IR 05000341/1987026
| ML20237K041 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 09/01/1987 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20237J982 | List: |
| References | |
| 50-341-87-26, NUDOCS 8709040168 | |
| Download: ML20237K041 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-341/87026(DRP)
Docket No. 50-341 Operating License No. NPF-43 Licensee:
Detroit Edison Company 2000 Second Avenue i
Detroit, MI 48226 Facility Name:
Fermi 2 Inspection At:
Fermi Site, Newport, Michigan Inspection Conducted:
June 9 through July 20, 1987 Inspectors:
W. G. Rogers M. E. Parker
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Approved By:
E. G. Greenman, Deputy Director Division of Reactor Projects Date Inspection Summary Inspection on June 9 through July 20, 1987, (Report No. 50-341/87026(DRP)
Areas Inspected:
Routine, unannounced inspection by resident inspectors of previously identified items, regional requests, events, 10 CFR 50.55(e), LERs, operational safety, maintenance, surveillance, startup testing, plant trips, report review, and management meetings.
Results:
Six violations were identified (Paragraphs 2.b, 2.c, 8, 9.b, 9.c, 4.b, and 4.c) and one unresolved item was identified (Paragraph 5.c).
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DETAILS 1.
Persons Contacted a.
Detroit Edison Company
- F. Abramson, Operations Engineer
- F. Agosti, Vice President, Nuclear Operations L. Bregni, Compliance Engineer
- S. Cashell, Licensing G. Debner, Startup Engineer, Test Phase i
- K. Earle, Technical Engineer, Nuclear Production
- R. Eberhardt, Radiation Protection Engineer L. Esau, Maintenance Engineer
- S. Frost, Licensing C. Gelletly, Nuclear Projects and Plant Engineering J. Green, Systems Engineering R. Kelm, Director, Nuclear Security J. Leman, Director, Plant Safety, Nuclear Production
- R. Lenart, Plant Manager, Nuclear Production
- L. Lessor, Advisor to Plant Manager A. Lim, Systems Engineering
- J. Madsen, Licensing
- R. May, Superintendent, Maintenance and Modification
- W. Orser, Vice President, Nuclear Engineering and Services
- J. Plona, Operations Support Engineer
- E. Preston, Assistant Director, Plant Safety
- T. Randazzo, Director, Regulatory Affairs
- R. Sekotnicki, Planning and Scheduling B. Sheffel, Nuclear Production, Technical Engineering ISI M. Sierra, Technical Engineering
- L. Simpkin, Director, Nuclear Engineering
- B. R. Sylvia, Group Vice President, Nuclear Operations J. Thorpe, Systems Engineering G. Trahey, Director, Quality Assurance
- W. Tucker, Superintendent, Operations
- E. Wilds, Systems Engineer
- J. Wold, Supervisor, PQA b.
U.S. Nuclear Regulatory Commission M. Parker, Resident Inspector W. Rogers, Senior Resident Inspector i
2.
Followup On Inspector Identified Items (92701)
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a.
(Closed) Unresolved Item (341/86034-02(DRP)):
This item concerns the controls placed on the reactor building corner room doors as they relate to meeting flood protection and separation requirements to satisfy single and common mode failure criteria for the emergency core cooling system (ECCS).
As addressed in Inspection Report (
No. 50-341/87020, the licensee has provided Technical Specification Interpretation TS-87-004, attempting to address the inspector's
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concerns.
The licensee has subsequently modified the interpretation, TS-87-004, Revision 3, to change an eight-hour grace period to one hour after which the associated ECCS systems would be declared inoperable.
Technical Specification Interpretation TS-87-004, Revision 3, adequately addresses the inspector's concern and this
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item is considered closed.
b.
(Closed) Unresolved Item (341/87020-03(DRP)):
High pressure coolant injection (HPCI) test return line to CST isolation valve, E41-F011, found in the energized position.
As identified in Inspection Report No. 50-341/87020(DRP), E41-F011 was found closed in the energized position.
The HPCI test return valve, as a condition of the license,
is required to be closed and deenergized and only operable during l
HPCI and reactor core isolation cooling (RCIC) testing periods.
As such, the test return valve should have been secured upon completion of HPCI testing on June 4, 1987, at approximately 3:00 a.m. EDT.
This valve remained in the energized position for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after completion of HPCI testing.
Subsequent discussions with the office of Nuclear Reactor Regulation determined that this was an unacceptable time frame and the intent behind the Supplemental Safety Evaluation Report was to have the valve secured and deenergized immediately after testing and in no case, any longer than four hours.
This is considered a violation (341/87026-01(DRP)) of License Condition No. 2.C.(9)(a).
c.
(Closed) Unresolved Item (341/87020-04(DRP)):
HPCI turbine exhaust line drain to suppression chamber valve, E41-F022, found out of position.
As identified in Inspection Report No. 50-341/87020(DRP),
E41-F022 was found in the closed position; but it is required by the system operating Procedure, P0M 23.202, "High Pressure Coolant Injection System," Revision 20, to be in the open position.
Since identification of this condition on June 4,1987, the licensec has reviewed the conditions that led to this valve being out of position.
The licensee was able to determine that draining of the HPCI system was in progress to support work on the HPCI suction relief valve, E41-F020, and that the draining was taking an excessive amount of time.
The control room nuclear supervising operator (CRNS0)
speculated that another source of water was supplying the system.
The CRNS0 then directed E41-F022 to be closed.
It was subsequently identified that E41-F022 could not have been the source of water as the turbine exhaust line drains into the torus.
Due to miscommunications with the CRNSO under instruction and inadequate follow-up by the CRNSO, the valve was not returned to its proper position.
In addition, the abnormal lineup sheet (ALS) was in the field with the power plant operator and not available to amend the previous isolation to cover the manipulation of E41-F022.
This is considered an example of violation (341/87026-02a(DRP)) of 10 CFR 50 Appendix B, Criterion V for failure to properly remove a component from service as required by P0M 21.000.01, " Conduct of Shift Operations."
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3.
Follow-up Action On 10 CFR 50.55(e) Items (92700)
(Closed) 50.55(e) Item 50-341/85003-EE, (DECO 146):
" Failure of emergency diesel generator (EDG) No. 11 fifteen minutes after it started."
Inspection activities documented in Inspection Reports No. 50-341/85046 and No. 50-341/87013 adequately followed up on this report.
Therefore, based upon those inspection results, this matter is considered closed.
4.
Licensee Event Reports Follow-up (92700)
a.
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.
(Closed) LER 85-019 ESF actuation due to trip of turbine building HVAC radiation monitor.
(Closed) LER 85-051 &
Control center HVAC shift to chlorine LER 85-051-01 mode.
(Closed) LER 85-057 Fire watch out of area.
(Closed) LER 85-071 Reactor trip - spurious level 3 signal.
(Closed) LER 85-081 &
Distressed bearings found in diesel l
LER 85-081-01 generators.
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(Closed) LER 86-001 &
Actuation of control center HVAC emergency LER 86-001-01 mode.
(Closed) LER 86-015 CCHVAC recirculation mode actuation.
(Closed) LER 86-019 ESF actuations caused by trip of reactor building vent and exhaust radiation
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monitor.
In this LER the licensee was to evaluate the need for a time delay.
The evaluation was performed and management decided the time delay was unnecessary.
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(Closed) LER 86-023 ESF actuation of control center ventilation and SGTS.
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(Closed) LER 86-028 ESF actuation during testing.
(Closed) LER 86-035 Malfunction of gland sealing steam pressure regulator.
(Closed) LER 86-038 &
ESF actuations caused by blown fuse.
LER 86-038-01 l
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e (Closed) LER 87-004 ESF actuation during maintenance.
(Closed) LER 87-008 Reactor scram on high pressure.
b.
(0 pen) LER 87-019:
Missed surveillance of standby gas treatment system (SGTS) C02 system due to incorrect scheduling.
In the review of the LER, it was apparent that the licensee had not complied with Technical Specification 4.7.7.3.2.b.2 in that the surveillance requirement had not been accomplished in the specified 18-month time frame plus a 25% allowance.
Surveillance Requirement 4.7.7.3.2.b.2 requires the low pressure carbon dioxide system for the SGTS charcoal filters be demonstrated operable by verifying flow from each nozzle every 18 months.
The surveillance was last completed on May 24, 1985,
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and should have been completed by April 9, 1987.
Upon identifying a scheduling error, the surveillance was successfully completed on May 22, 1987.
Even though the violation was licensee identified, i
previo a corrective actions within the last two years should have identified and remedied the matter.
Therefore, this is considered a violation (341/87026-03(DRP)) of Technical Specification 4.7.7.3.2.b.2.
The licensee's corrective actions are stated in LER 87-019 and the
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response to the Notice of Violation and Imposition of Civil Penalty dated June 12, 1987, with an understanding that the independent checks of the corrective actions shall be accomplished by September 1987.
No response to this Notice of Violation need be submitted as a result of these corrective actions.
c.
(0 pen) LER 87-021, Reactor coolant system (RCS) leakage limit surveillance interval exceeded due to personnel error.
The LER discusses the failure of operations personnel to execute surveillance
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Procedure 24.000.02, Attachment 1, in the prescribed time interval.
Attachment 1 provides the procedure for performance of the RCS leakage calculation by checking how much water has drained into the floor drain and equipment drain sumps.
Technical Specification surveillance requirements 4.4.3.2.1.b and 4.4.3.2.1.c state that the RCS leakage shall be determined every four hours by checking the sumps.
Technical Specification 4.0.2 allows a 25% extension on the performance of this surveillance requirement.
On June 7, 1987, the RLS leAage had been checked at 0800 and had to be checked by 1300 to be in compliance with Technical Specification surveillance requirements.
The surveillance was not performed until 1400.
When the surveillance was performed at 1400, no leakage in excess of Technical Specification requirements was noted.
This matter is considered a violation (341/87026-04(DRP)) of Technical Specification surveillance requirements 4.4.3.2.1.b and 4.4.3.2.1.c in that the surveillance was not accomplished within the specified time interval plus the 25% allowance.
5.
Follow-up of Events (93702)
a.
During the inspection period, several events occurred, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72.
The inspectors pursued the events onsite with licensee and/or other NRC officials.
In each case, the inspectors verified that the
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notification was correct and timely, if appropriate, that the i
licensee was taking prompt and appropriate actions, that activities
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The specific events are as follows:
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Reactor Core Isolation System Isolation.
June 24, 1987 Initiation of a plant shutdown due to shutdown
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of reactor recirculation B-MG set.
June 25, 1987
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Reactor core isolation system injection.
June 25, 1987
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Reactor water cleanup system isolation.
Emergency equipment cooling water / emergency June 28, 1987
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equipment service water initiation.
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Overpressurization of HPCI suction piping.
Initiation of reactor shutdown.
July 18, 1987
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Reactor scram on high bearing vibration on main turbine.
b.
On June 26, 1987, an unplanned mode change occurred.
This event was followed up by an inspection team from Region III.
Their inspection findings are documented in Inspection Report No. 50-341/87027.
c.
The inspector completed review of Deviation / Event Report (DER)87-174.
This DER was partially reviewed in Inspection Report No. 50-341/87020.
The licensee has revised or is in the process of revising procedures to state that only one division override switch may be used at a time.
Use of the switches will only be allowed in surveillance and operating procedures.
During the inspector review of the Updated Final Safety Analysis Report (UFSAR), it was apparent that a safety evaluation on the Emergency Equipment Cooling Water (EECW) system had not been incorporated into the UFSAR.
On May 7, 1985, a 10 CFR 50.59 review was performed to allow one of the EECW head tank manual valves to be closed unless there was initiation of the EECW system at which time operator action would be taken to open the valve.
During the i
loss-of-offsite power test, this action was proven in that it could
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be performed with a minimum shift complement.
This matter was identified to the licensee for their modification in the next UFSAR revision.
Potential discrepancies in the UFSAR is considered an I
unresolved item (341/87026-05(DRP)) pending further review by the inspector.
No violations or deviations were identified in this area.
6.
Follow-up on Regional Requests (937058)
During the inspection period an earthquake occurred in the central Midwest.
The licensee was contacted as to whether their seismic monitors registered any ground movement.
The monitors did not register any ground movement.
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The inspector concluded that if any activity had occurred, with respect i
to Fermi, it was insufficient to trigger the seismic monitoring equipment, and had no further questions.
7.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the period from June 9 through July 20, 1987.
The inspectors verified the
operability of selected emergency systems, reviewed tagout records and verified proper return to service of affected components.
Tours of the reactor building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance.
The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
These reviews and observations were condrcted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR, and administrative procedures.
On June 7, 1987, the inspector reviewed the operator rounds sheets and observed that the EDG No.12 day tank levels recorded for June 5-6, 1987, were less than acceptable.
The situation was pointed out to the operating shift.
The shift immediately determined the day tank level and found it to be acceptable.
Subsequent follow-up by the operations staff determined that the readings had been transposed from 520 gallons to 250 gallons.
The matter was discussed with the rounds recorder and reviewer and the rounds sheets were upgraded to designate Technical Specification equipment acceptance criteria in red to further highlight their importance.
No violations or deviations were identified in this area.
8.
Monthly Maintenance Observation (62703)
Station maintenance activities on safety-related systems and components i
listed below were observed to ascertain that they were conducted in l
accordance with approved procedures, regulatory guides and industry codes
or standards and in conformance with Technical Specifications.
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The following items were considered during this review:
the limiting
conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were
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performed prior to returning components or systems to service; quality
control records were maintained; activities were accomplished by
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. qualified pe'rsonnel; parts and material's used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.
Work requests were reviewed to determine the' status of-outstanding jobs and to assure that' priority is assigned to safety-related equipment maintenance which may affect system performance.
The following maintenance activities were observed:
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Repair and replacement of' reactor recirculation MG set of "B"
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brushes.
Preventative maintenance on Division I and II post accident
recorders.
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Following completion of maintenance on the "B" reactor recirculation l
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MG set, the inspectors verified that these systems had been returned
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to service properly.
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'While observing the preventative maintenance on the post-accident l
recorders, the inspector noted that independent verification was not L
being provided at the completion of the maintenance activity.
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the maintenance, wiring was disconnected to allow installation of a
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fluke meter;-the wiring was reconnected upon removal.of the fluke meter.
The Administrative Procedure 12.000.080, " Conduct of Electrical Field Activities," is the governing document for use of independent verification during maintenance.
Step 7.5.1 states, "An independent second check of restoring to normal shall be performed for all interim alterations performed under work orders designated as Safety-Related on the Work Order Package Attachment A."
The work packages on the. post-accident recorders were designated safety-related.
The inspector inquired of I&C supervision why independent verification was not being utilized.
The response was that the I&C shop used the master instrument list (MIL) to determine whether an instrument was safety-related.
By the MIL the post accident recorders are nonsafety-related, so the I&C shop did not utilize independent verification.
Further discussion with I&C and engineering personnel revealed that.almost all indicators and recorders in the control room'are classified as nonsafety-related.
Therefore, the lack of independent verification following maintenance,was a widespread situation.
The failure of field personnel to properly adhere to Administrative Procedure 12.000.080 is considered an example of a violation (341/87026-02b(DRP)) of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings."
9.
Monthly Surveillance Observation (61726)
a.
The inspectors observed surveillance testing required by Technical Specifications and verified that:
testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with Technical Specifications and procedure
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requirements and were reviewed by personnel other than the i
individual directing the test, and any deficiencies identified
during the testing were properly reviewed and resolved by
appropriate management personnel.
l The inspectors also witnessed portions of the following test activities:
i 24.404.02 Standby Gas Treatment System Filter Monthly Operability Test.
44.010.129 APRM "F" Channel Functional Test.
The inspectors performed a record review of completed surveillance tests. The review was to determine that the test was accomplished within the required Technical Specification time interval, procedural steps were properly initiated, the procedure acceptance criteria were met, independent verifications were accomplished by people other than those performing the test, and the tests were signed in and out of the control room surveillance log book.
The surveillance tests reviewed were:
24.139.02 SLC Pump and Check Valve Operability Test.
24.000.02 Shiftly, Daily, Weekly and Situation Required Surveillance b.
On June 12,.1987, the inspector witnessed licensee actions to comply with Techt. cal Specification Limiting Condition for Operation Action i
Statement 3.8.1.1.b.
The action statement was invoked when emergency l
diesel generator (EDG) No. 13 was taken out of service for preventative j
maintenance at 0517.
In accordance with a portion of the action statement, the licensee is to demonstrate the operability of all alternating current power sources by performing surveillance l
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Requirement 4.8.1.1.1 within one hour and once per eight hours thereafter until the EDG is returned to service.
Surveillance
Requirement 4.8.1.1.1, Method for Demonstration of Operability, is a verification of correct breaker alignments and indicated power availability for each independent circuit between the offsite transmission network and the onsite Class 1E distribution system.
Surveillance Procedure 24.000.02, Attachment 9, Section 5, is the licensee's implementation mechanism for surveillance Requirement 4.8.1.1.1.
At 0545, an operator obsersed breaker alignments and bus voltages for buses 101, 102 and 301 and initialed the situation required surveillance log sheet, Attachment 10 to Procedure 24.000.02, as satisfactorily completing the surveillance.
The Nuclear Assistant Shift Supervisor (NASS) then initialed the required surveillance log sheet.
At this point the inspector reviewed the surveillance procedure and observed that none of the data or initials required in the body of the surveillance procedure had been done.
This situation was brought to the attention of the NASS.
Upon discussion with the NASS, the surveillance was reperformed and the body of the procedure was properly c;mpleted within the required one-hour time frame.
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. June'15, 1987,_the inspector reviewed all the surveillance performed
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on,the offsite power sources while the EDG was out of service.
The second. performance of the_ surveillance procedure was'also devoid of data:and initials in the body of the-procedure. -Section 6.3 of N
Procedure 24.000.02 provides general instructions for the performance
.of-any surveillance activities per this procedure.
Step 6.3.3 states
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in part, "A check mark should be used only if no value is available
'to be recorded such as observing an annunciator status.
In all' cases where a value.is' observed to satisfy a numerical criterion of.this procedure, it sho'uld.be recorded." At 0545 and 1300 on June 12, 1987, personnel performirig offsite power source verification'did not perform-
.the actions required by Surveillance Procedure 24.000.02, step 6.3.3.
.This is' considered an example of a Violation (341/87026-02c(DRP)) of
10 CFR 50 Appendix B, Criterion V, in that activities affecting quality were not' accomplished in accordance with approved procedures.-
-It is also apparent that both NASS reviews at 0545 and 1300 on June 12,_1987, were not adequate in that there was incomplete objective evidence available at the time of their review to support
' successful completion of the surveillance requirement.
During the review of Section 5 of Attachment 9 to Procedure 24.000.02, the inspector challenged whether this section of the procedure adequately prescribed the'necessary action to implement Surveillance Requirement 4.8.1.1.1.
For the Division I Distribution System, breaker alignments / bus voltages from the 345 kv buses to the 4.16 kv buses were not designated.
For the Division II Distribution System, breaker alignments / bus voltages from the 120 kv bus to the 4.16 kv buses were not designated.
The 4.16 kv buses are the start of'the onsite Class 1E Distribution System.
During the week of June 15, 1987, the licensee issued-night orders prescribing the proper breaker
. alignments / bus voltages that must be observed and recorded to comply
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with Surveillance Requirement 4.8.1.1.1.
On July 14, 1987, the night order was cancelled with the issuance of a new revision to Procedure
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24.000.02.
On July 15, 1987, an LER was submitted by the licensee on this matter.
Due to the inadequacies of Procedure 24.000.02, Attachment 9, Section 5, whenever the licensee entered into Technical Specification Action Statement 3.8.1.1.b, they did not comply with Surveillance Requirement 4.8.1.1.1.
This is considered a violation l
(341/87026-06(DRP)) of Technical Specification Surveillance i
Requirement 4.8.l.1.1.
c.
In a review of completed Surveillance Procedure 24.000.02, "Shiftly, Daily and Weekly Channel", on June 18, 1987, the inspector identified a concern with the MSIVLCS channel checks.
In Attachment 4, Steps 3.3 through 3.6, main steam line pressure and control air pressure
are to be checked using dual indicators B21-R801 and R804.
These steps implement Technical Specification Surveillance Requirement 4.6.L4.d.1. which requires the pressure control instrumentation of the MSIVLCS be channel checked at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The instrument readings associated with Division II had not been recorded but the' operator had identified this condition with a note which said
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" gauge removed for maintenance".
The NASS had considered Mis explanation acceptable and annotated that Attachment 4 had been
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completed and met Technical Specification Requirements.
Prior to the performance of the channel check, the gauge had been removed and digital fluke meters installed to provide the necessary instrument readings on the MSIVLCS.
The inspector notified the Nuclear Shift i
Supervisor (NSS) that this was not in compliance with Technical l
Specifications.
The NSS immediately had the MSIVLCS system channel
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checked using the fluke meter readings with satisfactory results.
A review of.previously performed channel checks revealed that the i
same annotation and acceptance of the channel check started on June 13, 1987, and continued until identified by the inspector.
Therefore, Surveillance Requirement 4.6.1.4.d.1 was not accomplished within the specified time interval of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> plus 25%.
This is considered a violation (341/87026-07(ORP)) of Technical Specification surveillance requirements.
The inspector pursued how the fluke meters were installed and why operators were not using them.
This review determined that on May 8, 1987, I&C personnel observed the wiring cf indicator E21-R804 in preparation for a revision to the MSIVLCS Surveillance Procedures.
The I&C personnel determined that the as-built wiring configuration was not in accordance with drawing 6I721-2006-21.
Specifically, the drawing showed a field wire attached at Terminal Point three, whereas the wire was actually attached at Point 16.
Also, the drawing or vendor manual did not show an actual 250 ohm resistor in the circuitry.
I&C personnel researched previous drawing revisions and determined that a Field Modification Request (FMR) had been written in 1981 to install the 250 ohm resistor and connect the field wiring to terminal points two and three.
This FMR was accomplished in 1981 and was successfully walked down.
However, the FMR did not revise the appropriate drawing / vendor manual.
This situation explained the resistor condition.
How the field wire was connected between terminal points two and 16 instead of two and three is unknown.
I&C personnel initiated a potential design change and wrote a work request to wire the indicator in accordance with FMR 2695.
On May 23, 1987, during the rewiring / testing effort, the indicator was broken beyond repair.
That night a temporary modification was initiated to install two digital fluke meters behind the main control board to provide steam pressure and control air pressure indication.
However, the administrative procedure governing the temporary modification process did not require a review to determine whether any procedure revisions were necessary.
Therefore, the channel check procedure was not revised to identify the fluke meters.
This administrative procedure has since been revised to require such a review and was revised prior to the identification of the MSIVLCS situation.
Since the drawings did not agree with the as-built condition of the plant, a Deviation Report (DER) was required to be written.
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Administrative Procedure 12.000.52, " Deviation and Corrective Action Reporting," Step 6.5 requires all Fermi 2 organizational
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unit supervisors and personnel be responsible for determining the need for initiating a DER.
Failure to write a DER is considered an example of violation (341/87026-02d(DRP)) of 10 CFR 50, Appendix B Criterion V.
10.
Startup Test Witnessing and Observation (72302)
The inspectors reviewed portions of startup test procedures, reviewed procedure results completed to date, toured the areas containing system equipment, interviewed personnel, and obse-ved test activities of those startup tests identified below.
During this review, the inspectors noted that the latest revision of the test procedure was available and in use by crew members, the minimum crew requirements were. met, the test prerequisites were met, appropriate plant systems were in service, the special test equipment required by the procedure was calibrated and in service, the test was performed as required by approved procedures, temporary modifications such as jumpers were installed and tracked per established administrative controls.
The inspector observed the performance of STUT. 03F.015, "HPCI System--Cold Vessel Injection," and STUT. 03E.015, "HPCI System--Hot Vessel Injection."
During the performance of these tests, problems were encountered which resulted in an overspeed turbine trip, HPCI injection valve tripping on thermal overload and overpressurization of the HPCI suction line.
The cold vessel injection and hot vessel injection tests will be reperformed as a result of repair and modification to the HPCI system to correct these problems.
No violations or deviations were identified in this area.
11.
Report Review (90713)
During the inspection period, the inspector reviewed the licensee's Monthly Operating Report for May 1987.
The inspector confirmed that the information provided met the requirements of Technical Specification 6.6.A.3 and Regulatory Guide 1.16.
No violations or deviations were identified in this area.
12.
Plant Trip (93702)
Following the plant trips on June 25, 1987, and July 20, 1987, the inspectors ascertained the status of the reactor and safety systems by observation of control room indicators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant chemistry.
The inspectors verified the establishment of proper communications and reviewed the corrective actions taken by the licensee.
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All systems' responded as expected, and the plant was returned to t
operation on June 28, 1987, and July 23, 1987, respectively.
00violationsordeviationswereidentified.
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13.
Management Meetings (30702)
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.
senior licensee and NRC management met in Region III
,
a.
On June 29, 1987,
,
s to discuss the licensee's request to operate the Fermi 2 plant at power levels up to 7S4 of rated thermal power.
The licensee and NRC concluded that favorable consideration of the licensee's earMcr March 27, 1987
'
-request to exceed 50% power would not be provided at this time due to current plant operational problems.
b.
On Juiy 7, 1987, the Regional Administrator and members of the
Region III staff met with licensee management regarding the unplanned
'
mode change on June.26' 1987.
,
14.
Unresolved Items Unresolveditemsaremattersaboutwhichmoreinformationisrequired
in order.to ascertain whether they are acceptable items, violations or deviations.
An unrescived item identified during the inspection is
' discussed in Paragraph 5.c.
15.
Exit I_nterview (307031 The inspectors met with licenste representatives (denoted in Paragraph 1)
on July 16, 1987, and informally throughout the inspection period and
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summar,ized the scope and findings of the inspection activities.
The inspectors also discussed the likely informational content of the
'
inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any such documents / processes as proprietary.
The licensee acknowledged the findings of tMs inspection.
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