IR 05000341/1989034
| ML20012C333 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 03/09/1990 |
| From: | Defayette R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20012C331 | List: |
| References | |
| 50-341-89-34, NUDOCS 9003210051 | |
| Download: ML20012C333 (23) | |
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U.S. NUCLEAR REGULATORY COMMIS$10N REGION Ill
Report No. 50-341/89034(DRP)
j-Docket No. 50-341 Operating License No.'NPT-43 i
Licensee: Detroit Edison Company
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2000 Second Avenue
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Detroit, MI 48226 Facility Name:
Fermi 2 Inspection At:
Fermi Site, Newport, Michigan (
Inspection Conducted: November 29, 1989 through January 8,1990 l
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Inspectors:
W. G. Rogers S. Stasek
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D. Schrum M. Farber P. Byron i
p. Moore is-
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r Approved Bye R. W. DeFayet
, Chief Reactor Projects Section 2B Date
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Inspection' Summary i
Inspection on November 29. 1989 to January 8, 1990 (Report No. 50-341/89034(DRP))
Areas Inspected:
Action on previous inspection findings; followup of events; operational safety; sustained control room / plant observations; engineered safety features walkdown; maintenance; surveillance; followup of events; plant trips; LER followup; regional requests; QA/self assessment.
Results: Licensee weaknesses were:
three violations were identified and 9.c)phs 7 b and 9.a). Twounresolveditemswereidentified(Paragraphs 3.a (Paragra and two open items were identified (Paragraphs 3.a. 9.c).
Preparation
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for ascension to power following the refueling outage and performance of activities during the ascension reflected weaknesses within the licensee's
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organization and a clear decrease in overall licensee performance.
First, a large quantity of paperwork needed to be closed prior to startup; in the administration of that paperwork some requirements were omitted. Second, supervision did not acquire enough feedback of proper accomplishment of all required tasks in preparation for power ascension. Third, some of the administrative controls, LCO tracking and protective tagging, proved to be inadequate.
Fourth, troubleshooting activities were slow due to weak maintenance shift turnovers, marginal troubleshooting documentation, lack
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of system familiarity / understanding of systems and lack of teamwork.
Fifth, apparent lack of attention to detail for power operations once out of the refueling outage, resulted in numerous personnel errors including one reactor scram.
9003210051 900309 POR ADOCK 05o00341 Ct PDC
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I Licensee strengths were:
a shift supervisor may have prevet.ted an
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unnecessary reactor shutdown by alertly questioning some data he received
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(Paragraph 3.a.(6)
another shift superviscr took a conservative approach
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to reactor operati8)n;s by scramming the plant when he was confeented with a i
fire in the main generator (Paragraph 8); the ISEG was contributing substantially to the licensee's self-assessment capability, even though and following startup, control room; during the period immediately preceding it is understaffed (Paragraph 10.c)
activities were generally orderly and
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organized (Paragraph 3.b.(1)); the Quality Engineering and Quality Program Assurance groups are well staffed and substantial resources are devoted to
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eachsurveillanceandaudit(Paragraph 10.f);thePlantSafetygroupis contributing significantly to root cause analyses and the plant s self-assessment capability (Paragraph 10.d).
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DETAILS
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1.
Persons Contacted a.
Detroit Edison Company
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- P. Anthony, Licensing
- T. Bradish, Supervisor, PQA L. Bregni, Licensing
- S. Catola, Vice President, Nuclear Engineering and Services W. Colonnello, HPES Coordinator D. Eisenhut, NSRG Chairman
- P. Fessler, Supervisor, Plant Safety
- D. Gipson, Plant Manager
- L. Goodman, Director of Licensing
- K Howard, Principal Engineer, Plant Systems
- A. Kowalczuk, Superintendent, Maintenance
- R. McKeon, Superintendent, Operations J. Nyquist, Supervisor, ISEG G. Ohlemacher, Principal Engineer, Licensing
- W. Orser, Vice President, Nuclear Operations J. Pendergast, Compliance Engineer J. Plona, Operations Engineer
- G. Preston, Director, Nuclear Training T. Riley, Licensing B. Sheffel, Nuclear Production, Technical Engineering 151 f. Svetkovich, Operations Support Engineer
- B. R. Sylvia, Senior Vice President, Nuclear Operations J. Tibai, Staff Engineer, NSRG J. Wald, Supervisor, Quality Engineering
- G.Trahey, Director, Projects
- R. Stafford, Director, Quality Assurance W. Tucker, Assistant to the Vice President b.
U.S. Nuc1 car Regul_atory Commission
- W. Rogers, Senior Resident Inspector
- S. Stasek, Resident Inspector D. Schrum, Reactor Engineer, RIII M. Farber, Project Engineer, Rlll P. Byron, Senior Resident Inspector, Davis-Besse P. Moore, Resident Inspector, Monticello NPS
- Denotes those attending the exit meeting on January 10, 1990.
The inspectors also interviewed others of the licensee's staff during this inspection.
2.
Action on Previous Inspection Findings (92701)
a.
(Closed) Unresolved Item (341/89030-04(DRP)):
Deficiencies associated with SRV actuators noted durirg walkdown.
The licensee subsequently determined that all but ont. of the items had no affect i
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on continued operability of the associated valves.
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item, (where SRV K was found with duct tape covering the actuator's t
exhaust port) potentially could have had an affect on the relief
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mode of operation for the valve.
However, the licensee indicated
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that SRV K was not associated with the Automatic Depressurization
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System (ADS) nor served a low-low-set function.
Since post-maintenance
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testing included cycling each SRV from the control room with the reactor at pressure, the effect of duct tape over the exhaust port
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would have been determined.
The inspector agreed with the licensee's determination of significance.
However, a concern still exists with the manner in which maintenance personnel (including supervisors)
i complete work activities and the condition in which a component is left following completion of maintenance activities.
This issue will continue to be evaluated as part of the routine inspection program, b.
(0 pen) Unresolved Item (341/88035-01(DRP)):
Deficiencies Identified
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with Temporary Modifications.
On January 3, 1990, the inspector i
noted that operator aid 88-13, a label on control room panel 804 i
associated with No. I and No. 2 feedwater heater local level
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indication, was still posted despite completion of certain modifications to the level control system.
Subsequent discussions with control room operators revealed that the operator aid provided required actions on increasing heater levels including a reactor
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scram at 40 inches as indicated locally via sightglasses installed under Temporary Modification 86-0133.
These actions were necessary since no extraction steam check valves had been installed on the extraction lines to the No. I and No. 2 heaters and should heater water level substantially increase, moisture would back up into the
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main turbine causing damage there.
Since control room indication was offscale high during normal operation prior to the refuel outage due to level control problems, these actions had been based upon the local sightglass readings.
Review of the associated alarm response procedures (ARPs) verified that they were consistent with the operator aid.
However, a review of temporary modification 86-0133 revealed that it had been cancelled and the local sightglasses removed in October 1989.
This was due to completion of an Engineering Design Package (EDP), which allowed better control of heater levels and resulted in No. I and No. 2 heaters being controlled within the visible band on the control room indicators.
Subsequently, the operator aid was removed and a revision to the associated ARPs was initiated.
Further review of this issue will be conducted during the next inspection period, c.
(Closed) Open Item (341/87046-01(DRS)):
Feedwater system responsiveness.
In Inspection Report No. 341/89030 this item was closed but the actual
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closure number used in Paragraph 2 was 341/88003-03.
No violations or deviations were identified in this area.
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3.
Operational Safety verification (71707 & 71715)
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Routine Plant Observations
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The inspectors observed control room operations, reviewed applicable l
logs and conducted discussions with control room operators during the period from November 29, 1989 to January 8, 1990.- 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 I
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The inspectors, by observation and direct interview, verified that
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the physical security plan was being implemented in accordance with
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the station security plan.
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The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
(1) During a walkdown conducted of the refuel floor on November 29, 1989, the inspector noted foreign material in the inlet of valve T46-F410 (Refuel floor air inlet to Standby Gas Treatment
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System).
Specifically, the debris consisted of four long strips of cloth attached to the valve inlet with duct tape.
All four strips were observed to be physically stuck between the valve seat and disc (which was closed at the time).
Upon being notified, the operating authority promptly removed the foreign materisi and stroke tested the valve.
Deviation Event Report (DER) 89-1395 was initiated and a review conducted to determine root cause.
Subsequently, the licensee found that the cloth strips had been
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temporarily installed to monitor air flow during the
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depressurization phase of the integrated leakrate test (ILRT)
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that had been completed on November 21, 1989.
The test
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engineer's log documented the installation of the cloth strips,
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however, the ILRT procedure did not direct any specific actions of this type.
Consequently, the strips were not removed at completion of testing. This is considered an unresolved item (341/89034-01(DRP)) pending completion of licensee review and inspector followup.
(2) On December 11, 1989, upon returning the out-of-service diesel fire pump to an operable condition the control room information l
system (CRIS) dot associated with the diesel fire pump was not removed.
Once identified to the shift the dot was removed.
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(3) On December 15, 1989,.a emergency equipment service water
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control switch was partially disassembled without the Control
Room Nuclear Supervising Operator being aware that this had occurred.
The portion of the switch that was disassembled did
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not affeet operability of the system.
Once identified to the control room operator the switch was reassembled.
(4) Valve E51-F029 was providing dual position indication in the control room and no control room information system (CRIS) dot
had been placed on the control board.
(5) During a plant tour a box approximately 6'x 6' was observed in the DC switchgear room below the hatch to the 4th floor auxiliary building.
The box was wooden and appeared to present a fire hazard.
The Shift Supervisor was contacted and the operating authority immediately contacted the personnel
responsible for the box.
Once contacted, electrical maintenance l
personnel placed the contents of the box on the floor of the DC t
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switchgear room and removed the box from the area.
The box contained a reactor building HVAC fan motor which was scheduled to be installed in mid-January.
The installed
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location for this fan is one floor above on the 4th floor auxiliary building.
Therefore, the motor / box had been staged there for the upcoming installation.
The next day, another inspector observed that the fan motor had not been blocked and could roll around on the floor and potentially impact safety-related equipment.
The shift supervisor was contacted and electrical maintenance was contacted by the Shift Supervisor.
Subsequently, the motor
was properly blocked.
The inspector discussed this matter with electrical maintenance supervision.
From this conversation the inspector questioned whether the supervisor involved had received fire hazards training.
The training department was contacted and the matter discussed.
The inspector determined that training appeared to be only a procedure review with a signoff acknowledging review completion.
Training supervision indicated that the program in this area was being upgraded.
Subsequently, the inspector determined that the box was not of sufficient size to justify a transient fire hazards evaluation.
(6) While in the control room the inspector observed the Shift
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Supervisor receive a completed oil analysis preventive maintenance work request indicating that the water concentration in the upper motor bearing of a core spray pump was greater than expected.
The Shift Supervisor contacted the cognizant o Mite expert who stated that the pump was still operable.
Had the Shift Supervisor acted upon the information at hand or not been able to contact the individual a decision to declare that core
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spray pump inoperable was highly probable.
Declaration of an l
inoperable core spray pump at that time would have caused an j
immediate plant shutdown due to other equipment also out of
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service.
Such problems would not occur if there were definite
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operable / inoperable acceptance criteria for moisture content.
The licensee acknowledged this concern and stated that all Safety related pumps would have such criteria for oil analysis by April 1, 1990.
This is considered an Open Item
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(341/89034-02(DRP)).
(7) During the inspection period two situations arosv regarding cascading Technical Specifications.
The first dealt with emergency equipment cooling water (EECW)
surveillance testing.
Such testing renders an EECW division inoperable during the testing.
Due to the emergency core cooling Technical Specifications and the equipment cooled by the EECW the licensee appeared to be in an immediate shutdown
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situation.
The condition lasted less than three hours.
The inspector identified the condition a number of days af ter the situation occurred and notified the licensee who indicated
they were unaware that the situation had occurred until afterwards.
The licensee provided the inspector with a draf t Technical Specification change indicating that this was its analysis covering the time frame in question.
The second situation arose on December 28, 1989, and dealt with the mechanical draft cooling tower fan brakes.
A nitrogen cylinder providing motive power to a brake was leaking.
The Shift Supervisor declared the brake, associated fan, ultimate heat sink division, EESW and EECW division inoperable.
The inspector inquired as to why the associated ECCS components would not be inoperable.
The operating authority contacted senior plant management and licensing.
1.icensing provided the inspector with a draf t letter for the NRC on Detroit Edison's position on the brakes.
Under the draft letter the associated fan would not be declared inoperable provided a tornado alert was not present.
Cascading Technical Specifications was one of the tcpics discussed in a meeting held in December between the licensee and the NRC and the licensee is concerned because of potential generic implications.
The inspector also notified regional management of his concerns; this cascading matter will continue to be pursued.
b.
Expanded Plant Observations l
On reviewing the length and complexity of the first refueling outage, the NRC determined that augmented coverage of pre-startup
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This additional coverage consisted of additional inspectors on-site during the pre-startup phase and around-the-clock coverage of startup activities for six
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days following entry into Mode 2.
NRC inspectors monitored
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procedure usage, routine control room operations, shift turnovers for both operations and maintenance, observed rod withdrawal to criticality, monitored maintenance and surveillance activities, reviewed control room logs, monitored Limiting Conditions for Operations (LCOs), conducted system walkdowns as previously discussed, and examined housekeeping and material c'onditions in the reactor, auxiliary, and turbine buildings.
The inspectors monitored pre-startup activities from November 27 through December 6, 1989, on a routine day shift basis and with the plant's entry into Mode 2, on an around-the-clock basis from December 6 through December 12, 1989.
The results of these observations were:
(1) Control room activities, including operations shift turnovers, were generally orderly and organized.
(2) Valve lineups were accomplished appropriately.
The inspectors walked down the accessible pertions of the following systems to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists.
Core Spray System - Divisions I and II
Standby feedwater System
Standby Liquid Control System
CRD Hydraulic Control Units (all banks)
Class IE Batteries - Divisions I and II Only one minor nomenclature problem associated with core spray Division II was identified.
(3) The inspectors observed control rod withdrawal during startup and verified that the licensee had completed NPP-22.000.01, Plant Startup Master Checklist, Rev. 23 and that the steps in NPP-22.000.02, Plant Startup to 25 percent Power, Rev. 3 were being properly completed and signed off.
The inspectors observed the approach to criticality.
The licensee withdrew rods in sequence following the approved pull sheet and proceeded with single notch movement once four doubling times had been observed on the most conservative SRM channel.
The licensee then performed their shutdown margin test per j
54.000.01, Shutdown Margin Check, Rev. 20.
This calculation yielded a shutdown margin of 2.978 percent delta K/K, greater than the required 2.07 percent. The difference between the
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calculated reactivity and the actual reactivity was -0.3 percent delta K/K which was within the minimum allowed deviation limit.
The reactor went critical on December 8, 1989, at 0036 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> on rod 38-27, Notch 2, with a 241 second period.
(4) Communications between the control room and personnel in the plant continue to be a shortcoming in the operations area.
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The lack of telephones in the plant or sound-powered phones at j
the instrument racks reduces the efficiency of personnel j
attempting communications and causes difficulty in the transfer
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of important information between the control room and the plant.
In addition, the use of radios and the Gai-tronics peger can be very confusing in certain instances.
The use of j
the page system to conduct conversations continues to be
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especially distracting.
This issue has been identified by NRC in the past (Reference Inspection Reports No. 341/86019 and
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341/89008) and licensee actions on this concern are tracked J
under Open Item 341/86019-01.
The licensee is aware of the need to upgrade communications and plans to do so during the
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forthcoming outage.
l (5) Almost all LCOs were properly entered and exited as required with the exception of:
LCOs associated with transmitter 821-N081C which is the I
subject of a special inspection (Reference Report No. 341/89036).
i LCO associated with primary containment isolation valve
B31-F020 (discussed in Paragraph 9 of this report).
Independently, the inspectors reviewed bypassed LPRM detectors to verify that the requirements contained in Technical Specification Table 3.3.1-1(e) were satisfied.
The inspector
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reviewed the 00-8 printout as well as the local panel switches on the LPRM cabinets and compared them against the LPRM locations listed in NPP-57.000.10, LPRM Operational Status, Rev. 20 Enclosure 1.
The review indicated that the licensee was meeting the Technical Specification requirements (less than two LPRM inputs per APRM level and less than 14 LPRM inputs per APRM channel were bypassed).
Also, the inspectors visually verified that inoperable Control Rod 38-31 was properly disabled.
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(6) Maintenance and surveillance activities were not always well-tracked and properly implemented as identified below:
Troubleshooting efforts for problems associated with High
Pressure Coolant Injection turbine speed indication appeared weak (discussed in Paragraph 6 of this report).
A problem with the Reactor Manual Control System was
identified at the beginning of the startup when the operator could not select a control rod to be withdrawn.
The inspector monitoring the troubleshooting effort noted that the first troubleshooting team, consisting of engineers and I&C technicians, appeared to lack familiarity with the system and expended considerable time in locating components.
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Their efforts did not appear methodical, they did not
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document voltage measurements on components, and many i
measurements were repeated.
The inspector also noted that i
the lack of adequate documentation prevented a good exchange of information between the shifts.
No progress was evident until the next shift when an engineer from the technical
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staff who was methodical and more knowledgeable of the
system took charge of the effort.
The problem an
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unterminatedwireinapowersupply,wasidentlfiedin approximately one hour.
Calibration of the hydrogen monitor for offgas was not
performed in the correct time frame (discussed in
paragraph 7 of this report).
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Five safety-related work requests were identified in the
licensee's computerized tracking system as closed when the work requests still had post-maintenance testing to be i
accomplished before work request closure.
Fortunately, these work requests were still aanotated against their
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respective safety system in the LCO logbook.
There was a lack of appreciation by an operator for an
abnormal control room indication associated with standby gas treatment flow during surveillance testing (discussed in Paragraph 5).
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The lack of attention to detail of the operating crews in a number of the above activities is of concern to the inspectors.
Followup of the situation with the operations superintendent revealed that he was aware of these weaknesses and was currently in the process of making his operators more sensitive to off-normal plant conditions and adherence to detail.
As for the support organizations, during the pre-startup phase, the inspectors noted that the maintenance department seemed to be unable
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to accurately project man-hours expended on jobs, unable to properly sequence work to avoid interferences,-unable to factor previous job experience into job duration estimates, and unable to respond to emergent problems in an effective manner.
Of concern to the inspectors were the common observations of:
lack of familiarity and understanding of the systems, lack of documentation of troubleshooting findings, lack of effective shift
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turnovers between the troubleshooting crews, and the lack of a coordinated effort.
Each of these shortcomings can individually hamper the troubleshooting process; the combination of all four in l'
these situations resulted in an effort that appeared disorganized, disorderly, and ineffective.
To address concerns in both operating crew and tupport organization performance the licensee submitted letter NRC-89-0300,
" Accountability Action Plan," to address NRC concerns.
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inspectors will continue to review operator / support organization
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performance as part of the routine inspection program and licensee i
performance / corrective actions will be one of the subjects of discussion at the upcoming management meeting on January 16, 1990.
No violations or deviations were identified in this area other than those
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discussed in other sections of this report.
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4.
ESF Walkdown (71710)
During the inspection period, in addition to the system walkdowns discussed in Paragraph 3, the inspector performed a more in-depth walkdown of the accessible portions of the Thermal Recombiner System (Divisions I and II) to verify operability.
Plant drawings and system
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operating and surveillance procedures were reviewed to confirm consistency with the as-built configuration.
Hangers and supports were verified against drawings for proper placement, alignment, and makeup.
System components were inspected for proper installation, position, energization, and labelling.
Availability / operability of ventilation and i
other support systems was also reviewed.
Required instrumentation was
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verified operable and within current calibration periodicity.
Verification that required electrical power was provided and/or available was also made, i
The following was noted during the walkdown:
a.
System Operating Procedure NPP-23.409, "lhermal Recombiner System", Rev. 21 Attachment 3, which provides the instrument lineup checklist, was found to include erroneous instrument PIS numbers.
This was communicated to the licensee and a revision to the procedure was initiated.
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b.
An unauthorized pipe support was identified on the torus supply header between supports G18 and G19.
The support consisted of a braided type metal cord attached in a semi permanent manner to the overhead.
The piping support expert in the licensee's nuclear engineering group was contacted and performed an evaluation of the extra support.
No affect on operability of the piping system was found, however, the engineer agreed the support was not supposed to be installed and would be removed.
Later that day, maintenance personnel removed the cord, No violations or deviations were identified in this area 5.
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.
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i The following items were considered during this review:
the limiting
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conditions for operation were met while components or systems were
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removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were
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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 i
implemented.
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performance.
The following maintenance activities were observed:
WR 016C891208 Repair Speed Sensor on HPCI Turbine.
WR 007B880425 Springpack Replacement on Valve E51-F045.
- WR 0080890531 Inspect / Test E51-F084.
- WR 0098880429 Springpack Replacement and Perform PM on Valve E51-F022.
Following completion of maintenance on the HPCI system, the inspectors verified that the system had been returned to service properly.
No violations or deviations were identified in this area.
6.
Monthly Surveillance Observation (61726)
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The inspectors observed / reviewed surveillance testing required by Technical Specifications and verified that:
testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with Technical Specifications and procedure 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.
The inspectors witnessed the following test activities:
24.202.02 HPCI Flow Rate Test at 165 psig Reactor Steam Pressure
24.206.01 RCIC System Pump and Valve Operability Test
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24.206.04 RCIC System Automatic Actuation and Flow Test at 150 psig
24.404.02 Division I SGTS Filter and Secondary Containment Isolation Damper Operability Test
27.112.03 Turbine Generator Mechanical Overspeed on Load Test
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27.112.05 Turbine Generator Electrical Overspeed on Load
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Test
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44.010.033 RPS and NSSSS-Drywell Pressure, Division I Functional Test
44.160.001 Attachment 10, Fire Detection Operability and Functional Test a.
Regarding Surveillance 24.404.02, the inspector noted that the I
associated SGTS Control Room flow recorder was showing a low flow condition during the run (i.e., outside the predetermined green band).
This was communicated to the control room supervising t
operator who indicated the cause of the low flow was not known but that no acceptance criteria in the surveillance was impacted.
The inspector then asked whether an actual low flow condition existed or if the problem was solely one of indication on the recorder.
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following subsequent troubleshooting, a determination was made that the recorder pen had become stuck; the modulating damper was in fact controlling to the required flowrate, i
b.
Regarding surveillance 24.202.02, a problem was identified during the performance of the flow rate surveillance at 165 psig when the HPCI speed indication failed to register the correct value.
A number
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of corrective actions were taken with no apparent success, including
replacement of a potentiometer, realignment of the speed sensor gear, and replacement of the EGR box.
These actions had no logical sequence and the inspectors noted the lack of a coordinated troubleshooting effort.
Information gathered by each of the shifts was not documented or collected; such an effort would have prevented many of the problems encountered during the effort and aided the analysis of the overall troubleshooting process.
The inspectors also noted that shift turnover between maintenance and I&C crews was nearly non-existent as demonstrated by the duplication of specific troubleshooting activities by successive shifts.
Efforts which required the operation of the HPCI turbine caused excessive steam demands which nearly scrammed the reactor.
Control room operators tripped the HPCI turbine to avoid the scram and then, believing that the troubleshooting crew did not understand the effect of their testing on the reactor, directed that troubleshooting be suspended pending a review of previous events.
This review resulted in a coordinated plan and the eventual identification of a misaligned magnetic sensor.
The inspectors performed a record review of completed surveillance tests.
The review was to determine that the test was accomplished within the required Technical Specification time interval, procedural steps were properly initiated, the procedure acceptance criteria were met, independent verifications were accomplished by people other than those performing the test, and the tests were signed in and out of the control room surveillance log book.
The surveillance tests reviewed were:
24.139.002 SLC Pump and Check Valve Operability' Test
24.139.003 SLC Manual Initiation, RWCU Isolation, and Storage Tank Heater Operability Test
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24.203.001 CSS Discharge Piping Filled and Valve Position
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Verification
24.203.002 Division I CSS Pump and Valve Operability and
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Automatic Actuation
24.203.003 Division II CSS Pump and Valve Operability and Automatic Actuation 24.203.004 Core Spray Valve Operability and Position-
Verification Test
24.205.008 RHR Cooling Tower Fan Operability and RHRSW and EESW Valve Line-Up Verification
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24.207.05 EECW Valve Oper6bility Test.
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24.208.03 Division II EESW Pump and Valve Operability Test
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24.404.002 Division I SGTS Filter and Secondary Containment i-Isolation Damper Operability Test
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24.404.003 Standby Gas Treatment System Operability Test
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24.404.004 Division II SGTS Filter and Secondary Containment Isolation Damper Operability Test
27.501.21 Electric Fire Pump Weekly Test
27.501.27 Diesel Fire Pump Weekly Test
44.010.124 RPS - APRM A Channel Functional Test
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44.010.128 RPS - APRM E Channel Functional Test
44.010.129 RPS - APRM F Channel Functional Test
44.101.160 Flow Unit A Functional Test
44.010.164 Flow Unit A Calibration
44.020.004 NSS$5 - Reactor Vessel Low Water Level (Levels 1 and 2), Channel Functional Test
44.020.231 NSSSS - RCIC Steam Line Flow, Division I Functional Test
44.020.232 NSSSS - RCIC Steam Line Flow, Division II Functional Test No violations or deviations were identified in this area.
7.
Followup of Events (93702)
During the inspection period, the licensee experienced several events, 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 within regulatory requirements, and that corrective actions would prevent
future recurrence.
The specific events are as follows:
November 29, 1989 ESF Actuation During Surveillance Testing Due to a Blown Fuse
December 7, 1989 Michigan Department of Natural Resources (MDNR)
Notification of Chloride Levels Above Daily Discharge Limits for Circulating ~ Water System
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December 7, 1989 ESF Actuation (Start of EECW/EESW Div II)
During Surveillance Testing j
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December 8, 1989 HPCI Declared Inoperable Due to Failed Speed Indicator
- December 10, 1989 Reactor Wide Range Level Indication Found Upscale
December 12, 1989 Failure to perform Technical Specification
Surveillance Associated with Hydrogen Monitoring of Offgas System
December 18, 1989 Reactor Scram Due to Personnel Error
Initiating Closure of MSIVs
December 23, 1989 Manual Scram Due to Lagging Fire on Main Turbine
December 26, 1989 Unplanned ESF Actuation (Start of EECW/EESW Div I) During Surveillance Testing
December 26, 1989 Emergency Notification System Inoperable
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December 27, 1989 Report to Offsite Agency, MDNR, Concerning a
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Glycol Spill into the Circulating Water Reservoir
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a.
Regarding the December 10 event, the root cause was determined to be improper installation of the level transmitter and is the subject of a special inspection (Reference Report No. 341/89036)
b.
Regarding the December 12 event, Technical Specification 3.3.7.12 requires, as part of the associated table, that the offgas syst?m hydrogen monitor be operable during operation of the offgas system.
The surveillance to implement this requirement is NPP-44.080.501,
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"Offgas Hydrogen Monitoring System Channel Functional Tests and Channel Calibrations" and is periodically performed during operation of the system.
However, due to discussions with the I&C department l
in the past as to how this surveillance is performed, the surveillance group was under the erroneous impression that the surveillance was required prior to exceeding five percent reactor power.
Normally, reactor startup would include use of the main condenser mechanical vacuum pumps up to near 5 percent power where I
the offgas system would then be placed into service and the required
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surveillances performed.
The licensee has analyzed operation of the
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mechanical vacuum pumps up to the five percent powpr level and determined that hydrogen production is not significant up to that i
level.
The computer generated tracking system was at some point revised to include a note that NPP-44.080.501 was only required to be done prior to five percent.
Consequently, during reactor startup, on December 10 the offgas system was placed into service
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without NPP-44.080.501 being performed or the compensatory periodic
grab samples being initiated.
This is considered a violation l
(341/89034-03(DRP)).
Subsequently, NPP-44.080.051 was successfully
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performed and the monitor was declared operable.
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i The root cause of the violation was the improper identification in the surveillance tracking system tying hydrogen monitor calibration to a mode restraint and not a situational restraint.
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No other violation or deviations were identified.
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Plant Trips (93702)
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Following the plant trips on December 18 and 23, the inspectors ascertained the status of the reactor and safety systems by observation of control room indicators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant
chemistry.
All systems responded as expected, and the plant was returned to operation on December 19 and 23, respectively.
Except for the operator error which caused the first trip (the operator recognized his error
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immediately), operator performance following the trips was excellent.
No violations or deviations were identified.
9.
Licensee Event Report Followup (92700)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications.
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a.
(0 pen) LER 89037, Missed Primary Containment Valve Surveillance Test
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(1) Event Description The inspector reviewed the circumstances surrounding a missed ASME Section XI stroke time test for air-operated valve B31-F020.
This valve is in the sampling line of the B reactor recirculation line and must be opened to perform grab samples of the reactor coolant system.
The valve also functions as a primary containment isolation valve.
During the refueling outage with the plant in cold shutdown, the reactor coolant sampling system was replaced under EDP 7814 and valve B31-F020 was designated in the tagging system as a boundary valve to perform this plant modification.
On October 24, 1989 the air to the valve was isolated / red tagged and the valve itself was closed (no red tag).
Documentation of the tagging was recorded on Abnormal Lineup Sheet (ALS) 89-1478.
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On November 9, 1989 plant operators performed surveillance test
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NPP-24.138.02 which stroke time tests a number of valves including B31-F020.
However, with B31-F020 isolated this particular valve was not tested.
Subsequently,lthe requirement to test the valve was added to a Limiting Condition for Operation (LCO) logbook entry, (No. 89-0783),
against the primary containment integrity LCO.
Included with LCO entry 89-0783 were other primary containment isolation valves that were out of service or needed testing.
On November 14, 1989 a temporary modification was implemented to allow sampling of the reactor coolant system via B31-F020 through a cooler and an old sample sink.
However, one of the temporary valves installed under the temporary modification was identified as not being a high temperature qualified valve.
Actions were initiated to acquire and change out the valve with an appropriately qualified valve.
On November 23, 1989, following restoration to service of all the valves associated with LCO entry 89-0783, except B31-F020, LCO entry 89-0783 was closed.
The requirements to test B31-F020 were transferred to another LCO entry, 89-0911.
However, this entry was not associated with primary containment integrity, but with primary containment sampling.
On November 25, 1989, changeout activities for the non qualified temporary valve were initiated.
Also, the critical surveillance date expired on this date.
Therefore, the valve became inoperable.
On November 29, 1989, air was restored to B31-F020 but the valve position continued to be designated closed.
Upon completion of the high temperature valve changeout there was no need for B31-F020 to be an isolation boundary for the design modification or the temporary modification.
-On December 6, 1989 the plant entered the startup mode and primary containment integrity became a Technical Specification requirement.
However, a primary containment integrity valve, B31-F020, was not operable.
On December 18, 1989, plant conditions required a grab sample of the reactor coolant system be taken. Valve B31-F020 was opened and sampling begun.
Opening the valve was contrary to the tagging ALS.
However, since B31-F020 was not red tagged or a control room information system (CRIS) magnetic dot present on the control board the operator had no way of telling that the ALS still required the valve be in the closed position.
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On December 19, 1989 the sampling was completed and the valve
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closed.
On December 20, 1989, the missed surveillance was identified and the surveillance successfully performed.
During the review of the ALS for EDP 7814 the inspector noted numerous documentation inadequacies which included an independent valve position verification not present, a reactor operator authorization signature for a tagging boundary modification not present, a senior reactor operator signature not present for acknowledgement of a tagging boundary modification, and the notification stamps to maintenance personnel that the tagging boundary had been modified not present.
(2) Results (a) Technical Specification 3.0.4 states in part " Entry into an OPERATIONAL CONDITION shall not be made unless the conditions for the Limiting Condition for Operation are met without reliance on provisions contained in the ACTION requirements." When the licensee entered the startup mode on December 6, 1989, a violation (341/89034-04(DRP)) of Technical Specification 3.0.4 occurred.
The root cause of this violation was the inappropriate transfer of the B31-F020 testing requirements from a primary containment integrity LCO entry to a primary containment sampling LCO entry by licensed on shift operations personnel.
(b) Once the air was restored to the B31-F020 valve, restrictions on valve position should have been removed or the air not restored to the valve.
As such the tagging measures were inadequate, allowing the valve to change position as noted on December 18-19 without any reasonable tagging measure present to prohibit such an action.
The root cause of this situation was that the tagging philosophy utilized and allowed by the established administrative procedure on tagging, NPP-OPI-12, for valve B31-F020, was poor.
(c) Operators failed to comply with the existing tagging procedure, NPP-0P1-12, when establishing and modifying the tagging boundary under ALS 89-1478.
The root cause of this situation was a lack of attention to detail compounded by cumbersome tagging controls.
(d) 10 CFR 50, Appendix B, Criterion V requires in part
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" Activities affecting quality shall be prescribed by
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... procedures... and shall be accomplished in accordance with these... procedures...." The deficiencies identified identified in b. and c. above are examples of a violation (341/89034-05(DRP)) of
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10 CFR 50, Appendix B, Criterion V.
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(0 pen) LER 89024, Missed Secondary Containment Damper Surveillance
Test i
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Under the corrective actions to this LER the licensee provided additional training to the applicable licensed personnel on the computerized situational surveillance program.
The inspector interviewed a number of the personnel who received the training and determined that they knew of the missed damper surveillance.
The personnel also had some understanding of the computerized surveillance tracking system.
However, there was a wide variance on the individual's ability to utilize that knowledge on the computer.
Absent formal hands-on training with the computer and a user friendly
computer handbook, operations personnel will still be hampered in determining what situational surveillances are needed to be performed.
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The inspector discussed this matter with the operating authority who directed that steps be taken to remedy the situation.
c.
(0 pen) LER 89030 Improperly Installed Reactor Vessel Level Transmitter The situation discussed in this LER was the subject of a special inspection (reference report 89036).
However, two ancillary matters were pursued outside of that inspection.
The first issue dealt with the level deviation between actual level and indicated level for the wide range level indicators.
Since these wide range indicators are
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calibrated based upon operating temperature there appears to be a non-conservative deviation from actual level during the reactor startup process.
The licensee indicated that this matter had been previously analyzed and that analysis would be provided to the inspector for review.
This matter is considered open (341/89034-06(DRP)) until after a review of the analysis.
The second issue dealt with the impact statement associated with the surveillance procedure used to calibrate the transmitter in question.
An impact statement explains what equipment is affected by the calibration and the ramifications to the facility.
However, a set of relay contacts appeared to have been omitted from the statement and the applicable valves actuated by these relay ccntacts not listed.
This matter will be pursued with I&C supervision and is considered an unresolved (341/89034-07(DRP)) item.
No other violations or deviations were identified in this area.
10.
Evaluation of Licensee Self-Assessment Capability and Evaluation of l
Licensee Quality Assurance Program Implementation (40500) (35502)
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The fermi Plant has four formal groups that focus on the licensee's self assessment programs to prevent problems by monitoring and evaluating
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plant performance, providing assessments and findings, and following-up on corrective action recommendations.
Three of these groups are required by Technical Specifications (TS):
the Operations Safety Review
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Organization (OSRO), Nuclear Safety Review Group (NSRG) and the l
Independent safety Engineering Group (ISEG).
The fourth group to which
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the licensee has committed resources was Plant Safety.
This group, in addition to its normal task of evaluating DERs for adequate root cause
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analysis and adequate corrective actions, in addition to other tasks, t
also coordinates the Human Performance Evaluation System (HPES), and
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performs trending of DERs.
(Additional licensee eelf-assessment methods l
and quality assurance program implementation are ifscussed in this section.)
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a.
NSRG
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The NSRG appears to be performing effective reviews of plant activities.
The NSRG meets bi-monthly, in full day sessions, to review significant licensee issues.
This was in excess of the
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required two meetings each year.
The inspector reviewed the TS requirements for the NSRG and determined that the group meets the l
TS requirements for composition, alternate members, meeting
frequency, and quorum requirements.
A review of a sample of meeting minutes and a comparison with TS requirements indicates that the committee was fulfilling its responsibility, i
The NSRG engineer appe5 red to be writing detailed minutes of the meetings.
Inspector review of the minutes determined that the NSRG was effeco:e in reviewing documents such as LERs for
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completeness and determining areas that required additional investigations or corrective actions.
The group had also reviewed audits and asked that they be reperformed if they were determined to be inadequate.
The licensee had assembled persons with multiple functional areas of expertise to be on the NSRG.
The inspector attended an emergency TS change meeting on November 15, 1989 and a regular session of the NSRG on November 30, 1989.
The meetings were not dominated by any individuals and concerns were resolved i
prior to giving the approval to any of the topics discussed.
Open
items that resulted from the meeting were included on the licensee's tracking system.
The NSRG engineer ensured that quorum requirements were met throughout the meeting, b.
Operations Safety Review Organization (OSRO)
The OSR0 was effective in performing reviews of plant activities,.
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which included, maintenance, modifications, and operational problems.
The inspector reviewed the TS requirements for the OSRO.
The committee was found to meet the requirements for composition, alternate members, meeting frequency, and quorum requirements.
Review of meeting minutes indicated that the committee had covered required areas of review and was fulfilling its responsibilities.
The committee was proactive in initiating investigations and ensuring followup of corrective actions for previously identified problems and areas of weakness.
The inspector attended an OSR0 meeting on November 14, 1989.
There was an excellent interaction of personnel with no individuals dominating the meeting.
The meeting was well managed by the Plant Operations Supervisor.
The procedure and design changes that
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were reviewed during the meeting had the author of the change at the
meeting to present the change to the group.
If the person was not
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available the change package was not discussed.
Documents were not
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concurred to if items had not been resolved during'the meeting,
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Approximately 15 people were in attendance throughout the meeting, j
with most plant groups represented.
During this time period
meetings were being held daily due to the outage.
The normal j
frequency of meetings during plant operations is once a week.
Documents for review were sent out well in advance of meetings with adequate time for review.
People reviewing packages were the individuals in attendance at the meeting.
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The inspector had two concerns with the administration of the OSRO.
The OSR0 minutes were not in sufficient detail to give an idea of the logic of the concerns expressed and resolved during the meeting.
This would be important for NSRG review.
The minutes had been in
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backlog due to a change of secretaries who wrote and issued the
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meeting minutes.
The backlog was resolved during this inspection
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period.
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Independent Safety Engineerina Group (ISEG)
The ISEG appeared to meet TS requirements and was conducting in depth reviews of selected areas of the plant.
However, the resources of this group appeared strained by all of the required tasks, which limits the number of totally independent overviews of selected areas of the plant.
The group was performing actual plant inspections and was not isolated from daily plant activities and problems.
The staff
issued DERs for items found during reviews that required immediate resolution.
Recommendations were issued in reports for other items.
A weakness was that no tracking system existed for following these items.
Other than this issue the ISEG was contributing substantially to the licensee's self-assessment capability, d.
Plant Safety
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This group of approximately 22 members was trained in root cause analysis and was performing DER reviews for the adequacy of root cause analysis and corrective action adequacy.
This group was also perforfking trending of DERs, coordinating the Human Performance Evaluation System (HPES), and performing the OSRO administrative tasks.
All of the groups' actions contributed to the licensee's
self-essessment capability or quality verification.
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To contribute to the quality of root cause analysis, a large number of the plant staff had been trained in root cause analysis, which improved the DER inputs during the SALP period.
A selected sample of DERs indicated that Plant Safety was performing adequate review of DERs to ensure that the majority of root causes had been accurately assessed and that adequate corrective actions were.being taken to resolve the problems.
Several layers of management concurred with the overall DER corrective actions.
The DER process was found to
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be' efficient because the majority of all plant problems were fed
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into and tracked by this system.
Because the DER process was being
used for purposes other than deficiencies and had a low threshold
for reporting deficiencies, there is a large number of DERs; however, these are not indicative of the actual number or severity of
deficiencies in the plant.
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The licensee trends DERs quarterly to find potential problems or adverse trends.
Most of the trended data was current and useful in assessing data.
The major categories trended were personnel i
errors, equipment failures, and procedural problems.
If an adverse trend occurred, a memo, the data used, and the trend were sent to the respective plant group for evaluation.
If the group's analysis was determined not to be satisfactory or timely, a DER was issued to ensure adequate corrective actions.
The trending system was thus found to be an effective management tool for performing j
self-assessments.
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One additional system that contributes to the licensee's
self-assessment of plant problems was HPES.
During this SALP period approximately 15 additional persons were trained for conducting HPES
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investigations.
Also, a full-time HPES coordinator was appointed to ensure the success of the program.
The plant had been performing an i
average of one HPES investigation per month.
To obtain the maximum
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impact for plant safety most of the HPES resources had been used in
the I&C and Operations area of the plant.
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The inspector reviewed several HPES reports and found them to be
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thorough investigations into particular plant problems.
The HPES reports had been selected from DERs that had a high significance for plant safety.
The findings were issued with recommendations in the reports.
A DER was issued for problems that were determined needing additional corrective actions or followup.
The DER process then followed the corrective actions to completion.
The HPES process
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also included anonymous reporting, so individuals could report
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identified or suspected problems without being known.
Overall, the
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licensee had made substantial progress in the implementation of HPES and the process was contributing to the licensee's self-assessment capability, e,
Self-SALPs Self-SALPs are being performed on a 6 month cycle at Fermi.
These are an additional example of licensee resources being devoted to self-assessment. The inspector was told that the self-SALP had predicted the previous NRC SALP ratings.
The second Self-SALP for this year had been delayed due to the outage.
f.
Quality Assurance Groups The groups reviewed were Quality Engineering and Quality Program Assurance.
The groups appeared to be well staffed and substantial licensee resources were devoted to each surveillance and audit.
All
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QA groups, including Procurement Quality Assurance, had made j
substantial progress in training personnel and performing performance based audits during this SALP period.
An inspector review of audits found them to be detailed and thorough, with some audits up to 70 percent performance based.
These groups were found to be contributing substantially to
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licensee self-assessments and quality verification capabilities.
11.
Regional Requests During the inspection period regional management contacted the inspector j
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about a potential security matter.
A member of the public had informed
regional management that some personnel were either trapped within Fermi
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or were trapped in the protected area perimeter fence.
The inspector l
immediately contacted the operating authority regarding this matter who was unaware of any problems of this nature.
Operations persoinel were put on alert for this situation.
Security personnel visually inspected i
the perimeter fence and the owner controlled area.
Additionally, the inspector visually inspected the perimeter fence.
No problems were identified.
12.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or
deviations.
Unresolved items disclosed during the inspection are discussed in Paragraphs 3.a and 9.c.
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13.
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
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on the part of the NRC or licensee or both.
Open items disclosed during the inspection is discussed in Paragraphs 3.a and 9.c.
14.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
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on January 10, 1990, and informally throughout the inspection period and summarized the scope and findings of the inspection activities.
The
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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.
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