550 January 31, 1986

                                                                                                              )

Mr. John Nyouist Detroit Edison Co. Fermi II Nuclear Power Plant 6400 North Dixie Highway Nrwoort, MI 48166 Re: Fairbanks Morse Diesel Enoine ' FaAA Case No. WDC17064

Dear Mr. Nyouist:

Following up on cuestions asked by the NRC staff on January 24, 1986, I have the following observations and comments. The demonstrations planned for EDG 13 and either EDG 11 or EDG 12 will be fair tests of the availability of the Fairbanks Morse. diesels during an 18-month refueling cycle at Femi II. Use of the .002 in. gap check to detect loss of free spread on the upper crank line main bearings is an appropriate acceptance criteria for this test. The loss of free spread that is revealed by a gap check failure is due to the non-uniform heating of the bearing's inner surface by friction after interruption of the hydrodynamic oil film. The themal stresses cause the inner surface to yield in compression, creating a residual stress state that pulls the bearing parting lines in toward the crankshaft after cool-down. Interruption of the oil film is caused by substantial transfer of aluminum from the bearings to the crankshaft, creating geometric deviations so large that hydrodynamic lubrication can no longer be developed. Transfer of aluminum from the bearing to the shaft can occur in an amount low enough to avoid disruption of the oil film, but still cause some pitting or surface scoring of the bearing where aluminum is removed from its surface. SOSTON

• DETROIT e HOUSTON
• LOS ANGELES e PALO ALTO e PHOENIX e WASHINGTON. O C o

g .m .7 , , . , I

     ! r ., .                ,,

Mr. John Nyquist , January 31, 1986 _. Page 2 4 Considering the case where surface scoring has occurred, but not of sufficient intensity to disrupt the oil film and reduce free spread (i.e., cause gap check failure), the future reliability of such a bearing / journal pair is of concern to the NRC staff. Even in the presence of surface scoring, the retention of free spread (i.e., passing the gap check) shows that a hydro-dynamic oil film continues to separate the bearing and journal, preventing a high friction, high temperature failure. The resulting oil film will be j thinner than the oil film in a bearing without surface scoring, making the l bearing more sensitive to oil-borne particulates, subsequent fast starts, or excursions in operating conditions. However, the surface scoring is not an i inevitable precursor to failure as conservatively defined by the gap check. At Fermi II, there has been evidence of recovery from the condition of j surface scoring. Through the processes of normal wear and plastic flow of the bearing material, healing of s' cored bearings can occur and has been observed, e.g., EDG 13, lower crankshaft #4 main bearing. If every bearing survives the i planned demonstration without failing the gap check, then the future

availability of the diesels is reasonably assured with respect to bearing problems. The incorporation of the seven-day run at the end of the start cycles would allow even bearings that hypothetically had suffered surface scoring to begin the recovery process.

j The upcoming demonstrations will show the benefit of " seasoning" ) crankshaft journals. The reported surface finish of a " seasoned" journal j versus a freshly lapped journal decreases the probability of harmful bearing-to-journal contact and excessive transfer of aluminum to the journal. Very ruly r i l LeeA. Mechanical Swanker,Ph.f.P.E. Metal rgical Engineer Director Washington Office l l LAS2/MSW/L-FermiWDC17064 l tadure Assocates

   -   ,---,-.-,-...,-,..a                . - - - , - - - - - - - - - -          - - -   - - - -   - - . - . - - - . -        ,  -?--..--

Enclosure 5 Main Steam Bypass Lines On September 17, 1985, the licensee identified a leak in the east steam bypass line. It was determined through investigation that the 30 inch diameter Steam Bypass Lines have experienced the development of a number of large cracks as well as damage to lugs and pipe restraints. Although this line is not safety-related, due to its relative importance to safe plant operations, a review of the licensee's actions concerning this problem was performed. Items reviewed during this inspection included: Operational history of the Steam Bypass Lines Licensee's evaluation of the cause of the cracking Results of readings from the instrumentation installed on the pipe 4 Techniques used to repair the cracks l' Results of metallurgical tests conducted on a sample removed from an area of the cracked pipe The NRC inspectors concluded after this review that the Steam Bypass Lines were experiencing very acute fatigue induced failure. This is unusual in that the lines have a very short (approximately 2 months) operational history and that the unit has been limited to 5% of rated power. It appears that the fatigue problem is related to two factors; (1) the large diameter thin wall configuration of the piping (30 inch diameter. 0.375 inch wall); (2) the high frequency acoustic vibrations induced by the steam bypass valves. A permanent j modification to address the fatigue problem must consider both of these factors. Additionally, during the NRC inspection the licensee discovered a new crack .l which had developed since the last repair. The NRC inspectors concluded that further failure of the lines was imminent and that continued operation represented a risk to continues operation of the unit. The licensee agreed to shut the

';     unit down and initiate replacement of the damaged piping. The above is documented in Inspection Report No. 50-341/85045 (Enclosure SA).

The licensee has replaced the steam bypass lines from the bypass valves to where they penetrate the main condenser. Region III has inspected the replacement activities and has identified no problems with the modification work. The ! results of the followup inspection are documented in Inspection Report No. 85049 i (Enclosure SB). ) i Lead Responsibility: Region III, DRS 7

ENCLOSURE 5.A l OCT 311985 D:cket No. 50-341 The Detroit Edison Company

• i ATTN: Wayne H. Jens Vice President i

Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 G2ntlemen: This refers to the special safety inspection conducted by Messrs. J. Jacobson cnd J. Muffett of this office on October 8 and 9, 1985, of activities at Enrico Fermi Atomic Power Plant, Unit 2, authorized by NRC Operating License No. NPF-33 and to the discussion of our findings with Messrs. D. Spiers and S. Noetzel at the conclusion of the inspection. 4 The enclosed copy of our inspection report identifies areas examined during tht,' inspection. Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel. No violations of NRC requirements were identified during the course of this inspection. In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosures will be placed in the NRC's Public Document Room. We will gladly discuss any questions you have concerning this' inspection. Sincerely, I , '. : .21 C:- .::! by J. J. I: cc: :: - l  : l l J. J. Harrison, Chief l

Engineering Branch '

l

Enclosure:

Inspection Report l No. 50-341/85045(DRS) l See Attached Distribution i i

                          /

The Detroit Edison Company 2 OCT 311985 Distribution cc w/ enclosure: L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DCS/RSB (RIDS) ~ Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voigt, Esq. . Nuclear Facilities and - Environmental Monitoring Section Monroe County Office of Civil Preparedness l RIII"/'I / RIII RI) N tobHU Mek *fsslgg RIII 40tK ) oury S Ha(f 1 e son /jp Muffett Danielson son , 1D/28/85 fofyijyg- I j yel5\ l

f U.S. NUCLEAR REGULATORY COMISSION REGION III Report No. 50-341/85045(DRS) D cket No. 50-341 License No. NPF-33 Licensee: Detroit Edison Company l 2000 Second Avenue Detroit, MI 48224 Facility Name: Enrico Fermi Atomic Power Plant, Unit 2 Inspection At: Enrico Fermi Site, Monroe, MI Inspection Conducted: October 8 and 9, 1985 L Inspect s: Jacobso /0 3/ !f'1' Date

                  %N J. Muffett                                              it/sr /R5 Dat'e    '

Approved By: D. Danielson, Chief i Materials and Processes Section /8/8/ l' Date Inspection Summary Inspection on October 8 and 9, 1985 (Report No. 50-341/85045(DRS)) Areas Inspected: Special announced safety inspection of the 30" steam bypass line failure; and licensee actions on previous inspection findings. The inspection involved 18 inspector-hours onsite by two NRC inspectors. Jtesults: No violations or deviations were identified. i Y/Ly Cpos/ / 3 .

I DETAILS

1. Persons Contacted i

Detroit Edison Company (Deco) J. Conen, Licensing Engineer J. Mullens, Welding Engineer l *D. Spiers, Director, Field Engineering

85. Noetzel, Assistant Manager

           *M. Williams, Senior Engineer
           *T. O'Keefe, Superintendent, Nuclear Engineering

• Denotes those attending the exit meeting on October 9, 1985

2. Licensee Action on Previous Inspection Findings

a. (Closed) Violation (341/85038-01(DRS)): Failure to properly qualify a welding procedure in accordance with the AWS D1.1 Code.

Procedures used by the electrical contractor, L. K. Comstock (LKC), to weld cable trays and supports did not address fillet size as required by the Code for "prequalified" ststus. l The licensee initiated DER No. 85-640 to document this deficiency. Per the Detroit Edison Specification 3071-128, the smallest fillet weld attaching structural steel is 3/16 of an inch. In order to evaluate work previously completed by LKC, the licensee conducted weld procedure qualification tests simulating the most severe field conditions with regard to minimum size multi pass fillet welds. The The qualifications are documented in Engineering Research Report No. 83E78-40. These qualifications were performed in accordance with LKC procedure WI-000-03001 in the horizontal, vertical and overhead positions. In order to verify the adequacy of other site

contractors with regard to this deficiency, a review of their "prequalified" weld procedures was conducted by the licensee. All i

documentation was reviewed by the NRC inspector. This qualification testing is considered an acceptable resolution of this ites.

b. (Closed) Open Item (341/85038-02(DRS)): Linear indications on j radial box beam 5028. Calculations performed by Sargent and Lundy i Engineers (SLS-EF-099, Calc NP-Al and NS-E2-023BF) to resolve NCR 84-1839 were reviewed by the NRC inspector and found to be acceptable. Based on the review of this analysis, this item is considered closed.

3. Review of Steam Bypass Line Failure The 30 inch diameter Steam Bypass Lines have experienced the development I of a number of large cracks as well as damage to lugs and pipe restraints, j Although this line is not safety related, due to its relative importance 2

to safe plant operations, a review of the licensee's actions concerning this problem was performed. Items reviewed during this inspection included:

• Operational history of the Steam Bypass Lines
• Licensee's evaluation of the cause of the cracking

<

• Results of readings from the instrumentation installed on the pipe i
• Techniques used to repair the cracks
• Results of metallurgical tests conducted on a sample removed from an area of the cracked pipe l The NRC inspectors concluded after this review that the Steam Bypass Lines

;    were experiencing very acute fatigue induced failure. This is unusual in that the lines have a very short (approximately 2 months) operational history and that the unit has been limited to 5% of rated power. It appears that the fatigue problem is related to two factors. The first being the large diameter thin wall configuration of i.he piping (30 inch diameter, 0.375 inch wall). The second being the high frequency acoustic vibrations induced by the steam bypass valves. A permanent modification i    to address the fatigue problem must consider both of these factors.

Additionally, during the NRC inspection the licensee discovered a new crack which had developed since the last repair. The NRC inspectors concluded that further failure of the lines was imminent and that continued operation represented a significant risk to safe operation i of the unit. The licensee agreed to shut the unit down and initiate

,    replacement of the damaged piping. No violations or deviations were identified.

The NRC plans to review this matter further. This is an open item (341/85045-01).

4. Exit Interview The inspectors met with licensee representatives (denoted in Persons Contacted paragraph) at the conclusion of the inspection. The inspector summarized the scope and findings of the inspections noted in this l report. The inspector also discussed the likely informational content

, of the inspection report with regard to documents or processes reviewed by the inspector during the inspection. The licensee did not identify any such documents / processes as proprietary. i il

1 3

gf .l ENCLOSURE 5.B Jh;J 101986 . , l l Docket No. 50-341 The Detroit Edison Company ATTN: Wayne H. Jens Vice President Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 Gentlemen: This refers to the special safety inspection conducted by Mr. J. Jacobson of this office on December 3 5, 1985 and January 9, 1986, of activities at Fermi Nuclear Power Plant, Unit 2 authorized by NRC Operating License No. NPF-33 and to the discussion of our findings with Mr. F. Agosti and others of your staff at the conclusion of the inspectiun. The enclosed copy of our inspection report identifies areas examined during the inspection. Within these areas, the inspection consisted of a selective Oxamination of procedures and representative records, observations, and interviews with personnel. No violations of NRC requirements were identified during the course of this inspection. ' In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the, enclosed inspection report will be placed in the NRC Public Document Woom. - We will gladly discuss any questions you hrve concerning this inspection. Sincerely,

                                         ,: : _1 C ;;.;j 17 J. f. f*l.'.
                                                                         ~

J. J. Harrison, Chief Engineering Branch l See Attached Distribution P r. cobsen/mj paniels'ene ,h eilg , "8 Wrlgt "ShA-Harrison do sla s f Ip fht ols'

i s J A:J 101986 The Detroit Edison Company 2 . Distribution cc w/enclosuse: L. P. Bregni, Licensing - Engineer ^ P. A. Marquardt, Corporate 1 Legal Department DCS/RSB(RIDS) Licensing Fee Management Branch Resident inspector, RII.I Ronald Caller., Michigan Public Service Comrission Harry H. Voight, Esq. Nuclear Facilities and Environmental Monitoring Section Monroe County Office of Civil Preparedness t t e e f I l l 1

U.S. NUCLEAR REGULATORY COMMISSION REGION !!! Report No. 50-341/85049(DRS) Docket No. 50-341 License No. NPF-33 Licensee: Detroit Edison Company 2000 Second Avenue ~ Detroit, MI 48224 Facility Name: Fermi Nuclear Power Plant, Unit 2 Inspection At: Fermi 2 Site, Monroe, MI Inspection Conducted: December 3-5, 1985 and January 9, 986 ffe< j Inspector: J. Jacobson I ( ol k Date j Approved By: W#/+ D. Danielson, Chief /0 b Materials and Processes Section Date Inspection Summary Inspection on December 3-5, 1985 and January 9. 1986 (Report No. 341/85049(DRS)) Areas Inspected: Special announced safety inspection of piping replacement for the steam bypass line failure ,and followup on allegations resulting from this effort. The inspection involved a total of 16 inspector-hours onsite by one NRC inspector. Results: No violations or deviations were identified. I l

               %f   I

DETAILS I. Persons Contacted Detroit Edison Co. (Deco)

          **J. Conen, Licensing Engineer
            *D. Spiers, Director, Field Engineering
            *J. Contoni, Lead Engineer, Mechanical l            *J. Quinn, Maintenance Welding Engineer
            *J. Malaric, Plant Modificatiens Engineer
            'J. Rotondo, Senior Quality Specialist
            " Denotes those attending the onsite exit meeting on December 5,1985.
          ** Denotes those telephonically contacted on January 9, 1986, for the final exit interview.

2. Followup on Allegations (Closed) Allegatica RIII-A-85-0200: Weld quality deficiencies of automatic welds performed on steam bypass piping replacement. It should be noted that this particular system is not a safety-related system.

As part of the steam bypass piping replacement, Deco elected to utilize i automated flux-cored arc welding techniques on accessible welds. The decision to use this process was based on the decreased welding time when compared with manual welding. Two individuals contacted the NRC with four quality concerns, these concerns were reviewed by the NRC inspector as follows: Concern (1) A downhill welding technique was used by the automatic welding operators. The alleger stated that in his many years of (manual) welding experience he had not seen downhill welding used in a powerhouse. NRC Review The automated welding procedure utilizes the flux-cored are welding process. This process involves welding currents considerably higher than manual welding and consequently requires techniques which differ. Depositing the root pass using the automatic flux-cored process in the uphill direction would cause excessive heat input and burn through. This procedure was properly qualified for a downhill root pass and is technically acceptable. Concern (2) The a'lleger stated that the welding procedures were not Detroit Edison's. (Deco) proceduras and that they were obtained from Texas. I 2 l

l l l NRC Review When the licensee elects to contract a work task, the contractor's procedures may also be approved and utilized. In addition, a Deco representative was sent to the contractors shop (Texas) to participate  ; in the procedure development and qualification. No violations of NRC  ! requirements or industry standard practice was found. ' Concern (3) The alleger stated that the backing rings utilized to aid in welding of the pipe joint roots are not adequately fused. This observation was based on the alleger's involvement in the cut out of a weld joint due to improper pipe length. Furthermore, the alleger stated that the weld was of poor quality. NRC Review The automatic welding procedure was found to be properly qualified in accordance with the requirements of Section IX of the ASME Code. The governing code for installation and weld inspection was ANSI B31.1, While this code requires only a final visual inspection of the weld, Deco elected to utilize magnetic particle examination of both the partial and completed welds. This enhanced inspection and proper procedure qualification coupled with the complete removal of the weld noted by the Alleger, gives assurance that the installed welds will adequately meet the design requirements per the governing code. The NRC inspector examined a weld joint mock-up welded with the automatic

process. During the initial examination, three pieces of the backing ring, l each approximately 2" in length, were removed from the weld joint. The j backing ring sections exhibited adequate fusion and the weld joint exhibited full penetration of the root. Subsequent to this examination, the NRC inspector observed the removal of approximately 25" of the backing ring utilizing hammers and chisels. The inspector concluded that the automatic welding process produced complete joint penetration and adequate fusion of the backing ring.

The alleger also stated that the weld mock-up was, "a lot different from the welds in the plant in that the mock-up was stress relieved and that it helped fuse the backing ring." Stress relieving, or more properly , called post weld heat treatment, is required per ANSI B31.1 on pipe with a wall thickness of 3/4" or greater. All welds requiring post weld heat treatment, including the mock-up received this process. Post weld heat treatment is performed to relieve residual stresses caused by the welding process and in no way helps to fuse the backing ring to the joint. Concern (4) The alleger stated that two root passes instead of the required one had been used on a weld. Also that some welds were made using incorrect polarity.

                                                                                  )

l l 3  !

i NRC Review 1 The use of two weld passes for the roct is nct considered an essertial variable per ASME Section IX and therefore did not require requalification  ; of the procedure. This technique for welding the root is technically l acceptable uten backing rings are used in the joint. l The flux-cored arc welding process will not operate with incorrect polarity and therefore could not have been used to deposit a weld. Conclusions (1) This item was substantiated in that a downhill welding technique was usec. This technique hcwever, was properly g.alified and is technically acceptable. (2) This item was substar.tiated in that the welding procedure was not a CECc tualified proceoure. The practice of licensee review and approval of a contractors procedure to be used or. contracted work is acceptable. (3) This item was partially substantiated in that during the cut out of a weld joint due to imprope dimensions, it was apparent that the backing ring was not comple ly fused to the weld joint. Since this weld joint was complett.y removed, it has no effect on the piping system. Weld quality using this procedure was properly demonstrated by a successful ASME, Section IX qualification test. In addition, the NRC inspector examined a weld mock-up which demonstrated complete joint penetration and adequate fusion of the backing ring. Furthermore, weld joint quality of the installed i piping was demonstrated by the use of magnetic particle examination. This examination was performed on all welds though the code required a visual examination only. (4) This item could not be substantiated in that the process will not operate using incorrect polarity. The use of two weld passes instead of one could not be substantiated, and even if substantiated, is of no technical significance. It was noted that several instances of tampering with the automatic equipment, by persons unknown, were reported during the welding operation. This tampering did not effect weld quality although sore production tire was lost. Although some of these allegations were substantiated, none had any impact of plant safety.

3. Review of Steam Bypass Line Repair As outlined in NRC Inspection Report No. 341/85045(DRS) the steam bypass lines experienced acoustic vibration induced failures. As a result of l

4 ,

these failures, the licensee proceeded to replace the affected piping. Due to engineering considerations modifications to the original design of this piping installation were made. The systen, as originally designed, contained piping with a 30" diameter and 3/8" thick wall which was connected by means of a reducer to a 24" diameter pipe with a 3/8" thick wall. This configuration was changed so that the system etcployed 30" diameter piping with a 1" thick wall and 24" diameter piping with a 1" thick wall. The increase in pipe wall thickness server to substantially reduce the stress levels associated with the acoustic vibrations. Orifice plates were installed in the piping syster in an effort to j reduce the acoustic energy created at the discharge of the bypass valves. The source of the acoustic vibration is the large pressure

differential across the throat of the bypass valve. The orifice plates serve to reduce the vibration due to back pressure and attenuation.

l The bypass line failures originated at points or. the outside of the wall where welded attachments were located. Apparently any disruption of the natural vibratory pattern results in a localized stress intensification. To alleviate this probler:, the welded attachments were removed during the modification. The NRC inspector reviewed Deco EDP 4410 fcr design information and I inspected the installed piping system. Strain gages were installed at 11 locations to be used by DECO during operation to detennine the effect of these design changes. l

4. Exit Interview ,

i The inspector met with licensee representatives (denoted in Paragraph 1) at the conclusion of the onsite inspection. The inspector sunnarized the  ! scope and findings of the inspections noted in this report. The inspector i also discussed the likely infonnational content of the inspection report l with regard to documents or processes reviewed by the inspector during the inspection. The licensee did not identify any such documents / processes as proprietary. Additional infonnation was discussed telephonically with a licensee representative (denoted in Paragraph 1) on January 9,1986. 5

_ ENCLOSURE 7.A

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[ NUCLEAR 90ULATORY COMMISSON

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                                                       ?I15                  n) auj y r      ,;;upop Docket No.: 50-341 Dr. Wayne Jens Vice President - Nuclear Operations The Detrott Edison company                                                                            i 2000 Second Avenue Detroit, Michigan 48226

Dear Dr. Jens:

subject: i Isolation Requirement 4 for primary Containment penetretten X-354 l In revioutng your F54R. we have detemined that you submitted a revision in Amendment 51 (October 1983) So the FSAR which represents a deviation from to 10 the CFRrequirements of Genera" Design Critarion (EDC) M of Appendia A part 80 Specifica11, r, stated in Amendment El that you were modifying penetration X-354 throu inery containment so that containment isolation for this line is prey! a single check valve outside conta fruent. Furthemore you atate n Table s.2-1 of your F5AR that you complywith comply with80C theM.requiremen,ts of SDC 54 but de not indicate whether you This latte design criterion is very specific with re-perd to the need contaimenti namely,foryou twosaast isolatplon valves on Ifnes penetM ting primary containment. Our position on t wide one valve inside and one valve outside check valve outside containment tis mettar is that by providing only a sin Accordingly, we require thatrevise yaa, you are in violation of our regulations.gle the isolation capability of penetration X-35E in accordance with the requirements of SDC M. In responding on this matter y the requirements of GDC 56. ,No su may consider requesting en exemption from i sever if you do request such an exemptlon, you should provide a detailed j ustification exemption request. to form the bests for yor.c Inthistoj quirements of Item II.E.4.2, *l, krd, your response should consider it.e re.

;    RUltEG-0737. ' Clarification of 1 pntainment Isolation Dependability,' of Position (3) of Item II.E.4.2 7 equires  4 Action Plan Requirements." Specifically.

bc automatically isolated by tm that "all nonessential systems shall that the Trevaling Incore Probe (TIP) pure contatrument signal." It is our position cssential line and that Item 11.E.4.2(3) is getherefore X-354) is a non-Ifne (i.e.applicable. To satisfy eur Mqufrements on t cf the present outboard contaimhis matter, we would accept the replacement which would close estomatica113 on ent isolation valve with an isolation valve signals in accordance with our g receipt of the required diverse isolation section of Itan II.E.4.2. We so ut.: uidance in Item t in the clarification also find acceptable a check valve to satisfy the requirement for en isolation valve inside con,tainment. MGoits

Dr. Nayne dens -E-In order that us any obtain a 14mly mselution of this setter provide an initial mspense within ene weelt of receipt of this letter indItating when  ; you will respond substantively m the issues in question. Your substantive 1 response should include a disculision of when you will be able to com into cogliance with GDC 56. If you have any questions on thi me matters, contact the Ferut-2 Project Manager. M. D. Lynch, at (301) @2-7060. Sfacerely, f

s. 4 'oungb Licin ing 8 nch No. 1

                                                                  . Chief Divis on of Licensing cc: See next page l

l l l l M l

ENCLOSURE 7.B DE,",oY, ~ n .m.a ' Md ' Groit s,m, lW g,n idison Ess"= 1985 December 20 YF-85-0238 E l Director of Nuclear Reactor Regulation Atto: Ms. Elinor C. Adensas. Chief Licensing Branch No. I lg' Division of Lic ensing D. S. Nuclear Regulatory Commission Washington, D. C. 20555

Reference:

1) Fermi 2 NRC Docket No. 50-341 RRC Lic ens e No. EFF-43

                                                                       " Isolation

2) NRC Letter toforDetroit Edison Primary Containment Requirements

                            - 7enetration 1-35C". dat ed Novemb er-21,1985 "Frimary

3) Detroit Edison Letter to MRC, containment Fenetration 1-35C". YF-85-0222 dated December 3. 1985 Sub j ec t : TIP Purre Line sub=Ittal ith -th e In 1t eT e r e n c eTth e nC Ta8-18 & nTit i e d a c on c e rn-wnitrogen purge

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design of traversing in-core probethe (TIF) ~ ~ ~ current design did line. The ERC had indicated that of General Design Criterion (CDC) not meet the requirementsreviewed the design of this line

56. Detroit Edison has prior to restart from the first and commits to modify it scheduled refueling outage to provide compliance with implemented prior CDC 56. An interim modification will beoutage to attain an enhanced to restart from the current isolation capability f or this line to allow the 2 through continued first fuel startup and operation of Fermiinterim modification vill not provide cycle. Because this Edison will provide .

full compliance with CDC 56. Detroit and an amendment to

                                                                                             'A both a formal exemption request  in a submittal which will be Operating provided Lic ense NFT-43to the NRC the week of January 6. 1986.
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Ms. Ellaer C. Adonsco December 20, 1985

              ?P-85-0238 Page 2 Please direct any questions to Mr. Robert L. Woolley at (313) 586-4211.

sincerely, cc: Mr. P.M. Byron Mr. M. D. Lynch Mr. J. C. Lane USNRC Document Control Desk Washington, D.C. 20555 de .- - 5 1 I l

t mi ll. Jefne

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[OISOn m..~, ..y*e - g,,;,,,, December 31, 1985 VF-85-0237 Director of Nuclear Reactor Regulation Attn: Ms. Elinor C. Adensam, Chief

• Licensing Branch No. 1 Division of Lic ensing U. S. Nuclear Regulatory Commission Washington, D.C. 20555

Reference:

1) Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43

2) NRC to Detroit Edison Letter, " Isolation Requirements for Primary Containment Fenetration I-35C". dated Wavenber 21, 1985 _ _ _. _, _

Subject:

Traversing In-Core Probe Furge Line (Penetration 2-35C) Reference 2 indicated that the design of the traversing in-core probe (TIP) nitrogen purge line did not comply with Central Design Criterion (CDC) 56. The following presents the basis for the current system design, as wet 1 as a description of the design modTficatio'ns that ~~~~ Detroit Edison commits to implement in the short and long term. In October 1983 Detroit Edison submitted Amendment 51 to the Fermi 2 FSAR. Section 6.2.4.2.2.1 and Table 6.2-2 of the FSAR were revised to include a description of penetration I-35C. the Traversing Incore Probe (TIP) nitrogen purge line penetration. Note 30 of Table 6.2-2 was added in Amendment 51 indicating that the TIP purge line was classified as an instrument line. The isolation design complied with the NRC's guidance for instrument lines in that it provided a check valve outside containment in compliance with Paragraph C.2.a of Regulatory Guide 1.11.

Ms. Elinor C. Adenson December 31. 1985 VF-85-0237 - Page 2 The classification as .s n instrument line was deemed acceptable since the line is of small diameter (i.e.. 3/8 inch), does not qualify as an ASME Code process line, and while it does not transmit an analog instrument signal, does service the TIP instrument system. As reflected in the FSAR, the design of this  ! line follows the reconnendations of Regulatory Guide 1.11 which provides acceptable alternatives to the - isolation requirements of Ceneral Design Criteria (CDC) 1 55 and 56 for instrument lines. (Instrument lines are , explicitly exempted from the requirements of NUREC-0737 Item II.E.4.2 which imposes specific isolation

  .                        requirements on nonessential penetrations).

As noted above, the NRC indicated in Reference 2 that this line is to be designed in accordance with CDC 56. l Detroit Edison thereby couaits to revise the isolation design of this line to comply with GDC 56. Compliance I with GDC 56 allows the installation of a containment isolation valve outside of containment and a containment 4 solation er check salva inside of montainment. . Detroit Edison will install a check valve inside of containment , and have at least one containment isolation valve outside of containment. In accordance with GDC 56 the isolation valve will receive diverse isolation signals.

Due to the scope of this modification, and the lead time included in the design and procurement activities hv41 sad,- f=11 4caplianc e with CDC 5.6_cannot be achieved until the first scheduled refueling outage without l significantly delaying restart from the current outage, or impseting later startup or operations activities.

Detroit Edison estimates that development of the design, procurement and installation of this modification will require approximately 6 conths. This includes seismic design, procurement of nue! ear quality components, and installation of appropriate seismic supports. Installation during the current outage would require reentry i~nto the drywell and extension of the outage. 1 I 4 I

Decoobor 31 1985 TF-85-0237 Pcgo 3 Therefore. Detroit Edison proposes to install an interis modification to the TIF nitrogen purge line that will provide an enhanced isolation design, though not provide full compliance with CDC 56. Two ball valves outside of primary containment will be installed on the TIF purge l line prior to restart from the' current outage. These i two valves will be QA level 1 and will be powered from, and receive containment isolation signals (i.e.. reactor , vessel level 3 and high dryvell pressure) from the same circuits which power and isolate the ball valves for the balance of the TIF system containment isolation valves. Upon loss of power, the valves have spring-actuated closure to ensure failure in the safe position. In addition, these valves will be seismically mounted. Following installation, a local leak rate test per 10CFR50 Appendiz J will be performed, and the valves will undergo a functional test to assure operability. Due to the fact that the interim modification presented above does not provide full compliance with the inboard / outboard isolation valve requirements of GDC 56 Detroit Edison requests an exemption from the requirements of CDC 56 for the T17 altrogen purge line _. _in_mecordance with 10CFR50.12. .The._szempt. ion is requested to allow reactor restart and operation with the identified interim modification until the first scheduled refueling outage. Elenificant Bazarda Analvain Detroit Edison requests that Fermi 2 Operating License m EFF_fj.,)2_AmeDded_.to m f,1_ec.t_the exemption re3uested from CDC 56 to allow operation from restart from the current outage until the first schedule'd refueling outage. The proposed license amendment has been reviewed by Detroit, Edison and does not involve a significant hazards consideration. in accordance with 10CFR50.92. i l e e 9

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. Ms. E11aor C. Adensco Deceober 31, 1985 VP-85-0237 - Fogo 4 a) The interim modification does not involve a significant increase in the probability or consequences of an accident previously evaluated. The proposed design modification , vill provide a sys tem which more closely l matches the requirements of GDC 56. per the  ; incorporation of two ball valves with containment isolation and redundant fail - closed capability. The enhanced isolation design will provide a more reliable barrier. b) The interim modification will not create the possibility for a new or different kind of accident from any accident previously evaluated. The interim modification uses the same type ball valve and isolation signals as is presently used for the balance of the TIP system. c) The interim modification does not involve a significant reduction in a margin in safety. In fact, the redundant isolation valve configuration will enhance the existing margin of saf ety. - - The interin modification will have no adverse effect on the health and safety of the public nor the environment in that the isolation capability for the TIP nitrogen purge line will be enhanced by the interim modification. LerYD1tTIdtrc~n tas evaluates tais requist-in -- accordance with the criteria in 10CFR170.21 and has enclosed an application fee of one hundred fifty dollars ($150.00) as initial payment for this application for amendment urder Facility Category A (Power Reactors). In accordance with 10CFR50.91, the State of Michigan has been provided a copy of this letter. l l l 1 __ _ _ ___a

k Mo. Ellaer C. Adonson Decocbor 31, 1985 ' VP-85-0237 Page 5 - Direct any questions to Mr. R ob e r t L. Woolley at (313) 586-4211. Sincerely. f. Yk0

tS With attachment ec: Mr. P.M. Byrons#

Mr. J. C. Lane Mr. M. D. Lynch Supervisor. Advance Planning and Review Section Michigan Public Service Commission USNRC Document Control Desk Washington, D.C. 20555 DN646$eg S O 9

Ms. Elinor C. Adensso December 31, 1985 1 VF-85-0237 l Fage 6 ) i l I. WAYNE H. JENS. do hereby affirm that the foregoing statecents are based on facts and circums tanc es which are true and accurate to the best of my knowledge and belief.

                                                         'al            84s if WAYNE I. JENS Vice President Nuclear Operations On this             /    day of                        . 1985, before me personally appeared Wayne E. Jens, being first duly sworn and says that be executed the foregoing as bis free act and deed.

hob Notary Public Eiu:0:A BUCK Notary Public. Wac.tenaw County, Mi My Commission Dpires Dec.% W

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l mes. Wests 3 states ENCLOSURE 9.A

                %,                NUCLEAR REGULATORY COMMisslON

.S meoion m e

l 799 moostvtLT moAo t / sten eLLv=. stumois sein o.... JAN 3 1986 Docket No. 50-341 The Detroit Edison Company ATIN: Wayne H. Jens Vice President Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 . Gentlemen:  ; This refers to the special safety inspection conducted by Messrs. S. DuPont, A. Gautam, and C. Ramsey of this office on December 2-6, 1985, of activities at Enrico Fenni Nuclear Power Plant authorized by Facility Operating License No. NPF-43 and to the discussion of our findings with Mr. G. R. Overbeck at the conclusion of the inspection. The enclosed copy of our inspection report identifies areas examined during the inspection. Within these areas, the inspection consisted of a selective sxamination of procedures and representative records, observations, and interviews with personnel. No violations of MRC requirements were identified during the course of this inspection. However, the items identified in paragraphs 4, 6.g.(1), 6.g.(2) and 6.g.(3) are to be verified acceptable by MRR and items 6.f and 7.b by Region III prior to startup from the current outage. In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosed inspection report will be placed in the NRC's Public Document Room. We will gladly discuss any questions you have concerning this inspection. Sincerely, C. J. Pa r llo, Director Division Reactor Safety

Enclosure:

Inspection Report No. 50-341/85050(DRS) See Attached Distribution l 4(;cD1/0D2d Me-vu l

                                                                                    ..     . _ - .   \

The Detroit Edison Company 2 JAN 319A6 cc w/ enclosure: L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DCS/RSB(RIDS) Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Carmission ~ Harry H. Voigt. Esq. Nuclear Facilities and Environmental Monitoring Section Monroe County Office of Civil Pieparedness a R I f RIII RIII RI JtII RII RII l llWsey/rr G t Gul &mond WFTght e er e o ll) /86

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U. S. NUCLEAR REGULATORY COP 9tISSION REGION III Report No. 50-341/85050(DRS) Docket No. 50-341 License No. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48224 , Facility Name: Enrico Femi Nuclear Power Plant, Unit 2 Enrico Femi 2 Site, Monroe, Michigan  ! Inspection At: Inspection Conducted: 0%cember 2-6, 1985 . l In:pectors S. Dupo d' #/3/Irl Date

                                %                                                 8 A. Gautam                                                    Utte' i

W'7S C( Ramsey ll~1/t~l Date Approved By: (6/sirr //J/# W. G. Gul nd, Chief Date i Operational Programs Section Inspection Sumary Inspection on December 2-6, 1965 (Report No. 50-341/85050(DRS$) Areas Inspected: Special safety inspection conducted to verify the licensee's implementation of an independent alternative shutdown system as required by Condition No. 2.c.(9)(d) of Facility Operating License No. NPF-43. The , inspection involved 90 inspector-hours by 3 NRC inspectors including 17 inspector-hours onsite during offshifts and 2 inspector-hours conducting in-office review at the Region III office. Results: Of the six areas inspected, no violations were identified.

         .gb o/pjMLNf 1                     -                      - .       _ ..   . _ _ - - . .           -   --   _ _ - - _ -.

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1. Persons Contacted DECO

              *G. Overbeck, Superintendent - Operations
              *E. Preston, Operations Engineer
              *R. Anderson, Systems Engineer                                         .
               *S. Heard, Operations
              *R. Olson, Fire Protection Engineer D. Holland, Fire Protection Specialist
               *J. Conen, Nuclear Licensing Engineer
               *B. Ackerman, Quality Assurance M. Hobbs, Operations
               *R. Woolley, Acting Supervisor, Nuclear Licensing NRC M. Parker, Resident Inspector

• Denotes those personnel in attendance at the December 6, 1985 exit meeting.

2. Alternative / Dedicated Shutdown System Design l By letters dated October 22, 1984 (EF2-72001 and EF2-71994 - W. Jens-DECO i to B. Youngblood - NRC), the licensee consnitted to install a postfire alternative / dedicated shutdown system at the Fermi 2 facility for several fire areas in the auxiliary building control complex. The proposed design of this independent shutdown system was reviewed and accepted by the NRC

.               as discussed in Supplements No. 5 and 6 of the Fermi 2 Safety Evaluation Report (SER). Co.dition No. 2.c.(9)(d) of Facility Operating License No. NPF-43 requires that this system be operational prior to startup after the first refueling outage or prior to startup after the first known extended outage of three weeks or longer, whichever occurs first after September 30, 1985, but not to go beyond December 31, 1986.

The inspectors reviewed this installation as a complete system capable of accomplishing all of the postfire safe shutdown performance goals i which are necessary to minimize the release of radioactivity to the

environment.

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a. Systems Provided to Achieve and Maintain Hot and Cold Shutdown Conditions During and Following Fire ,

The required systems and associated components are included in the design to mitigate the adverse consequences of a disabling fire in the fire areas of concern. With three exceptions (discussed in l paragraphs 6.g.(1), 6.g.(2), and 6.g.(3) of the report), the , capability is provided to achieve and maintain hot and cold shutdown j j conditions as follows: ) (1) Emergency Power - Combustible Turbine Generator (CTG) No. 11,  ! ! located tn the Unit 1 facility, provides an independent I i

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l l l 1 (dedicated) power supply for all of the systems and associated ' components that are included in the independent alternative shutdown system design. There are four CTGs of equal capacity located in the Unit I facility which are used for other purposes. However, only CTG No. 11 has black start capability (diesel engine) which can be initiated from the control room or at the independent alternative shutdown panel. Once started, it takes 6 to 10 minutes for CTG No.11 to provide the power supply needed for the independent shutdown system. If a fire occurs in one of  : the fire areas of concern in coincidence with a loss of offsite , power, there could be an approximate 10 to 15 minute complete station blackout (except in areas where 8-hour battery pack emergency lighting units have been provided) while CTG No. 11 is being started and the emergency bus is being stripped and re-loaded with the required essential loads. There is no designated backup power supply for the system. (Thisisfurther_ discussed in paragraph 4 of the report). (2) Maintaining Reactor Vessel and Fuel Cladding Integrity Circulation of reactor coolant (makeup water) is provided by a (dedicated) standby feedwater system which takes suction from the condensate storage tank. Reactor pressure control is 4 provided by operation of safety relief valves functioning in the safety mode. The plant can be maintained in a stable hot shutdown condition by using the standby feedwater system and one safety relief valve (SRV ho. "G") discharging steam into the torus to control reactor pressure. t (3) Maintaining Containment Integrity and Removal of Decay Heat i Coatainment isolation can be accomplished by remote controls. l Drywell cooling, torus cooling, and component cooling capability

is provided by (alternative) paths from the Residual Heat i Removal (RHR), RHR Service Water (RHRSW), Emergency Equipment Service Water (EESW), and Emergency Equipment Cooling Water

(EECW) systems. The capability for control of support systems ,

such as drywell cooling fans and RHR room cooling fans is also i

provided. Cold shutdown can be achieved by placing the RHR system in the Shutdown Cooling Mode. Required instrumentation such as reactor level and pressure, i standby feedwater flow rate, torus water temperature and level, -j condensate storage tank level, bus voltage monitor, and primary containment temperature indications are provided on the indepen-i dent alternative shutdown (3L) panel. Isolation transfer l switches and local controls which are independent of the fire areas of concern are provided on the 3L panel and at variouc j locations in the reactor building for required breakers and , motor control centers. The instrumentation provided meets NRC , guidelines for BWRs. No violations or deviations we*e identified. 3 l . __ - - - . - . . . - . - - . _ - -

3. Functional Testing to Detemine Operability of the System The inspectors reviewed the following test procedures and resultant data  !

and detemined that the functional testing demonstrated the operability i

             .of the system described in preceding Paragraph 2.a.                                                 l l

! a. 47.000.83, Revision 0, " Third Remote Shutdown Panel (C3600)  ! l Supervisory Control Testing and Calibration." The objective of the test was to evaluate the technical perfomance of the telemetering linking of the Third Remote Shutdown Panel (3L) at Femi 2 to CTG-11-1 and controls at Femi 1. The subsystems tested included the Femi 2 master control and transfer, Femi 1 remote control and transfer, status indicators, and the undervoltage trip scheme,

b. 48.000.05, Revision 0, " Remote Shutdown Panel (3L) H21-P623 Post-Modification Test."

The objective of the test was to verify the transferring of the control of the Appendix R alternative shutdown system from the Femi 2 control room to the Remote Shutdown Panel (3L) by verifying positive and negative component operation, and a simulated loss of offsite power to demonstrate control of the 120 KV MAT and CTG-11 i from the remote shutdown panel.

c. 24.321.01, Revision 0, " Remote Shutdown System (3L) Operability Verification."

The objective of the test is to verify the operability of the entire Remote Shutdown Panel (3L). The testing will include actual verifi-cation of transferring control of the affected components from the

                    ' Femi 2 control room to the 3L panel. This is a surveillance test to verify the operability of the system at an 18 month frequency which was initially tested after modification by procedure 47.000.83.

as described above. The inspectors verified that the test included positive and negative verification checks. No violations or deviations were identified.

4. Proposed Technical Specifications  ;

i  ! By letter dated September 27, 1985 (RC-LG-85-0051, W. Jens --DECO to B. J. Youngblood - NRC), the licensee requested an amendment to technical specifications for the independent alternative shutdown system. The technical specifications define limiting conditions for operation of the alternative shutdown system that appear to be consistent with the "Model Technical Specifications for Alternative Shutdown Systems" required by 10 CFR Part 50, Appendix R (NRC Internal Memorandum dated March 10, 1983, M. Virgilio to T. Wambach). In addition, the licensee proposed limiting conditions for operation for several components used in the independent i alternative shutdown system that are not described in the "Model Technical Specifications for Alternative Shutdown Systems." 4 l

The inspectors' review indicated that the licensee's proposed technical specifications and amendment were satisfactory except as follows: The action statement (3/4.7.9) as proposed for the loss of CTG No. 11 requires verification that 120 KV offsite power is available to supply power to the shutdown panel and establishment of a roving fire watch for ! all fire areas where alternative shutdown capability is utilized. The licensee believes the availability of 120 KV power and a roving fire watch in the fire areas of concern to be sufficient to allow a period of up to 30 days in which either to restore CTG No.11 to an operable status or provide .an alternative power supply. Within 60 days, the licensee proposes to restore CTG No.11 to an operable status or be in at least hot shutdown within the next 12 hours and be in cold shutdown within the following 24 hours. The inspectors infortned the licensee that, based on discussions with NRR during the inspection, a designated backup power supply other than 120 KV offsite power will have to be made available within 30 days if CTG No.11 is inoperable for more than 30 days. At the conclusion of the inspection, the licensee agreed to designate this backup power supply either by providing one of the remaining CTG units with black start capability or by supplying another alternate source of power. The licensee indicated that this connitment would be formally transmitted to NRR and reflected in the proposed technical specification bases or in some other document. The inspectors informed the licensee that this issue must be resolved prior to startup from the current outage. This is considered an Open Item (50-341/85050-01(DRS)) pending verification by NRR and Region III prior to startup from the current cutage. No violations or deviations were identified.

5. Proposed Technical Specification Surveillances 1

The inspectors reviewed the proposed Technical Specification Table 4.3.10,.  !

                " Appendix R Alternative Shutdown Instrumentation and Controls Surveillance Requirements" and various surveillance procedures to verify that procedures exist for the required instrument channel calibration and checks. The

, following procedures were verified to satisfy the Technical Specification requirements: 44.110.26, Revision 0, " Alternative Shutdown System Primary Containment Temperature Channel Calibration." 44.110.25, Revision 0, " Alternative Shutdown System Torus Water l Level Channel Calibration." 44.110.24 Revision 0, " Alternative Shutdown System Torus Water Temperature Channel Calibration." l 44.110.23 Revision 0, " Alternative Shutdown System Reactor Pressure Channel Calibration." 5

• 44.110.22 Revision 0, " Alternative Shutdown System Reactor Water Level Channel Calibration."

      "     44.110.21 Revision 0, " Alternative Shutdown System Standby Feedwater Flow Channel Calibration."
      "     44.110.20, Revision 0, " Alternative Shutdown System Condensate Storage Tank Level Channel Calibration."

• 24.324.01 (draft) Revision 0, " CTG-11-1 Monthly Operability Check."

In addition to reviewing the above Technical Specification surveillance procedures, the inspector verified that the following control room alam procedures correctly addressed the Appendix R alternative shutdown Technical Specification 3.3.10. " Appendix R Alternative Shutdown Instru-4 mentation and Controls" and 3.7.9, " Appendix R Alternative Shutdown Auxiliary System":

• ARP11049, Revision 0, " Dedicated Shutdown Supervisory Control Activated."
• ARP11053 Revision 0, " Dedicated Shutdown Supervisory Control Trouble."
• ARP11D57, Revision 0, "120 KV Undervoltage Scheme Abnomal."

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• ARP 11D61, Revision 0, " Dedicated Shutdown Transfer Pushbutton Amed."

No violations or deviations were identified.

6. Reanalysis of Associated Circuits Supplement No. 5 of the SER required that the licensee perfom a reanalysis of those circuits which could have an adverse affect on the proper func-tioning of the independent alternative shutdown capability.

On a sample basis, the inspectors reviewed certain of these circuits to verify their electrical and physical isolation from the fire areas of concern. To prevent some spurious actuations due to fire damage to circuits, the licensee installed acceptable isolation transfer switches. In other instances (for example, core spray and RCIC systems), the licensee elected to strip the loads off of Class 1E AC and DC buses. In addition, to prevent spurious actuations from adversely affecting

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reliability of CTG No. 11 operation, selected balance of plant (BOP) loads are also stripped from the BOP AC and DC buses prior to re-energizing. The associated circuit concerns evaluated were:

a. Comon bus associated circuits - The comon bus concern is found in circuits, either non-safety related or safety-related, where there is a comon power source with shutdown equipment and the power source is not electrically protected from the circuit of concern.

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b. Comon enclosure associated circuits - The comon enclosure concern is found when redundant circuits are routed together in a raceway or enclosure and they are not electrically protected or fire can destroy both circuits due to inadequate fire protection means.

c. Spurious signal associated circuits - The spurious signal concern consists of two parts:

(1) False motor, control, and instrument readings such as occurred at the 1975 Brown's Ferry fire. These indications could be caused by a fire initiated ground, shorts, or open circuits. (2) Spurious operation of safety related components that would adversely affect shutdown capability (e.g., RHR isolation valves).

d. The following schematic and wiring diagrams were reviewed:

(1) H21-P623 Dedicated Remote Shutdown (3L) Panel. Drawings 61721-2782-1, Revision 0, 61721-2783-1, Revision 0, 61721F-2592-2, Revision 0, 01721F-2592-3, Revision 0 (2) EF1-EF2 Supervisory Control Panels, "3L" System Remote. Drawings 6SD721F-150, Revision 0, 6SD721-163, Revision 0, 6SD721-166, Revision 0, 6SD721-164, Revision 0, 6SD721-165, Revision 0 (3) H21-P625 Dedicated Local Control Panel, Transfer Control from MCC 72C-3A Drawings 61721-2201-78, Revision 0, 61721-2201-75, Revision 0 (4) H21-P626 Dedicated Local Control Panel, Transfer Control from MCC 728-3A Drawings 61721-2201-71, Revision 0, 61721-2201-79, Revision 0 (5) H21-P627 Dedicated Local Control Panel, Transfer Control from MCC MCC 72C-F Drawings 61721-2201-81, Revision 0, 61721-2201-80, Revision 0 (6) N21083-F001 Standby Feedwater Isolation Valve Motor Operator (MO) Drawing 6I721-2317-28, Revision 0 (7) N2103-F002 Standby Feedwater Control Valve M0 Drawing 61721-2317-29, Revision 0 7

l l l (8) N2103-F003 Standby Feedwater Flow Control Valve M0 Drawing 61721-2317-30, Revision 0 , (9) Dedicated Shutdown System Diagram 61721-2784-7, Revised June 6, 1985 , (10) One line diagram, Plant 4160V and 480V System Service Drawing 6SD721-2500-1, Revision 1 l

(11) 4160V, Bus 65W Incoming Breaker Drawings 61721-2311-40, Revision A 6SD721-2501-81, Revision A (12) 4160V, Bus 64V Incoming Breaker Drawings 61721-2311-39 Revision A 6D721-2501-85, Revision B 61721-2315-8, Revision A (13) 4160V, Bus 64V, 65W Tie Breaker, Pos V3 Drawings 61721-2311-41, Revision 0 6SD721-2501-83, Revision A ,

(14) N2103-C001 Standby Feedwater System Pump A, Bus 64V Drawings 61721-2311-35, Revision 0 6SD721-2501-82, Revision A l (15) N2103-C002 Standby Feedwater System Pump B. Bus 65W Drawings 61721-2311-36, Revision 0 6SD721-2501-84, Revision 0

e. Electrical Isolation - Connon Bus, Common Enclosure, and Spurious Operation Concerns CTG No.11 and the Standby Feedwater System are dedicated systems The that are electrically)

         "3L" (remote           shutdownindependent          of the fire panel No. H21-P623,       asareas well asofthe concern.

4160V switchgear for buses No. 64V and 65W are physically located in the radwaste building outside the fire areas of concern. According to

the licensee, all controls and instrumentation circuits for the "3L" panel are provided with dedicated transmitters that will not be affected by a fire in the areas of concern.

For example, for a fire in the control room, supervisory switch l No. EF1 on panel No. H21-P623 (3L panel) can be placed in the local position. This allows a signal to be transmitted using the tone i signal generator inmodem in the supervisory control panel to initiate i starting of CTG No. 11. By placing the system transfer switch No. EF2 on the "3L" panel to the local position, dedicated relays in 4160 volt switchgear in conjunction with controls at the "3L"

panel, allow for remote operation of the Standby Feedwater System and associated valves that provide a flow path for reactor' coolant makeup from the condensate storage tank. Control circuits for the l standby feedwater pumps and valve motor operators have been modified i in accordance with Engineering Design Packages (EDPs) No. 1701 and 8

l l l l l I 1702, Revision 0. Fuses and control swit:hes have been added to , these circuits in order to isolate them from damage resulting from ,1 fires in the areas of concern. /l The circuitry to standby feedwater pump No. AN2103C001 (drawing No. 61721-2311-35, Revision 0), was modified to add new 50 Amp and 30 Amp fuses, and Relays No. 43X/K1V2 and 43X/K2V2 in the 4160 volt switchgear. This permits isolation of circuits in the control room by transferring Switch No. EF2 on the "3L" panel to the local position. When in the local position, Switch No. EF2 on the "3L" panel transfers power and control of Standby Feedwater rump No.- A l and its associated valves to a separate circuit that is electrically i isolated from the fire areas of concern. Panel No. H21-P623 also provided breaker control for offsite 120KV power breakers GM, GK, GH, and GD, as well as controls for CTG 11 and associated breakers which provide a dedicated source of power ! for buses 64C, 64Y, and 64W and associated shutdown equipment during j a fire in the referenced fire areas. In the event of a fire in panel No. H21-P623,120KV breaker control could be lost. However, according to the licensee, this power source can be retained at the

;      control room, or another 345KV offsite power source can be used for control of breakers from the control room. All other controls on the dedicated shutdown panel No. H21-P623, including SBFW pumps, safety l

relief valves, and instrumentation, could be lost at the "3L" panel without adversely affecting safe shutdown from the control room. In this case, safety-related Division I and II ECCS would still be

,       available.

The circuitry for local control panel Nos. H21-P626 and H21-P627 was also reviewed. Both panels were found to have appropriate isolation through fuses, relays, and transfer switches so that RHR loads on MCC No. 72C-F and MCC No. 72B-3A can be transferred to separate 1 circuits that are electrically independent of the fire areas of concern.  : l By placing all transfer switches on local control panel No. H21-P627 in the local position, controls for RHR Loop A and B discharge and l isolation valve Nos. E11-F010, F015A, and F017A are isolated from the control room. Transfer switches No. 435-3A and 435-2C allow for

control of the isolation valves through a new set of fuses and l contacts that are independent of the fire areas of concern.

' The licensee indicated that similar modifications have been completed for all the circuitry to the systems and components that are included j in the independent alternative shutdown system.

f. Cable Separation Division 11 Remote Shutdown Panel l By letter dated November 27, 1986 (VP-85-0215, W. Jens - DECO to

B. J. Youngblood - NRC), the licensee informed the NRC that Detroit

Edison has decided not to electrically disable the Division II remote I shutdown panel until completion of the installation of the "3L" panel l system. Detroit Edison connitted to disable the Division 11 remote 9 . .

i o shutdown panel in order to resolve NRC concerns about Class IE and non-class IE interfaces in the panel. This comitment was sede in the licensee letter No. VP-85-0132 dated June 5, 1985 in response to Region III Inspection Report No. 50-341/85009. According to License Condition No. 2.c.(9)(d) of Facility Operating License No. NPF-33, the "3L" panel must be operational prior to  ! startup after the present outage. Therefore, the licensee has , inferred that the Division II remote shutdown panel will be electri- l cally disabled prior to startup from th( present outage. ThisisanOpenItem(341/85050-02) pending verification by Region III prior to startup from the current outage.

g. Cable Separation Independent Alternative Shutdown ("3L") Panel

!                                    During their review the licensee identified three electrical cable feeds used in the independent alternative shutdown system that are routed through the fire areas of concern for which the shutdown system is provided. A fire in these areas could disable normal shutdown systems as well as the independent alternative shutdown system. This is in conflict with commitments made to the NRC by the licensee in Correspondence No. EF2-72001, dated October 22, 1984 (W. Jens - DECO l                                   to B. J. Youngblood - NRC).
                                    'The following cables are routed through the fire areas of concern:

(1) Electrical feed cable No. R.I. 005 2P, supplying power to distribution cabinet No. ZPB-2, which supplies power to safety relief valve (SRV) No. F013G solenoid (enabling control of the

   .                                       SRV from the independent alternative shutdown panel), is routed
,                                          into Fire Zone 8 at the 631 foot elevation of the auxiliary building. This cable originates at the Division 11 battery room, passes through Fire Zone 8 of the auxiliary building and
;                                          terminates at the ZPB-2 distribution cabinet.

To correct this condition, the licensee installed a 3H brand 1 one-hour fire barrier wrap on this cable throughout its exposure to Fire Zone 8. Fire Zone 8 is protected by an automatic carbon . dioxide fire suppression system and automatic fire detectors. Th'e inspectors informed the licensee that the corrective actions taken for this condition were found to be in conformance with Section III.G.2.c of Appendix R to 10 CFR 50. However, the condition and corrective actions taken must be formally submitted by the licensee to NRR for acceptance. i Thisisconsideredanopenitem(341/85050-03) pending

• verification of NRR acceptance of the licensee's corrective actions prior to startup from the current outage.

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        '(2) Calvert Bus Additionally, the 4160 volt feed between the Division 1 Switchgear Room Buses and the Radwaste Switchgear Room Buses              +

was found to be routed through the cable area at the 603'-6" level of the Auxiliary Building. This location is one of the fire areas of co.icern. The 4160 volt feed is also known as the Calvert Bus and is part of the power supply for the Appendix R Dedicated Shutdown System (3L). The inspectors verified the Calvert Bus location visually and by reviewing the drawings 6E721-2988-1 through 5.

>              Because the Calvert Bus is unprotected, a fire in the Auxiliary Building Fire Zone 2 could cause the loss of power to the SBFW pumps as well as the loss of normal shutdown systems. To correct this condition, the licensee has proposed wrapping all the divisional power, instrumentation, and control cables in the Fire Zone 2 in a 3M brand one-hour firewrap material. By wrapping the Divisional cables, the licensee's intent is to meet                        '

the requirement of Appendix R SectionIII.G.2 in this zone. i This zone is provided with an automatic suppression system and fire detection. The inspectors infonned the licensee that the proposed corrective actions for this condition deviates from a previous comitment to confonn to Section 3.L of Appendix R in this zone. Therefore, acceptability of the resolution to this condition must be pursued with NRR. Thisisconsideredanopenitem(341/85050-04) pendipg verifica-tion of NRR's acceptance of the licensee's corrective actions prior to startup from the current outage. (3) Reactor pressure, reactor level, torus temperature, torus level ar.d EECW instrumentation cables for the independent elternative shutdown panel are routed in Fire Zone 1 at the 551 to 562 foot elevation of the Auxiliary Building (basement). Some cables in this zone are partially wrapoed in 3M brand one-hour fire barrier material. This zone is protected by an automatic sprinkler system and automatic fire detectors. According to the licensee, corrective actions taken for these conditions will be in confonnance to Section III.G.3 of Appendix R to 10 CFR 50. The inspectors informed the licensee that the corrective actions taken for these conditions must be fonnally submitted by the licensee to NRR for acceptance. This is considered an open item (341/85050-05) pending verification of NRR acceptance of the licensee's corrective actions by Region III prior to startup from the current outage. 6 11 ,

i i (4) Spurious Operation of Various Valves 4 1 Supplement No. 5 of the SER described spurious operation of various valves in the RHR and HPCI systems from multiple hot , shorts. As resolution, the SER required power be removed from one or two of the RHR suction isolation valves and the test return valve from the RCIC and HPCI systems to the CST. The l inspectors reviewed the following procedures and documents, ' and verified that the licensee's actions are in agreement with the SER: 23.202, Revision 8 "High Pressure Coolant Injection System (HPCI)." 23.205, Revision 6. " Residual Heat Removal System (RHR)."

    -                   Engineering Design Package (EDP) - 4200, Revision A.
                        " Restoration of Valve Position Indication During Circuit De-energization for E1150-F008 and E4150-F011."

No violations or deviations were identified.

7. Supplemental Procedures Developed to Implement the Independent Alternative Shutdown System

a. Methodology The inspectors reviewed the abnormal operation procedure 20.000.18

                " Control of the Plant From the Dedicated Shutdown Panel", and determined that, initially, the procedure did not meet the intent of Supplement No. 5 of the SER in that a 10 minute assessment period was included in the issnediate operator actions section of the procedure. The above methodology us included in the licensee's response EF2-72001 to Mr. B.J. Youngblood (Division of Licensing, NRC) dated October 22, 1984 but was not included in the supplement to the SER. The purpose of the 10 minute assessment was to evaluate if the fire was extinguished or not and what actions to take. However,    ,

Appendix R and the SER do not allow for a delay in actions based on i time to extinguish the fire but require imediate actions to control the plant and to achieve Hot Standby. The licensee agreed and revised the procedure by removing the 10 minute assessment methodology and required issnediate actions to control the plant in Hot Standby and to achieve Cold Shutdown as required by Appendix R. In addition to the above methodology, the inspectors verified that the remainder of the procedure did agree with Appendix R and the supplement to the SER in that the reactor is scramed, reactor vessel level and pressure control is assured at the remote shutdown panel by using Standby Feedwater (SBFW) and the dedicated Safety Relief Valve (SRV),

electrical loads are stripped and the dedicated safe shutdown loads for Hot Standby are restored by supplying the dedicated buses from i CTG-11-1, and that primary containment torus and long-term shutdown 1

cooling are lined up. l 12

b. Walkdown The inspectors witnessed a walkdown of the procedure by two operators.

During the walkdown the inspectors verified the locations of the local panels, availability of procedures at the local panels, and the i methodology of the revised procedures. However, two open inspection

'            items wre identified: due to locations, time required, and com-plexity of the operator actions at the local panels, the evolutions require three operators - one operator to control. reactor vessel           l pressure and level at the Remote Shutdown Panel and two operators           i perfoming the local lineups. The procedure currently requires only two operators, one at the Remote Shutdown Panel and one perfonning the local operations. The licensee comitted to include instructions in the operator's night-order book or the procedure to utilize two operators for the local operations. This is an open item (341/85050-06) until the licensee's comitment is verified. In addition to the manpower requirement above, comunication is also identified as an open inspection item (341/85050-07) in that due to the distance and time requirements of the evolutions, portable radios are needed to assure the completion of the local operations. The licensee has committed to provide portable radios at the Remote Shutdown Panel for use by the two operators perfonning the local operations.

The inspectors reviewed the comunication survey and verified that at all local panel and operation locations, good radio reception is achievable.

c. Training The inspectors attended one training session on the abnonnal operation procedure 20.000.18 and found it to be satisfactory.

The training included the details of the procedure, methodology, and a walkdown in the plant with hands-on demonstration. In addition, the licensee has scheduled retraining by operator shifts to ensure that familiarity is maintained as part of the operator's retraining and certification program. No violations or deviations were identified.

8. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspectors, and which involve some action on the part of the NRC, the licensee, or both. Open items disclosed during the inspection are discussed in Paragraphs 4, 6.f. 6.g.(1),

6.g.(2), 6.g.(3), and 7.b. These items are required to be resolved prior to startup from the current outage. 13

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9. Exit Interview The inspectors met with the licensee representatives at the conclusion I of the inspection on December 6,1985, and sunr.arized the scope and findings of the inspection. The licensee acknowledged the statements made by the inspectors. The inspectors also discussed the likely infor-mational content of the inspection report with regard to documents reviewed by the inspectors during the inspection. The licensee did not identify any such documents as proprietary. On December 18, 1985, in a telephone conversation with the licensee, additional concerns regarding associated circuits for the independent alternative shutdown system ,

were discussed with the licensee. u_ _ _. f I 14

ENCLOSURE 10.A DEC 181985 Docket No. 50-341 The Detroit Edison Company ATTN: Wayne H. Jens Vice President Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 Gentlemen: This refers to the special safety inspection conducted by Mr. Roger Smeenge of this office on December 4-6, 1985, of activities at Enrico Fermi Nuclear Power 1 Plant authorized by NRC Operating License No. NPF-33 and to the discussion of cur findings with Mr. L. Simpkin and others of your staff at the conclusion of i.he inspection. The enclosed copy of our inspection report identifies areas examined during the inspection. Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel. 4 No violations of NRC requirements were identified during the course of this inspection. In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosed inspection report will be placed in the NRC Public Document Room. We will gladly discuss any questions you have concerning this inspection. Sincerely,

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Original Signed by J. J. H u f1502 J. J. Harrison, Chief Engineering Branch i

Enclosure:

Inspection Report No. 50-341/85051(DRS) See Attached Distribution () -{000/ I RIII / p< AIII R4 K Snee ge/1d Williams )' r d t H$r ison I (1.ll6 l w.

The Detroit Edison Company 2 DEC 181985 Distribution cc-w/ enclosure: L. P. Bregni, Licensing Engineer P. A. Marquardt, Corporate Legal Department DCS/RSB (RIDS) Licensing Fee Management Branch Resident Inspector, RIII Ronald Callen, Michigan Public Service Commission Harry H. Voigt, Esq. Nuclear Facilities and Environmental Monitoring

• Section Monroe County Office of Civil Preparedness 7

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l U.S. NUCLEAR REGULATORY COPHISSION REGION III Report No. 50-341/85051(DRS) Docket No. 50-341 License No. NPF-33 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48224 Facility Name: Enrico Fermi Nuclear Power Plant, Unit 2 Inspection At: Enrico Fermi 2 Site, Monroe, MI ~ Inspection Conducted: December 4-6, 1985 Inspector: Ro Smeenge /J//#/PI y Date' 31 l gh@V Approved By: . C. Williams, Chief - Plant Systems Section Date Inspection Summary Inspection on December 4-6, 1985 (Report No. 50-341/85051(DRS)) Areas Inspected: Special unannounced inspection of licensee actions on work being performed in regards to the environmental qualification requirements of 10 CFR 50.49. The inspection involved a total of 23 inspector-hours onsite by cne regional inspector. R2sults: Of the areas inspected, no violations or deviations were identified. I l 0 ,

1 DETAILS

1. Persons Contacted Detroit Edison Company

              *L. Simpkin, General Supervisor, Q/E
              *Q. Duong, Supervisor, EQ
              *J. Conen, Licensing Engineer

• P. Pierron, EQ Engineer L. Raisanes, EQ Engineer C. Emanuele, Materials Engineering Group J. Nanka, Materials Engineering Group NRC P. Byron, Senior Resident Inspector

              *M. Parker, Resident Inspector

• Identifies those persons who attended the exit meeting on December 6, 1985.

2. Inspection Details

a. Documents Reviewed The inspector reviewed the following documents which currently implement the licensee's program for review and approval of work performed and procurement of Environmentally Qualified (EQ) equipment:

(1) NE-1.16.1, "The Engineering Evaluation of Stock and Non-Stock Items and Services," Revision 0, dated April 26, 1985 (2) NE-3.9, " Preparation, Review and Approval of Engineering Design Packages (EDPs)," Revision 4, dated August 30, 1985 i (3) NOP-103, " Nuclear Safety Review Program," Revision 0, dated November 19, 1985 (4) Procedure 7.2, "Q-List," Revision 1, dated August 6, 1985 (5) Procedure 7.7, " Overview of the Environmental Qualification Program," Revision 0, dated June 6, 1985 (6) Policy Letter EF2-68,607, " Equipment Qualification kequirements for QA-1 Electrical Spare / Replacement Parts," dated January 11, 1985 ( (7) " Environmental Qualification of Safety Related Electric Equipment for Harsh Environments" (specific equipment qualification summaries) 2

b. Engineering Design Packages At the time of this inspection, the licensee was performing a review of 273 Engineering Design Packages (EDPs) which were associated with the plant 21 safety-related systems that contain EQ equipment. This review was initiated by the licensee EQ group to ensure that all EDPs, issued to date, regarding EQ equipment had received the required reviews. The NRC inspector monitored this licensee review and was appraised of progress throughout the course of this inspection.

Prior to the exit meeting on December 6, 1985, the licensee had completed their review. Of the 273 EDPs reviewed by the licensee, 180 were identified as not requiring EQ review due to the following: 20 were cancelled, 106 were nonsafety related applications, 53 were for equipment that was not required to operate in an accident environment, and 1 was combined with another EDP. Of the 93 remaining,

                                                                                                   )

48 were completed EDPs with evidence of the required EQ review and 45 were not yet issued or required beyond a Potential Design Change (PCD). The inspector reviewed seven completed EDPs for EQ equipment. One EDP reviewed, relocated a transmitter from a harsh to mild environment and the other six replaced unqualified equipment, located in a harsh environmeni., with qualified equipment. The seven packages had documented reviews by the QE group and sign off by Quality Assurance (QA) for hold points and completed work.

c. Purchase Requisitions Reviewed The NRC inspector reviewed ten purchase requisitions for equipment identified on the Q-List (identifies plant safety-related equipment).

The nine which required EQ had been reviewed by the licensee and the EQ requirements identified on the associated equipment qualification summaries sheets were included in the purchase requisitions. Replacement equipment which had initially been qualified to NUREG-0588, Category II was upgraded to Category I as required by 10 CFR 50.49.

3. Inspection Results In this limited scope EQ inspection no violations or deviations were identified. A more detailed EQ inspection is scheduled for mid-1986.

l l 4. Exit Interview The inspector met with the licensee representatives (denoted in Persons Contacted) at the conclusions of the inspection on December 6, 1985. The inspector summarized the purpose and findings of the inspection, which were acknowledged by the licensee. The inspector also discussed the likely informational content of the inspection report with regard to , documents or processes reviewed by the inspector during the inspection. l The licensee did not identify any such documents / processes as proprietary. l 3 __- . . _ _ __ a -_.. _ _ _ _ _ . . _ _ . _

ENCLOSURE 16.N [ '

             ~g                            UNITED STATES NUCLEAR REGULATORY COMMISSION

[ , j t a REGION lil g / 7senoostvtLT noap g aLa= a Lov=. n.uevois som o o. .. / Docket No. 50-341  ; The Detroit Edison Company ATTN: Wayne H. Jens Vice President Nuclear Operations 6400 North Dixie Highway Newport, MI 48166 Gentlemen: This refers to the special safety inspection conducted during the period of July 1 through October 15, 1985, of activities at Fenni 2 authorized by NRC operating License No. NpF-43. The results of this inspection were discussed during management meetings in Glen Ellyn, Illinois, on July 23, 1985 and on September 10, 1985. We are releasing this report at this time for your information. You will be notified by separate correspondence of our decision regaroir.g enforcement action based on the findings of this inspection. No written response is required until you are notified of the proposed enforcement action. In accordance with 10 CFR 2.790 of the Comission's regulations, a copy of this letter and the enclosures will be placed in the NRC's Public Document Room. We will gladly discuss any questions you have concerning this inspection. Sincerely, fwg4 MA Charles E. Norelius, Director Division of Reactor Projects

Enclosures:

1. Inspection Report No.

50-341/85040(DRP)

2. Ltr Jens to Keppler dtd 10/10/85 See Attached Distribution 1

The Detroit Edison Company 2 Distribution cc w/ enclosures: L. P. Bregni, Licensing Engineer . P. A. Marquardt, Corporate Legal Department DCS/RSE (RIDS) Licensing Fee Management Branch Resident Inspector, RIII i Ronald Callen, Michigan Public Service Commission Harry H. Voigt, Esq. Nuclear Facilities and Environmental Monitoring Section Monroe County Office of Civil Preparedness I i

U.S. NUCLEAR REGULATORY COMMISSION REGION III Report No. 50-341/85040(DRP) Docket No. 50-341 License No. NPF-43

                                                                                                                                                                      ]

Licensee: Detroit Edison Company 2000 Second Avenue - Detroit, MI 48226 . Facility Name: Fermi 2 l

!          Inspection At:              Fermi Site, Newpor+, MI Inspection Conducted: July 1 through October 15, 1985 Management Meetings At: Glen Ellyn, Illinois on July 23 and September 10, 1985 Inspectors:          P. M. Byron M. E. Parker D. C. Jones i           Approved By:              .       .         right, Chief                                                                                    /h/    W Projects Section 2C                                                                                                 Date Inspection Summary l             Inspection on July 1 through October 15, 1985, and Management Meetings on July 23 and September 10, 1985 (Report No. 50-341/85040(DRP))

- Areas Inspected: Special, unannounced inspection by resident inspectors of activities surrounding the out-of-sequence rod pull, the control room HVAC, the RCIC/ core spray room cooler, the cooling tower bypass valve, the hydrogen recombiner and the breach of primary containment integrity. The inspection involved a total of 246 inspector-hours onsite by three inspectors including ~; 77 hours onsite during off-shifts. The Management Meetings involved a total of 153 hours by 26 NRC personnel. Results: Twenty-six violations (including examples) were identified (seven - Limiting Condition for Operations and nineteen - Procedural). i . l y '5 9 l'? ' uW r

! DETAILS

1. Attendees

a. Persons Attending Management Meeting on July 23, 1985 Deco

!                C. M. Heidel, President W. H. Jens, Vice-President, Nuclear Operations R. S. Lenart, Assistant Manager, Nuclear Production A. Wegele, Compliance Engineer D. A. Aniol, Nuclear Shift Supervisor G. R. Overbeck, Superintendent, Operations P. A. Marquardt, General Attorney L. C. Lessor, Advisor, Management Analysis Co.

Public B. Campball, Reporter, Detroit Free Press NRC HQ's E. Jordon, Director, Division of EP B. J. Youngblood, NRR Licensing Chief, Branch No.1 M. D. Lynch, NRR Licensing Project Manager NRC RIII a J. G. Keppler, Regional Administrator C. J. Paperiello, Director, Division of Reactor Safety E. Greenman, Deputy Director, Division of Reactor Projects N. J. Chrissotipos, Chief, Branch 2 DRP L. A. Reyes, Chief, Operations Branch, DRS j G. C. Wright, Chief Section 2C, DRP P. M. Byron, SRI, Fermi 2 T. E. Lang, Operater Licensing B. Stapleton, Enforcement Specialist W. H. Schultz, Enforcement Coordinator

5. Stasek, Project Inspector, Fermi R. B. Landsman, Project Manager, Section 2C, DRP

5. G. DuPont, Reactor Inspector R. D. Lanksbury, Reactor Inspector l

1

b. Persons Attending Managenent Meeting on September 10, 1985 Deco C. M. Heidel, President W. H. Jens Vice-President, Nuclear Operations R. S. Lenart, Assistant Manager, Nuclear Production T. Randazzo, Director, Regulatory Affairs E. P. Griffing, Assistant Manager, Regulatory Compliance L. C. Lessor, Advisor, Management Analysis Co.

Wolverine Power Supply C. Borr, Member, Services Coordinator J. Gore, Consultant Public T. Lam, Reporter, Ann Arbor News S. Benkelman, Reporter, The Detroit News B. Campball, Reporter. Detroit Free Press M. Johnston, Member Safe Energy Coalition of Michigan J. Puntennery, Director, Safe Energy Coalition of Michigan i F. Kuron, Monroe County Commissioner J. Eckert, Director Office of Civil Preparedness NRC HQ's M. D. Lynch, NRR Licensing Project Manager L. P. Crocker, NRR Licensing Section Chief, Quality Branch NRC RIII J. G. Keppler, Regional Administrator A. B. Davis, Deputy Regional Administrator C. E. Norelius, Director, Division of Reactor Projects E. Greennan, Deputy Director, Division of Reactor Projects G. C. Wright, Chief. Section 2C, DRP P. M. Byron, SRI, Fermi 2 B. W. Stapleton, Enforcement Specialist J. Strasma, Public Affairs Officer R. Lickus, Chief, State of Government Affairs , J. A. Hind Director, Division of Radiation Safety and Safeguards I W. D. Shafer, Branch Chief. Emergency Preparedness and Radiological Protection R. B. Landsman, Project Manager, Section 2C, DRP C. H. Weil, Compliance Specialist i T. E. Lang, Operator Licensing L. Dimmock, Operator Licensing , I I 3 _ _ _. _. ~ _.

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2. Out-of-Sequence Rod Pull While withdrawing control rods to achieve criticality on July 1, 1985, the Nuclear Supervising Operator (N50) pulled eleven control rods in Group 3 to position 48 rather than position 04 as required by the control rod pull sheets.

The afternoon shift N50 had started pulling control rods around 10:21 p.m. EDT on July 1, 1985, and completed pulling control rods through step 37 at 11:15 p.m. EDT. The night shift N50 started to pull rods at step % one minute and eleven seconds later. The night shift N50 had observed the off going N50 for a period of time before taking the controls. The nightshift N50 utilized a Shift Technical Advisor in Training (STAIT) to monitor the Source Range Monitor (SRM) instrumentation to facilitate the rod pull rather than perform that function himself. The N50 completed pulling rods in Group 2 and then commenced pulling rods in Group 3 (step 46). Starting with step 46 and for the next 10 steps the N50 pulled each control rod to the full out position (48) rather than position 04 as required by the procedure. The N50 verified by his initials, on the rod pull sheet, that each of the eleven control rods was at position 04 when in fact they were at position 48. While pulling the eleventh control rod in Group 3 (control rod 18-51), the Short Period Alarm annunciated five times and the pen for the Channel A SRM recorder failed to ink for about three minutes. When the pen started inking again the NSO and STAIT observed that recorder was reading approximately 5x103 counts per second and increasing. The Shift Reactor Engineer (SRE) had predicted that criticality should occur

  <       between steps 150 and 160, when the N50 observed the increasing count rate he was only on step 56. The NSO instructed the STAIT to inform the Nuclear Shift Supervisor (NSS) of the situation and immediately started to insert rod 18-51. It took 14 minutes and 41 seconds to insert all eleven control rods to position 04. Thirty-five (35) seconds later the N50 continued the startup by pulling rods from step 57 of the procedure.

During the control rod pulls the NSS and the Nuclear Assistant Shift Supervisor-(NASS) were in the NSS's office. The SRE was behind the panels 4 and could not observe the rod pulls. The N50 in charge of the control room was at his desk facing the panels and the Shift Technical Advisor (STA) and the Shift Operations Advisor (50A) were by the N50's desk. Neither the N50 in charge, the SOA, nor the STA were observing the rod pull nor were they aware of the incident. The STAIT informed the SRE of the event who wrote in his log that the reactor may have been critical. 1 The NSS reviewed the event with the N50 (at the controls) and the STAIT and determined that the reactor had not gone critical. The NSS then directed that rod pulling recommence. The NSS apparently did not seek the advice or counsel of the SRE, the SOA, or the STA. The SRE also lined out in his log book the reference of the unit being critical. Neither the NSS nor the NSO logs contained an entry regarding the

       -   -.            - _ - _ _ .        _ _-       M 4.    . _ _ _      _                  __ _

1 i out-of-sequence rod pull. The NSS, however, did write a Deviation / Event Report (DER) (No. NP-85-0334) describing the event and stated that the reactor had not gone critical.

DER No. NP-85-0334 was reviewed by the licensee's Corrective Action l Review Board (CARB) on July 2, 1985, who concurred with the NSS's

;         determination that the incident was not reportable under either 10 CFR l          50.72 or 50.73. It appeared that there was disagreement within the

! licensee's organization as to whether or not the reactor had been critical. i The licensee directed that additional engineering review be made. The licensee informed the Resident Inspector (RI) of the event on July 3, 1985, and stated that the unit had not gone critical but that there was a question among the staff and that Reactor Engineering was performing a ,

technical review. The licensee stated that they would get back to the j RI when the determination had been made. The RI informed RIII of his i meeting.

H A SRE made the determination on July 4, 1985 that the reactor had been critical on July 1,1985, with a 114 second period and informed his management of the determination. Several licensee meetings were held on July 5 and 6, 1985 to discuss this event and to initiate an investigation

into its cause.

l The next discussion with the NRC' resident staff, after July 3, 1985, ! was on July 15, 1985, when the Senior Resident Inspector (SRI) ! was asked by licensee management if he was aware of the July 1, 1985 i incident and that the reactor had been critical. The SRI was aware of

the out-of-sequence rod pull but was not aware that the reactor had i been critical. The SRI informed RIII of the meeting, and the new information on criticality.

!          Region III issued a Confirmatory Action Letter (CAL-RIII-85-10) to the

licensee on July 16, 1985. The CAL detailed the corrective action the licensee was to take relating to the out-of-sequence rod pull. The i CV. is oeisiled in Inspection Report 50-341/85043(DRP). The licensee 1 made a presentation in Region III on July 23, 1985, regarding their corrective action program and findings related to the event which is

described in Paragraph 9 of this report. The licensee's presentation i is included as an attachment to their response to the CAL, DECO letter RC-LG-85-0017 (Jens to Keppler), dated September 5, 1985.

1 i During the inspection and review of the event, nine examples of apparent 4 violations of Technical Specification requirements were identified and are j as follows: ! Technical Specification 6.8.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable f procedure recommendations of Appendix A of Regulatory Guide 1.33,

!           Revision 2, 1978. Appendix A of Regulatory Guide 1.33 lists the j            following activities under Administrative procedures:

l 5

i i i I ! - Hot Standby to Minimum Load (Nuclear Startup)

                     -      Authorities and Responsibilities for Safe Operation...
                     -      Equipment Control i                     -      Shift and Relief Turnovers
                     -      Log Entries i

Contrary to the above. -the licensee failed to adhere to the provisions of Technical Specification 6.8.1.a covering the startup of the reactor on , July 1, 1985, as indicated below: *

a. POM Procedure 51.000.08, " Control Rod Sequence and Movement Control," paragraph 3.1.1, requires that rod withdrawals in the

, region from 100% Rod Density to 201 Reactor Power must be

performed according to the rod pull sheet. The. rod pull sheets in effect on July 1,1985, required the rods for Group 3 to be pulled in notch control (00-04, 04-08, etc.). The licensee 3

pulled eleven control rods in Group 3 to the full out position ] (48) rather than to the 04 position as required (341/85040-01a).

b. POM Procedure 51.000.08, Paragraph 3.1.4 states, in part, "Following each rod move the Nuclear Supervising Operator (NS0) shall verify the control rod was left in the proper position indicated and shall document this verification by initialing the ' Final Position Verified' block of Attachment 1." The NSO verified eleven rods to

be at position D4, by initialing the pull sheet, when in actuality they were at position 48 (341/85040-Olb).

+

c. POM Procedures 12.000.57, " Nuclear Production Organization" and

! 21.000.01 " Shift Operation and Control Room" delineate the l responsibilities of the NSS to include supervision of all l activities and observation and/or direction of major plant i evolutions to ensure compliance with Technical Specifications, i procedures, and regulations. The NSS did not appropriately i discharge his duties on Julv L and 2, 1985, in that he neither ! supervised, observed, nor diccted the activities. associated j with the control rod pulls (a major plant evaluation) nor was i he in the proximity of the appropriate control panel and j associated neclear instrumentation (341/85040-01c). ! d. POM Procedure 21.000.01, Enclosure 1, Item 12, requires the Nuclear i Assistant Shi"t Supervisor (NASS) to provide direct supervision of shift personn:1. The NASS did not provide direct supervision of the 1

NSP manipulating the controls on July 1 and 2, 1985 nor was he in j the proximity of the appropriate control panel and associated l nuclearinstrumentation(341/85040-01d). I

e. POM Procedure 21.000.01, Enclosure 2, Item 5 requires the N50 to be responsible for the plant's main control room operation.

, The control room NSO was unaware of the out-of-sequence rod 4 pull and thus was not successfully discharging his duties (341/85040-01e). 1 i I 6 I

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f. POM Procedure 21.000.01, Enclosure 6, Item 2, requires the Shif t Operations Advisor (SOA) observe actuation of annunciators to ensure 1 that they are being promptly and properly addressed with actions

, taken. Five short period alarms were received in less than four

minutes while pulling rod 18-51 on July 1,1965. The NSO at the i i controls was allowed to continue pulling rods and the SOA did not  !

I dischargt his responsibilities by failing to become involved in the

!                        resolution of the short period alarms (341/85040-01f).

g. POM Procedure 21.000.02, " Operating Logs and Records," Section 4.2.5.8, requires the NSS to record the occurrence of significant j events in the NSS log. The NSS log for July 1, and 2, 1985, contained no entries for the out-of-sequence rod pulls, a significant event, which occurred between 11:40 and 11:59 p.m.

on July 1, 1985 (341/85040-019).

h. POM Frocedure 21.000.01, " Shift Operation and Control Room," Section 6.3.8 states, " Reactor Engineering Administrative Procedure No.

51.000.10, ' Reactor Engineering Conduct of Operations,' details the duties and responsibilities of on-shift Reactor Engineering personnel." Procedure 51.000.10, Section 1.0, states, "The purpose of this procedure is to outline operational interfaces between Reactor 4 Engineering and Plant Operations and to clarify the overall responsi-l bilities of on-shift Reactor Engineering personnel." Procedure 51.000.10 does not detail the duties and responsibilities of the on-shift ReactorEngineer(341/85040-01h).

i. POM Procedure 21.000.01, Section 6.8 addresses shift relief and Section 6.8.4 specifically addresses the control room nuclear supervising operator (NS0). The procedure defines the required turnover for the NSO in charge of the control room but does not i define any turnover requirements for the NSO assigned to duties in the control room but not in charge of the control room (341/85040-011).

!               3. Control Room HVAC On July 11, 1985 PN-21 No. 286934 was issued to inspect the Division II Control Room HVAC condensate tray. For personnel protection the Division II Control Poom HVAC supply fan control switch was placed in the off position at 8:35 a.m. on July 18, 1985 and the feeder break was opened and red

' tagged at 8:50 a.m. The Nuclear Supervising Operator (NS0) entered the action in his log but did not list the Technical Specification applicability.

The NSO also entered the action in the Control Room Information System (CRIS) equipment status file and placed the applicable CRIS dot next to the switch on the panel. The NSO also advised the protection leader that protection had to be removed by 3:00 p.m. on July 25, 1985, however, the NSO failed to notify the NSS of the change in equipment status. Neither the NSS log nor the out-of-specification log contain any entries on the inoperable Division II HVAC. The work was completed and the request to 7

remove protection was made at 1:20 p.m. on July 18, 1985. However, the package was misfiled in the " active" file rather than the " protection to be cleared" file. The out-of-specification condition went unnoticed for 27 shift turnovers by the oncoming NSS, NASS, and NS0's even though the switch was marked, a log entry had been made, and it was entered in the CRIS equipment status file. It was not until July 27, 1985 that a nightshift NSS questioned the status of the Division II Control Room HVAC fan and had the fan returned to service at 5:38 a.m. on July 27, 1985. During the inspection and review of the event, two apparent violations of Technical Specification requirements were identified as follows:

a. Technical Specification 3.7.2.C.1 requires that with the control center emergency filtration system supply fan inoperable, with the plant in cold shutdown, the fan be made operable in seven days or initiate and maintain operation of the system in the recirculation mode of operation.

Contrary to the above, the licensee failed to place the control room emergency filtration system in the recirculation mode of operation on July 25, 1985; seven days after the system was i rendered inoperable on July 18, 1985. This condition existed i for approximately forty-five (45) hours (341/85040-02).

b. Technical Specification 6.8.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedure recomendations of Appendix A of Regulatory Guide 1.33 Revision 2, 1978. Appendix A of Regulatory Guide 1.33 lists the following activities under Administrative Procedures:

Authorities and Responsibilities for Safe Operation...

            -    Equipment Control Shift and Relief Turnovers Log Entries...

Contrary to the above, the licensee failed to adhere to the provisions of Technical Specification 6.8.1.a as follows: (1) POM Procedure 21.000.01, " Shift Operations and Control Room," delineates the shift turnover responsibilities of the Nuclear Shift Supervisor (NSS) the Nuclear Assistant Sh'ift Supervisor (NASS) and the Nuclear Station Operator (NS0). Included in the responsibilities is a review of past log entries, and a review of each Combination Operating Panel for off-nonnal conditions or the addition of CRIS " dots." The NSS, NASS, and NSO all failed to adequately perfonn the required activities as indicated below (341/85040-03a): i 8

(a) The Control Center Division II HVAC supply fan switch was placed in the off position on July 18, 1985, and not observed to be out of position until July 27, 1985. The out-of-specification switch position went unobserved for 27 shift turnovers. (b) The NSO entered the switch position in the equipment status file and placed a CRIS " dot" by the switch on July 18, 1985. The CRIS " dot" went unobserved for 27 shift turnovers. (c) The NSO had logged placing the Division II Control Center HVAC supply fan in the off position at 8:35 a.m. on July 18, 1985. Subsequent reviews of the log either failed to note the entry or failed to recognize its significance. (6 NSS turnovers, 15 NASS turnovers, and 27 NSO turnovers) (2) P0M Procedure 21.000.01, Section 6.19.1.1 states, in part,

                  " Evaluate the consequences of removing the system or component from service considering such items as Technical Specifications Limiting Condition for Operations which require an action statement to be carried out...." The licensee failed to evaluate the consequences of removing components from service

in that no acknowledgement of any Technical Specification applicability was made in either the NSO log of the Control Room Information System (CRIS) when the Division II Control

Center HVAC was removed from service (341/85040-03b).

4. RCIC/ Core Spray Room Cooler The NSS observed while reviewing the combination operating panels during his turnover on July 24, 1985, at 6:30 p.m. that the control switch for the Division I Reactor Core Injection Cooling (RCIC)/ Core Spray Room Cooler was in the off-reset pos'ition, this made both RCIC and Division I core spray inoperable. The NSS who discovered the out-of-position switch stated that it was in the proper position at 3:30 p.m. on July 23, 1985.

The licensee also determined that the Motor Control Center (MCC-728-3A Position 2D) feeding the room cooler was found in the off position. Subsequent investigation by the licensee did not reveal any reason for l the coolers status nor could any PN-21s be identified which would have

authorized de-energizing the MCC feeder breaker. The room cooler was returned to service and the licensee documented the incident in DER NP-85-0390.

The unit was in the startup mode of operation (Operational Condition 2)

at the time the room cooler was taken out of service, but was in a planned shutdown due to the loss of the South Reactor Feed Pump when the cooler was found out of service. (Reactor pressure had been reduced l to less than 150 psig at 7:30 a.m. on July 24,1985.) RCIC is not i

! 9

l l i required to be operational below 150 psig; however, the High Pressure i Core Injection (HPCI) had been inoperable since July 11, 1985 thus for ' approximately sixteen (16) hours the HPCI, RCIC and Division I core spray systems were all inoperable. During the inspection and review of the event, two apparent violations

of Technical Specification requirements were identified as follows

I a. Technical Specification 3.5.1.C.1 requires that during the startup mode of operation, the High Pressure Core Injection (HPCI) system may be inoperable provided that the Core Spray (CS) system, the

Low Pressure Coolant Injection (LPCI) system, the Automatic

Depressurization System (ADS), and the Reactor Core Isolation Cooling (RCIC) system are operable, j Cor.trary to the above, the licensee failed to ensure that the

! RCIC and Division I core spray systems were operable when they g allowed the RCIC/CS room cooler to be removed from service at 3:30 p.m. on July 23, 1985 with the HPCI system already inoperable

!            as of 3:00 a.m. on July 11, 1985. This condition existed for j             approximately sixteen hours, with the reactor in the Startup
;            condition (441/85040-04).

l 1

b. Technical Specification 6.8.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedure recomendations of Appendix A of Regulatory l Guide 1.33 Revision 2, 1978. Appendix A of Regulatory Guide 1.33

lists the following activities under Administrative Procedures

ll l - Authorities and Responsibilities for Safe Operation...

               -    Equipment Control

'I - Shift and Relief Turnovers l

               -    Log Entries...

l Contrary to the above the licensee failed to adhere to the j provisions of Technical Specification 6.8.1.a as follows: (1) POM Procedure 12.000.15"PN-21(WorkOrder) Processing," 4 Section 7.2.1 states, in part, "All work activities at ! Femi 2...shall be controlled by a PN-21 and Attachment ' A' l to the PN-21." The licensee failed to write a PN-21 to de-energize the feeder breaker (MCC-72B-3A Position 20) for j the RCIC/ Core Spray room cooler fan on July 23 and 24, 1985 l (341/85040-05a).

!             (2)   POM Procedure 21.000.01, " Shift Operations and Control Room,"

delineates the shift turnover responsibilities of the Nuclear Shift Supervisor (NSS) the Nuclear Assistant Shift Supervisor l (NASS) and the Nuclear Station Operator (NS0). Included in the respons'ibilities is a review of past log entries, and a review , i i 10

i

of each Combination Operating Panel for off-nomal conditions or the addition of CRIS " dots." The NSS, NASS, and NSO all failed to adequately perfom the required activities as the .

RCIC/ Core Spray room cooler fan switch was in the "off-reset"  ! position for approximately 24 hours on July 23 and 24,1985. The l l normal position for the switch is in the " Auto" position. The  ! out of position switch went unobserved for two shift turnovers ) (341/85040-05b). (3) POM Procedure 21.000.01, Section 6.19.1.1 states, in part, ! " Evaluate the consequences of removing the system or component

from service considering such items as Technical Specifications Limiting Condition for Operations which require an action statement to be carried out...." The licensee failed to 4 evaluate the consequences of removing components from service as he did not take into account the existing inoperability of

 '                                  the HPCI system prior to removing the RCIC/ Core Spray room cooler from service nor was the action entered into the NSO log or the CRIS equipment status file (341/85040-05c).

5. Cooling Tower Bypass Valve l

On July 26, 1985, while performing surveillance testing on Division I, Emergency Diesel Generator (EDG) #11, a Diesel Generator Service Water

;                (DGSW) Low Flow Alarm was received. The alam indicated a lack of cooling water for the EDG. The operator verified the low flow and

) innediately shutdown the EDG. The licensee, upon further investigation,

!                detemined that the mechanical draft cooling tower bypass valve E1150-F603A was closed and de-energized. This valve is required by a i                 condition of the license to be open and de-energized, or one of the t

cooling tower shutoff valves E1150-F604A/F605A is to be open and de-energized to prevent spurious closure due to hot shorts in the event

,                of a~ fire in the plant. The normal position for this motor operated valve is de-energized and open per POM Procedure 23.208, Revision 8.

ThisisanapparentviolationofLicenseCondition2.C.(9)(d)(341/85040-06). Investigation into the reason why the bypass valve was out of proper position, identified that the valve was last manipulated on July 23, 1985, while running the Reactor Heat Removal Service Water (RHRSW) i system. The valve had exhibited a tendency to trip either the thermal overloads or the torque switches during stroking and an operator had been

required to partially stroke the valve to the desired position as well as i reset the themal overloads to allow continued stroking from the control room. It appears that clear instructions were not given to the Reactor Building Rounds Operator as he was not aware of the necessity of leaving

the E1150-F603A valve in the open de-energized condition.

I The E1150-F603A valve is located in the discharge flow path to the l j cooling water reservoir and its closure affects multiple systems. With l

the valve closed, flow of Emergency Equipment Service Water (EESW), i l

22 . J

i RHRSW, and DGSW is blocked. Besides affecting the Division I EDG's, with the bypass valve closed all Division I emergency core cooling

!                         systems were inoperable including the core spray and residual heat
 >                        removal systems.

At the time the bypass valve was discovered in the closed position, the reactor was in cold shutdown, Condition 4, with the reactor temperature at approximately 130"F and atmospheric pressure. In cold shutdown the plant is required to have one operable division of ECCS, and one operable division of EDG's (two diesels). This condition was satisfied, however, the bypass valve E1150-F603A had been closed since about 1:19 p.m. on July 23, 1985. On July 23, 1985, the unit was in Condition 2 (Startup) which requires both divisions of ECCS and both divisions of the onsite electrical power source (EDG's) to be operable. As a result of the bypass valve beine closed, only one division was operable. The failure 4 to take remedial action with one division of the EDG's inoperable is an apparent violation of T.S. 3.8.1.1.b (341/85040-07). On July 23, 1985, the licensee comenced a reactor shutdown at about 1:15 p.m. as a result of the failure of the South Reactor Feed Pump. It was fortuitous that the licensee connenced a vtactor shutdown about the same time the cooling tower bypass valve was de-energized in the closed position, as the licensee was by chance complying with the Limiting Condition for Operation (LCO) action statements in reducing power and proceeding to cold shutdown. Without this action, the plant would have been in further violation of technical specifications.

6. Hydrogen Recombiner On June 20, 1985, the licensee completed maintenance on the Division II hydrogen recombiner per Work Order PN-21269327 to replace a leaking blower seal. The work order stated that post maintenance testing was required, and identified Plant Operations Manual (POM) Procedures 43.409.01, " Post LOCA Themal Recombiner System Test," and 24.409.01, l " Post LOCA Themal Recombiner Functional Test." These procedures were required to demonstrate leak tight integrity and operability, respectively. The work order was signed off as completed by the Nuclear Shift Supervisor on June 20, 1985, without the leakage test having been perfomed per POM Procedure 43.409.01. This is an apparent violation of Technical Specifications (T.S.) 6.8.1.a and 6.8.4.a in that the licensee l

failed to follow established procedures and comply with the leakage reduction program (341/85040-08). On August 26, 1985, the licensee initiated a Deviation / Event Repor*.

(No. NP-85-0455) to document the failure to perfom the post maintenance leak rate testing on the Division II hydrogen recombiner. After detemining the failure to perfom testing, the licensee had sufficient infomation to declare the hydrogen recombiner inoperable, as a result of exceeding the 30 day LCO limit, and the licensee did not take action per technical specification 3.0.3. to place the unit in hot shutdown l

l

   - - -    . _ _ _ _ _ .           -- . ___ _ _ - - - - _ _ . ._lE- __ ._. -        _ --.  - _ _ _ - _ _ - - - -

within six hours. The licensee proceeded to determine the leakage rate and on August 28, 1985, declared the Division II hydrogen recombiner inoperable as a result of the initial leakage rate testing. Subsequently on August 29, 1985, at 2:46 p.m. the licensee determined that the leakage rate was in excess of the allowable containment leakage. This is an

apparent violation of T.S. 3.6.6.1, and 3.0.3 in that the licensee failed to comply with the LCO action statements (341/85040-09).  :

At 6:00 p.m., on August 29, 1985, the licensee conenenced preparations to proceed to hot shutdown. The hydrogen recombiner was repaired, leak tested, and declared operable on August 29, 1985, at 9:00 p.m. The. plant was returned to the startup mode with pressure at 950 psig and 3.8% power for HPCI and SCRAM time testing at 10:40 p.m. During the time period from June 21 to July 21, 1985, the plant entered Operational condition (Startup) on five (5) occasions including initial criticality (June 21, 1985, June 29, 1985, July 2, 1985, July 6, 1985, and July 10,1985) without both divisions of hydrogen recombiners operable. This is an apparent violation of T.S. 3.0.4 (341/85040-10). l l 7. Breach of Primary Containment Integrity The licensee discovered a Containment Monitoring System Valve (T50-071A) which is a primary containment boundary, in the open position and uncapped i on September 2,1985. The valve was shut upon discovery. The Nuclear

!         Shift Supervisor (NSS) was informed of the event on September 4,1985, approximately 39 hours after discovery. A Deviation / Event Report (DER)

(No.NP-85-0469) was written to document the open valve. l Valve T50-071A was installed under Engineering Design Package (EDP) i No. 1970 dated March 25, 1985. The EDP included the installation of four test connection cutoff valves in the primary containment monitoring ! system. Valves T50-068A and B were installed in piping from the bottom of the torus while valves T50-071A and B were installed in piping from ! the top of the torus. PN-21 (Work Order) No. 814949 was written to 4 install the "A" valves in Division I and PN-21 No. 814948 was written to , install the "B" valves in Division II. Both PN-21s were signed off as  !

          " Order Completed" on June 20, 1985. It should be noted that neither EDP         ,

1970 nor the four PN-21s associated with it were closed out as of September 10, 1985. Both PN-21s for the primary containment monitoring system required Local Leak Rate Tests (LLRTs) plus Plant Operations Manual Procedure 24.000.05, " Monthly Continuity Light and Channel Check Test," Section 4, l " Precautions and Limitations" to be completed. The NSS signed the PN-21s as order complete on June 20, 1985. The licensee reviewed EDP  ; 1970 and detemined that the LLRTs for the primary containment monitoring 1 system modifications had not been performed. DER No. NP-85-471 dated

September 5, 1985, was written to document this discrepancy. The licensee subsequently performed the missed LLRTs and three of the four LLRTs met

__ ___ _.. _ _13._ _ _ _ ____ _ ___ . _ _ _ _' __ _ _ _ _

procedural criteria. The LLRT for Penetration X203A (POM Procedure 43.401.386) which contains valve T50-071A did not meet the leakage criteria. Two of the three boundary valves were repaired and the penetration subsequently met the test criteria. During the inspection and review of the event, three apparent violations were identified as follows:

a. Technical Specification 3.6.1.1 requires that PRIMARY CONTAINMENT INTEGRITY shall be maintained in Operational Conditions 1, 2, and 3.

Without PRIMARY CONTAINMENT INTEGRITY restore PRIMARY CONTAINMENT INTEGRITY within one hour or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours. Contrary to the above, the licensee failed to maintain containment integrity from June 21 to September 2,1985, in that primary containment monitoring system valve (T50-F071-A) was in the open position ar.d the line downstream of the valve was uncapped which resulted in an open pathway from the primary containment to the reactor building. Primary containment integrity was required during this time frame except for 6.25 days of the interval (341/85040-11).

b. Technical Specification 6.8.1.a requires that written procedures shall be established, implemented, and maintained covering the applicabic procedure recomendat ons of Appendix A of Regulatory Guide 1.33 Revision 2, 1978. Appendix A of Regulatory Guide 1.33 lists the following activities under Administrative Procedures:

(1) Equipment Control (2) Log Entries... Contrary to the above, the licensee failed to adhere to the provisions of Technical Specification 6.8.1.a as follows: POM Procedure 12.000.15. "PN-21 (Work Order) Processing," Revision 11, August 20, 1985, paragraph 7.3.16 states: "Upon completion of all maintenance, testing, STR or EPC and after the ' Accepted for Service By' slot has been signed, the pink copy of PN-21 is forwarded to the Nuclear Shift Supervisor who will review the order and sign ' Order , Completed.'" Contrary to the above, the licensee failed to adhere to the requirements of POM Procedure 12.000.15 in that Work Order PN-21 No. 814945 (covering the addition of leak rate test connection valve T50-F071A) was signed " order completed" on June 20, 1985, without the post installation leak rate testing being performed as specified on the work order (341/85040-12).

c. 10 CFR 50, Appendix B, Criterion VI, states, in part, " Measure shall be established to control the issuance of documents, such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting quality. These measures shall assure that documents including changes are reviewed for adequacy...."

                                   . 14 m

i POM Procedure 12.000.64, "EDP Implementation Procedure," Revision 2, dated March 5,1985. Section 6.5.1 states, in part, "The responsible 1 PSE shall identify the plant documents requiring revision when the l package is prepared." ) 1 Contrary to the above, the EDP Implementation Procedure for EDP

No. 1970, covering the installation of the containment sample system l 1eak rate test connection valve T50-F071A, did not identify all the plant documents requiring revision in that it did not identify 3 POM Procedures 24.425.01, " Primary Containment Integrity Verification for Valves Outside Containment," or 47.000.77, " Test Vent and Drain (TVD) Cap and Plug Verification." The failure to identify these documents resulted in valve T50-F071A (and seven other valves) not being incorporated into the procedures used to verify containment integrity (341/85040-13).

8. Sumary Twenty-six violations (including multiple examples) of NRC requirements are identified in this report. The majority of these fr.'.; into the category of failure to follow procedures. This represents a breakdown in the licensee's ability to operate the plant in accordance with

! prescribed procedures as required by the Technical Specifications. The licensee's Operational Assurance (OA) organization has a program i called Procedure Compliance Module (PCM) which monitors, on a monthly 1 bases, procedural compliance by various organizations. The results of six monthly surveillances (January-June 1985) clearly revealed that the operations section had had problems in following procedures. Procedural i compliance ran from 74% to 100% and there was no trend--the results were erratic. The six-month average was 87% with 99% compliance as a goal. It should be noted that the findings of the PCM program are not absolute but are excellent indicators of potential problem areas. The results, both current and cumulative, are issued monthly. The licensee had sufficient knowledge of procedural compliance problems to initiate corrective actions rather than wait for a larger data base. Seven of the violations were failures to meet Technical Specification Limiting Condition for Operations (LCO's). Each of these were serious and collectively represented a breakdown in the licensee's administrative and ' management controls design to safely operate the plant. The safety significance of the violations was mitigated considerably by two items: the plant had only operated for 20 days at an average power of 2 percent; and the failure of the South Reactor Feed Pump turbine which resulted in the licensee shutting the reactor down. The inspectors consider the second item to be fortuitous in that the reactor was removed from an operating condition which required certain equipment to be operable or actions to be taken when the licensee was unaware that the actions or equipment were required, i 1 _ _ _ _ ' _ . . _ . . _ _ _ _ _ . _15_ _ _ _ _ _ _ _ , _ _ _ _ . _,. . _ _. . _ _

i l l Twenty-six violations, many of them repetitive, have been identified in this report. Operating history mitigated their safety significance;  ; however, they demonstrated a major breakdown in the licensee's i administrative controls to safely operate the plant. ! 9. Management Meetings ,

a. Out-of-Sequence Rod Pull l DECO management (denoted in Paragraph 1) met with RIII management in Glen Ellyn, Illinois, on July 23, 1985, to discuss the sequence of 1 events surrounding the out-of-sequence rod pull which occurred on

!                           July 1 and 2, 1985, and their subsequent actions. This meeting was attended by the public.

1 The licensee's presentation included a ' detailed sequence of events

;                           insnediately preceding and following the event, the rod pull sheets,

and the Source Range Monitor (SRM) strip chart which corresponded to

! the time of the incident. The licensee also presented a layout of I the control room and the relative location in the control room of those on shift at the time of the event. A great deal of discussion

,                           was focused on the events and licensee actions subsequent to the incident. The adequacy of the onshift review was discussed; RIII's position was that the onshift review was insufficient. Considerable i

discussion was focused around the adequacy, completeness, and f timeliness of the reporting of the incident to the NRC. The ! licensee did not consider the event to be reportable under 10 CFR i 50.72 or 50.73. Region III concurred that the incident was not ~ i reportable under 10 CFR 50.72 or 50.73, Nt given the proximity of ! the Comission's full power briefing, Deco should have been more

sensitive to the importance of keeping the NRC informed. The 1

Regional Administrator informed the licensee that he had requested theOfficeofInvestigations(01)toinvestigatetheevent. l. l The licensee also discussed their actions pertaining to whether or l not the unit had been critical, as a result of the out-of-sequence l rod pull, and their corrective action program. The licensee was ! informed that Region III would send an inspection team to Fermi 2 to assess control room operations and the effectiveness of the i corrective action program. l The licensee's presentation is included as an attachment to DECO I letter No. RC-LG-85-0017 (Jens to Keppler) dated September 5,1985.

b. Corrective Action Program

! DECO management (denoted in Paragraph 1) met with Region III j management in Glen Ellyn, Illinois, on September 10, 1985, to discuss j their corrective action program to preclude the repetition of the events which were reported to the NRC during July and August 1985 and

documented elsewhere in this report. The meeting was attended by i j representatives of the Monroe County Government and the public.

i j 16

i. The licensee proposed a corrective action program based on 9 ~ observations and recomendations made by the Institute of Nuclear Power Operations (INPO) assistance inspection team, findings of two recent NRC team inspections, conditions of the Confimatory Action ,' Letter (CAL-RIII-85-10) dated July 16, 1985, findings by the resident NRC inspectors, and recomendations made.by Management Analysis Corporation (MAC). The program was divided into short and long tem actions. Short tem actions were to be completed prior to power escalation atove five percent. Long tem actions l addressed programatic areas with the licensee indicating a phased l implementation to minimize pertubations to plant operations. , Long tem actions were to be initiated prior to exceeding five i percent power but not to be completed until some later date with the longest date of December 1, 1986. ) DECO requested that the five percent power restriction be lifted but

. that they would commit to not exceeding twenty percent power until l after the forthcoming outage which is scheduled to start during 1 October 1985. The request was denied.

I Region III requested that the licensee docket the corrective action

!                     program which had been presented and include methods of monitoring

. the effectiveness of the corrective actions. The licensee subsequently submitted their " Reactor Operations Improvement Plan" in a letter from Jens to Keppler (DECO No. VP-85-0198) l dated October 10, 1985 (copy attached). i The licensee was also infomed that another inspection team would i be sent to Femi 2 to observe operations and review the corrective action program and its effectiveness before the five percent i

,                     restriction could oe lifted. This action was predicated upon a satisfact,ory resolution of the O! investigation.                  l I

10. Enforcement Conference '

I The NRC staff met with licensee representatives (denoted in Paragraph 1) during the management meetings and at various times during the inspection and reviewed the issues discussed in this report. 1 1 The staff also discussed the likely infomational content of the j inspection report with regard to documents or processes review by the l inspectors during the inspection. The licensee did not identify any ] such documents / processes as proprietary, i I 4 i l l N 17 .}}