IR 05000341/1989011
| ML20246K471 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 07/07/1989 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20246K438 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.C.5, TASK-TM 50-341-89-11, GL-87-06, GL-87-6, IEIN-87-008, IEIN-87-8, NUDOCS 8907180184 | |
| Download: ML20246K471 (38) | |
Text
{{#Wiki_filter:._ __ ___ _, -. . I U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-341/89011(DRP)
Docket'No. 50-341 Operating License No.-NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name: Fermi 2 Inspection At: Fermi Site, Newport, Michigan Inspection Conducted: April 11 through June 5, 1989 . Inspectors: W. G. Rogers S. Stasek P. Pelke K. Ridgway Approved By: Mark A. Ring, Chi M D ' Reactor Projects Sec ion 3B Date Inspection Summary Inspection on April 11 to June 5, 1989 (Report No. 50-341/89011(DRP)) Areas Inspected: Action on previous inspection findings; operational safety; maintenance; surveillance; followup of events; LER followup; NUREG 0737 action items; TI 2515/100 followup; CAL followup; operating experience reviews; organizational changes; generic letter review; information notice review; management meetings; strike preparation; and regional requests.
Results: Five violations were identified (Paragraphs 2, 3 and 4) and two examples.of an apparent violation (paragraphs 2e and 3a) were also identified.
No unresolved items were identified and three open items were identified (Paragraphs 4, 6 and '7).
I Q D G ' _ _ _ _ _ _ _ _ _ _ - - - - - - - i
. _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ . . DETAILS 1.
Persons Contacted a.
Detroit Edison Company
- P. Anthony, Licensing
- S. Booker, Principal Engineer, Maintenance
- C. Cassise, General Supervisor, Electrical Maintenance
@#5. Catola, Vice President, Nuclear Engineering and Services @#G. Cranston, General Director, Nuclear Engineering
- P. Fessler, Director, Plant Safety
@J. Flynn, Senior Attorney @*#D. Gipson, Plant Manager @*#L. Goodman, Director, Licensing @R. Kelm, Director, Nuclear Security @J. Lobbia, President
- P. Lovallo, Senior Engineer, Chemistry
@W. McCarthy, Chairman of the Board '
- R. McKeon, Superintendent, Operations
@P. Marquardt, General Attorney
- R. Matthews, Superintendent, Maintenance
@*#W. Orser, Vice President, Nuclear Operations
- E. Page, Risk Assessment Engineer
- J. Pendergast, Licensing Engineer
- L. Schuerman, General Supervisor, Nuclear Engineering
- A. Settles, Superintendent, Technical Engineering
@#R. Stafford, Director, Nuclear Quality Assurance and Plant Safety ^#F. Svetkovich, Assistant to the Plant Manager @B. Sylvia, Senior Vice President @#G. Trahey, Director, Special Projects
- W Tucker, Assistant to the Vice President J. Walker, Plant Engineering General Supervisor b.
U.S. Nuclear Regulatory Commission @A. Bert Davis, Administrator, RIII @J. Grobe, Director, Enforcement @R. Knop, Projects Branch Chief, RIII @J. Lieberman, Director, Office of Enforcement @J. Luehman,' Senior Enforcement Specialist @J. Partlow, Associate Director, NRR
- P. Pelke, Inspector
- K. Ridgway, Inspector
@M. Ring, Projects Section Chief, RIII @*#W. Rogers, Senior Resident Inspector @J. Stang, Project Manager, NRR
- S. Stasek, Resident Inspector
@ Denotes those attending the Enforcement Conference on April 27, 1989.
- Denotes those attending the exit meeting on May 5,1989.
i l
- Denotes those attending the exit meeting on June 12, 1989.
-__ __-
_ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ _ _ _ _ _ ____ __ -_____ ____ _-_ _ - - _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ - _ ___ -.~
- ,
a
- )
The inspectors also interviewed others of the licensee's staff during i this inspection.
) 2.
Action on Previous Inspection Findings (92701) ..i a.
-(0 pen) Open Item (341/88037-16(DRP)): Procedure FIP-cal-01 was not always followed in practice.
The Diagnostic Evaluation Team (DET) was concerned with several aspects of the Deviation and Corrective Action Reporting Program.
One concern was the compounding of Deviation Event Reports (DER) by adding similar events or problems into an existing DER or combining separate events or problems which could have different root causes into one DER.
This clouded the determination of root cause and defeated the trending of both event frequency and root causes.
The licensee revised DER numbering to permit assigning more than one problem to a DER and to assign more than one cause. code in those cases where it would be important to trend multiple causes.
The practice of consolidating DERs with identical corrective actions and causes has been discontinued.
The other DET concern of having separate systems for the tracking ' and trending of DERs remains open.
These separate systems are to be combined into one computer system and this is expected to be completed in August 1989.
b.
(0 pen) Open Item (341/87020-01(DR.P)): EXO Sensor Action Plan.
In the last review of this item, Inspection Report 341/89002, the loss of electrolyte by evaporation had been corrected by plugging vent holes in the sensor, which were installed for ambient pressure changes. This change extended the sensor life up to four and one-half years.
This item was left open until the new testing schedule of three month intervals versus monthly intervals and the sensor change out schedule from six months to three years, could be initiated and approved.
This should take place before June 1989 when the next six month change out is due.
Because of the long period of time between sensor change outs, the inspector questioned whether there should be a shelf life placed on the spare sensors that may be stored in the warehouse for up to nine years.
The licensee agreed to review this issue.
c.
(0 pen) Open Item (341/89008-03(DRP)): Control Center Heating and Ventilation (CCHVAC) fan failure.
On February 9, 1989 the Division II supply fan experienced high vibration.
Upon shutting down the fan the mounting bracket bolts were found sheared.
Subsequently, that division of CCHVAC was declared inoperable and DER 89-0235 was written.
Work request 010C890209 was initiated to investigate and repair the fan.
During the investigation maintenance personnel observed an undercut on the fan rotor.
This undercut may have allowed an excessive gap between the rotor and the bearings. The bearing grease was observed to be hard and old even though there were periodic. lubrication requirements for the bearings.
These two conditions indicated that the sheared bracket bolts were the result of the fan vibration and not due to improper torquing of the bracket bolts.
DER 89-0259 was initiated on February 16, 1989 discussing the rotor undercut condition.
On February ]2, 1989, replacement
_ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _
_ - _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ -. ._ _.
. ' . i . parts were installed into the fan housing and testing of the repaired fan was completed.
During the testing a high amperage condition was noted which is discussed in unresolved Item 341/89008-04.
The failed fan components were sent to-the licensee's Engineering and Research Department (ERD) to determine the failure mechanism.
At the end of the inspection period the inspector was verbally informed of the ERD results.
The failure mechanism was attributed to the hard, old1 grease.
This matter will remain open pending review of the written ERD investigation results and any appropriate corrective action, d.
(Closed) Open Item (341/87016-02(DRS)): Deficiencies in the operator training program for Cycle 4-86.
This open item was based upon the requalification program prior to October 1987 (two year license intervals).
The current requalification program is based upon a six year license interval.
Therefore, this open item is no longer applicable and is considered closed.
e.
(0 pen) Unresolved Item (341/89008-05(DRP)): Standby Gas Treatment (SGTS) System hardware and procedural concerns identified during inspector walkdown.
The licensee subsequently addressed five of the ' six areas of concern and the inspector has no further questions on those matters.
However, the area concerning design and testing of air operated containment isolation valves with dual solenoids remains at issue.
The. inspector originally identified five valves which appeared not to be properly surveillance tested in accordance with Technical Specifications. The licensee review subsequently determined j that a population of 16 valves was involved: ' T46-V402, SGTS Drywell Isolation T46-F411, SGTS Drywell Isolation Bypass T46-F400, Suppression Chamber Isolation Damper T46-F401, SGTS Suppression Chamber Exhaust Air Purge T46-F412, SGTS Suppression Chamber Exhaust Air Bypass T48-F404, Sui;ression Chamber Inlet Isolation T48-F405, Suppression Chamber Purge Isolation T48-F407, Drywell Purge Isolation T48-F408, Drywell Nitrogen Supply Isolation T48-F400, Suppression Chamber Nitrogen Supply Isolation T48-F454, Pressure Control Drywell Makeup T48-F453, Pressure Control Drywell Vent T48-F410, Suppression Chamber Nitrcgen Supply Isolation T48-F456, Pressure Control Nitrogen Supply Isolation T48-F457, Pressure Control Inlet Isolation T48-F458, Pressure Control Exhaust Isolation The licensee's original test methodology was via performance cf surveillance procedure 44.020.002, "NSSS - Division II, Logic System Functional Test," and surveillance procedures 44.020.011 through 44.020.018 and 44.020.109 through 44.020.112 which included response time testing for each initiating signal.
Procedure 44.020.002 simulated the individual containment isolation inputs to the logic causing closure of the applicable isolation valves.
The response time tests verified that the required relaying in the logic train dropped out.
- -- - - , . - e.
, '(* ,[. Y In the dual solenoid. arrangement for the 16 valves. identified above one solenoid is safety-related and the other is balance of plant (B0P).
Both solenoids receive a closure signal from the same.
containment isolation.. initiating signals.
The inspector could not-identify where; differentiation was made between the dual solenoids as to which'one was actually being vented causing valve closure.
The inspector questioned the appropriateness of the licensee not-explicitly testing the safety-related solenoid separate-from the: ' B0P solenoid.
The' licensee initiated a review into the. testing methodology and determined that'the methodology was: inadequate as
identified by the inspector.
Since.the original testing methodology- ); 'did not' adequately demonstrate operability of the subject contain-F ment isolation valves, this is considered a violation (341/89011-01A(DRP)) of 10 CFR.50, Appendix B, Criterion XI, " Test Control."
~ ~ A special test of only the safety-related solenoids was prepared and conducted by the licensee on. April 19, 1989..All 16 valves ' passed the test and were verified operable.
On April'.'21, 1989, as a result of the inspector inquiries into the . configuration and testing of the dual solenoid valves, the licensee identified that the manual containment isolation initiation capability for the 16 valves was being accomplished by the B0P solenoids.
Item 1.h of Table 3.3.2-1.in Technical Specification 3.3.2 requires manual containment isolation capability for isolation groups 14 and 16 amongst others.
Table 3.6.3-1 in Technical Specification 3.6.3 identifies these 16 valves as part of those groups.
The original requirement for manual initiation capability is from IEEE Standard 279-1971, " Criteria for Protection Systems for Nuclear Power Generating. Stations," and was carried forward into the Technical
- Specifications.
The licensee originally considered this requirement met by relying upon the individual open/ closed pushbuttons located in the control room.
However, these pushbuttons only control the BOP solenoids.
The original design for the mtaen valves used solely BOP circuitry / solenoids to accomplish the automated and manual containment isolation function.
In 1984 the licensee recognized that the containment isolation function had to be accomplished with E safety-relat;d components / circuits.
The licensee identified this ! situation and informed the NRC in a 10 CFR 50.55(e) report dated April 16,1984.
In that report it stated "The containment isolation valves in question are solenoid actuated, pneumatic powered valves designed to go to the safe position (closed) on loss of power to the solenoids or loss of air.
As a consequence there was no need for a Class IE power source as long as appropriate safety grade controls were used."
To rectify the design deficiency the licensee installed a second solenoid with accompanying pneumatic piping between the valve and !
L , _.. _
_ _ _.
' - l l , the BOP solenoid.
The new solenoid received a containment isolation automatic signal to vent the valve thereby closing the valve.
l However, the manual isolation capability (the control pushbutton) I was not changed to control the safety-related solenoid but remained connected to the B0P solenoid.
The inspector was informed of the design configuration on April 21, 1989, and the inspector met with the operating authority, plant manager and applicable design engineering personnel that day.
During the meeting, engineering personnel considered the design acceptable.
Some of the rationale was based upon: The manual containment isolation function is not taken credit
for in any accident or transient analysis.
Failure of the automatic or manual circuitry would not innibit
the circuit from functioning.
The manual and automatic circuitry were separated.
'
However, the plant manager determined that the matter should be further reviewed and in the interim another set of switches would be taken credit for to provide the containment isolation function.
These switches were located in the relay room under the control room.
The relay room shares the same environment as the control room and is habitable in an accident.
The switches were test switches and a part of the safety related circuit / solenoid configuration.
The switches had been tested within the requisite Technical Specification surveillance intervals since they were used during surveillance testing.
The licensee changed the applicable operating procedure that day and trained operators as they took the watch on use of the switches.
Based upon these actions the inspector was satisfied that the manual initiation function was present.
The licensee initiated DER 89-0504 on this matter.
During the DER review the licensee determined that IEEE 279-1971 was not met.
LER 89-009 was submitted on the design deficiency.
Failure of the licensee to design the containment isolation manual initiation function for the sixteen subject valves with safety related circuits / components is considered a violation (341/89011-02A(DRP)) of 10 CFR 50 Appendix B, Criterion III, " Design Control."
As a result of the pushbutton circuitry not being safety related, another concern arose as to whether the licensee met post-accident monitoring requirements of Technical Specification 3.3.7.5.
This Technical Specification requires primary containment isolation valve position status.
The technical requirements on what type qualification is necessary for position indication is embodied in j Regulatory Guide 1.97, Rev. 2.
However, NRR has yet to issue a
Safety Evaluation Report (SER) on Regulatory Guide 1.97.
This is scheduled for August 1989.
_ _ _ _ _ _ _ _ _ _ -
_ __ - _ _ _ ._ _ - _ _ _. . . _ l The. inspector contacted the applicable NRR representatives and determined that the isolation valve status design would not be challenged at this time but would be explicitly reviewed for the SER.
Also, the inspector reviewed the licensee's submittal on Regulatory Guide 1.97 and determined that these valves were not discussed explicitly. As such the licensee committed to submit additional information on these valves as part of. their Regulatory Guide submittal.
This item will remain open until this matter is resolved.
f.
(0 pen)UnresolvedItem(341/88003-02(DRP)l: RHR service water discharge valve inservice test requirement.
During the inspection period the inspector met with NRR representatives and a contract representative associated with the inservice test program.
During this meeting the inspector identified the discharge valve and how it is opert ed within the facility.
Based upon that information the initial conclusion of the contract representative was that the valve-belonged in the inservice test program.
The licensee was contacted by the inspector regarding this meeting.
Again, the licensee , reviewed the conditions and noted that this valve was also questioned in the licensee's Safety System Functional Inspection (SSFI) on the RHR system.
The licensee provided the inspector with the response to the SSFI findings and reiterated that the valve did not appear to belang in the inservice test program.
Also, the inspector discussed with the licensee why this valve's position changed from normally open (at the time of the IST Safety Evaluation Report) to normally closed.
The licensee stated that i ! they would retrieve that information and how the valve position changed and whether the inservice test review was performed during that configuration change.
The inspector requested that the licensee and NRR representatives meet to discuss this valve, its application and what testing is warranted, ' g.
(Closed) Open Item (341/84049-22(DRS)): Revision of emergency lighting surveillance procedure to increase the number of lighting units being tested to 20 percent of the units required for safe shutdown.
By an internal letter dated December 22, 1988 from J. A. Hughes, Senior Engineer to T. L Riley, Supervisor Compliance and Special Projects Nuclear Licensing, the licensee staff specified that Procedure 37.000.14 was written and approved to provide the means for performing the 18 month emergency lighting test, including an 8 hour discharge test on 20 percent of the lighting units required for safe shutdown of the plant.
This satisfies this concern.
Therefore, this item is considered closed.
h.
(Closed) Open Item (341/88026-02(DRP)): Changing of the reactor recirculation motor brushes to a more durable type brush.
Under EDP-7599 the brush change out was accomplished in the fall of 1988.
This item is considered closed.
i.
(0 pen) Open Item (341/88035-02(DRP)): Concerns identified while observing general maintenance on the 24/48 VDC instrumentation batteries R32005001 and R3200S002.
DER 89-0269 was issued to track
_ _ _ _ _ _ _
_ _ _ _ _. _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _. _ ._ _ __ - . _. _ _ _ _ _ _ _ - . l; L.
i - the concerns.
On December 18, 1988, while performing Procedure NPP-35.310.002 in accordance with WR No.-003B070288, temporary batteries were connected to supply the loads normally supplied by R3200S001.
No LCO Sheet was completed by the shift for this work request.
In response to NRC questions, the Superintendent, Technical Engineering, issued a memorandum that stated that the 24/28 VDC batteries are indirectly required to maintain compliance to Technical Specification 3.3.7.5.
The memorandum further stated that if the normal batteries were isolated from the loads, the. affected instrumentation must be considered inoperable.
The IRMs were used to take credit for the flux monitoring required in a loss of off-site power event.
Other Technical Specification related instrumentation included the source range monitors, radwaste i effluent radiation monitors, and fuel pool ventilation exhaust monitors.- ! Procedure NPP-0PI-11, Rev. 3, Step 5.3.2 required an LC0 Sheet be completed for all Technical Specification systems and components determined to be inoperable regardless of the plant's opeNcional condition.
Maintenance on R3200S001 rendered source range ' monitoring Channels A and C; intermediate range nonitoring Channels A, C, E, and G; Radwaste Effluent Radiation Monitor RME-K604; and Fuel Pool Ventilation Exhaust Radiation Monitor Indicator and Trip Units Channels A and C inoperable.
Failure to complete an LC0 Sheet
is an example of a violation (341/89011-03A(DRP)) of 10 CFR 50, ' Appendix B, Criterion V, " Instructions, Procedures,.and Drawings."
Corrective action for this violation should include appropriate revisions to the systems training manuals, plant procedures, and the Technical Specification Support System Matrix (which is still under development).
j.
(0 pen) Open Item (341/89008-06(DRP)): On April 12, 1989, during the completion of Work Request No. 002C890408, the east hydrogen ! recombiner fe. rotor was reinstalled without specifying mounting bolt torque values in the work package.
Discussion with workers, foremen and QC personnel indicated that torque values were not normally specified for motor mountings.
The hydrogen recombiner skid is safety-related and seismic. NPP-35.329.002, " General Maintenance of 480 VAC Motors," did not specify that torquing is required.
Procedure NPP-35.000.240, Rev. 20, " Bolting and Torquing," is the licensee's generic bolting and torquing procedure.
This procedure prescribed the method for prestressing bolts and other fasteners and provided limited torque values for bolts and other fasteners when torque values are not specified in other approved procedures / instructions or drawings.
However, this procedure did not specify when torquing values must be prescribed.
Procedure NPP-PS1-01, Rev. O, " Planning of Maintenance Activities," prescribed the method for processing and planning a maintenance activity.
This procedure did not state when torquing requirements must be specified.
Additionally, Part 2(A) of the Work Request Planning Checklist did not list torquing as one of the specific requirements to be considered by the planner in preparing a work package.
Failure to provide torquing acceptance criteria in
_ _ - _ _ _ _ _ _ - _ _ _ _
'., . the work package for Work Request No. 002C890408 is an example of a violation (341/89011-03B(0RP)) of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings."
Due to the inspector's concern in this area the thermal recombiner division was not placed into service without an engineering evaluation as to the correct torquing requirements and the bolts verified to be torqued to those requirements.
k.
(Closed) Unresolved Item (341/89008-04(DRP)): Control Center HVAC fan running with high amperage.
During the second week of March 1989, the inspector queried the licensee as to the acceptability of running with a high amperage condition on the newly repaired CCHVAC
supply fan.
The licensee indicated that the matter had been reviewed'and considered an acceptable situation.
The inspector requested to review'the disposition of this matter with the - appropriate personnel.
At first the licensee provided their verbal evaluation of the condition.
The inspector requested to see the written disposition of the matter and was told that none existed or ' was required.
The inspector requested the engineering personnel explain why amperage in excess of the nameplate rating did not constitute a nonconforming condition with the licensee's design requirements.
Eventually, the engineering personnel retrieved a design calculation, 4322, delineating the maximum acceptable amperage allowed for this fan as 110% of. nameplate based upon a letter dated November 15, 1984, from the fan manufacturer.
Given that the actual condition was 113% of nameplate, a nonconforming condition did exist.
This condition was dispositioned in writing by the engineering personnel as acceptable after an appropriate review.
The inspector pursued as to why thi.s situation was not originally flagged as a nonconforming condition prior to placing the CCHVAC into service.
Based upon interviews and a review of the work package the inspector ascertained that fan repair activities commenced on February 10, 1989.
Fan repair was complete on l February 14, 1989, and post maintenance testing commenced.
During the testing a high amperage condition in excess of the acceptance criteria existed.
In the work request planning section under Step 15 it stated, "Take voltage and current and current must be within 115% of name plate and on the post maintenance testing form 48 amps to 115% of running current is considered the acceptance criteria for performance of this test." Fan flow was adjusted to 113% of the nameplate current.
Even though the acceptance criteria was met maintenance personnel contacted the on-call engineering representative who called one of the electrical engineers.
After consultation the engineer determined that this was an acceptable condition in the short term at 113% of nameplate rating.
The inspector inquired as to why the post-maintenance testing acceptance criteria was set at 115%. Based on these inquires the i inspector ascertained that 115% had been considered the maximum ! I acceptable during pre-operational testing.
At that time the as-found amperage conditions were utilized as inputs into design calculation 4322.
In high amperage instances each fan was handled ,
l ,
- - - - - , l .. !' i l
b l: on a case-by-case basis in design calculation 4322.
The maintenance personnel still perceived the pre-operational criteria as appropriate and utilized 115% as acceptance criteria.
From this review the inspector concluded that the post maintenance testing acceptance criterion was inadequate and should not have specified amperage in excess of the results of design calculation 4322.
This is a violation (341/89011-01B(DRP)) of 10 CFR 50,. Appendix B, Criterion XI, " Test Control."
, Also, when engineering personnel concluded that the 113% condition was acceptable it was without knowledge that design calculation 4322 existed.
This generated a broader concern with the inspector as to the potential overload of the emergency diesel generators (EDG) due i to an increase in current load from the CCHVAC fan or from the cumulative effect of air handling units drawing more current than calculated without an appropriate evaluation of the additional ' load on the EDGs.
In the written evaluation on the specific CCHVAC fan the licensee concluded that running with high amperage was an ' acceptable condition and that the additional amperage loading would cause a three kilowatt increase on diesel 14 and there is 100 kilowatt margin on the diesel.
Therefore, there was no overloading of the EDG.
In response to the broader concern the licensee preliminarily evaluated i high amperage on the air handling units and concluded the the additional loads would have minimal effect on the EDG loadings.
This concern will be folded into the present actions from the RHR SSF1 on control of EDG loads.
1.
(0 pen) Open Item (341/86032-03(DRP)): A review of the loads and the consequences of loss of power to modular power units 1, 2, and 3.
Engineering will complete these reviews on July 15, 1989.
Modular power units 4, 5, and 6 will be completed before the refueling outage this fall.
Also, load and consequence analysis will be part of the modular power unit 4, 5, and 6 review.
! m.
(0 pen) Unrer.olved Item (341/89002-01(DRP)): Secondary containment integrity and the condensate tank for the auxiliary boiler.
As a result of questions with regards to maintaining secondary containment integrity, the licensee intends to establish an action plan to deal with some of the concerns.
This action plan will be completed during the next inspection period.
The inspector will review the action plan once approved.
n.
(0 pen) Violation (341/88037-01(DRP)): Redlining of drawings.
On May 10, 1989, the inspectors took a sampling of Temporary Modifications (TM) and verified whether the drawings associated with the TMs had been redlined.
During the sampling five drawings were observed with no TM or the wrong TM posted against the drawing.
Also one alarm response procedure had not been revised as a result
of a TM.
Technical group personnel were contacted and a 100% reverification of drawing redlining / revised procedures was initiated.
In the discussion with the licensee the inspector ascertained that a new redlining procedure had been enacted in recent months.
This l
! I - _ _ _ _ _ _ _ _ _ _
- - - - p a l .
)
1 procedure excluded the tagging center microfilm drawings.
The licensee is revising the TM procedure to annotate the microfilm drawings in the automated records management system (ARMS). _Since this procedure has yet to be issued the potential existed for a TM to be implemented without the microfilm drawings being annotated against the TM.
Technical group personnel were immediately directed to assure that those drawings were annotated for any TMs issued before the revised procedure is issued.
o.
(0 pen) Open Item (341/88026-03(DRP)): Installation of star lugs.
The licentee documented the NRC concern with the utilization of star lugs in DER 88-2000.
In resolving DER 88-2000, the licensee indicated that during the first week of June, star lug installation would commence.
Star lug installation will be accomplished through the use of temporary change notifications to appropriate surveillance procedures.
Also, a log will be'kept of star lug locations, an administrative procedure is being written on star lug control and the procedure review checklist will be revised to consider star lug installation / removal.
, p.
(Closed) Unresolved Item (341/88037-07(DRP)): One hundred-fifty (150) procedures overdue for two year periodic review.
The inspector contacted the Supervisor of Procedures and Coordination to discuss whether there were 150 procedures overdue.
Based upon this discussion the inspector ascertained that there were a significant number of overdue procedures during the diagnostic evaluation team (DET) inspection.
Evidently, as a result of the site wide procedure rewrite effort a number of procedures did not receive their prescribed periodic review.
Through discussion with the Procedures and Coordination Supervisor the inspector ascertained that an audit, A-QS-P-87-34-04, was conducted in late 1987 and identified the two year periodic review was not being performed in accordance with Technical Specification 6.8.3.
The audit findings were presented to the Plant Manager on or about January 21, 1988.
As a result of this audit finding, corrective action was established for the Supervisor of Procedures and Coordination to monthly inform the appropriate section heads through a memo of those procedures that were overdue.
As a result of these efforts the percentage of procedures overdue dropped from the original 3.2 percent in March 1988 to 2.5 in April to 2.1 in May of 1988.
The Quality Assurance audit finding was closed out based upon QA's determination as stated, " Evaluated results for the past three months in order to determine the effectiveness of section heads to complete the overdue periodic reviews.
The results are as follows: March 3.2 percent; April 2.5 percent; May 2.1 percSt remaining overdue.
Since a declining trend has been evident for the past three months, it is determined that the corrective action taken has been effective.
This finding is considered closed." The audit finding was subsequently closed out on June 7, 1988.
However, by the end of October 1988, as identified in Memo PC-88-0034 dated November 30, 1988, there were 125 procedures that were overdue, 40 of which had been reviewed and required revision, 85 which had not been reviewed for revision, and 51 that were in suspension.
This was the report that the Diagnostic Team Members reviewed along with previous reports that had shown a decrease in the number of overdue procedures, but still
- _ _ - - - -
I._ ~ ~ ~ .g - - t
Y ' r ., f '.
- a continuation of overdue procedures beyond the two year periodic reviews. -The inspector reviewed the last two reports for April and May 1989 and noted that there were no overdue procedures for the two year periodic review. 'However, the failure to perform i
the'two year periodic review at the. time that this matter was identified is considered a violation (341/89011-04(DRP)) of Technical Specification 6.8.2.
It should be noted that the corrective actions.' appear adequate,.though slow, as evidenced by the~1ast two month's overdue procedures report.
Therefore, a response to this violation is not necessary.
With regards to the adequacy of the quality assurance department-- closing the audit finding based on a declining trend the inspector showed this audit to.the quality assurance manager.
The manager did not consider'this an acceptable method for resolving audit findings.
He initiated.a review of all 1988 audit findings and determined that this was the only finding handled in'this manner.
The inspector considered the handling of this audit finding as an isolated occurrence and a violation unnecessary.
, The inspector pursued what involvement the offsite oversight , committee, the Nuclear Safety Review Group (NSRG), had in reviewing this Technical Specification violation.
Technical Specification 6.5.2.7.e requires NSRG review violations of Technical Specifica-tions.
The inspector discussed how a Technical Specification violation identified'in an audit finding is reviewed by the NSRG.
The inspector ascertained that audit findings are on distribution to the NSRG secretary who provides them to the audit subcommittee and any other interested committee member for review.
After discussion with the secretary the inspector ascertained that the audit finding was reviewed at meeting 88-01.
However, given the time frame of the teeting, the final resolution of the audit finding was not reviewed.
Then the inspector explored how Technical Specification violations identified on'a deviation event report (DER) are brought to the attention of the NSRG.
It was apparent that any DERs requiring 50.73 reporting would be reviewed as part of the LER review.
The ' inspector then selected a DER which identified a Technical Specification violation which was not required to be 50.73 reported.
DER 89-0314 was selected.
This DER dealt with two quality assurance audits being conducted outside of the required twelve month interval.
Through discussion with the NSRG secretary the inspector ascertained that all DERs are submitted to the NSRG secretary who screens them for referral to the appropriate subcommittee or the main body of the committee.
In this particular instance the DER was given to the audit subcommittee for review.
The subcommittee chairman had concerns with the DER and the subcommittee chairman, the secretary of the NSRG, and the QA manager met to discuss the DER and the resolution to the DER.
The meeting concluded with the subcommittee chairman comfortable with the actions being taken.
The matter never was brought forward to the full membership of the NSRG.
Furthermore, in the discussion
, - - _ _ _ - _ - _ - _ _ _
. . with the NSRG secretary it was noted that there is no charter for 'I , the audit subcommittee.
The interface between the_ subcommittee responsibility to the whole body of the NSRG will be pursued in a future inspection report.
Then the inspector explored how the Onsite Review Organization (OSRO) carried out reviews of non-50.73 reportable Technical Specification violations.
Technical Spec)fication 6.5.1.6.f establishes the OSR0 as responsible for investigations of all violations of the Technical Specifications, including the preparation and forwarding of reports covering evaluation and recommendations to prevent recurrence, to the Vice President-Nuclear Operations and to the Nuclear Safety Review Group.
The inspector discussed the matter with the head of plant safety who stated that he reviewed all DERs for placement on the OSR0 agenda.
The head of plant safety stated he would not have necessarily flagged Technical Specificatica violations of Section 6, administrative controls, for OSR0 review.
He considered Section 6 different than the rest of the Technical Specifications.
The inspector informed the plant safety , head that the pnly difference dealt in the deportability aspect of a Section 6 violation.
The head of plant safety directed a review of the DER logs for Section 6 violations.
Forty-four were identified and subsequently reviewed by OSR0.
The failure of OSR0 to review the Section 6 violations is considered a violation (341/89011-05 (DRP)) of Technical Specification 6.5.1.6.f.
However, given the corrective action taken by the licensee and the understanding the head of plant safety now has on what needs to be referred to OSR0, no further action to this violation is warranted, q.
(Closed) Open Item (341/86007-03(DRP)): Establishment of vibration testing criteria for the high pressure core injection (HPCI) pump.
The inspector reviewed Procedure 24.202,01, "HPCI Pump Operability and Flow Test of 1,000 psi and Valve Operability." The procedure prescribed the ASME inservice test requirements to be performed at least once every 92 days.
Inclusive in this testing was vibration
data on the pump with appropriate acceptance criteria.
This item is considered closed.
i r.
(Closed) Violation (341/87026-01(DRP)): High pressure coolant l injection (HPCI) test return line to the condensate storage tank
isolation valve, E41-F011, found energized in violation of License l Condition 2.c(9)(a).
The inspector verified proper positioning and i deenergization of this valve is included in the current revision of system operating Procedure 23.202, "High Pressure Coolant Injection System," as well as surveillance Procedures 24.202.01, "HPCI Pump Time Response and Operability at 1000 psi," and 24.202.02, "HPCI Flow Rate Test at 165 psig Reactor Steam Pressure." Proper l configuration of E41-F011 was also included in operator initial and ' requalification training programs, with the information of concern specifically provided as part of lesson Plan ST-0P-315.039-001 , (Rev. 5).
This violation is closed.
s.
(0 pen) Open Item (341/89002-04(DRP)): Weaknesses in communications between control room operators and personnel performing activities
_ -
- _ - _ _. .. . affecting the configuration of important plant equipment.
To date, Procedure'44.160.02, " Fire Protection Detection Operability and Functional Test," has not been revised.
Additionally, another example to be included under this item is discussed in Paragraph 3.
No other violations or deviations were identified in this area.
3.
Operational Safety Verification (71707) The inspectors observed control room operations, reviewed applicable logs
and conducted discussions with control room operators during the period from April 11 to June 5, 1989.
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.
During the inspection, the inspectors walked down the accessible f portions of the following systems to verify operability by comparing ' system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could degrade performance; and verified that instrumentation was properly valved, functioning, and calibrated.
Standby Liquid Control System Core Spray System - Division II Standby feedwater System Emergency Diesel Generator No. 13 Emergency Diesel Generator No. 14 The inspectors also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barreling.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedures.
a.
During the inspection period the inspector noted that Division I CCHVAC was in off/ reset with the supply fan, recirculation fan, exhaust fan, chiller pump and cooling coil pump control switches flashing.
This is a normal condition and a normal alignment for one CCHVAC division and the division is considered operable by the licensee even though it is in off/ reset.
The inspector pursued why this alignment was considered acceptable.
In conversations with the operating authority the inspector was told that both CCHVAC
- _ _ _ _ _ _ _ _ - _ _ _
-- - - - _ - _ - _ _ _ _ _ _ _ _ - - _ _ _ _ _ - _ _ _ _ _ , f ,y divisions cannot initiate and operate simultaneously without overpressurization of the ductwork. :The inspector reviewed the: . UFSAR and.the SER and determined that having one division in L off/ reset was acceptable but no reason was given.
- The inspector began to investigate whether a. single failure in the off/ reset division of CCHVAC could cause that division to initiate along with the other~ division which.was in automatic.
After a review of the schematic drawings the inspector noted that the . recirculation fans could initiate simultaneously and operate with a
- '
single active failure in the logic circuity.
Then:the inspector' pursued whether.the perception of the operators of overpressurization of the ductwork in such a condition truly existed.
The inspector-contacted the engineering department to ascertain this.
During the' review for this condition the~ licensee identified that' the CCHVAC ductwork on the suction of the recirculation fans was ' not designed in accordance with statements in the UFSAR.
In UFSAR - Appendix A, "Conformance to Regulatory Guides," Item A.1.52 , committed the licensee to designing the CCHVAC ductwork in accordance with an Oak Ridge National Laboratory standard, ORNL-NSIC-65, for this particular section of ductwork.
The applicable tables of Section 2.8.1.of the ORNL standard required , - 18 ga. sheet metal' for the reinforced spacing used but the actual construction was of 16 ga. sheet metal.
Failure to design the CCHVAC ductwork to the appropriate regulatory standard is. considered an example of a violation (341/89011-02B(DRP)) of 10 CFR 50, Appendix B, Criterion III, " Design Control."
On April 20, 1989, the licensee initiated DER 89-0508 stating that the oesign of the duct work was not in conformance with ORNL-NSIC-65. Also, the design calculations on the ductwork had not assumed that CCHVAC would be in service during a postulated earthquake. -Therefore, earthquake loading had not been added to the system operating stresses.
The licensee performed a technical evaluation as to the ramifications of not designing the ductwork in accordance with the approved standards including earthquake loading.
The licensee determined that the ductwork would experience some slight deformation reducing the flow area by 6 percent but would still be able to meet the minimal flow' requirements for CCHVAC as prescribed in the Technical Specifications.
Based upon the technical evaluation results the licensee concluded that the CCHVAC system was operable.
LER 89010 was subsequently written on the .. > design deficiency and submitted to the NRC on May 22, 1989.
l In the original DER determination the engineer and the reviewer of j the DER failed to check the blocks associated with a 10 CFR 50.59 review, a potential 10 CFR 21 or a significant condition adverse to quality (SCAQ)..This situation was identified by the Safety Group Reviewer and and the blocks were subsequently checked.
However, the block associated with 10 CFR 50.59 was checked yes with a note to see further information in the DER.
Further information in the DER states, "A safety evaluation will be prepared
-..... . _ _ - _
I . . if the analysis resulted in a UFSAR change or a design change." On i May 30th the inspector brought this to the attention of engineering i management.
The specific questions were why a safety evaluation was j not already performed or why the technical evaluation that was performed for operability of the.CCHVAC ductwork was not in the form of a safety evaluation.
It was clear that the design of the CCHVAC was not in conformance with the committed standard identified in the UFSAR.
Engineering management stated that a safety evaluation was appropriate and one was initiated.
The inspector discussed the overpressurization aspect of dual recirculation fan operation with the cognizant engineer who discovered the original design deficiency.
Upon a review of the fan discharge capacities the engineer's perception was that there was adequate margin for dual fan operation.
However, a final review was needed.
The inspector will pursue this matter in a future inspection period.
Also, the inspector noted that another DER, 89-0588, was written as an additional investigation into the CCHVAC ductwork.
This ' DER identified that a portion of the ductwork had not been preoperationally leaked test.
The inspector reviewed the DER and the initial resolution evaluation which stated,'" Engineering has performed a quantitative assessment of the expected leakage in the duct work assuming the same quality of construction as other duct work that was leak tested the results are as follows." However, later in the OER it stated, "It is recommended that a visual inspection of the duct work be performed to indeed determine if the duct work is of the same quality of construction as other tested duct work." It is questionable as to the adequacy of this resolution given that the duct work was not inspected.
The inspector brought this to the attention of engineering management on May 30th for-further review and determination as to the acceptability of this type of resolution.
The inspector will pursue this matter in a subsequent inspection period.
b.
On May 18, 1989, the Operations Superintendent notified the Senior Resident Inspector of a significant operational occurrence that had occurred earlier during the day.
The Operations Superintendent recounted that on the previous day, during swing shift, the Standby Liquid Control (SLC) system had been taken out of service for ' surveillance testing.
The system was not returned to service until nine hours later on graveyard shift.
Technical Specification 3.1.5 requires an inoperable SLC system be returned to service within eight horrs or be in at least hot shutdown within the next twelve hours.
On-shift operations personnel were unaware that they entered i~ i the twelve hour shutdown portion of the Technical Specification l until after the system was returned to service.
Subsequently, DER 89-0610 was written on why personnel didn't understand where ! they were in the Technical Specification action statement.
The ! Operations Superintendent stated that a critique of this matter j would be accomplished.
- 1
_ - _ - _ - __ _-- - __ _ ., - ,g ... f.
L Later the. inspector'was furnished with the critique.
From the " critique the inspector ascertained that.one of the two divisions of SLC had been taken out of service for preventative maintenance on dayshift, May 17,'1989.
This placed the licensee into a seven day limiting condition for operation (LCO) action statement after which the unit must be placed'in hot shutdown within 12 hours.. Main-tenance was completed at the end of dayshift and surveillance-o ' testing was required prior to declaring the division operable.
However, during the surveillance testing the the common suction valve to both SLC pumps must be closed.
Therefore, the test . rendered both divisions inoperable which is an eight hour LCO action.
' statement.
Testing was assigned to a licensed reactor operator and a power plant operator.
The test was approved to be performed by the swing shift operating crew and testing commenced. 'In the approval of the test the operating crew failed to recognize'that the-SLC system would be rendered. inoperable.
No formal briefing was held on the testing evolution.
At.1745 the suction valve was closed and the eight hour LC0 entered, though the operating crew was not aware of this.
Also, the testing reactor operator did not identify that , , an eight hour LC0 was initiated.
At 2100, partially through the testing, problems were encountered.
To resolve all the problems . consultation with the assistant shift supervisor (NASS) and the shift supervisor (NSS) along with the approval of a temporary.
procedure change by.the NASS and NSS were required. During the review of the change the shift supervisor recognized that the suction-valve;was closed.
The shift supervisor made a' decision that the SLC system could be considered operable with the common suction valve from the tank to the two SLC pumps closed provided an operator was stationed at the valve.
By the end of the shif t the procedure change was approved and the completion of the testing would have to be accomplished on graveyard shift.
The NSS and NASS discussed the configuration of SLC.
The conclusion of the conversation was that the eight hour LCO would be entered into at the point that the valve had been closed.
The NSS chose that time to have been when.the testing problems were encountered at 2100 not the actual time of 1745.
The NSS did not consult the testing reactor operator but assumed 2100 was the appropriate time.
In the process of turnover the offgoing NASS informed the. oncoming NASS that they were in the eight hour LC0 which expired at 0500.
The offgoing NSS did not provide this information to the oncoming NSS and did not log that the short term LCO had been entered even though Procedure NPP-0P-11 Section 5.3 required such an action.
Subsequently, in the shift meeting the oncoming NASS notified the oncoming NSS that they were in the eight hour LC0 action statement.
SLC testing resumed and was completed with the cystem returned to service at 0245.
Corrective actions in the critique included: Addition of a caution in the SLC surveillance procedure to
specify that an eight hour LC0 is being entered.
. _ - - - _ _ _ _ _ _ _ _ _ _ _ _
- i
) - i Add a step in the SLC surveillance procedure for the NSS to
acknowledge the new caution statement.
I Require logging of the time the suction valve is closed.
- i I
Review by all licensed personnel of NPP-0P1-11.
- Issue a night order informing operating personnel of the
problems encountered while performing thc SLC surveillance.
Add this problem into the Technical Specification case study
program.
Evaluate the need to flush the SLC system following
surveillance testing per Procedure 24.139.02.
Add the critique to licensed and non-licensed required reading.
- All corrective actions would be completed by August 1, 1989.
, The inspector conducted selected interviews with individuals involved in this matter and generally confirmed the accuracy of the critique
and how the problem was identified.
The oncoming NSS was bothered by the'offgoing NSS not informing him that he was in an 8 hour LCO action statement to the point of re-reviewing the logs associated with the surveillance testing and the control room log.
Without satisfactory resolution in those documents he proceeded to review the surveillance log and noted the time frame in which the surveillance had begun.
He again reviewed the surveillance and noticed that the first step required that the suction valve to be closed and concluded that the tiine frame of the LC0 action statement that they were currently in could not be proper.
Therefore, he contacted the offgoing shift and ascertained the decision made by the NSS. -He subsequently stated that he did not consider this an appropriate manner in which to handle the SLC system.
At this point in time the LC0 action statement had in fact been exceeded by approximately an hour and the system was being returned to service.
The NSS informed the Operations Engineer of the situation and DER 89-0610 was initiated.
The failure of the shift crew to not recognize that they entered into an 8 hour LC0 for the SLC system is considered another example of a violation (341/89011-03C(DRP)) of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings," in that procedure NPP-OP1-11 was not followed.
Even though this violation was licensee identified other violations in this area have been given in the last two years.
Another matter came to the inspector's attention during these interviews.
The inspector concluded that this matter was not a contributor to the SLC problem but was of concern to the inspector.
When swing shift assumed the watch the production schedule was considered excessive by the shift supervisor resulting in the NSS not concurring with the schedule.
The NSS performed those tasks he
- _ _ _ _ _ _
. D felt capable of performing but the schedule was never revised.
The inspector discussed this situation at the exit and stated that routine inspector observations would include scheduling interaction / approval by the operating authority.
No other violations or deviations were identified in this area.
4.
Monthly Maintenance Observation (62703) Station maintenance activities on safety-related systems and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.
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 I inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality ' control records were maintained; activities were accomplished by qualified personnel; parts and materials 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 tn assure that priority is assigned to safety-related equipment ' maintenance which may affect system performance.
The following maintenance activities were observed:
WR No. R036890328 PM on 130V Battery Charger R325021B e WR No. 00781222 Seal leaks on Standby Coolant Pump for EDG 12
WR No. 009C890310 Drain Valve Plugged - R30F041C I
WR No. 839890328 Semi-annual PM on EDG 12.
- WR No. R088890328 Inspect, Lube, and Test MOV R30F607
WR No. Y$85890328 Clean SGTS CO2 Tank Condenser Coil Fins
WR No. T016890228 PM North SGTS Exhaust Fan
WR No. T024890328 PM North SGTS Cooling Fan
WR No. A5548904 PM T4100B016 SGTS North Room Essential Cooling Unit
WR No. 004C890602 Replace Backup Manual Scram Circuit Interrupter Pertinent observations were: a.
During the PMs on the SGTS equipment, the inspector verified that , l the different greases used in the field matched the CECO Database.
b.
During the PM on R325021B (Procedure NPP-35.309.001), procedural problems occurred in that the hardware did not match the procedural requirements. For example, Step 4.1.3 required the application of 0 volts to the voltmeter and verification that the meter read in the range of -3.0 to 3.0 volts.
However, the voltmeter on the charger reads from 75 to 150 volts.
Additionally, other procedural problems !
-_ _
_.
_- _ -. _ . __ . g
a- ,
,, ,
were' identi fied.
Subsequently,-Rev. 23 to the procedure was issued
and the PM was completed.
The inspector noted that these procedural inaccuracies caused delays and ultimately'resulted in the PM p ', ~ . spanning two days.
On the first day the electricians left the job' site with a Technical Specification (TS) fire door (barrier) blocked open.
This was [- identified by a security guard on patrol who notified the NSS and the. door was subsequently closed.
On the'next day,.May 3, 1989,- .while the inspector was watching the job, both electricians left to' .go to the control room with two TS doors blocked open. The inspector. remained ~in the area.
When the electricians returned, the inspector _ asked them what their responsibilities were.regarding the blocking of TS fire doors. open.
They responded that as long 'as' they notified the NSS that.thel doors would be opened at the start of'the job there'was..no need for them to stand fire watch.
Further review by the inspector determined that a fire watch must be. maintained in this case,at all times while the doors were blocked open by a person who has been properly. qualified-.in accordance with TS 3.'7.8.
, .The situation was identified to cognizant maintenance management personnel.
A meeting was held with craft. personnel to discuss their understanding of the' fire watch requirements.. The'results _ of the meeting revealed that craft personnel had the same general l perceptions as the individuals on the battery job.
The inspector also determined that only select maintenance journeyman are' fire watch qualified. This appears impractical since in the course of a journeyman's activities a TS fire door is eventually going to'be blocked open requiring a qualified fire watch.
DER 89-0565 was written to track this concern.
DER 89-0565, Part .5A, stated that Nuclear Training is modifying the training program to specifically state the responsibilities of a fire watch as they pertain to leaving a fire barrier breached and that fire watch will be included as a topic for the next continuing training cycle.
Failure to maintain adequate training for TS 3.7.8 fire watches is a violation (341/89011-06(DRP)) of 10 CFR 50, Appendix B, Criterion II, " Quality Assurance Program.*' Ouring followup activities, the inspector noted that DER 89-0565 l was assigned to Maintenance for disposition and it was subsequently routed to Plant Safety for review.
No interface was established with Operations to document any corrective actions that they would take to prevent recurrence, e.g., remind journeymen of their responsibilities when TS door is blocked open, verification that the journeymen are qualified fire watches, etc.
c.
Review of Generic Lubrication Program Concerns Based on 17 DERs written on equipment lubrication concerns and NRC
open items, the licensee issued DER 89-0529 on April 28,1989, to a document and resolve the generic concerns.
On May 16, 1989, the ] i l
1 _ _ _ - _ _ - _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ - _
_ . _ _ - - _ _ _ _ __ _ _ _ _ _ _ -- _ _ _ - - _ _ - - - - - _ _ _ - _ - _ - _ _ - - - _ - - - _ _ - - - _ - - p' W J l . , -I +
- , f , U Plant' Manager issued a memorandum with an enclosed action plan.. The plan contains'18 actions recommended to strengthen the lubrication-program.
Resolution of DER 89-0529 and implementation of the action plan is an Open' Item (341/89011-07(DRP)). DER 89-0579 was issued on May 8,1989, for incorrect lubricant in the EECW Pump motors.
A previously completed PM on P4400C001B ' documented the use of Shell Alvania 2EP for lubrication of the pump motor bearings. The CECO Database specifies Dolium R.
Preliminary investigation indicates the same condition exists for P4400C001A.
The' hardcopy lube manual, Re' v. B, dated March 1986, specified the' wrong-grease.
The new CECO computerized database has the correct grease specified.
Additionally, the environmental qualification letter, EQ1-EF2-280, Rev 1 fcr P4400C001A/8, had the incorrect ;;rease specified since it was dev11oped based on the March 1986 lube manual.
This may be a conce'n in that the EQ personnel who developed the EQ letter obtained their information from the lube manual rather than independently checking vendor manuals / environmental qualification reports.
Disposition of , DER 89-0579 will be tracked under the previous open item.
- No other violations or deviations wer-identified in this area.
5.
Monthly Surveillance Observation (61726) The inspectors observed the following surveillance testing required by ' Technical Specifications and verified that: testing was' performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operatico were met, removal and restoration of the affected components were accomplished, test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate managetrent personnel.
- 24.610.05 RPS - Backup Hanual Scram Functional Test
24.405.03 Secondary Containment Integrity Test ,
24.307.14 Emergency Diesel Generator No. 11 - Start and ' Load Test i
24.307.15 Emergency Diesel Generator No. 12 - Start and Load Test No violations or deviations were identified in this area.
6.
FollowupofEvents(937021 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 notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted - _ - _ _ _ __.-___-_m___- _ - _ _ _ _ _ _ _ _ _ _ _ - _
- - - - - _ _ _ _ - _ _ - _ _ _ - _ _ - - ' e, ,, within regulatory requirements and that corrective actions would prevent ' future recurrence.
The specific events are as follows: j '
- April 17, 1989 Fire in the Availability Improvement Building.
&
h); April 20,~ 1989 Control Center HVAC Potentially Outside of Design' ~' Basis.
May 25, 1989 HPCI Level 8 Trip Found Outside of Allowable Value During Surveillance Testing.
June 2, 1989 Failure of the Backup Manual Scram Breaker B to Trip When Transferring Reacto'r Protection' System Power From Alternate to Normal.
June 2, 1989 Notification to the FAA of Loss of'Some of the-Cooling Tower Lights.
June 3, 1989 Unplanned ESF Actuation During Surveillance Testing Causing Numerous Containment Isolations and ' Energization of the HVAC, Standby Gas Treatment, and . Control Air compressor Systems.
There were numerous security events followed up during this inspection period.
The June 2 event cccurred.while the electrical power supply for reactor-protection system (RPS) B'was being manually realigned from its alternate > supply (480v Distribution cabinet 72C-2D-2) to its normal supply (RPS MG set B).
This was a dead bus transfer and smral half-isolations and half trips were anticipated by the operators.
However, a trip of the B Backup Manual Scram (BUMS)-did not occur.as expected.
Licensee immediate r actions were both timely and comprehensive..The failure was determined to be within' circuit interrupter C71-00S004B within the RPS trip system B
electrical panel.
The panel was then quarantined.
A like-for-like ! replacement was assembled (consisting of ITE Siemens-Allis. circuit
interrupter model E22S100A and an undervoltage trip coil attachment 001E60) and subsequently installed and successfully tested.
The failed component was removed without chanr3 to the failure configuration and shipped to Detroit Edison's Enginetaing Research Department (ERD) to l determine root cause'of the failure.
Since this type of breaker had l earlier failed in 1987 in the other RPS division, this will remain an
- open item pending completion of the ERD analysis (341/89011-08(DRP)).
No violations or deviations were identified in this area.
'7.
Licensee Event Reports Followup (92700) Through direct observations, discussions with licensee personnel, and l: review of records, the following event reports were reviewed to determine l that deportability requirements were fulfilled, immediate corrective L action was ac.:omplished, and corrective action to prevent recurrence had I been' accomplished in accordance with technical specifications.
. . . . i
, _ .__ . _ - - - _ _ _ _ _ - _ _ _ _ w ... . a.. (Closed) LER 87-056, Reactor Scram Due to Personnel Error and ~ Subsequent Reactor Water Cleanup System Isolation.
On Decemt,er 31, 1987, while at 75% power, a temporary modification to install a monitor and printer to determine the Number 1 Feedwater Heater level was being installed.
During the installation, it was determined that the gross megawatt signal could not be used as input to the monitor and feedwater flow signal was substituted without changing the temporary modification.
During the installation, the I&C Technician accidentally grounded one lead of the A Loop feedwater flow instruments chat in turn blew the fuse on the feedwater square root converter power supply.
This power supply also supplies power for the proportional amplifier that sums the feedwater flows through both A and B Loops.
Since one of the loop indicated flows was lost, the total indicated feedwater flow was decreased by fifty percent thereby increasing the actual feedwater flow and the reactor water level until a high level trip closed the turbine control valves scramming the reactor.
The initiation of the event was caused by the inadvertent grounding of a lead to the feedwater controller, however, the work being carried out was a change from the approved temporary modification and the change had ' not been reviewed or approved.
The temporary modification procedure in use at the time, 12.000.025, Rev. 10, did nc,t specifically state that any changes to the approved temporary modifications would be reviewed and approved the same as the original.
Licensing Action Notice (LAN) No. 88-038 was issued and Rev. 11 of the procedure approved February 9,1988 now requires a full review and approval of changes to the original temporary modification.
Licensing Action Notice No. 88-036 requested Nuclear Training to review and if needed upgrade training prc, grams in plant configuration control.
Nuclear Training included this lesson learned event in Procedure Compliance Unit 1 on both configuration concrol and compliance with procedures and added the upgraded Unit 1 as a requirement for Fermi Orientation A Initial and also all Requalification Training.
In' addition after the Procedure Compliance Unit I videotape was revised the Senior Vice President directed all site personnel to review the tape by June 29, 1988.
The engineered safety features challenged during the scram responded as designed, however, the shutdown was complicated by isolation of the Reactor Water Cleanup (RWCU) system by a differential flow condition.
The RWCU isolation was caused by a sequence of events during which the RWCU pumps were tripped by low flow when the RWCU nstem delay volume flashed to steam and shortly after establishing i gravity diain f rom the RWCU system to the condenser, low RWCU pressure automatically closed the path.
Trapped water released past the downstream flow controller caused a differential flow condition which isolated the RWCU system.
It is postulated that the RWCU low pressure condition was caused by the failure of the reactor vessel head vent value to operate and equalize the reactor pressure and the RWCU pressure.
The RWCU isolation on differential flow is as designed.
Rev. 35 to POM 23.707, RWCU, was issued to add a caution to minimize the time that the RWCU valves to the main condenser and to
< _ _ _ _ _ _ - _ _ _ -
_ _ _ _ _ _ - _ - _ _ _ _ - - _ - ., .c radwaste.are open when the RWCU flow control valve is closed to prevent a. differential flow isolation of the RWCU system.
The flashing in the RWCU system during normal plant shutdown causing RWCU pump shutdown from low flow had been a previous problem (five LERs in 1985).
Engineering Design Package (EDP) 6671, approved on December 27, 1987 before the event occurred, has been installed replacing the 24 inch section of pipe called the delay volume with a 6-inch pipe.
There have been no further RWCU system flashing problems since the EDP change in early 1988.
The position indication switches and relays for the reactor vessel head vent valve were replaced and the valve is operable.
b.
(Closed) LER 88-16, Failed Relay Causes RHR Shutdown Cooling (SDC) Outboard Isolation Valve to Close.
This event occurred on April 20, 1988, when a primary containment isolation system logic relay failed because of a defective metal cxide varistor (MOV) GE-MOV II, Model No. V130LA2. The isolation removed one RHR SDC division from service until Isolation Valve E11-F008 was manually opened in 37 ' minutes.
This restored both SDC divisions to operation, as required by Technical Specifications, while the unit was in Mode 4.
The failed MOV is an integral part of Relay A71-B-K75.
The relay had been installed and tested five days earlier during regular preventive maintenance and had been operated two times prior to F failure.
The failure was discovered following uninterruptible power (UP) testing and modifications which caused voltage transients to the relay.
This failure of the MOV is attributed to these voltage transients which were beyon1 the limits of the MOV; however, at least five other similar relays subjected to the transients did not fail.
The MOV failure was classed as a premature failure not typical of these MOVs, since there were no other vendor or user experiences of similar failure at the time or in the intervening time period, c.
(Closed) LER 89-008, Inadvertent Initiation of the EECW Division II During Testing.
On March 16, 1989, while performing a monthly channel functional test of the Drywell pressure actuation of the RHR, CSS and HPCI systems and with the plant at 0 power in Startup Mode 2, an Instrument and Control Technician inadvertently placed a volt-ohmmeter lead on the wrong terminal inside panel H11-P626 actuating EECW Division II.
The EECW system responded as designed
and was promptly returned to the normal standby lineup.
There have i been four similar occurrences of this error in the past, probably caused by the inaccessibility of the terminal strip where the reading must be taken.
A portable tes. box developed following the last occurrence reduces the necessity ' taking many of the required readings at the terminal strip inside the panel; however, several readings must be still taken by connecting to terminals inside the panel.
Potential Design Change, P')C 10,334, has been initiated which will provide banana test jacks on a spare terminal strip in l these panels for those particular surveillance terminals which have been a problem in the past.
Potential Design Change 8123 has also ~been approved to permanently mount the portable test box at each of
_ __ _ -
_ __- - __ - _ - _ - _ _ _ - _. _ _ _ _ _ - _ _ - _ _ _ _ - -. . .
-l 'these panels.
This LER will be closed and the completion of-PDC'10334 will be added to previously identified Open Item (341/89008-13(DRP)).for implementation of PDC 8123.
. An accountability meeting was held April 7, 1989, between management and the involved technicians and a description of this event will be " required reading" for all technicians.
' - d.
(Closed) LER 87-036, Reactor Scram Due to Misaligned RHR System blves.
e, (Closed) LER 88-035, Automatic Scram' Signal Genersted During.
Shutdown Due to Failure to Follow Procedure.
The cause of this event was attributable to the Control Room Nuclear Supervising Operator (CRNS0) resetting a reactor scram signal using a sequence which was not~in accordance with system operating Procedure 23.610, Reactor Protection System.
A weakness was subsequently identified in operator knowledge onshift in that some operators were not aware that Procedure 23.610 was applicable to the subject situation.
In , response, the licensee counseled the operators directly involved in the event, a lesson learned (No. 88-011) was issued as part of the operator required-reading program, and an operating experience training session was conducted during operator requalification training cycle #89-1 (completed February 17, 1989) addres. sing, in part, this event (reference training work request (TWR) 89-00822 and Lesson Plan No. LP-LO-233-8911).
In addition a simulator exercise was conducted which required all operators (*) properly reset the-Reactor Protection ~ System.
f.
(Closed) LER 88-001, Neutron Monitoring Instruments Inoperable Due to Procedural Inadequacy and Technical Specification Impracticality.
To prevent recurrence, the licensee revised APRM calibration procedures to include verification of the setdown trip setpoints upon adjustments to the fixed neutron flux upscale trips.
Urgent Required Reading Package 88-2-1 was issued and included a discussion of this event, and a Technical Specification change to add notes to Table 1.2 "0PERATIONAL CONDITIONS" to better define mode switch requirements during performance of surveillance tests was submitted and subsequently approved by the NRC.
Operator trainir.g was conducted addressing this LER and the Technical Specification change.
g.
(Closed) LER 87-007 and Rev 1, Inadequate Procedure Allows Operators l to Void Residual Heat Removal Piping Resulting in ESF/RPS Actuation.
L In response, the licensee revised System Operating Procedure 50P 23.205 l to incorporate changes to operating configuration designed to prevent E a recurrence of this event, a Lessons Learned (No. 87-004) was issued for review by all shifts, and incorporation of this event to the Licensed Operator Requalification Training Program was done (reference training work requests (TWR) Nos. 87-0689, 87-1008, 87-2063, 87-2205, 87-2156, and 87-2088).
Additionally, the particular operational configuration was subsequently modeled on the simulator.
!
- ~ - - - - - - - - - - - ~ --- -- --- - - - - - ,.m.
c.. ., m s, y y ~ ) r h.
(Closed) LER' 87040'and Rev.1: Trip of the Reactor Protection ' System (RPS). Motor-Generator (MG)' Set from a postulated overvoltage condition.
On August 27, 1987, RPS MG Set A tripped.
Further testing did not provide a conclusive cause for'the eventi-The licensee determined that a possible cause was the presence of 1_. contaminants in the potentiometer for the voltage regulator. While subsequent testing'was being conducted, an electrician dropped a lead, causing another loss of power to RPS Bus A on September 29, 1987. ; Subsequent to these events, RPS MG. Set A voltage swings occurred on November 3, 1987 and were documented in DER 87-427.
On-November 7,1987, the voltage regulator'for RPS MG Set A was replaced with a new one.
On July'28,1 1988, the wire wound voltage adjustment potentiometer was replaced in accordance with PDC / Minor Modification No. 8254.
Procedure NPP-42.610.01 was revised to include exercising the potentiometer windings by rotating the adjustment knob through the full range several. times.
Subsequently, no voltage problems have occurred.
The LER stated that' guidelines for electricians work-ing on energized equipment will be developed by. January 31, 1988.
This commitment ' was tracked by Licensing Action Notice'(LAN) 87-468.
Training Work-Request (TWR) 8702477 was issued to Training by the Superintendent, Maintenance and Modifications, to formulate a class on " Precautions ' ! to take while working on energized equipment." The inspector checked the status of the TWR with the Director, Nuclear Training, who determined that the TWR was dispositioned as not being required on March 18, 1988.
The basis for this disposition was that this type'of training is covered throughout the electrician's initial '15-week skills training and is also covered in monthly safety . meetings.
However, during Training's independent review of Off.s (at-the. time of this inspection) for incorporation of commitments into-
- the training program, they reviewed the DER associated with LER 87040.
-and opened TWR-8900767 to track the same training commitments.
Disposition of this TWR is an open item (341/89011-09(DRP)). i.
(0 pen) LER 88031: Failure to Perform Accelerated Valve Stroke Time Testing as Required by ASME.
This item will remain open pending verification that certain corrective actions to prevent recurrence documented as complete in DER 88-1520 are still implemented.
These include publishing the IST Pump and Valve Out-of-Specification Status Report on a semi-monthly basis and addressing the use of the Valve Stroke Time Trending Data Sheet in a. procedure.
j.
(. Closed) LER 87-015, Standby Liquid Control Concentration Exceeded.
No violations or deviations were identified in this area.
8.
NUREG 0737, TMI-2 Action Items (Closed) Item I.C.5: Procedures for Feedback of Operating Experiences to Plant Staff.
Fermi Management Directive, FMD SRI, Safety Review and- , ! Evaluation, dated December 21, 1987, establishes the requiren,ents for a program to systematically review and evaluate the safety of Fermi 2
. _.
- - . _ _. _- _ _ _ _ _ _ _ _ _ _ _ _ _
. < l ' operations.
Included in_the required reviews are the operating experiences at Fermi, the experiences of industry, rnd also the issuances of industry and regulatory agencies.
Responsibilities for initial reviews are assigned through the DER system and the OER Enhancement Plan as documented below (Paragraph 11).
Fermi Management Directive, FMD CA1, Rev. 1, dated April 11, 1988, establishes requirements for the identification, documentation, notification, evaluation and correction of events o, nonconforming l' conditions that have the potential of affecting the safe operation of l Fermi 2 and assign responsibilities for implementing these requirements.
It covers not only conditions found to be adverse to quality at Fermi 2, but also all reportable events and nonconformances identified by other industry organizations and regulatory agencies, and other industry and agency issuances.
It also establishes the Deviation / Event Report (DER) System that is used to document each event, nonconforming items, issuances, etc., assigns responsible units, and controls the DER until it is satisfactorily completed and approved.
The Directive also assigns the organizational responsibility for initiating DERs for all external and some internal issuances.
Nuclear Engineering is responsible for ' initiating all authorized nuclear inservice inspections and vendor issuances; Quality Assurance and Plant Safety, all INPO and American Nuclear Insurer issuances; Nuclear Services all vendor initiated 10 CFR 21 reports; and Nuclear Licensing all NRC issuances and violations, unresolved items, and open items.
The Directives are implemented by Fermi Interfacing Procedures FIP-CA1-01, Deviation and Corrective Action Reporting and FIP-TQ1, Training and Qualification Manual.
FIP-CM1-01 prescribes the method for processing DERs, for the identification, documentation, notification, evaluations, reporting and trending of events or nonconforming conditions having the potential for affecting safe and reliable Fermi 2 operations.
One individual in Plant Safety is assigned the responsibility of initial review of all DERs for significance and inclusion in INP0 Nuclear Network and Fermi Focus, a local publication, for more general information.
lie also reviews for NRC deportability or potential deportability.
FIP-TQ1-18-SQ, Training Program Evaluation, dated March 10, 1988, specifies that all onsite and offsite operating experiences and Fermi 2 design changes will be routed to Nuclear Training for their evaluation for including the item in the training program.
Each item selected is included in the Simulator Configuration Management System (SCMS) which tracks all the items until training is completed.
All changes at Fermi 2 including engineering design packages, temporary modifications, as-built changes, preliminary design changes, and engineering change requests are reviewed for inclusion in the training program and also for any changes that might be required to update the simulator.
The inspector cor/iudes that the licensee's procedures in this area are adequate to assare that both internal and external operational experiences are inciuded in the Fermi 2 training program or are directed
- -_ ._ - _ _ _ _ _ _ _ _____ ___- _ _ __.
- _ ,, I 6; to the Fermi personnel needing the information; therefore, this Action Plan Item is considered to be closed.
I 9.
Temporary Instruction 2515/100, Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel Oil (255100) ,
Since there have been several past events at other sites from plugged or failed filters and strainers as reported in I&E Circular 77-15, NRC Information Notice 87-04, and INP0 SERs 87-19 and 88-1700 and SEN 44, this TI was a request to inspect the licensee's program to maintain adequate quality of EDG fuel oil.
The.four Fermi EDG fuel oil systems are housed in reinforced-concrete, seismic Category I structures with each system enclosed in its own concrete cell and each isolated from the other units.
Each system has its own fuel & oil storage, transfer system and day tanks housed in the structure.
The ventilation system for each cell is designed to maintain the temperature Letween 65 and 104 degrees Fahrenheit throughout the year.
Each EDG has dual transfer pumps to the-day-tank with strainers on the pump suctions with differential pressure { (dp) indication locally.
Each storage tank is fitted with level sight i glasses and high/ low level alarm in EDG control room and in the main , control room.
Each day tank also has a level sight glass and low level alarm located as above. There is a strainer with dp local indication on both the engine driven and motor driven oil feed pumps from the day tanks to the EDG and a duplex fuel filter on the pump discharge to the fuel header with local dp indication.
The duplex filter downstream dp tap also p.ovides a fuel oil low pressure alarm in the EDG control room and also in the main control room if pressure falls from normal operating pressure 20 psig to 10 psig.
Strainers are cleaned and filters changed if the dp nears 10 psig and on an eighteen month frequency.
The Up's are taken every 30 minutes during test runs and trended so cleaning or replacement is completed before the 10 psig limit is reached.
Fuel quality is established by purchase order and during the receipt inspection which includes sampling and analysis per ASTM 04057-81 and ASTM D975-81 as required by Technical Specifications.
The four tank truck compartments are separately sampled and composited.
Flash point, specific gravity, viscosit., and sulfur content are determined at the site before the truck is released for unloading.
Five other determinations: carbon residue, ash, distillation temperature, copper strip corrosion, and cetane number are made by an offsite laboratory within 31 days.
The storage tanks and day tanks are sampled for water content monthly following the test run and after any run greater than one hour.
The storage tank is sampled and analyzed monthly for particulate content per ASTM D2276-78.
If particulate are ever found to be greater than 10 mg/ liter, the Technical Specification limit, temporary hoses can be used to remove the out of specification fue oil tnrough the day tank to a I tank truck for disposal.
This is estimated to take about 70 hours.
This review indicates all r% uirements of Regulatory Guide 1.137 and ANS-59.51/N195-1976 have been met except that the duplex filter dp is not alarmed in the main control room; however, low fuel oil pressure down stream of the duplex filter is alarmed in both control rooms.
Also, there is no high level alarm on the day tank as it is normally overflowed to the storage t.ank and high level alarm is unnecessary.
This TI is considered to be closed.
L ,
- - _ - - - -. - _ - - - --- - - _ _.. _ _ - _ _ _ - - _ _ - - - - _ _-- , s! ' J.o ,f i >1 10.-. Followup on Confirmatory-Action Letter (92703)' X (0 pen) CAL-R111-88-20: This CAL, issued July 15, 1988, dealt with two ] events-of compression fitting failures in Reactor Water Cleanup.(RWCU) { . instrument lines in May and July.1988.
The CAL documented agreements ' with theilicensee on eight corrective actions of which only one remains open, the inspection of fittings on the RWCU system'and eight other l safety related systems, (see Inspection Reports No. 341/88026 and ' No. 341/89002).
The licensee ( > tablished a schedule for the above inspections and has I completed eighc of nine systems.
The inspections have been completed ahead of the scheduled times.
The inspections completed included 118 lines with 1807 fittings. -Of these, 774 fittings were found to be acceptable, 892 failed the "go-no go" gap test, 76' contained mixed Parker-Hannifin and Swagelok parts, and 83 failed the minimum ferrule engagement of at least half of the tube 0.D.. All mixed part fittings were corrected to similar parts, preferably Swagelok, and all connections inspected have been tested and left in an acceptable condition.
, Inspection and corrective work will continue on the remaining Ell-RHR system when outage time is available.
The work has been' completed on those fittings accessible without shutdown (about one-half).
All inspection and correction work will be completed by the end of the first refueling outage in September 1989.
11.
Operating Experience Reviews In September 1988, INP0 inspected the Fermi 2 Operating Experience Report .(OER) Program and in ' January 1989 provided assistance to the licensee in .this area after the INP0 inspectors expressed concerns with the methods used to disseminate industry experiences and with the timeliness and ' adequacy'of experience review and corrective actions taken.
In addition, two recent events (MOV torque. switch / limit switch. set points and Reactor Recirculation Pump MG SIL field breaker failure) eniphasized that industry operating experiences were not being properly evaluated to prevent similar occurrences at Fermi.
As a result, the Operating Experience Report Enhancement Plan was formulated and on February 22, 1989 management established goals for the review of 238 outstanding OERs to be completed by the end of April 1989 and required responsible management review and approval as well as senior management review and approval of each report.
These management reviews are also to continue for all newly received OERs.
By April 25, 1989, 227 OERs had been reviewed and approved by management.
Nine had been reviewed but had not been approved because of conflicts and 34 newly received OERs were presently under review.
If the conflicts cannot be resolved on the nine OERs, they will be sent to upper management for resolution.
Each OER, whether internal or external, is assigned and tracked by the DER system until completed.
In addition, Plant Safety has made up an OER summary sheet which is used to summarize responses, corrective actions, , l.
' . _ _ _ _ _ _ _ _ _
- - . _ _ _. _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ - _ _. _ _ _ _ _ _ _ _
. i j s.
i i and management approvals.
Plant Safety maintains a complete file of all OERs and summaries since the inception of the OER Enhancement Plan start, including the 1988 backlog, i The objectives of the OER Enhancement Plan are to assure that known industry events will not occur at fermi by: a.
Assigning OER reviews to appropriate personnel . b.
Completing the reviews and corrective actions in a timely manner.
c.
Periodically assessing the effectiveness of the program.
To implement the-first point, OERs will be classified by subject / topic , so that appropriate Fermi management will be assigned responsibility l for the timely review and completing any necessary corrective actions.
Plant Safety has formulated a matrix to be used to assign review responsibility.
Three groups, Training, Quality Assurance Program, and the Independent Safety Engineering Group (ISEG) will receive all OERs, , other groups will be assigned according to the matrix.
In addition, any OERs of general interest and concern will be publisheo in the Fermi Focus, a periodic newsletter available to all site personnel.
All SOERs
and any required corrective action will be summarized and placed in a book available to all appropriate section heads.
The 50ER book will be kept current to document corrective actions so that each responsible section can assure that the corrective actions are completed and being . maintained.
The second point has been previously discussed.
The backlog of OERs from 1988 has been completed except for nine which had conflicting reviews that had not been resolved.
Current OER reviews were being made in a timely manner.
The backlog of 1988 NRC Information Notices, numbering about 27, are now under active review.
The thira point, assessment of the programs effectiveness, is to be audited through regular QA audit / surveillance activities.
Specific SOERs have been added to scheduled audits depending upon subject / topic.
In addition, a poll of Fermi personnel will be taken at least annually to determine the extent information is being disseminated and retained.
The Director of Plant Safety will update management monthly on the status of the program.
Fermi personnel have also reviewed the OER programs at the Rancho Seco
and VC Summer which were cited by INPO to have effective programs.
Recommendations of the INPD assistance visit in January 1989 will be , evaluated for inclusion in the Fermi Plan.
i 12.
Review of Generic Letters (Closed) Generic Letter 87-06: Periodic Verification of Leak Tight Integrity of Pressure Isolation Valves.
This letter requested each licensee to submit a list of all pressure isolation valves at their plant, including for each valve, a description of the periodic tests or other measures performed to assure the integrity of the valve as an independent barrier at the reactor coolant pressure boundary along with j
_ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _
. . _. -__-_ -____-___ _ ___ . . , .
, l % l p i
V the acceptance criteria for. leakage, if any, operational limits,.if any, i and frequency of test performance.
If current plant Technical { Specifications require ' k rate testing of all of the pressure isolation va'lves 'in the plant, a y to that effect is sufficient.
All plants licensed after 1979 have all pressure isolation valves listed in the Technical Specifications along with testing intervals, acceptance criteria and limiting conditions for operation.
Detroit Edison submitted
- their response for Fermi on May 8,1987, which stated that the Technical m
. Specifications provide requirements for leak rate testing of all pressure isolation valves.
A listing of.the pressure isolation valves tested.and i the leakage criteria is also provided.
The surveillance requirements for these valves provide added assurance of' reactor coolant pressure boundary ok integrity. This item t' considered closed.
13.- Review of Information Notices (Closed) Information Notice 87-08: Degraded Motor Leads in Limitorque DC Motor Operators dated February 4,1987.
The motors in question were manufactured at H. K. Porter between December 1984~and December 1985.
The motors were fitted with Nomex-Kapton insulated leads that are ' susceptible to insulation degradation and subsequent short circuit failure.
The licensee issued DER 87-054 to track resolution of.the notice on February 10, 1987.
Earlier on January 5, 1987,.Limitorque notified DECO of the deficiency and-referenced Purchase Order NR-348010.
Valve B2103-F019 (Main' Steam drain line outboard isolation valve) was .; ' . identified' as the only valve with the degraded motor leads. - The motor was replaced on February 19, 1987 during completion of Work Request No..PN21262179.
Other corrective actions included a revision to the-Limitorque valve operator Acceptable Materials List,.a memorandum to the Materials Engineering Group providing instructions for ordering and inspection of Limitorque motor operators / spare replacement parts using the Acceptable Materials List, and a memorandum to PQA requesting that they use the Acceptable Materials List during PQA vendor audits of Limitorque.
14.
Organizational Changes During the inspection period the licensee performed a reorganization in their maintenance area.
Also, they removed the Ceneral Supervisor of Modifications out from under the Superintendent of Maintenance and.
Modifications and placed him under the Assistant to the Vice President Nuclear Operations.
The inspector inquired as to what safety evaluation j was performed to assure that this was an appropriate organizational change since the UFSAR identified the General Supervisor of Modifications as reporting to tSe Superintendent of Maintenance and Modifications. On 3pril 19th, the inspector discussed the situation with the Superintendent af Maintenance and Modifications, the Assistant to the Vice President Nuclear Operations, and'the Plant Manage; as to whether this was appropriate.
The licensee stated that no safety evaluation was performed nor a preliminary safety evaluation was performed.
As a result of e discussions with the licensee management on this, a safety evaluation , was performed and management stated that they clearly understood the $_ ! need for such safety evaluations and that'they would be accomplished in j the future.
Given the safety significance involved in this particular
_ ___ - I
__ __-_ __ - ,, j ___ d I [y . a organizational change and that the licensee clearly recognized the need-
- for'such safety. evaluations the-inspector did not consider that a violation.- } was warranted in this particular situation.
l 15.
Management Meetings a.
On-April 17, 1989, the inspector attended a meeting between the-licensee and NRR to discuss a proposed Technical Specification-change to tho Secondary Containment Integrity Technical Specification.
The need for the change was due to a change in g E the design of the pneumatic air supply to railroad car door seals.
The licensee discussed the modification that they intend to make " and how that will be accomplished.
This design will provide: . noninterruptible air from division I to one door and noninterruptible air from division 11 to the other door.
A restricting orifice-wi',1 be installed in the air stepply system to prevent a seal failure from rendering the NIAS system inoperable. Also the door' seal pressures would be individually alarmed in the control room. The seals themselves will be changed out or upgraded to withstand the ' NIAS. air pressure.
During normal operations both railroad car doors would remain closed.
b.
On April 27, 1989, the monthly meeting was held between Detroit Edison and NRC Region III at the licensee's Nuclear Operations Center.
The major elements of the meeting are discussed belos: Organizational Changes and Performance Assessment The Senior Vice President began by announcing an upcoming change in who he' reports to.
In the near future he would be reporting to the president of the company in lieu of the CEO and a safety evaluation would be accomplished for this organizational change.
He stated that they were adequately improved as reinforced by their performance indicators, they knew what their problems were and were focusing on corrective action implementation and they did not belong'on.the troubled plant list.
Performance Indicators The licensee presented tbs performance indicators along with a performance summary beginning in the first' quarter of 1988.
The.
indicators showed improvements in a number of areas.
Trends The licensee presented their DER trending activities which showed that ( the hardware,: personnel and procedure problems were decreasing.
The
Senior Resident asksd what would be the ramifications of removing ' the LLRT outage from this DER trend data given that the LLRT outage is of a different nature than normal operation in that the number of DERs would be different and probably more wide spread.
l l
1 '
g
___ _ _____ _________ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . + DER Comparison with ANI Data Recently, the American Nuclear Insurer (ANI) shared their trending data with the licensee.
The data was based on NRC vio~1ations and LERs.
The licensee showed that the ANI trending was consistent with their own DER trending.
The licensee stated that this provided an additional layer of confidence that problems were trending downward.
Railroad Door Event The licensee discussed the events surrounding the discovery of a design deficiency in reactor building railroad car door seal system.
The presentation included a sequence of events, the basic assumptions used in evaluating the deficiency against ficoding requirements, the standard utilized in the original design ar.d a general description of the new door seal system to be installed which would require a Technical Specification change prior to implementation.
During the presentation the NRR licensing project manager commented that the proposed Technical Specification submittals had been of excellent quality but the submittal on ' the silroad doors troubled him from a timeliness aspect.
It appeared to take the licensee a long time at arriving at a viable modified seal system. The senior resident inspector commented that this deficiency related to previous design bases problems.
Refueling Preparations The licensee presented a basic tramework for the outage along with themajormilestones.
The licensee discussed the tentative level of contractor involvement in the outage.
OER Enhancement Program The licensee provided a status of the OER program as of April 25,
1989.
The total 0ERs reviewed were 270.
Approval of corrective actions had been received on 227.
Nine were presently out for further review.
On April 27, 1989, quality assurance will begin a one week assessment of the line organization's disposition of the OERs.
The 82 significant INP0 DERs had been matrixed to specific QA audits to assure continued corrective action implementation. The last portion of the enhancement program, review of closed OERs, has not had a date set for beginning/ending.
Root Cause Analysis The licensee made a presentation on the basic elements of the licensee's root cause analysis training.
c.
On April 27, 1989, an Enforcement Conference was held between Detroit Edison and NRC Region III at the licensee's Nuclear Operations Center.
The Enforcement Conference involved six different issues in the areas of security, SPDS, Technical l l l
_ - - _ _ - _ _ _ - _ _ _ _ _ _ _ -
., - . .t .. , . - , .... -) .. Specification certification and engineering evaluations.
All ! ' the issues were related with' respect to (he accuracy and l completeness of. information provided to the.NRC by tha.) licensee in.
these areas.
The personnel present at the. conference are identified in Paragraph 1 of this: report, d.
On April 27, 1989, a meeting was held between Detroit Edison,and NRC Region III at the licensee's Nuclear 0perations Center.
The topic.
of the meeting was the licensee's Five Year Plan.
The presentation provided an insight into the process utilized to' develop the plan.
~The plan was provided as a list'of those major activities that will-he. accomplished over the next five years and how engineering resources'are established.
As~a result of this review the licensee identified three areas where NRC concurrence for deferral from the first refueling outage commitment date would be requested.
These dealt with installation of limiter plates on some RCIC valves, installation of a new, upgraded rod worth minioizer and deferral.
of somo _of.the Hurcan Engineering Discrepancies (HED) to the second and third refueling outage.
, e.
.On.May 26, 1989, the monthly me2 ting with the '.icensee was conducted-at the NRC Region III Office.
The. major elements cf the meeting are discussed below: . Plant Status-The meeting began with a statement of plant status.. The plant was at 95-1005 power and a potentially reportable event had occurred the night before dealing with a HPCI. level 8 trip transmitter being out of-Calibration. The licensee indicated that little change.had been observed in turbine vibration since startup from the manual scram on high turbine vibration.
The licensee stated that they had performed a 60 percent down power maneuver.to perform some valve maintenance in the"feedwater system and.that schedule delay problem 3 associated with'those maintenance activities were being critiqued.
Performance Indicators The licensee provided current performance indicators and trends.
Upon observing the indicators, the NRC inquired as to how far'the - . Preventative Maintenance (PM) Enhancement Program for electrical and mechanical had progressed.
The licensee stated that Phase 1, which was a review of the A PMs for the first six months, was completed on schedule end phase II is in progress.
Phase II deals with refueling PMs that will be accomplished.
The licensee stated that by the i~ end of the year that the classification of A and B PMs should be eliminated.
The licensee also stated that the maximum benefits from ' the Preventative Maintenance Enhancement Program will probably not be realized for one to two years after the completion of the program.
l-
- o .
- _ - _ - ___- -
- c Trends
.. The licensee, asLa result of a NRC comment during the previous monthly meeting, reperformed their deviation event. report (DER) ' trends eliminating the April 1988 LLRT outage. :Even with this removed there is still a reduction in the number of hardware, . procedural, and personnel error DERs since May of 1988.. The licensee also stated that 48 percent of the DERs being written are due to plant related problems and 26 percent are due to NRC or other external agency items.
Regarding the Operating Experience Review (OER) program, there were several OERs with corrective actions and/or corrective action' schedules yet to be decided.
As of the'last meeting the Quality Assurance Manager indicated that six additional 0ERs were added as a result of QA review and as of May 22nd, 297 OERs had been reviewed, 286 approved, and 11 were out fer management review to determine the appropriate corrective actions.
Performance Evaluation Program ' The licensee provided a presentation on the Performance Evaluation Program (PEP).
This was a program that was identified as not being completely implemented during the Diagnostic Evaluation Team Inspection.
The licensee began the presentation by explaining that the program entailed vibration monitoring of approximately 100 pieces of rotating machinery and that'there was a heat exchanger performance evaluation portion to this program.
Presently.there are 10 heat'exchangers for monitoring, 3 have yet to have there baseline,information provided.
As a result'of questions, the licensee not'ed that the PEP is based upon system evaluations and that for.1989, 38 of the most important systems have been targeted for' evaluation and incorporation of their equipment or components into the PEP program.
Presently, 13 of the 38 systems have been evaluated. The licensee has 120 total' plant systems but only 60 to 70 of these systems:would be applicable to the PEP scope.
Further-systems will'be. targeted for review in'1990. The presentation of the PEP was stopped due to time constraints.
Regulatory Guide 1.97 The Regi)nal Administrator was briefed on the Regulatory Guide 1.97 issue on Fermi as to the applicability of air operated or solenoid operated containment isolation valves to Regulatory Guide 1.97.
The licensee provided status of present containment isolation valves , ' and their conformance to Regulatory Guide 1.97.
The licensee identified 89 motor operated valves that were Class IE, seismic and environmentally qualified. Of the 72 air operated valves 38 were not qualified,16 were fully qualified and 18 were seismic and environmentally qualified but not off Class 1E power supplies.
Of the the 36 solenoid valves, seven were not qualified, nine were -- seismic and environmentally qualified, but not off Class 1E power l-and the rest of the valves were qualified.
The licensee indicated ' that they were working on the written submittal to the NRR with regards to the valves and that the letter is tentatively scheduled to be issued on June 16th.
L_ . _ _ __ _ . _ _ _. _ _ _ _. _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____
i .. ! o j Refueling Outage Preparation The licensee provided a presentation of the. refueling outage preparation. They indicated'that June 1 was the scheduled receipt date for the first fuel shipment.
They reiterated to the NRC that the inability to defer certain human engineering discrepancies, installation of limiter plates on three valves and installation of an upgraded rod worth minimizer would impact the refueling outage i schedule.
They indicated that they had submitted a letter to the Commission identifying these three areas for a request for deferral from action during the first refueling outage.
The rest of the licensee's presentation dealt with how the organization for the refueling outage will be configured, discussion of the outage shift manager duties, size of contract force to be utilized during the refueling outage, and the reactor disassembly /CRD change out work would be contracted out.
The licensee indicated that they do not envision any major problems with the outage at this point.
16.
Strike Preparations (92709) , In response to the potential strike of AFL/CIO affiliated Local 223 the inspector discussed strike plans with licensee management on June 6, 1989.
Local 223 represents 177 personnel that encompassed non-licensed operators, I&C technicians, and electrical and mechanical maintenance personnel.
These are the areas affected by the strike.
Management indicated that a strike was a possibility.
As a result of this the inspector obtained and reviewed the licensee's approved strike contingency plan.
The inspector ascertained that the appropriate mininum operations shift staffing capability could be maintained.
The licensee had performed a training and qualification program audit involving the potential replacement personnel.
The licensee briefed the inspector on the audit findings which noted minimal problem; with the qualifications of the perconnel.
The inspector discussed turnover between the potential striking personnel and the replacement individuals and determined that there would be turnovers associated with each position.
The inspector ascertained that the licensee's management had established a plan to assure unimpeded access to the plant of personntl necessary to maintain staffing and, delivery of goods onsite including consumables such as diesel fuel, nitrogen, and hydrogen.
Appropriate law e forcement agencies had been contacted to deal with non-docile strikers or an event that would threaten the plant safety.
The licensee issued appropriate memoranda to all employees on how to deal with a strike and a picket line.
Given that the strike did not involve any of the licensed operators, the inspector did not review in depth the qualifications and training of the personnel that would be put in the non-licensed positions since they are licensed operators.
In the inspector's review of the strike contingency plan it was noted the local fire department and ambulance service had not been specifically contacted nor the State Radiological Health Agency.
The inspector contacted appropriate licensee management to assure that those agencies had been contacted or will be contacted.
- _ - - - _ _ _ - _
-. .. 17.
Regional Request a.
On May 5, 1989 the inspector received memoranda from the Division Director of Reactor Projects discussing recent operational events.
Two events were discussed.
The first dealing with the failure of a freeze plug in a six inch service water line during valve maintenance.
The second event involved the identification of a hydrogen tank farm on the roof of a control room at a Region V plant.
The inspectors informed the licensee of the first event and canvassed the licensee for information regarding hydrogen cylinders in terms
of their location and amount of hydrogen that is stored on site.
b.
On May 9, 1989 the Resident Staff received a memorandum from the Division Director of Reactor Projects, requesting information on hydrogen storage at the facility.
The information requested was (1) the distance from the hydrogen storage facility to the nearest safety-related structure or air intake and (2) the maximum volume of ga:,eous or liquid hydrogen stored on site in standard cubic feet or gallons.
, The inspector subsequently determined that at Fermi, hydrogen is stored outside at grade level within a fenced area approximately 370 feet from the reactor building and 370 feet from the nearest station service transformer.
The anount stored onsite normally varies depending on current amount in use.
However, the maximum volume would include 15,600 cubic feet in the storage tank itself and an additional 5,200 cubic feet in a truck trailer parked within the fenced storage area for a total of 20,800 cubic feet.
No hydrogen is stored on the roof of the control room.
c.
During the inspection period regional management requested information on fuel oil for the Emergency Diesel Generators (EDG).
The questions asked were (1) what type of fuel oil is used for the EDGs, (2) is there any shelf life established for the oil, and (3) how long would it take for the oil stocks to turn over.
The answers to questions 1 and 2 are: number 2 fuel oil is used, no shelf life is applied to the oil, however, the oil is sampled monthly in accordance with Technical Specifications (see Paragraph 9).
In terms of the turnover of oil stock without replenishing the supply, - it would take approximately 4 years to use all the oil.
Detroit Edison receives oil approximately every 3 to 4 months in order to maintain the seven day supply.
d.
In a memorandum dated April 14, 1989, the Division Director of Reactor Projects directed the resident staff inform the licensee of the existence of a NRC report on emergency diesel generator reliability, NUREG/CR-5078.
The inspector informed the licensee of the document in a meeting on May 8, 1989, with the plant manager during the inspection period.
I ' I , l
l L
- , -. . I 18.
Open Items Open items are matters which have been discussed with the l'icensee, 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 4, 6 and 7.
19.
Exit Interview (30703) The inspectors met with licensee representatives (denoted in Paragraph 1) on June 12, 1989, and informally throughout the inspection period and summarized 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 the inspection.
' , i
1 - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
, . - .- - . s.
g' F
i DETAILS , 1.
Persons Contacted a.
Detroit Edison Company
L . P. Anthony, Licensing
! . S. Booker, Principal Engineer, Maintenance
- C; Cassise, General Supervisor, Electrical Maintenance
@#5 Catola, Vice President, Nuclear Engineering and Services @#G. Cranston, General Director, Nuclear Engineering ~
- P. Fessler,. Director, Plant Safety m
@J. Flynn, Senior Attorney-
@*#D. Gipson, Pla'nt Manager @*#L. Goochnan, Director, Licensing ,.. @R. Kelm, Director, Nuclear Security -@J. Lobbia, President
- . P. Lovallo,. Senior Engineer, Chemistry
@W. McCarthy, Chairman of the Board
- R.'McKeon,. Superintendent, Operations
@P.-Parquardt, General Attorney
- R. Matthews, Superintendent, Maintenance
@*#W. Orser, Vice' President, Nuclear Operations -
- E. Page, Risk Assessment Engineer
- J...Pendergast,, Licensing Engineer
'
- L. Schuerman,-General Supervisor, Nuclear Engineering-
- A. Settles, Superintendent, Technical Engineering
@#R. Stafford, Director, Nm; lear Quality Assurance and. Plant Safety
- F. Svetkovich,. Assistant to the. Plant Manager
@B. Sylvia, Senior Vice President @#G. Trahey, Director, Special. Projects
- W. Tucker, Assistant to the Vice President
. J. Walker, Plant Engineering General Supervisor b.
U.S. Nuclear Regulatory Commission @A. Bert Davis, Administrator, RIII @J. Grobe, Director, Enforcement @R. Knop, Projects. Branch Chief, RIII @J. Lieberman, Director, Office of Enforcement . @J. Luehman, Senior Enforcement Specialist @J. Partlow, Associate Director, NRR
- P. Pelle, Inspector
- K. Ridgway, Irapector
-@M. Ring, Projects Section Chief, RIII @*#W. Rogers, Senior Resident Inspector @J. Stang,, Project Manager, NRR
- S. Stasek, Resident Inspector
@ Denotes-those attending the Enforcement Conference on April 27, 1989.
- Denotes those attending the exit meeting on May 5, 1989.
- Denotes those attending the exit meeting on June 12, 1989.
0 y 0 7.'8 @N- [ =-- _ -- _ - _ - - - -
_ - - _ - _ .. , The inspectors alsa interviewed others of the licensee's s;aff during this inspection.
2.
Action on Previous Inspection Findings (92731) a.
(0 pen) Open Item (341/88037-16(DR?)): Procedure FIP-cal-01 was not always followed in practice.
The Diagnostic Evaluation Team (DET) was concerned with several atpects of the Deviation and Corrective Action Reporting Program.
One concern was the compounding of ' Deviation Event Reports (DER) by adding similar events or problems into an existing DER or combining separate events or problems which could have different root causes into one DER. This clouded the determination of root cause and defeated the trending of both event frequency-and root causes.
The licensee revised DER numbering to ! permit assigning more than one problem to a DER and to assign more than one cause code in those cases where it would be important to trend multiple causes.
The practice of nsolidating DERs with identical corrective actions and causes no been discontinued.
The other DET cencern of having separate systems for the tracking and trending of DERs remains open.
These separate systems are to be combined into one computer system and this is expected to be completed in August 1989.
b.
(0 pen) Open Item (341/87020-01(DRP)): EX0 Sensor Action Plan.
In the last review of this item, Inspection Report 341/89002, the loss of electrolyte by evaporation had beer, corrected by plugging vent holes in the sensor, which were installed for ambient pressure changes.
This change extended the sensor life q to four and one-half years.
This item was left open until ! the new testing schedule of three month intervals versus monthly intervals and the sansor change out schedule from six months to three years, coult' te initiated and approved.
This should take place before June 1939 when the next six month change out is due.
Because of the long pwiod of time between sensor change outs, the inspector questioned whether there should be a shelf life , placed on the spare sensors that may be stored in the warehouse for up to nine years.
The licensee agreed to review this issue.
c.
(0 pen) Open Item (341/89008-03(DRP)): Control Center Heating and Ventilation (CCHVAC) fan failure.
On February 9, 1989 the Division II supply fan experienced high vibration.
Upon shutting down the fan the mounting bracket bolts were found sheared.
Subsequently, that division of CCHVAC was declared inoperable and DER 89-0235 was written.
Work request 010C890209 was initiated to investigate and repair the fan.
During the investigation maintenance personnel observed an undercut on the fan rotor.
This undercut may have allowed an excessive gap between the rotor and the bearings.
The bearing grease was observed to be hard and old even though there were periodic lubrication requirements for the bearings.
These two conditions indicated that the sheared bracket bolts were the result of the fan vibration and not due to improper torquing of the bracket bolts.
DER 89-0259 was initiated on February 16, 1989 discussing the rotor undercut condition.
On February 12, 1989, replacement l - _ _ - _ _ _ -
- _ -. . - _ - _ _ - - _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _
- 9
.. parts were installed into the fan housing ar.d testing of.the repaired fan was completed.
During the testing a high amperage condition was noted which is discussed in unresolved Item 341/89008-04.
The failed fan components were sent'to the licensee's Engineering and Research 'j Department (ERD)'to determine the failure mechanism. -At the end of the inspection period the inspector was verbally informed of the ERD results.
The failure mechanism was attributed to the hard, old grease.
This matter will remain open pending review of the written ERD investigation results and any appropriate corrective action.
d.
(Closed) Open Item (341/87016-02(DRS)): Deficiencies in the operator training program for Cycle 4-86.
This.open item was based upon the requalification program' prior to October 1987 (two year license intervals).
The current requalification program is based upon a six year license interval.
Therefore, this open item is no longer applicable and is considered closed.
e.
(0 pen) Unres Ived Item (341/89008-05(DRP)): ' Standby Gas Treatment (SGIS) Systesa ardware.and procedural concerns identified during inspector walkdcwn.
The licensee subsequently addressed five of the six areas of concern and the inspector has no further questions on those matters.
However,'the area concerning design and testing of air operated containment isolation valves with dual solenoids remains at issue.
The inspector originally identified five valves which appeared not to be properly surveillance tested in accordance with - Technical Specifications.
The licensee review subsequently determined that a population of 16 valves was involved: T46-F402, SGTS Drywell Isolation T46-F411, SGTS Drywell Isolation Bypass T46-F400, Suppression Chamber Isolation Damper T46-F401, SGTS Suppression Chamber Exhaust Air Purge T46-F412, SGTS Suppression Chamber Exhaust Air Bypass T48-F404, Suppression Chamber Inlet Isolation T48-F405, Suppression Chamber Purge Isolation T48-F407, Drywell Purge Isolation T48-F408, Drywell Nitrogen Supply Isolation T48-F409, Suppression Chamber Nitrogen Supply Isolation T48-F454, Pressure Control Drywell Makeup T48-F453, Pressure Control Drywell Vent T48-F410, Suppression Chamber Nitrogen Supply Isolation T48-F456, Pressure Control Nitrogen Supply Isolation T48-F457, Pressure Control Inlet Isolation 148-F458, Pressure Control Exhaust Isolation The licensee's original test methodology was via performance of surveillance procedure 44.020.002, NSSS - Division II, Logic System Fanctional Test," and surveillance procedures 44.020.011 through 44.020.018 and 44.020.109 through 44.020.112 which included response time testing for each initiating signal.
Procedure 44.020.002 simulated the individual containment isolation inputs to the logic causing closure of the applicable isolation valves.
The response l.
time tests verified that the required relaying in the logic train dropped out.
L__ _ _ _
. ._.
. _. .- - - - - _ _ - - ' f2 g , / > .. , .
'
- .
'In the d'ual solenoid arrangement for the 16 valves identified above L 'one solenoid is' safety-related and the other'is balance of. plant- - (B0P).
Both solenoids receive a closure signal from the same !; . containment isolation initiating, signals.. The inspector could not-identify where differentiation:was made between the dual solenoids- , as to which one was actually being' vented causing valve closureL The inspector questioned the appropriateness of:the licensee.not' explicitly testing the safety-related solenoid separate from the - BOP solenoid.
The licensee initiated a review into the~ testing-h - methodology and determined that the methodology was inadequate as identified by the inspector.
Since the original; testing. methodology did.not adequately demonstrate operability of the subject ~contain-ment isolation valves, this is considered a violation (341/89011-01A(DRP)) of 10 CFR 50, Appendix B, Criterion XI, " Test Control."
l A'special test of only the safety-related solenoids was' prepared ~ and conducted by the licensee on April 19, 1989.
A11'16 valves passed the. test and were verified operable.
i On April 21, 1989, as a result of the inspector inquiries into the configuration and testing of the dual solenoid valves, the licensee identified that the manual containment isolation initiation capability.for the 16 valves was being accomplished by the 80P
- solenoids. '
. Item 1,h of Table 3.3.2-1 in Technical Specification 3.3.-2 requires manual-containment isolation capability for isolation groups 14 and 16.amongst others.
Table 3.6.3-1 in Technical Specification 3.6.3 identifies these 16 valves as part of those groups.
The original requirement for' manual initiation capability is from IEEE Standard 279-1971,." Criteria for Protection Systems for Nuclear Power Generating Stations," and was carried forward into the Technical - Specifications.
The licensee originally considered this requirement met by relying upon the individual open/ closed pushbuttons located in the control room.
However, these pushbuttons only control the BOP solenoids.
The original design for the sixteen valves used solely. BOP circuitry / solenoids to accomplish'the automated and manual containment isolation function.
In 1984 the licensee recognized that the containment isolation function had to be accomplished with safety-related components / circuits.
The licensee identified this situation and informed the NRC in a 10 CFR 50.55(e) report dated April 16, 1984.
In that report it stated "The containment isolatioa valves in question are solenoid actuated, pneumatic powered valves designed to go to the safe position (closed) on loss of power to the solenoids or loss of air.
As a consequence there was no need for a Class 1E power source as long as appropriate safety grade controls were used."
To rectify the design deficiency the licensee installed a second solenoid with accompanying pneumatic piping between the valve and
5 i -
.- . .-
' [ , .. the BOP solenoid.
The new solenoid received a containment isolation automatic signal to vent the valve thereby closing the valve.
However, the manual isolation capability (the control pushbutton) was not changed to control the safety-related solenoid but remained connected to the BOP solenoid.
The inspector was informed of the design configuration on April 21, 1989, and the inspector met with the operating authority, plant manager and applicable design engineering personnel that day.
During the meeting, engineering personnel considered the design acceptable.
Some of the rationale was based upon:
The manual containment isolation function is not taken credit for in any accident or transient analysis.
j Failure of the automatic or manual circuitry would not inhibit
the circuit from functioning.
The manual and automatic circuitry were separated.
- However, the plant manager determined that the matter should be further reviewed and in the interim another set of switches would be taken credit for to provide the containment isolation function.
These switches were located in the relay room under the control room.
The relay room shares the same environment as the control room and is habitable in an accident.
The switches were test switches and a part of the safety-related circuit / solenoid configuration.
The switches had been tested within the requisite Technical Specification surveillance intervals since they were used during surveillance testing.
The licensee changed the applicable operating procedure that day and trained operators as they took the watch on use of the switches.
Based upon these actions the inspector was satisfied that the manual initiation function was present.
, The licensee initiated DER 89-0504 on this matter.
During the DER review the licensee determined that IEEE 279-1971 was not met.
LER 89-009 was submitted on the design deficiency.
Failure of the licensee to design the containment isolation manual initiation ' function for the sixteen subject valves with safety-related circuits / components is considered a violation (341/89011-02A(DRP))
of 10 CFR 50 Appendix B, Criterion III, " Design Control."
. As a result of the pushbutton circuitry not being safety-related, another concern arose as t! whether the licensee met post-accident monitoring requirements of Technical Specification 3.3.7.5.
This Technical Specification requires primary containment isolation valve position status.
The technical requirements on what type , qualification is necessary for position indication is embodied in l Regulatory Guide 1.97, Rev. 2.
However, NRR has yet to issue a ' Safety Evaluation Report (SER) on Regulatory Guide 1.97.
This is scheduled for August 1989.
. _ __
____-- ! , . . .- I ! The inspector contacted the applicable NRR representatives and determined that the isolation valve status design would not be challenged at this time but would be explicitly reviewed for the SER.
Also, the inspector reviewed the licensee's submittal on Regulatory Guide 1.97 and determined that these valves were not discussed explicitly. As such the licensee committed to submit additional information on these valves as part of their Regulatory Guide submittal.
This item will remain open until this matter is resolved.
f.
(0 pen) Unresolved Item (341/88003-02(DRP)): RHR service water discharge valve inservice test requirement.
During the inspection period the inspector met with NRR representatives and a contract representative associated with the inservice test program.
During this meeting the inspector identified the discharge valve and how it is operated within the facility.
Based upon that information the initial conclusion of the contract representative was that the valve belonged in the inservice test program.
The licensee was contacted by the inspector regarding this meeting.
Again, the licensee reviewed the conditions and noted that this valve was also questioned in the licensee's Safety System Functional Inspection (SSFI) on the RHR system.
The licensee provided the inspector with the response i to the SSFI findings and reiterated that the valve did not appear to belong in the inservice test program.
Also, the ' inspector discussed with the licensee why this valve's position changed from normally open (at the time of the IST Safety Evaluation Report) to normally closed.
The licensee stated that i they would retrieve that information and how the valve position ' changed and whether the inservice test review was performed during that configuration change. 'The inspector requested that the licensee and NRR representatives meet to discuss'this valve, its application and what testing is warranted.
g.
(Closed) Open Item (341/84049-22(DRS)): Revision of emergency lighting surveillance procedure to increase the number of lighting units being tested to 20 percent of the units required for safe shutdown.
By an internal letter dated December 22, 1988 from J. A. Hughes, Senior Engineer to T. L. Riley, Supervisor Compliance and Special Projects Nuclear Licensing, the licensee staff specified that Procedure 37.000.14 was written and approved to provide the means for performing the 18 month emergency lighting test, including an 8 hour discharge test on 20 percent of the lighting units required for safe shutdown of the plant.
This satisfies this concern.
Therefore, this item is considered closed.
h.
(Closed) Open Item (341/88026 02(DRP)): Changing of the reactor recirculation motor brushes to a more durable type brush.
Under EDP-7599 the brush change out was accomplished in the fall of 1988.
This item is considered closed.
i.
(0 pen) Open Item (341/88035-02(DRP)): Concerns identified while observing general maintenance on the 24/48 VDC instrumentation batteries R3200S001 and R3200S002.
DER 89-0269 was issued to track
- _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.. _ .. _
% @_. Q' p . fo ~e g ///// (%b*jp //j/// , O.% IMAGE EVALUATION O % ' %ff' TEST TARGET (MT-3) [$?' (gg ' 3,' NNNNk I p l.0 li 73 m
- E' Ex U
' I 2.0 , j,l ~ 4== l.8 1.25 1.4 1.6 + 150mm > d 6" > . ? ll
- h)
,c: . e #&~ ? a y/, x
- (i% q g
.. _ _ _ _ D 2's _
. - _ _ _ - _ _ - _ - _ - - - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ - - _ _ _ _ - t ' e,z#>AQp ( _ o ,, v.
,5.9i X, W. %, IMAGE EVALUATION , j' ;}f[% /(p //o //p,, " ' Q )f* </ ' TEST TARGET (MT-3) \\ \\\\ l 7N/ g px k/g<r % / + m,m tlI0EE E-ll' l,l { "" O2o li ime l 1.8 , = = 1.25 ! 1.4 l 1.6 l i_
- 150mm >
..- 6" > t %)
- <b,o,y 4,$?
7f //A
A g,,Ng s;gy,y,,/ 19., k ~e - . , m Oy y g . _ _ _ _ _ _ - _ _
. _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ kb
%+ a4
,, < ' '#' IMAGE EVALUATION /J a \\ [/o *: Y, {;k* TEST TARGET (MT-3) '/ O'97 4%, / k /// \\\\\\\\\\/ p I.0
- . ?
'" " . 0, 22_ - = M l 23 ll 1.4 ll1.6 nn-- i t__ u _.
._.- 150mm > g_.. _. _.. _. - 6" > 'h //4% '5 + ggg ' y,,, 7,
- p
,, --e vp
- o s - - - - - - - - - - - - - - _ _ _ _ _ _ _ _ - ._ _
. . . - - - - - - - - ek d S$q)h l to .A
IMAGE EVALUATION [[/// / /[%;, x\\;/o/ lf / TEST TARGET (MT-3) , + 's 1.0 Em W 5 {$l E I.I l "' M ' M 1.25 1.4 1.6 . _ _ _
150mm >
6" > % + d *%-
- ,rp,,+
ns y.. x i q; , - -. . _ - -. y - %v b n*& a N 5 Qg, 0] &. !
p _ _ _ _ _
,,"~~'}_ - - - - - - - - - - - - - - , r , Pk@, , ,
{lm W ' '
' the concerns.
On December 18, 1988, while performing l Procedure NPP-35.310.002 in accordance with WR No. 003B070288, j temporary batteries were connected to supply the loads normally supplied by R3200S001.
No LC0 Sheet was completed by the shift for q this work request.
In response to NRC questio~.ss, the Superintendent, j Technical Engineering, issued a memorandum that stated that the c 24/28 VDC batteries are indirectly required to maintain complitoce ! . to Technical Specification 3.3.7.5.
The me'orandum further stated m ' that if the normal batteries were isolated from the loads, the affected instrumentation must be considered inoperable.
The IRMs were used to take credit for the flux monitoring required in a loss , of off-site power event.
Other Technical Specification related instrumentation included the source range monitors, radwaste effluent radiation monitors, and fuel pool ventilation exhaust monitors.
Procedure NPP-OPI-11, Rev. 3, Step 5.3.2 required an LC0 Sheet be completed for all Technical Specification systems and c mponents determined to be inoperable regardless of the plant's operational condition.
Maintenance on R32005001 rendered source range monitoring Channels A and C; intermediate range monitoring Channels A, C, E, and G; Radwaste Effluent Radiation Monitor RME-K604; and Fuel Pool-Ventilation Exhaust Radiation Monitor Indicator and Trip Units Channels A and C inoperable.
Failure to complete an LCO Sheet is an example of a violation (341/89011-03A(DRP)) of 10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings.' Corrective action for this violation should include appropriate revisio'ns to the systems training manuals, plant procedures, and the Technical Specification Support System Matrix (which is still under development).
j ' (0 pen) Open Item (341/89008-06(DRP)): On April 12, 1989, during . the completion of Work Request No. 002C890408, the east hydrogen recombiner fan motor was reinstalled without specifying mounting bolt torque values in the work package. Discussion with workers, foremen and QC personnel indicated that torque values were not i normally specified for motor mountings.
The hydrogen recombiner skid is safety-related and seismic.
NPP-35.329.002, " General Maintenance of 480 VAC Motors," did not specify that torquing is required.
Procedure NPP-35.000.240, Rev. 20, " Bolting and Torquing," is the licensee's generic bolting and torquing procedure.
This procedure prescribed the method for prestressing bolts and other fasteners and provided limited torque values for bolts and other fasteners when torque values are not specified in other approved procedures / instructions or drawings.
However, this procedure did not specify when torquing values must be prescribed.
Procedure NPP-PSI-01, Rev. O, " Planning of Maintenance Activities," prescribed the method for processing and planning a maintenance activity.
This procedure did not state when torquing requirements must be specified.
Additionally, Part 2(A) of the Work Request Planning Checklist did not list torquing as one of the specific requirements to be considered by the planner in preparing a work package.
Failure to provide torquing acceptance criteria in
___-___ _____
m:x y , , ' , , ,
g ,. i
the work package for Work Request No. 002C890408 is al example of a ' violation (341/89011-03B(DRP M of 10 CFR 50, AppendiN B, Criterion V.
" Instructions, Procedures, and Drawings."
'Due to the inspector's' concern in this area the thermal recombiner division was not placed into service without an engineering evaluation as to the correct torquing requirements and the bolts verified to be torqued to those requirements.
- k.
(Closed) Unresolved item (341/89008-04(DRP)): Control Center HVAC fan running with high amperage.
During the second week of March 1989, the inspector queried the licensee as to the acceptability of running with a high amperage condition on the newly repaired CCHVAC r.upply fan.
The licensee indicated that the matter haa been ' . reviewed and considered an acceptable situation.
The inspector requested to review the disposition of this matter with the ., , appropriate personnel.
At first the licensee provided their verbal " - evaluation of the' condition.. The inspector requested to see the written' disposition of the matter and was told that none existed or was required.
The inspector requested the engineering personnel explain why amperage in excess of the nameplate rating did not constitute a nonconforming condition with the licensee's design requirements.
Eventually, the engineering personnel retrieved a design calculation, 4322, delineating the maximum acceptable amperage allowed for this fan as 110% of nameplate based upon a letter dated November 15, 1984, from the fan manufacturer.
Given e that the actual condition was 113% of nameplate, a nonconforming condition did exist.
This condition was dispositioned in writing by the engineering personnel as acceptable after an appropriate review.
The inspector pursued as to why this situation was not originally flagged as a nonconforming condition prior to placing the CCHVAC into service.
Based upon interviews and a review of the work package the inspector ascertained that fan repair activities commenced on. February 10,.1989. -Fan repair was complete on L February 14', 1989, and post maintenance testing commenced.
During-the testing a high amperage condition in excess of the acceptanca criteria existed.
In the work request planning section u., der Step 15 .it stated, "Take voltage and current and current mest be within 115% of'name plate and on the post maintenance testing form 48 amps to 115% of running current is considered the acceptance criteria for performance of this test." Fan flow was adjusted to 113% of the nameplate current.
Even though the acceptance criteria was met maintenance personnel contacted the on-call engineering - representative who called one of the electrical engineers.
After consultation the engineer determined that this was an acceptable condition in the short term at 113% of nameplate rating.
The inspector inquired as to why the post-maintenance testing acceptance criteria was set at 115%. Based on these inquires the inspector ascertained that 115% had been considered the maximum acceptable during pre-operational testing.
At that time the as-found amperage conditions were utilized as inputs into design calculation 4322.
In high amperage instances each fan was handled
__ - _ _ - - _ _ .. -. -
- - _ - _ - _ _ __.
_- _ _.
_ . _ _ _. _ _ - _ _ _ _ _ _ _ - .., . .f on a case-by-case basis in design calculation 4322.
The maintenance personnel-still perceived the' pre-operational criteria as appropriate and utilized 115% as acceptance criteria.
, From this review the inspector concluded that the post maintenance testing acceptance criterion was inadequate and should not have specified amperage in excess of the results of design calculation 4322.
This ;s a violation (341/89011-01B(DRP)) of 10 CFR 50, Appendix B, Criterion XI, " Test Control."
Also, when engineering personnei concluded that the 113% condition was acceptable it was without knowledge that design calculation 4322 existed. This generated a broader concern with the inspector as to , the potential overload of the emergency diesel generators (EDG) due l to an increcse in current load from the CCHVAC fan or from the ' cumulative effect of air handling units drawing more current than calculated without an appropriate evaluation of the additional load i on the EDGs.
In the written evaluation on the specific CCHVAC fan the licensee concluded that running with high amperage was an acceptable condition and that the additional amperage bading would cause a three kilowatt increase on diesel 14 and there is 100 kilowatt margin on the diesel.
Therefore, there was no overloading of the EDG.
In response to the broader concern the licensee preliminarliy evaluated high amperage on the air handling units and concluded the the additional loads would have minimal effect on the EDG loadings.
This concern will be folded into the present actions from the RHR SSFI on control of EDG loads.
1.
(0 pen) Open Item (341/86032-03(DRP)): A review of the loads and the consequences of loss of power to modular power units 1, 2, and 3.
Engineering will complete these reviews on July 15, 1989. Modular power units 4, 5, and 6 will be completed before the refueling outage this fall.
Also, load and consequence analysis will be part of the modular power unit 4, 5, and 6 review.
l ' m.
(0 pen)UnresolvedItem(341/89002-01(DRjPT: Secondary containment I integrity and the condensate tank for the auxiliary boiler.
As-a result of questions with regards to maintaining secondary containment integrity, the licensee intends to establish an action plan to deal with some of the concerns.
This action plan will 'e completed during the next inspection period.
The inspector wi'll I review the action plan once approved.
n.
(0 pen) Violation (341/88037-01(DRP)): Redlining of drawings.
I On May 10, 1989, the inspectors took a sampling of Temporary Modifications (TM) and verified whether the drawings associated with the TMs had been redlined.
During the sampling five drawings were observed with no TM or the wrong TM posted against the drawing.
Also one alarm response procedure had not been revised as a result of a TM.
Technical group personnel were contacted and a 100% reverification of drawing redlining / revised procedures was initiated.
In the discussion with the licensee the inspector ascertained that
a new redlining procedure had been enacted in recent months.
This
- _ _ _ _ - _
_ . .; l procedure excluded the tagging center microfilm drawings.
The licensee is revising the TM procedure to annotate the microfilm drawings in the automated records management system (ARMS).
Since this procedure has yet to be issued the potential existed for a TM to be implemented without the microfilm drawings.being annotated against the TM.
Technical group personnel were immediately directed to assure that those drawings'were annotated for any TMs issued before the revised procedure is issued.
o.
-(0 pen) Open Item (341/88026-03(DRP)): Installation of star lugs.
The licensee documented the NRC concern with the utilization of star ' lugs in DER 88-2000.
In resolving DER 88-2000, the licensee indicated .that during the first week of June, star lug installation would commence.
Star lug installation will be accomplished tnrough the use of temporary change notifications to appropriate surveillance , procedures.
Also, a log will be kept of star lug 17 cations, an administrative procedure is being written on star lug control and the procedure review checklist will be revised to consider star lug installation / removal.
p.
(Closed) Unresolved Item (341/88037-07(DRP)): One hundred-fifty (150) procedures overdue for two year periodic review.
The inspector contacted the Superviser of Procedures and Coordination to discuss whether there were 150 procedures overdue.
Based upon this discussion the inspector ascertained that there were a significant number of overdue procedures during the diagnostic evaluation team (DET) inspection.
Evidently, as a result of the site wide procedure rewrite effort a number of procedures did not receive their prescribed periodic review.
Through discussion with the Procedures and Coordination Supervisor the inspector ascertained that an audit, A-QS-P-87-34-04, was conducted in late 1987 and identified the two year periodic review was not being performed in accordance with Technical Specification 6.8.3.
The audit findings were presented to the Plant Manager on or about January 21, 1988.
As a result of this audit finding, corrective action was established for the Supervisor of Procedures and Coordination to monthly inform the appropriate section heads through a memo of those procedures that were overdue.
As a result of these efforts the percentage of procedures overdue dropped from the original 3.2 percent in March 1988 to 2.5 in April to 2.1 in May of 1988.
ihe Quality Assurance . audit findina was closed out based upon QA's determination as stated, i " Evaluated results for the past three months in order to determine the effectiveness of section heads to complete the overdue periodic reviews.
The results are as follows: March 3.2 percent; April 2.5 percent; May 2.1 percent remaining overdue.
Since a declining trend has been evident for the past three months, it is determined that the corrective action taken has been effective.
This finding is considered closed." The audit finding was subsequently closed out on June 7, 1988.
However, by the end of October 1988, as identified in Memo PC-88-0034 dated November 30, 1988, there were 125 procedures that were overdue, 40 of which had been reviewed and required revision, 85 which had not been reviewed for revision, and 51 that were in suspension.
This was the report that the Diagnostic Team Members reviewed along with previous reports that had shown a decrease in the number of overdue procedures, but still
_ - _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _-
p - _ _ _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _ - __ . - O a continuation of overdue procedures beyond the two year periodic reviews.
The inspector reviewed the last two reports for April - and.May 1989 and noted that there were no overdue procedures for l the two year periodic review.
However, the failure to perform the two year periodic review at the time that this matter was identified is considered a violation (341/89011-04(DRP)) of Technical Specification 6.8.2.
It'should be noted that the ' corrective actions appear adequate, though slow, as evidenced by the last two month's overdue procedures report.
Therefore, a response to this violation is not necessary.
l With regards to the adequacy of the quality assurance department closing the audit finding based on 7. declining trend the inspector showed this audit to the quality assurance manager.
The manager did not consider this an acceptable method for resolving audit findings.
He initiated a review of all 1988 audit findings and determined that this was the only finding handled in this manner.
The inspector considered the handling of this audit finding as an isolated occurrence and a violation unnecessary.
The inspector pursued what involvement the offsite oversight committee, the Nuclear Safety Review Group (NSRG), had in reviewing this Technical Specification violation.
Technical Specification 6.5.2.7.e requires NSRG review violations of Technical Specifica-tions.
The inspector discussed how a Technical Specification violation identified in an audit finding is reviewed by the NSRG.
The inspector ascertained that audit findings are on distribution to the NSRG secretary who provides them to the audit s 2 committee and any other interested committee member for review.
After discussion with the secretary the inspector ascertained that the audit finding was reviewed at meeting 88-01.
However, given the time frame of the meeting, the final resolution of the audit finding was not reviewed.
Then the inspector explored how Technical Specification violations identified on a deviation event report (DER) are brought to the attention of the NSRG.
It was apparent that any DERs requiring 50.73 reporting would be reviewed as part of the LER review.
The inspector then selected a DER which identified a Technical Specification violation which was not required to be 50.73 reported.
DER 89-0314 was selected. This DER dealt with two quality assurance audits being conducted outside of the required twelve month interval.
Through discussion with the NSRG secretary the inspector ascertained that all DERs are submitted to the NSRG secretary who screens them for referral to the appropriate subcommittee or the main body of the committee.
In this particular instance the DER was given to the audit subcommittee for review.
) The subcommittee chairman had concerns with the DER and the I subcommittee chairman, the secretary of the NSRG, and the QA manager met to discuss the DER and the resolution to the DER.
The meeting concluded with the subcommittee chairman comfortable with the actions being taken.
The matter never was brought forward to the full membership of the NSRG.
Furthermore, in the discussion
l _ _ _ _ _ _ _ _ _ ___ _ J
- _ _ - ______ ---_ - - _ -
-. , : o 1: I' with the NSRG secretary it was noted that there is no charter for ' the audit subcommittee.' The interface between.the subcommittee responsibility to the whole body of the NSRG will be pursued in a '- L-future' inspection report.
Then the inspector explored how the Onsite Review Organization '(OSRO) carried out reviews of non-50.73 reportable Technical . Specification violations. Technical Specification 6.5.1.6.f establishes the OSR0 as responsible for investigations of all violations of the Technical: Specifications, including the preparation and forwarding of reports covering evaluation and. L recommendations to prevent recurrence, to the Vice President-Nuclear Operations and to the fluclear Safety Review Group. The inspector discussed the matter with the head of plant safety who stated that he reviewed all DERs for placement on the OSR0 agenda..The head of plant' safety stated he would not have necessarily fitgged Technical Specification violations of Section 6, administrative controle, for OSR0 review.
He considered Section 6 different than the rest of the Technical Specifications. The inspector informed the plant safety f, head that the only difference dealt in the deportability aspect of a El Section 6 violation.
The head of plant safety directed a review of the DER logs for Section 6 violations.
Forty-four were identified and subsequently reviewed by OSRO.
The failure of OSR0 to review the Section 6' violations is considered a violation (341/89011-05 (DRP)) of Technical Specification 6.5.1.6.f.
However, given the corrective action taken by the licensee and the understanding the , head of plant safety now has on what needs to be referred to OSRO, no further action to this violation is warranted.
q.
(Closed) Open Item (341/86007-03(DRP)):. Establishment of vibration testing criteria for the high pressure core injection (HPCI) pump.
The inspector reviewed Procedure 24.202.01, "HPCI Pump Operability and Flow Test of 1,000 psi and Valve Operability." The procedure prescribed'the ASME inservice test requirements to be performed at least once every 92 days.
Inclusive in this-testing was. vibration data on the pump with appropriate acceptance criteria.
This item is considered closed.
r.
(Closed) Violation (341/87026-01(DRP)): High pressure coolant itijection (HPCI) test return line to the condensate storage tank isolation valve, E41-F011, found energized in violation of License Condition 2.c(9)(a).
The inspector verified proper positioning and deenergization of this valve is included in the current revision of system operating Procedure 23.202, "High Pressure Coolant Injection System," as well as surveillance Procedures 24.202.01, "HPCI Pump Time Response and Operability at 1000 psi," and 24.202.02, "HPCI Flow Rate Test at 165 psig Reactor Steam Pressure." Proper configuration of E41-F011 was also included in operator initial and requalification training programs, with the information of concern specifically provided as part of Lesson Plan ST-0P-315.039-001 (Rev. 5).
This violation is closed.
s.
(0 pen) Open Item (341/89002-04(DRP)): Weaknesses in communications between control room operators and personnel performing activities
=- _ _-_ - - _ -. _ _ _
.. . _ _ _. ., .. L I affecting the configuration of important plant equipment.
To date, l Procedure 44.160.02, " Fire Protection Detection Operability and Functional Test," has not been revised.
Additionally, another example to be included under this item is discussed in Paragraph 3.
No other violations or deviations were identified in this area.
3.
Operational Safety Verification (71707) The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the period from April 11 to June 5, 1989.
The inspectors verified the operability l 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.
During the inspection, the inspectors walked down the accessible portions of the following systems to verify operability by comparing ' system lineup with plant drawings, as-built configu ation or present valve lineup lists; observing equipment conditions that could degrade i performance; and verified that instrumentation was properly valved, i functioning, and calibrated.
Standby Liquid Control System Core Spray System - Division II Standby Feedwater System Emergency Diesel Generator No. 13 . Emergency Diesel Generator No. 14 j j The inspectors also witnessed portions of the radioactive waste system I controls associated with radwaste shipments and barreling.
These reviews and observations were conducted to verify that facility j operations were in conformance with the requirements established under ~; technical specifications, 10 CFR, and administrative procedures.
a.
During the inspection period the inspector noted that Division I CCHVAC was in off/ reset with the supply fan, recirculation fan, exhaust fan, chiller pump and cooling coil pump control switches flashing.
This is a normal condition and a normal alignment for one CCHVAC division and the division is considered operable by the licensee even though it is in off/ reset.
The inspector pursued why this alignment was considered acceptable.
In conversations with the operating authority the inspector was told that both CCHVAC
_ _ _ _ _ _ _ _ _ - _ _ _ _ - _
, _ - _ _ _ . % > I divisions cannot initiate and operate. simultaneously without - overpressurization'of the ductwork.. Thelinspector reviewed the ' UFSAR and the SER and determincd that having one division in-off/ reset was acceptable but ne reason was given.
' - The-inspector began'to investigat'e whether a single failure in the off/ reset division.of CCHVAC could cause that division to initiate along with the other division'which'was in automatic.
After a review of the schematic drawings the inspector noted that the recirculation fans could initiate simultaneous 1y'and operate with a
r . single active failure in the logic circuity.
Then the inspector pursued whether the perception of the operators of overpressurization of. the ductwork in such a condition truly existed.
The_ inspector contacted the engineering department to ascertain this.
During the review for this condition the licensee identified that the CCHVAC ductwork on the suction of the' recirculation fans was not designed in accordance with statements in the UFSAR.
In UFSAR Appendix A, "Conformance to Regulatory Guides," Item A.1.52 committed the licensee to designing the CCHVAC ductwork in accordance'with an Oak Ridge National Laboratory standard, e ORNL-NSIC-65, for this particular section of ductwork.
The applicable tables of Section 2.8.1 of the ORNL standard required 18 ga. sheet metal for the reinforced spacing used but the actual construction was of 16 ga. sheet metal.
Failure to design the . CCHVAC ductwork to the appropriate regulatory standard is coreidered . i i an example of a violation (341/89011-028(DRP)) of 10 CFR 50, l Appendix B, Criterion III, " Design Control."
L On April 20, 1989, the licensee initiated DER 89-0508 stating l that the design of the duct work was not in conformance with l ORNL-NSIC-65.
Also, the design calculations on the drctwork had not assumed that CCHVAC would be in service during a postulated earthquake.
Therefore, earthquake loading had not been added to the system operating stresses. The licensee performed a technical evaluation as to the ramifications of not designing the ductwork in accordance with the approved standards including earthquake loading.
The licensee determined that the ductwork would experience some slight deformation reducing the flow area by 6 percent but would still be able to meet the minimal flow requirements for CCHVAC as prescribed in the Technical Specifications.
Based upon the , technical evaluation results the licensee concluded that the CCHVAC system was operable.
LER 89010 was subsequently written on the design deficiency and submitted to the NRC on May 22, 1989.
In the original DER determination the engineer and the reviewer of the DER failed to check the blocks associated with a 10 CFR 50.59 review, a potential 10 CFR 21 or a significant condition adverse to quality (SCAQ).
This situation was identified by the Safety Group Reviewer and and the blocks were subsequently checked.
However, the block associated with 10 CFR 50.59 was ch cked yes with a note to see further information in the DER.
Funther information in the DER states, "A safety evaluation wil' be prepared
1
i y 'e .
if the analysis-resulted in a UFSAR change or a design change." On ' May 30th the inspector brought this to the attention of engineering management.
The specific questions were why a safety evaluation was not already performed or why the technical evaluation that was performed for operability of the CCHVAC ductwork was not in the form of a safety evaluation.
It was clear that the design of the CCHVAC was not in conformance with the committed standard identified in the UFSAR.
Engineering management stated that a safety evaluation was appropriate and one was initiated.
The inspector discussed the overpressurization aspect of dual recirculation fan operation with the cognizant engineer who discovered the original design deficiency.
Upon a review of the fan discharge capacities the engineer's perception was that there was adequate margin for dual fan operation.
However, a final review was needed.
The inspector will pursue this matter in a future inspection period.
Also, the inspector noted that another DER, 89-0588, was written as ar additional investigation into the CCHVAC ductwork.
This DER' identified that a portion of the ductwork had not been preoperationally leaked test.
The inspector reviewed the DER and the initial resolution evaluation which stated, " Engineering has , performed a quantitative assessment of the' expected leakage in the i duct work assuming the same quality of construction as other duct work that was leak tested the results are as follows." However, later.in the DER it stated, "It is recommended that a visual inspection of the duct work be performed to indeed determine if the duct work is of the same quality of construction as other tested duct work."
It is questionable as to the adequacy of this resolution given that the duct work was not inspected.
The inspector brought this to the attention of engineering management on May 30th for further review and determination as to the acceptability of this ~ type of resolution. The inspector will pursue this matter in a subsequent inspection period, b.
On May 18, 1989, the Operations Superintendent notified the Senior Resident Inspector of a significant operational occurrence that had occurred earlier during the day.
The Operations Superintendent recounted that on the previous day, during swing shift, the Standby Liquid Control (SLC) system had been taken out of service for surveillance testing.
The system was not returned to service until nine hours later on graveyard shift.
Technical Specification 3.1.5 requires an inoperable SLC system be returned to service within eight hours or be in at least hot shutdown within the next twelve hours. On-shift operations personnel were unaware thtt they entered the twelve hour shutdown portion of the Technical Spe<.ification until after the system was returned to service.
Subsequently, DER 89-0610 was written on why personnel didn't understand whom they were in the Technical Specification action statement.
'he Operations Superintendent stated that a critique of this matter would be accomplished.
. - - - _ - _ _ _ _ _ - _ _ _ _ - _ . _ _ - _ _ _ _ _ - _ . _ _ - _ _ _ - _ _ _ _ - _ _ - _ _ .-
.- - _ _. _ _ .. O Later the ir:pector was furnished with the critique.
From the critique the ir.spector ascertained that one of the two divisions of I I SLC had been taken out of service for preventative maintenance on l l-dayshift, May 17, 1989.
This placed the licensee into a seven day ' l limiting condition for operation (LCO) action statement after which the unit must be placed in hot shutdown within 12 hours.
Main-tenance was completed at the end of dayshift and surveillance testing was required prior to declaring the division operable.
However, during the surveillance testing the the common suction valve to both SLC pumps must be closed.
Therefore, the test rendered both divisions inoperable which is an eight hour LC0 action statement. Testing was assigned to a licensed reactor operator and a power plant operator. The test was apprcved to be performed by the swing shift operating crew and testing commenced.
In the approval of the test the operating crew failed to recognize that the SLC system would be rendered inoperable.
No formal briefing was held on the testing evolution.
At 1745 the suction valve was closed and the eight hour LC0 entered, though the operating crew was not aware of this.
Also, the testing reactor operator did not identify that an eight hour LC0 was initiated.
At 2100, par tially through the testing, problems were encountered.
To resol'e all the problems consultation with the assistant shift supervi or (NASS) and the shi't supervisor (NSS) along with the approva of a temporary procedure change by the NASS and NSS were required.
During the review of the change the shift supervisor recognized that the suction valve was closed. The shift supervisor made a dacision that the SLC system could be considered operable with the common suction valve from the tank to the two SLC pumps closed provided an operator was stationed at the valve.
By the end of the shift the procedure change was approved and the
completion of the testing would have to be accomplished on graveyard ' shift.
The NSS and NASS discussed the configuration of SLC.
The conclusion of the conversation was that the eight hour LC0 would be entered into at the point that the valve had been closed.
The NSS chose that time to have been wnen the testing problems were encountered at 2100 not the actual time of 1745.
The NSS did not consult the testing reacto". operator but assumed 2100 was the appropriate time.
In the process of turnover the offgoing NASS informed the oncoming NASS that they were in the eight hour LCO which expired at 0500.
The offgoing NSS did not provide this information to the oncoming NSS and did not log that the short term LCO had been entered even though Procedure NPP-0P-11 Section 5.3 required such an action.
Subsequently, in the shift meeting the oncoming NASS notified the oncoming NSS that they were in the eight hour LC0 action statement.
SLC testing resumed and was completed with the system returned to service at 0245.
Corrective actions in the critique included:
Addition ' a caution in the SLC surveillance procedure to specify thao sn eight hour LCO is being entered.
_ _ _ - - - _ _ - _
_ - _ - _ - . a Add a step in the SLC surveillance procedure for the NSS to
acknowledge the new caution statement.
Require logging of the time the suction valve is closed.
- Review by all licensed personnel of NPP-0P1-11.
- Issue a night order informing operating personnel of the
problems encountered while performing the SLC surveillance.
Add this problem into the Technical Specification case study
program.
Evaluate the need to flush the SLC system following
surveillance testing per Procedure 24.139.02.
Add the critique to licensed and non-licensed required reading.
- All corrective actions would be completed by August 1, 1989.
The inspector conducted selected interviews with individuals involved in this matter and generally confirmed the accuracy of the critique and how the problem was identified.
The oncoming NSS was bothered by the offgoing NSS not informing him that he was in an 8 hour LC0 action statement to the point of re-reviewing the logs associated with the surveillance testing and the control room log. Without satisfactory resolution in those docunents he proceeded to review the surveillance log and noted the time frame in which the surveillance had begun.
He again reviewed the surveillance and r.oticed that the first step required that the suction valve to be closed and concluded that the time frame of the LCO action statement that they were currently in could not be proper.
Therefore, he contacted the offgoing shift and ascertained the decision made by the NSS.
He subsequently stated that he did not consider this an appropriate manner in which to handle the SLC system.
At this point in time the LCO action statement had in fact been exceeded by approximately an hour and the system was being returned to service.
The NSS informed the Operations Engineer of the situation and DER 89-0610 was initiated.
The failure of the shift crew to not tecognize that they entered into an 8 hour LCO for the SLC system is considered another example of a violation (341/89011-03C(DRP)) of 10 CFR 50, Ap endix B, Criterion V, " Instructions, Procedures and Drawings,p' in that procedure NPP-0P1-11 was not followed.
Even though this violation was licensee identified other violations in this area have been given in the last two years.
Another matter came to the inspector's attention during these interviews.
The inspector concluded that this matter was not a contributor to the SLC problem but was of concern to the inspector.
When swing shift assumed the watch the production schedule was considered excessive by the shift supervisor resulting in the NSS not concurring with the schedule.
The NSS performed those tasks he
.. _ _ _ _ _ _ _ _ _ _._ _ _ _ _ _
_ _ _ _ - _ - _ _ - - _ -. - - - -. - - - - - _ - _ - - - - -, . . felt capable of performing but the schedule was never revised.
The inspector discussed this situation at the exit id stated that routine inspector observations would include scheduling interaction / approval by the operating authority.
No other violations or deviations were identified in this area.
4.
Monthly Maintenance Observation (62703) Station maintenance activities on safety-related systems and com90nents listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.
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 performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemcated.
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:
WR No. R036890328 PM on 130V Battery Charger R325021B e WR No. 00781222 Seal leaks on Standby Coolant Pump for EDG 12
WR No. 009C890310 Drain Valve Plugged - R30F041C
WR No. 839890328 Semi-annual PM on EDG 12.
- WR No. R088890328 Inspect, Lube, and Test M0V R30F607
WR No. Y585890328 Clean SGTS C02 Tank Condenser Coil Fins
WR No. T016890228 PM North SGTS Exhaust Fan
WR No. T024890328 PM North SGTS Cooling Fan
WR No. A5548904 PM T4100B016 SGTS North Room Essential Cooling Unit
WR No. 004C890602 Replace Backup Manual Scram Circuit Interrupter Pertinent observations were: a.
During the PMs on the SGTS equipment, the inspector verified that the different greases used in the field matched the CECO Database.
b.
During the PM on R32S0218 (Procedure NPP-35.309.001), procedural j problems occurred in that the hardware did not match the procedural requirements. For example, Step 4.1.3 required the application of 0 volts to the voltmeter and verification that the meter read in the range of -3.0 to 3.0 volts.
However, the voltmeter on the charger reads from 75 to 150 volts.
Additionally, other proce & ol problems
-- _ _ _ - -. . _ _
- _ - -_--- -- - ._ - - -_ . _ - - _ - - - _- -- -- _ H ac were identified.
Subsequently, Rev. 23 to the procedure was issued and the PM was completed.
The. inspector noted that thes_e procedural inaccuracies caused delays and' ultimately resulted.in the'PM spanning two days.- On.the first day the electricians left the job site with a Technical-Specification (TS) fire door (barrier) blocked open.
This was identified by a security guard on patrol who notified the NSS and
- the door was subsequently closed.
On the next day, May 3, 1989, while the inspector was watching the job, both electricians left to go to the control room with two TS doors blocked open.
The inspector remained in the area. When the electricians returned, the inspector asked them what their respons',bilities were regarding the blocking of TS fire.' doors open. -They 7esponded that as long as they notified the NSS that the doors would be opened at the start of the job there was no need for them to stard fire watch.
Further review by the inspector determined that a fire watch must be maintained in this case at a11' times while the doors were blocked open by a person who has been properly qualified in accordance with TS 3.7.8.
. The, situation was identified to cognizant maintenance management personnel.
A meeting was held with craft personnel to discuss their understanding of the fire watch requirements.
The results of the meeting revealed that craft personnel.had the same general perceptions as the individuals on the battery job.
The inspector also determined that only select maintenance journeyman are fire watch qualified. This appears impractical since in the course of a journeyman's activities a TS fire door is eventually going to be blocked open requiring a qualified fire watch.
DER 89-0565 was written to track this concern.
DER 89-0565, Part SA, stated that Nuclear Training is modifying the training program to specifir. ally state the responsibilities of a fire watch as they pertain to' leaving a fire barrier breached and that fire watch will be included as a topic for the next continuing training cycle.
Failure to maintain adequate training for TS 3.7.8 fire watches is'a violation (341/89011-06(DRP)) of 10 CFR 50, Appendix B, Criterion II, " Quality Assurance Program."
During followup activities, the inspector noted that DER 89-0565 was assigned to Maintenance for disposition and it was subsequently routed to Plant Safety for review.
No interface was established with Operations to document any corrective actions that they would take to prevent recurrence, e.g., remind journeymen of their l responsibilities when TS door is blocked open, verification that the journeymen are qualified fire watches, etc.
c.
Review of Generic Lubrication Program Concerns Based on 17 DERs written on equipment lubrication concerns and NRC open items, the licensee issued DER 89-0529 on April 28, 1989, to document and resolve the generic concerns.
On May 16, 1989, the
. _ _ _ _ - - _ - _ _._ - ..
_ _ _ _ k
,
, ! Plant Manager issued a memorandum with an enclosed action plan. -The plan contains 18 actions recommended to strengthen the lubrication program.
Resolution of DER 69-0529 and implementation of the action plan is an Open Item (341/89011-07(DRP)). DER 89-0579 was issued on May 8, 1989, for incorrect lubricant in , the EECW Pump motors.
A previously completed PM on P4400C001B documented the use of Shell Alvania 2EP for lubrication of the pump motor bearings.
The CECO Database specifies Dolium R.
Preliminary investigation indicates the same condition exists for P4400C001A.
The hardcopy lube manual, Rev. B, dated March 1986, specified the wrong grease.
The new CECO computerized database has the correct grease :pecified.
Additionally, the environmental qualification letter, EQ1-EF2-280, Rev 1 for P4400C001A/B, had the incorrect grease specified since it was developed based on the March 1986 luba manual-. This may be a concern in that the EQ personnel who developed the EQ letter obtained their information from the lube manual rather than independently checking vendor manuals / environmental qualification reports.
Disposition of DER 89-0579 will be tracked under the previous open item.
No other violations or deviations were identified in this area.
5.
Monthly Surveillance Observation (61726) The inspectors observed the following surveillance testing required by Technical Specifications and verified that; testing was performed in accordance c,th 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 requirements and were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
- 24.610.05 RPS - Backup Manual Scram Functional Test
24.405.03 Secondary Containment Integrity Test
24.307.14 Emergency Diesel Generator No. 11 - Start and Load Test
24.307.15 Emergency Diesel Generator No. 12 - Start and Load Test No violations or deviations were identified in this area.
6.
Followup of Events (93702) 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 notification was correct and timd y, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted
_ _ _
_-. _ - - . .. . within regulatory requirements and that corrective actions would prevent future recurrence.
The specific events are as follows: April 17, 1989 Fire in the Availability Improvement Building.
April 20, 1989 Control Center HVAC Potentially Outside of Design Basis.
May 25, 1989 HPCI Level 8 Trip Found Outside of Allowable Value During Surveillance Testing.
June 2, 1989 Failure of the Backup Manual Scram Breaker B to Trip When Transferring Reactor Protection System Power From Alternate to Normal.
- June 2, 1989 Notification to the FAA of Loss of Some of the Cooling Tower Lights.
June 3, 1989 Unplanned ESF Actuation During Surveillance Testing Causing Numerous Containment Isolations and Energization of the HVAC, Standby Gas Treatment, and Control Air Compressor Systems.
There were numerous security events followed up during this inspection l period.
_ The June 2 event occurred while the electrical power supply for reactor protection system (RPS) B was being manually realigned from its alternate supply (480v Distribution cabinet 72C-2D-2) to its normal supply (RPS MG set B).
This was a dead bus transfer and several half-isolations and half trips were anticipated by the operators.
However, a trip of the B Backup Manual Scram (BUMS) did not occur as expected.
Licensee immediate actions were both timely and comprehensive.
The failure was determined to be within circuit interrupter C71-005004B within the RPS trip system B electrical panel.
The panel was then quarantined.
A like-for-like replacement was assembled (consisting of ITE Siemens-Allis circuit interrupter model E225100A and an undervoltage trip coil attachment U01E60) and subsequently installed and successfully tested.
The failed component was removed without change to the failure configuration and shipped to Detroit Edison's Engineering Research Department (ERD) to determine root cause of the failure.
Since this type of breaker had earlier failed in 1987 in the other RPS division, this will remain an open item pending completion of the ERD analysis (341/89011-08(DRP)). No violations or deviations were identified in this area.
7.
Licensee Event Reports Followup (92700) . 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.
__ _._ - - _ _ _ -
__ ... -.
a.
(Closed) LER 87-056, Reactor' Scram Due to Personnel' Error and Subsequent Reactor Water Cleanup System Isolation.
On December 31, 1987, while at 75% power, a temporary modification to irastall a monitor and printer to determine the Number 1 Feedwater Heater level was being installed.
During the installation, it was determined that the gross megawatt signal could not be used as input to the monitor and feedwater flow signal was substituted without changing the temporary modification.
During the installation, the I&C Technician accidentally grounded one lead of the A Loop .feedwater flow instruments that in turn blew the fuse on the feedwater square root converter power supply.
This power supply also supplies power for the proportional amplifier that sums the feedwater flows through both A and B Loops.
Since one of the loop indicated flows was lost, the total indicated feedwater flow was decreased by' fifty percent thereby increasing the actual feedwater flow and the reactor water level until a high level trip closed the turbine control valves scramming the reactor.
The initiation of-the event was caused by the inadvertent grounding of a lead to the feedwater controller, however, the work being carried out was a change from the approved temporary modification and the change had not been reviewed or approved.
The temporary modification procedure in use at the time, 12.000.025, Rev. 10, did not specifically state that any changes to the approved temporary modifications would be reviewed and approved the same as the original.
Licensing Action Notice (LAN) No. 88-038 was issued and Rev.11 of the procedure approved February 9,1988 now requires a full review and approval of changes to the original temporary modification.
Licensing Action Notice No. 88-036 requested Nuclear Training to review and if needed upgrade training programs in plant configuration control.
Nuclear Training included this lesson learned event in Procedure Compliance Unit 1 on both configuration control and compliance with procedures and added the upgraded Unit 1 as a requirement for Fermi Orientation A Initial and also all Requalification Training.
In addition after the Procedure Compliance Unit 1 videotape was revised the Senior Vice President directed all site personnel to review the tape by June 29, 1988.
The engineered safety features challenged during the scram responded as designed, however, the shitdown was complicated by isolation of the Reactor Water Cleanup (RWCU) system by a differential flow condition.
The RWCU isolation was caused by a sequence of events during which the RWCU pumps were tripped by low flow when the RWCU system delay volume flashed to steam and shortly after establishing I a gravity drain from the RWCU system to the condenser, low RWCU pressure automatically closed the path.
Trapped water released past the downstream flow controller caused a differential flow condition which isolated the RWCU system.
It is postulated that the RWCU low pressure condition was caused by the failure of the reactor vessel head vent value to operate and equalize the reactor pressure and the RWCU pressure.
The RWCU isolation on differential flow is as designed.
Rev. 35 to POM 23.707, RWCU, was issued to add a caution to minimize the time that the RWCU valves to the main condenser ard to
- - - - _ _ - - _ _ _ - _ - _ _ -
- - _ _ _ - _ _ - _ i radwaste are open when the RWCU flow control valve is closed to prevent a differential flow isolation of the RWCU system.
The flashing in the RWCU system during normal plant shutdown causing RWCU pump shutdown from low flow had been a previous p_roblem (five LERs in 1985).
Engineering Design Package (EDP) 6671, approved on December 27, 1987 before the event occurred, has been installed replacing the 24 inch section of pipe called the delay volume with a 6-inch pipe.
There have been no further RWCU system flashing problems since the EDP change in early 1988.
The position indication switches and relays for the reactor vessel head vent valve were replaced and the valve is operable.
b.
(Closed) LER 88-16, Failed Relay Causes RHR Shutdown Cooling (SDC) Outboard Isolation Valve to Close.
This event occurred on April 20, 1988, when a primary containment isolation system logic relay failed because of a defective metal oxide varistor (M0V) GE-MOV II, Model No. V130LA2.
The isolation removed one RHR SDC division from service until Isolation Valve E11-F008 was manually opened in 37 minutt:s.
Tais restored both SDC divisions to operation, as required by Teci nical Specifications, while the unit was in Mode 4.
The failed MOV is an integral part of Relay A71-0-K75.
The relay had been installed and tested five days earlier during r< gular preventive maintenance and had been operated two times prior to failure.
The failure was discovered following uninterruptible power (UP) testing and mod;fications which caused voltage transients to the relay.
This failure of the MOV is attributed to these voltage transients which were beyond the limits of the MOV; however, at least five other similar relays subjected to the transients did not fail.
The MOV failure was classed as a premature failure not typical of these MOVs, since there were no other vendor or user experiences of similar failure at the time or in the intervening time period, c.
(Closed) LER 89-008, Inadvertent Initiation of the EECW Division II During Testing.
On March 16, 1989, while performing a monthly channel functional test of the Drywell pressure actuation of the RHR, CSS and HPCI systems and with the plant at 0 power in Startup Mode 2, an Instrument and Control Technician inadvertently placed a volt-ohmmeter lead on the wrong terminal inside panel H11-P626 actuating EECW Division II.
The EECW system responded as designed and was promptly returned to the normal stardby lineup.
There have been four similar occurrences of this error in the past, probably caused by the inaccessibility of the terminal strip where the reading must be taken.
A portable test box developed following the last occurrence reduces the necessity of taking many of the required readings at the terminal strip inside the panel; however, several readings must be still taken by connecting to terminals inside the panel.
Potential Design Change, PDC 10,334, has been initiated ' which will provide bariana test jacks on a spare terminal strip in these panels for those particular surveillance terminals which have been a problem in the past.
Potential Design Change 8123 has also been approved to permanently mount the portable test box at each of
i i
_ _. _ _ _ _ _ _ _ _ _ _ _ _ _ t '. e g l these panels.
This LER will be closed and the completion of ) PDC 10334 will be added to previously identified Open
Item (341/89008-13(DRP)) for implementation of PDC 8123.
{ i An accountability meeting was held April 7, 1989, between management and the involved technicians and a description of this event will be " required reading" for all technicians.
d.
-(Closed) LER 87-036, Reactor Scram Due to Misaligned RHR System Valves.
e.
(Closed) tER 88-035, Automatic Scram Signal Generated During Shutdown Due to Failure to Follow Procedure..The cause of this event was attributable to the Control Room Nuclear Supervising Operator (CRNS0) resetting a reactor scram signal using a sequence which was not in accordance with system operating Procedure 23.610, Reactor Protection System.
A weakness was subsequently identified in operator knowledge onshift in that some operators were not aware that Procedure 23.610 was applicable to the subject situation.
In response, the licensee counseled the operators directly involved in the event, a lesson learned (No. 88-011) was issued as part of the operator required reading program, and an operating experience training session was conducted during operator requalification training cycle #89-1 (completed February 17, 1989) addressing, in part, this event (reference training work request (TWR) 89-00822 and Lesson Plan No. LP-LO-233-8911).
In addition a sirnulator exercise was conducted which required all operators to properly reset the Reactor Protection System.
f.
(Closed) LER 88-001, Neutron Monitoring Instruments Inoperable Due to Procedural Inadequacy and Technical Specification Impracti-lity.
To prevent recurrence, the licensee revised APRM calibration procedures to include verification of the setdown trip setpoints upon adjustments to the fixed neutron flux upscale trips.
Urgent Required Reading Package 88-2-1 was issued and included a discussion of this event, and a Technical Specification change to add notes to Table 1.2 "0PERATIONAL CONDITIONS" to better define mode switch requirements during performance of surveillance tests was submitted and subsequently approved by the NRC.
Operator training wac conducted addressing this LER and the Technical Specification change.
l g.
(Closed) LER 87-007 and Rev 1, Inadequate Procedure Allows Operators to Void Residual Heat Removal Piping Resulting in ESF/RPS Actuation.
In response, the licensee revised System Operating Procedure 50P 23.205 to incorporate changes to operating configuration designed to prevent a recurrence of this event, a Lessons Learned (No. 87-004) was issued for review by all s'nifts, and incorporation of this event to the Licensed Operator Requalification Training Program was done (reference training work requests (TWR) Nos. 87-0689, 87-1008, 87-2063, 87-2205, 87-2156, and 87-2088).
Additionally, the particular operational configuration was subsequently modeled on the simulator.
_ _._____m__ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _. -
,__ __ . ,]. ... i h.
(Closed) LER 87040 and Rev.1: Trip of the Reactor Protection System (RPS) Motor-Generator (MG) Set from a postulated overvoltage condition.
On August 27, 1987, RPS HG Set A tripped.
Further ' testing'did not provide a conclusive cause for the event.
The a licensee determined that a possible cause was the presence of contaminants in the potentiometer for the voltage-regulator.
While i subsequent testing was being conducted, an electrician dropped a lead, causing another loss of power to RPS Bus A on September 29, 1987.
Subsequent to these events, RPS MG Set A voltage swings occurred on November 3, 1987 and were documented in DER 87-427.
On November.7,1987, the voltage regulator for RPS MG Set A was replaced with a new one.
On July 28, 1988, the wire wound voltage adjustment potentiometer was replaced in accordance with PDC / Minor Modification No. 8254.
Procedure NPP-42.610.01 was revised to include exercising the potentiometer windings by rotating the adjustment knob through the full range several times.
Subsequently, no voltage problems have occurred.
The' LER stated that guidelines for electricians working on energized equipment will be developed by January 31, 1988.
This commitment was tracked by Licensing Action Notice (LAN) 87-468.
Training Work Request (TWR) 8702477 was issued to Training by the Superintendent, Maintenance and Modifications, to formulate a class on " Precautions to take while working on energized equipment." The inspector checked the status of the TWR with the Director, Nuclear Training, who determined that the TWR was dispositioned as not being required on March 18, 1988.
The basis for this disposition was that this type of tr&ining is covered throughout the electrician's initial 15-week skills training and is also covered in monthly safety meetings.
However, during Training's independent review of DERs (at the time of this inspection) for incorporation of commitments into the training program, they reviewed the DER associated with LER 87040 and opened TWR 8900767 to track the same training commitments.
Disposition of this TWR is an open item (341/89011-09(DRP)). i i.
(0 pen) LER 88031: Failure to Perform Accelerated Valve Stroke Time Testing as Required by ASME. This item will remain open pending verification that certain corrective actions to prevent recurrence documented as complete in DER 88-1520 are still implemented.
These include publishing the IST Pump and Valve Out-of-Specification Status Report on a semi-monthly basis and addressing the uso of the Valve Stroke Time Trending Data Sheet in a procedure.
j.
_(_ Closed) LER 87-015, Standby Liquid Control Concentration Exceeded.
No violations or deviations were identified in this area.
8.
NURFG 0737, TMI-2 Action Items (Closed) Item I.C.5: Procedures for Feedback of Operating Experiences to Plant Staff.
Fermi Management Directive, FMD SRI, Safety Review and Evaluation, dated December 21, 1987, establishes the requirements for a program to systematically review and evaluate the safety of Fermi 2
- - _ - - _ - _ - - -
E L
E , operations.
Included in the required reviews are the operating experiences-at Fermi, the experiences of industry, and also the issuances of industry and regulatory agencies.
Responsibilities for initial i reviews are assigned through the DER system and the OER Enhancement Plan as documented below (Paragraph 11).
Fermi Management Directive, FMD CA1, Rev. 1, dated April 11, 1988, establishes requirements for the identification, documentation, notification, evaluation and correction of events or nonconforming conditions that have the potential of affecting the safe operation of Fer'ni 2 and assign responsibilities for implementing these requirements.
It covers not only conditions found to be adverse to quality at Fermi 2, but also all reportable events and nonconformances identified by other industry organizations and regulatory agencies, and.other industry and agency issuances.
It also establishes the Deviation / Event Repnrt (DER) System that is used to document each event, nonconforming items, issuances, etc., assigns responsible units, and controls the DER until it is satisfactorily completed and approved.
The Directive also assigns i the organizational responsibility for initiating DERs for all external ! and some internal issuances.
Nuclear Engineering is responsible for initiating all authorized nuclear inservice inspections and vendor issuances; Quality Assurance end Plant Safety, all INP0 and American Nuclear Insurer issuances; Nuclear Services all vendor initiated 10 CFR 21 reports; and Nuclear Licensing all NRC issuances and violations, unresolved items, and open items.
The Directives are implemented by Fermi Interfacing Procedures , i FIP-CA1-01, Deviation and Corrective Action Reporting and FIP-TQ1, Training and Qualification Manual.
FIP-CA1-D1 prescribes the method for processing DERs, for the identification, documentation, notification, evaluations, reporting and trending of events or aconforming conditions having the potential for affecting safe and reisable Fermi 2 operations.
One individual in Plant Safety is assigned the responsibility of initial review of all DERs for significance and inclusion in INP0 Nuclear Network and Fermi Focus, a local publication, for more general information.
He also reviews for NRC deportability or potential deportability.
l FIP-TQ1-18-SQ, Training Program Evaluation, dated March 10, 1988, l specifies that all onsite and offsite operating experiences and Fermi 2
- -
design changes will be routed to Nuclear Training for their evaluation for including the item in the training program.
Each item selected is included in the Simulator Configuration Management System (SCMS) which tracks all the items until training is completed.
All changes at Fermi 2 l including engineering design packages, temporary modifications, as-built changes, preliminary design changes, and engineering change requests are ' reviawed for inclusion in the training program and also for any changes I that might be required to update the simulator.
The inspector concludes that the licensee's procedures in this area are adequate to assure that both internal and external operational experiences are included in the Fermi 2 training program or are directed l
_ _ _ _ _. - _ _ - - _ _ _ _ _ - - - _ - _ - - _ - - _ - - - - - - _ -- - J
- _ _ _ - - _ - - _ _ _ - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ - - - _ _ _ _ _ _ _ - - - . 'c. ,('
', to the Fermi personnel'needing the information; therefore, this Action ' Flan Item is considered to be closed.
.9.
. Temporary Instruction 2515/100, Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel Oil (255100) Since.there have been.several past events at other sites from plugged or failed filters and strainers as reported in I&E Circular'77-15, NRC Information Notice 87-04, and INP0 SERs 87-19 and 88-1700 and SEN 44, this.TI was a request to inspect the licensee's program to maintain adequate quality of.EDG fuel oil.
The four Fermi EDG-fuel oil systems are housed in reinforced-concrete, seismic Category I structures with each system enclosed in its own concrete cell and each isolated from the other units.
Each system has its own fuel & oil storage, transfer system and day tanks housed in the structure.
The ventilation system for each cell.is designed to maintain the temperature between 65 and 104 degrees Fahrenheit throughout.the year.
Each EDG has dual transfer pumps to the day tank with strainers on the pump suctions with differential pressure (dp).indicationlocally.
Each storage tank is fitted with level sight glasses and high/ low level alarm in' EDG control room and in the main control room.
Each day tank also has a level sight glass and low level alarm located as above.
There is a strainer with dp local indication on both the engine driven and motor driven oil feed pumps from the day tanks to the EDG and a duplex fuel filter on the pump discharge to the. fuel header with local dp indication.
The duplex filter downstream dp tap also provides a fuel oil low pressure. alarm in the EDG control room and also in the main control room if pressure falls from normal operating pressure 20 psig to 10 psig.
Strainers are cleaned and filters changed.
.if the dp nears 10 psig and on an eighteen month frequency.
The dp's are taken every 30 minutes during test runs and trended so cleaning or replacement is completed before the 10 psig limit is reached.
Fuel quality is established by purchase order and during the receipt inspection which includes sampling and analysis per ASTM D4057-81 and ASTM D975-81 as required by Technical Specifications.
The four tank truck compartments are separately sampled and composited.
Flash point, specific gravity, viscosity and sulfur content are determined at the site before the truck is released for unloading.
Five other determinations: carbon residue, ash, distillation temperature, copper strip corrosion, and cetane number are made by an offsite laboratory within 31 days.
The storage tanks and day tanks are sampled for water content monthly following the test run and after any run greater than one hour.
The storage tank is sampled and analyzed monthly for particulate content per l ASTM D2276-78.
If particulate are ever found to be greater than 10 mg/ liter, the Technical Specification limit, temporary hoses can be used to remove the out of specification fuel oil through the day tank to a tank truck for disposal.
This is estimated to take about 70 hours.
This review indicates all requirements of Regulatory Guide 1.137 and An5-59.51/N195-1976 have been met except that the duplex filter dp is not , L alarmed in the main control room; however, low fuel oil pressure down stream of the duplex filter is alarmed in both control rooms.
Also, there is no high level alarm on the day tank as it is normally overflowed to t.he storage tank and high level alarm is unnecessary.
This TI is considered to be closed.
i . . l
.. . ' 10.
Followup 'on Confirmatory Action Letter (92703) l (0 pen) CAL-RIII-88-20: This CAL, issued July 15, 1988,' dealt with two events of compression fitting failures in Reactor Water Cleanup (RWCU) instrument lines in May and July 1988.
The CAL documented agreements with the licensee on eight corrective actions of which only one remains open, the inspection of fittings on the RWCU system and eight other safety related systems, (see Inspection Reports No. 341/88026 and l' No. 341/89002).
l' The licensee established a schedule for the above inspections and has ' completed eight of nine systems.
The inspections have been completed ' ahead of the scheduled times.
The inspections completed included 118 , lines with 1807 fittings.
Of these, 774 fittings were found to be ! acceptable, 892 failed the "go no go" gap test, 76 contained mixed ' Parker-Hannifin and Swagelok parts, and 83 failed the minimum ferrule engage' ment of at least half of the tube 0.D.. All mixed part fittings were corrected to similar parts, preferably Swagelok, and all connections inspected have been tested and left in an acceptable condition.
l Inspection and corrective work will continue on the remaining Ell-RHR l system when outage time is available.
The work has been completed on ' those fittings accessible without shutdown (about one-half).
All inspection and correction work will be completed by the end of the first refueling outage in September 1989.
l 11.
Operating Experience Reviews In September 1988, INPO inspected the Fermi 2 Operating Experience Report (OER) Program and in Januery 1989 provided assistance to the licensee in this area after the INPO inspectors expressed concerns with the methods used to disseminate industry experiences and with the timeliness and adequacy of experience review and corrective actions taken.
In addition, two recent events (MOV torque switch / limit switch set points and Reactor Recirculation Pump MG SIL field breaker failure) emphasized that industry operating experiences were not being properly evaluated to prevent similar occurrences at Fermi.
As a result, the Operating Experience Report Enhancement Plan was formulated and on February 22, 1989 management established goals for the review of 238 outstanding OERs to be ! completed by the end of April 1989 and required responsible management review and approval as well as senior management review and approval of each report.
These management reviews are also to continue for all newly received OERs.
By April 25, 1989, 227 OERs had been reviewed anC approved by management.
Nine had been reviewed but had not been approved because of conflicts and 34 newly received OERs were presently under review.
If the conflicts cannot be resolved on the nine OERs, they will be sent to upper management for resolution.
Each OER, whether internal or external, is assigned and tracked by the DER system until completed.
In addition, Plant Safety has made up an OER summary sheet which is used to summarize responses, corrective actions,
1 )
_ _-_ __ ___ . ,. .r and management approvals.
Plant Safety maintains a complete file of all OERs and summaries since the inception of the OER Enhancement Plan start, including the 1988 backlog.
The objectives of the OER Er.hancement: Plan are to assure that known industry events will not occur at Fermi by: a.
Assigning OER reviews to appropriate personnel .b.
Completing the reviews and corrective 3ctions in a timely manner.
c.
. Periodically assessing the effectiveness cf the program.
' To implement the first point, OERs will be clatsified by subject / topic so that appropriate Fermi management will be assigned responsibility for the timely review and completing arg necessary corrective actions.
Plant Safety has formulated a matrix to be used to assign review responsibility.
Three groups, Training, Quality Assurance Program, and the Independent Safety Engineering Group (ISEG) will receive all OERs, . other groups will be assigned according to the matrix.
In addition, any I OERs of general interest and concern will be published in the Fermi ' Focus, a periodic newsletter available to all site personnel, All 50ERs and any required corrective action will be summarized and placed in a book available to all appropriate section heads.
The 50ER book will be l kept current to document corrective actions so that each responsible section can assure that the corrective actions are completed and being maintained.
The second point has been previously discussed.
The backlog of OERs from 1988 has been completed except for nine which had conflicting reviews that had not been resolved.
Current OER reviews were being made in a timely manner. The backlog of 1988 NRC Information Notices, numbering about 27, are now under active review.
The third point, assessment of the programs effectiveness, is to be audited through regular QA audit / surveillance activities.
Specific SOERs have been added to scheduled audits depending upon subject / topic.
In addition, a poll of Fermi personnel will be taken at least annually to determine the extent information is being disseminated and retained.
The Director of Plant Safety will. update management monthly on the status of the program.
Fermi personnel have also reviewed the OER programs at the Rancho Seco and VC Summer which were cited by INP0 to have effective programs.
Recommendations of the INPO assistance visit in January 1989 will be evaluated for inclusion in the Fermi Plan.
12.
Review of Generic Letters (Closed) Generic Letter 87-06: Periodic Verification of Leak Tight Integrity of Pressure Isolation Valves.
This letter requested each licensee to submit a list of all pressure isolation valves at their l plant, including for each valve, a description of the oeriodic tests or other measures performed to assure the integrity of the valve as an independent barrier at the reactor coolant pressure boundary along with
..
_ _ _ _ _ _ _ - _ .., .b the acceptance criteria for leakage, if any, operational limits, if any, and frequency of test performance.
If current plant Technical Specifications require leak rate testing of all of the pressure isolation valves in the plant, a reply to that effect is sufficient.
All plants licens'ad after 1979 have all pressure isolation valves listed in the Technical Specifications along with testing intervals, acceptance criteria and limiting conditions for operation.
Detroit Edison submitted their response for Fermi on May 8, 1987, which stated that the Technical Specifications provide requirements for leak rate testing of all pressure isolation valves.
A listing of the pressure isolation valves tested'and the leakage criteria is also provided.
The surveillance requirements for these valves provide added assurance of reactor coolant pressure boundary integrity.
This item is considered closed.
13.
Review of Information Notices (Closed) Information Notice 87-08: Degraded Motor Leads in Limitorque DC Motor Operators dated February 4, 1987.
The motors in question were manufactured at H. K. Porter between December 1984 and December 1985.
The motors were fitted with Nomex-Kapton insulated leads that are susceptible to insulation degradation and subsequent short circuit failure.
The licensee issued DER 87-054 to track resolution of the notice on February 10, 1987.
Earlier on January 5, 1987, Limitorque notified DECO of the deficiency and referenced Purchase Order NR-348010.
Valve B2103-F019 (Main Steam drain line outboard isolation valve) was identified as the only valve with the degraded motor leads.
The motor was replaced on February 19, 1987 during completion of Work Request No. PN21262179.
Other corrective actions included a. revision to the Limitorque valve operator Acceptable Materials List, a memorandum in the Materials Engineering Group providing instructions for ordering and l inspection of Limitorque motor operators / spare - replacement parts using the Acceptable Materials List, and a memorandum to PQA requesting that
they use the Acceptable Materials List during PQA vendor audits of Limitorque.
' 14.
Organizational Changes l During the inspection period the licensee performed a reorganization in their maintenance area.
Also, they removed the General Supervisor of Modifications out from under the Superintendent of Maintenance and Modifications and placed him under the Assistant to the Vice President Nuclear Operations. The inspector inquired as to what safety evaluation was performed to assure that this was an appropriate organizational change since the UFSAR identified the General Supervisor of Modifications as reporting to the Superintendent of Maintenance and Modifications.
On April 19th, the inspector discussed the situation with the Superintendent of Maintenance and Modifications, the Assistant to the Vice President Nuclear Operations, and the Plant Manager as to whether this was appropriate.
The licensee stated that no safety evaluation was performed nor a preliminary safety evaluation was performed.
As a result of discussions with the licensee management on this, a safety evaluation was performed and management stated that they clearly understood the need for such safety evaluations and that they would be accomplished in the future.
Given the safety significance involved in this particular
< _ _ - _ - _ _ _ - - _ - - - - _ - _ _.
-.___..__- _ _ __ - n.
... organizational change and that the licensee clearly recognized the need for such safety evaluations the inspector did not' consider that a violation was warranted in this particular situation.
15.
Management Meetings a.
On April 17, 1989, the inspector attended a meeting between the licensee and NRR to discuss a proposed Technical Specification change to the Secondary Containment Integrity Technical Specification. The need for the change was due to a change in the design of the pneumatic air supply to railroad car door seals.
The licensee discussed the modification that they intend to make and how that will be accomplished.
This design will provide noninterruptible air from division I to one door and noninterruptible air from division 11 to the other door.
A restricting orifice will be installed in the air supply system to prevent a seal failure from rendering the NIAS system inoperable. Also the door seal pressures would be individually alarmed in the control room.
The seals themselves will be changed out or upgraded to withstand the NIAS air pressure.
During normal operations both railroad car doors would remain closed.
b.
On April 27, 1989, the monthly meeting was held between Detroit Edison and NRC Region III at the licensee's Nuclear Operations Center.
The major elements of the meeting are discussed below: Organizational Changes and Performance Assessment The Senior Vice President began by announcing an upcoming change in who he reports to.
In the near future he would be reporting to the president of the company in lieu of the CEO and a safety evaluation would be accomplished for this organizational change.
He stated that they were adequately improved as reinforced by their performance indicators, they knew what their problems were and were focusing on corrective action implementation and they did not belong on the troubled plant list.
. Performance Indicators The licensee presented the performance indicators along with a ' performance summary beginning in the first quarter of 1988.
The ' indicators showed improvements in a number of areas.
Trends l The licensee presented their DER trending activities which showed that the hardware, personnel and procedure problems were decreasing.
The Senior Resident asked what would be the ramifications of removing the LLRT outage from this DER trend data given that the LLRT outage is of a different nature than normal operation in that the number of DERs would be different and probably more wide spread.
l - w_ _ _ _ -- -
- ._. ___- - _ _ _ ... .- DER Comparison with ANI Data ' Recently,.the American Nuclear Insurer (ANI) shared their trending data with the licensee.
The data was based on NRC violations and LERs.
The licensee showed that the ANI trending was consistent with their own Deft trending.
Ihe licensee stated that this provided an additional '.ayer of confidence thct problems were trending downward.
RglroadDoorEvent %e licensee discussed the events surrounding the discovery of a design deficiency in reactor building railroad car door seal system.
The presentation included a sequence of events, the basic assumptions used in evaluating the deficiency against flooding requirements, the standard utilized in the original design and a general description of the new door seal system to be installed which would require a Technical Specification change prior to implementation.
P; ring the presentation the NRR licensing project manager commented chat the proposed Technical Specification submittals had been of excellent quality but the submittal on the railroad doors troubled him from a timeliness aspect.
It appeared to take the licensee a'long time at arriving at a viable modified seal system.
The senior resident inspector commented that this deficiency related to previous design bases problems.
Refueling Preparations The licensee presented a basic framework for the outage along with the major milestones.
The licensee discussed the tentative level of contractor involvement in the outage.
OER Enhancement Program The licensee provided a status of the OER program as of April 25, 1989.
The total 0ERs reviewed were 270.
Approval of corrective actions had been received on 227.
Nine were presently out for further review.
On April 27, 1989, quality assurance will begin a one week assessment of the line organization's disposition of the OERs.
The 82 significant INP0 OERs had been matrixed to specific QA audits to assure continued corrective action implementation.
The last portion of the enhancew nt program, review of closed OERs, has not had a date cet for beginning/ending.
Root Cause Analvsis The licensee made a presentation on the basic elements of the licensee's root cause analysis training.
c.
On April 27, 1989, an Enforcement Conference was held between Detroit Edison and NRC Region III at the licensee's Nuclear Operations Center.
The Enforcement Conference involved six different issues in the areas of security, SPDS, Technical
- - - _ _ _ - _ - _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ -. - _ - _ + 'd Specification certification and engineering evaluations. All the issues were related with respect to the accuracy and
completeness of.information provided to the NRC by the licensee in these areas.
The personnel present at the conference are identified in Paragraph 1 of this report.
d.
On April 27, 1989, a meeting was held between Detroit Edison and NRC negion III at the licensee's Nuclear Operations Center. The topic of the meeting was the licensee's Five Year Plan. The presentation provided an insight into the process utilized to develop the plan.
The plan was provided as a list of those major activities that will be accomplished over the next five years and how engineering resources are established. As a result of this review the licensee identified three areas where NRC concurrence for deferral from the first refueling outage commitment date would be requested. These dealt with installation of limiter plates on some RCIC valves, installation of a new, upgraded rod worth minimizer and deferral of some of the Human Engineering Discrepancies (HED) to the second and third refueling outage.
e.
On May 26, 1989, the monthly meeting with the licensee was conducted at the NRC Region III Office.
The major elements of the meeting are discussed below: Plant Status The meeting began with a statement of plant status.
The plant was at 95-100% power and a potentially reportable event had occurred the night before dealing with a HPCI level 8 trip transmitter being out of calibration.
The licensee indicated that little change had been observed in turbine vibration since startup from the manual scram on high turbine vibration.
The licensee stated that they had performed a 60 percent down power maneuver to perform some valve maintenance in the feedwater system and that schedule delay problems associated with those maintenance activities were being critiqued.
Performance Indicators The licensee provided current performance indicators and trends.
Upon observing the indicators, the NRC inquired as to how far the Preventative Maintenance (PM) Enhancement Program for electrical and mechanical had progressed.
The licensee stateo that Phase 1, which was a review of the A PMs for the first six months, was completed on I schedule and phase II is in progress.
Phase II deals with refueling PMs that will be accomplished. The licensee stated that by the h end of the year that the classification of A and B PMs should be eliminated. The licensee also stated that the maximum benefits from the Preventative Maintenance Enhancement Program will probably not be realized for one to two years after the completion of the program.
.____ -.._ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -
.. -- - .. - _ - - - _ _ _ _ - - -- _ - - - ,, r '$
. Trends-The licensee, as a result of a'NRC comment during the previous monthly meeting, reperformed their deviation event report (DER) trehds eliminating the April 1988 LLRT' outage.
Even with this removed there is still a reduction in the number of hardware, procedural, and personnel error DERs since May of 1988.
The licensee also stated that 48 percent of the DERs 'eing written are v due to plant related problems and 26 percent are due to NRC or other external agency items.
Regarding the Operating Experience Review (OER) program, there were several OERs with corrective actions and/or corrective action schedules yet to be decided.
As of the last meeting the Quality Assurance Manager indicated that six additional OERs were added as a result of QA review and as of May 22nd, 297 OERs had been reviewed, 286 approved, and 11 were out for management review to determine the appropriate corrective actions.
Performance Evaluation Program The licensee provided a presentation on the Performance Evaluation Program (PEP).
This was a program that was identified as not being completely implemented during the Diagnostic Evaluation Team Inspection. The licensee began the presentation by explaining that the program entailed vibration monitoring of approximately 100 pieces of rotating machinery and that there was a heat exchanger performance evaluation portion to this program.
Presently there are 10 heat exchangers for monitoring, 3 have yet to have there baseline information provided.
As a result of questions, the licensee noted that the PEP is based upon system evaluations and that for 1989, 38 of the most important systems have been targeted ) for evaluation and incorporation of their equipment or components ' into the PEP program.
Presently, 13 of the 38 system have been evaluated.
The licensee has 120 total plant systems but only 60 to
70 of these systems would be applicable to the PEP scope.
Further
systems will be targeted for review in 1990.
The presentation of the PEP was stopped due to time constraints.
Regulatory Guide 1.97 The Regional Administrator was briefed on the Regulatory Guide 1.97 issue on Fermi as to the applicability of air operated or solenoid operated containment isolation valves to Regulatory Guide 1.97.
The licensee provided status of present containment isolation valves
and their conformance to Regulatory Guide 1.97.
The licensee ! identified 89 motor operated valves that were Class IE, seismic and environmentally qualified.
Of the 72 air operated valves 38 were , not qualified, 16 were fully qualified and 18 were seismic and
i environmentally qualified but not off Class IE power supplies. Of the the 36 solenoid valves, seven were not qualified, nine were , seismic and environmentally qualified, but not off Class IE power i and the rest of the valves were qualified.
The licensee indicated that they were working on the written submittal to the NRR with regards to the valves and that the letter is tentatively scheduled i to be issued on June 16th, i
L_-_______ _
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _. . -
! ( Refueling Outage Preparation
The licensee provided a presentation of the refueling outage ! . preparation. They indicated that June 1 was the scheduled receipt date for the first fuel shipment.
They reiterated to the NRC that the inability to defer certain human engineering discrepancies, , i installation of limiter plates on three valves and installation of an upgraded rod worth minimizer would impact the refueling outage schedule.
They indicated that they had submitted a letter to the Commission identifying these three areas for a request for deferral from action during the first refueling outage.
The rest of the licensee's presentation dealt with how the organization for the refueling outage will be configured, discussion of the outage shift manager duties, size of contract force to be utilized during the refueling outage, and the reactor disassembly /CRD change out work would be contracted out.
The licensee indicated that they do not envision any major problems with the outage at this point.
16.
Strike Preparations (92709) In response to the potential strike of AFL/CIO affiliated Local 223 the inspector discussed strike plans with licensee management on June 6, 1989.
Local 223 represents 177 personnel that encompassed non-licensed operators, I&C technicians, and electrical and mechanical maintenance personnel.
These are the areas affected by the strike. Management indicated that a strike was a possibility.
As a result of this the inspector obtained and reviewed the licensee's approved strike contingency plan.
The inspector ascertained that the appropriate minimum operations shift staffing capability could be maintained.
The licensee had performed a training and qualification program audit involving the potential replacement personnel.
The licensee briefed the inspector on the audit findings which noted minimal , problems with the qualifications of the personnel.
The inspector l discussed turnover between the potential striking personnel and the replacement individuals and determined that there would be turnovers associated with each position.
The inspector ascertained that the licensee's management had established a plan to assure unimpeded access to the plant of personnel necessary to maintain staffing and, delivery of goods onsite including consumables such as diesel fuel, nitrogen, and hydrogen.
Appropriate law enforcement agencies had been contacted to deal with non-docile strikers o an event that would threaten the plant safety. The licensee issued appropriate memoranda to all employees on how to deal with a strike and a picket line.
Given that the strike did not involve any of the licensed operators, the inspector did not review in depth the qualifications and training of the personnel that would be put in the non-licensed positions since they are licensed operators.
In the inspector's review of the strike contingency plan it was noted the local fire department and ambulance service had not been specifically contacted nor the State Radiological Health Agency.
The inspector contacted appropriate licensee management to assure that those agencies had been contacted or will be contacted.
_ _- - _ _- _ _ _. _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ - _ _ _ - _ - _ _ _ _ - - _ _ _ - _ _ - _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ - _ - _ _ _ _ - _ -
_ - - _ - _ _ _ _ _ - - - - -_.
_ - _ _ _ _ - v , - . Lie . $ 17.
Regional Rtquest i la.
On May.5, 1989 the inspector received memoranda from the Division Director of Reactor Projects discussing recent operational events.
- Two events were discussed.
The first dealing with the failure of a-freeze plug in a six inch service water line during valve maintenance.- The second event involved the. identification of a g ' hydrogen tank farm on the roof of a control room at a Region V plant.. L . The. inspectors informed the licensee of the first event and canvassed - the licensee for information regarding hydroge" cylinders in terms of their location and amount of hydrogen the stored on site.
~ b On May 9,1989 the Resident Staff received a memorandum from the DivisionDirectorofReactorProjects,requestinginformationon hydrogen storage at the facility.
The information requested was (1) t e. distance'from the hydrogen storage-facility to the nearest h safety-related structure'or air intake'and ~(2) the maximum volume of gaseous or liquid hydrogen stored on site in standard cubic feet or . gallons. ' ~ The inspector subsequently determined that at Fermi, hydrogen is stored outside at grade level-within a fenced area approximate 1y'370 feet from the reactor building and 170 feet from the nearest station service-transformer.
The amount stored onsite normally varies depending on current amount-in use.
However, the' maximum volume would-include 15,600 cubic feet in the storage tank itself and an additional 5,200 cubic feet in a truck trailer parked within the fenced storage area for a total of 20,890. cubic feet.
No hydrogen is stored on the roof of the control room.
c.
During the inspection period regional management requested information on fuel oil for the Emergency Diesel Generators (EDG).
The questions asked were (1) what type of fuel oil is used for the EDGs,- (2) is there any shelf life established for the oil, and (3) how long would it take for the oil stocks to turn over.
The answers . to questions 1 and 2 are: number 2 fuel oil is used, no sheif life is applied to the oil, however, the oil is sampled monthly in accordance with Technical Specifications (see Paragraph 9).
In terms of the turnover of oil stock without replenishing, the supply, it would take approximately 4 years to use all the oil.
Detroit Edison receives oil approximately every 3 to 4 months in order to maintain the seven day supply.
d.
In a memorandum dated April 14, 1989, the Division Director of Reactor Projects directed the resident staff inform the licensee of the existence of a NRC report on emergency diesel generator reliability, NUREG/CR-5078.
The inspector informed the licensee of the document in a meeting on May 8, 1989, with the plant manager during the inspection period.
_ _ _ _ _ _ - - _ _ - _ _ _ -
.,. - - - - - t' $ >l f~ 18.
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 4, 6 and 7.
19.
Exit Interview (30703) The inspectors met with licensee representatives (denoted in Paragraph 1) on June 12, 1989, and informally throughout the inspection period and summarized 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 L inspectors during the inspection.
The licensee did not identify any such [ documents / processes as proprietary.
The licensee acknowledged the findings of the inspection.
l l , p
_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _-. _- _ _ - ._ .~ }}