ML20202H858
| ML20202H858 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 01/03/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20202H837 | List: |
| References | |
| 50-341-97-14, NUDOCS 9802230035 | |
| Download: ML20202H858 (31) | |
See also: IR 05000341/1997014
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 3
%
Docket No.: 50 341
License No.: NPF-43
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Report No.: 50 341/97014(DRP)
Licensee: Detroit Edison Company (DECO)
Facility: Er,rico Fermi, Unit 2
Location: 6400 N. Dixie Hwy.
Newport, MI 48166
Dates: September 23 through November 7,1997
Inspectors: G. Harris, Senior Resident inspector
C. O'Keefe, Resident inspector
G. Cashatt, Technical Training Specialist
Approved by: Bruce L. Burgess, Chiel
Reactor Projects Branch 6
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9902230035 990103
0 ADOCK 05000341
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A
EXECUTIVE SUMMAF<Y
Enrico Fermi, Unit 2
NRC Inspection Report 50 341/97014(DRP)
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This inspection included aspects of licensee operations, engineering, maintenance, and
plant support. The repert covers a six week period of resident inspection. During this
period, tiie plant was shut down for a sixteen day mid cycle outage and started up again
without any personnel errors. Major outage work included sipping the entire cose,
replacement of two leaking fuel bundles, safety relief valve replacement, and performance
of various surveillance tests.
QDerationg
The inspectors concluded that operators continued to exhibit improved performance
in monitoring plant conditions. Personnel on rounds continued to be effective in
identifying and reporting problems. Supervisory presence in the field for operations
increat;d, partly as a result ci having reduced the administrative burden in the
control room. inspectors identified concems with a repeat problem involving
inadvertent deenergization of equipment, and lack of documentation of entries into
allowed Technical Specification (TS) exceptions with limited time Juration. Section
01.1)
Both startup and shutdown evolutions were performed smoothly and without error.
Licensed operator trainees in the control room were properly supervised and
contributed positively to crew performance. Briefings were frequent and effective.
(Section 01.2)
The reactor vessel pressure test at the conclusion of the mid-cycle outage was
performed expeditiously in a coordinated and controlled manner. Preparations,
particularly the use of the simulator, were effective in minimizing the timo spent with
shutdown cooling secured during a relatively high decay heat condition. However. .
the inspectors concluded that distractions from the test were not effectively
minimized in the control room. (Section 01.3)
The H insee identified that operators violated a TS required situstional surveillance
ched af electrical power source operability, when it was completed nine minutes
late. This TS violation is of additional concern because it is similar to a recent failure
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to verify electrical power availability documented in Inspection Report 50 341/97007,
Prompt corrective actions significantly raised the visibility of TS actions among
operators. -(Section 01.4)
.
The licensee was able to reduce the number of Limiting Condition for Operations
(LCOs) entries by maintaining good equipment performance and by operations staff
actively pursuing resolution of all LCO issues and holding organizations accountable
for timely resolution. (Section O2.1)
Maintenance
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The inspectors identified that the standby liquid c)ntrol system configuration
challenged operators while performing surveillance testing, and that the high
pressure coolant injection surveillance test procedure did not include guidance to
pump down the
suppression pool. Coordination of switchyard 'nalntenance with ofisite personnel,
though improved over the last several monthP, continued to need additional .
Improvement. (Section M1.1)
The mid cycle outage was planned in greater detail than past outages, resulting in
better reviews, more complete preparations, and few schedule-related problems.
Problems observed during the previous refueling outage were observed to have
been effectively corrected. Teamwork and coordination were evident in identification
of equipment problems and performance of 'efueling floor activities. Outage
management personnel effectively communicated the results of risk analyses tn the
entire site. These improvements resulted in completing an a90ressive outage
schedule slightly ahead of schedule with a minimum of problems. (Section M1.2)
Enaineerina
The inspectors were concemed that the licensee did not formally evaluate and
document the operational impact cf the potential failure of selected solenold
operated valves remaining in service. Consequently, the licensee implemented
additional measures to pellodically verify operability of the affected valves. The
licensee's corrective action ofincreasing surveillance of selected systems was
acceptable. (Section E1.1)
Plant Support
The inspectors did not identify any specific issues in the area of plant support.
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Report Details
Summarv of Plant Status
The plant began this inspection period at 92 percent power. Power was reduced to
57 percent on September 24-20 for flux suppression testine !n responso to a second
fuelleak. A pinhole leak was determined to exist in a bundle in the center cell, and
one control rod was inserted to loca'ly suppress power. Power was returned to 93
.
percent until the plant was shut down on October 3, for a planr.ed mid cycle outage.
The outage was inltlated to sip the entire core, replace leaking fuel bundles, replace
and test safety relief valves, and perform a number of surveillance tests to support
extending the date of the next refueling outage. The plant was restarted slightly
' ahead of schedule on October 17 and the generator was synchronized to the grid on
October 19. The plant was operated at c. near 96 percent power for the remainder
of the inspection period, except for a brief power reduction during October 28 29 to
repair several hot spots on 345 kV switchyard bus connections.
LDporationg_
01 Conduct of Operations
01.1 Conduct of Operations - General Comments
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a. Inmection Scope (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews
of ongoing plant operations in the control room and in the field,
b. Findinas and Observallons
The insr '. ors r led that Nuclear Shift Supervisors (NSS) were active in
observing plant conditions and work in progress throughout the outage. On a
number of occasions, the NSS identified equipment problems during tours.
The inspectors noted that supervisory tours were a direct benefit to the shift,
and were a positive result of having reduced the administrative burden in the
control room when most work control activities were assumed by the Work
Control Nuclear Assistant Shift Supervisor (NASS). Also, the licensee
improved work coordination and allowed the NSS to become familiar with the
status of work and plant conditions by assigning NSSs to spend their first day
back from time off working in the outage management conference room.
The inspectors noted during turnover briefs and through reviews of Condition
Assessment Resolution Documents (CARDS) and logs that operators and
other licensee personnel on rounds were effective in identifying problems in
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the plant For example, a non licensed operator identified a low temperature
condition associated with an idle chiller in the control center heating,
ventilation, and air conditioning (CCHVAC) system. The system was promptly
declared inoperable and a faulty temperature switch was repaired. In another
example, a radiation protection (RP) technician on rounds reported that the
primary containment atmosphere monitoring system pump was making an
abnormal sound. The pump was promptly declared inoperable and repaired.
Throughout the outage, the licensee staff identified equipment problems
effectively. This is further discussed in Section M1.2.
The inspectors identified two instances where operators entered TS
exceptions with specific time frames without documenting the entry. During
the plant shutdown on October 3, the inspectors observed that the licensee
began de-inerting primary containment with the reactor operating above 15
percent power. -Technical Specification 3.6.6.2, applicability statement B,
allowed the licensee to de inert primary containment within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before
reducing power below 15 percent. The inspectors observed that this limited
time exception was entered but not noted in the logs or on a lim! ting condition
for operations (LCO) sheet. Additionally, on October 11, the inspectors noted
that the operators swapped divisions of shutdown cooling. An exception to
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TS 3.9.11.2 allowed removing the shutdown cooling pump from operation for
up to two hours per eight hour period. Again, this limited time TS action was
not documented. The inspectors were concerned that these TS entries into
s
allowed exception conditions with specific time frames were not adequately
documented to allcw tracking. This issue will be tracked as an inspection
followup item pending inspector review of licensee actions in response to
these observations. (IFl 50-341/97014-01)
On October 7, operators inadvertently deenergized the west station air
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compressor, necessitating entry into the abnormal operating procedure for
loss of station air. Prompt operator actions avolded unacceptably low air
pressure. Operators wrote CARD 97-11186 to document the event and track
corrective actions. The licensee concluded that the load list had not been
properly updated to clearly list the compressor when it was instalkd in August
1996,- The inspectors noted that this was similar to previous problems with
inadvertent deenergizing loads that occurred during motor control center
fused disconnect switch lubrication efforts in March-April 1997. The licensee
instituted similar corrective actione for both events. The methcd used by
operators to determine the impact of opening a breaker or switch relied upon
, limited review of documentation that included incomplete information. For the
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instances referred to, all unintentionally deenergized eqiilpment was non-
safety related. This will be tracked at an inspection followup item pending
further inspector review of the adequacy of load list documentation and
operator practices in preparing for electrical outages. (IFl 50-341/97014-02)
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The incpectors reviewed Operations Night Orders and noted that several
entries had been in active status for a n"mber of days. Operations
administrative guidance suggests that active night orderc, should normally be
in effect for up to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. The inspectors discussed their observations with f
operations management who stated that additional guidance was needed to
clarify management axpectations. The Inspectors reviewed the night orders
and noted that although most had exceeded the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> period, no
operational impact was evident.
c. Conclusions
The inspectors concluded that operators continued to er.hloit improved
performance in monitoring plant conditions. Personnel on rounds continued
to be effective in identifying and reporting problems. Supervisory presence in
the field for operations increased, partly as a result of having reduced the
administrative burden in the control room. Inspectors identified concerns with
a repeat problem with inadvertent deenergization of equipment and lack of 9
documentation of entries into allowed TS exceptions with limited time
duration.
01.2 Shutdown and Startuo Observations
a, lnspection Scope (71707. 71711)
The inspectors observed briefings and various plant evolutions associated
with the shutdown and subsequent startup from the mid-cycle outage, both in
the control room and in the field.
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b. Qbjervations and Findinas
During the plant shutdown process, the inspectors observed that operators y
effectively briefed each significant evolution. The shutdown schedule
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included ample time for each evolution. Trainees performed many of the
control room operations with qualified oparator supervision. Reactivity
controls were notably formal and controlled. Procedure use and adherence
was evident.
Similarly, the inspectors observed a careful and deliberate startup without any
personnel errors. The inspectors observed that the licensee appropriately
decided to discontinue the approach to criticality when it became clear that
criticality would have been achieved close to shift turnover time. Rod
withdrawal was also conservatively stopped while a process computer
--problem was correctedc-- The-approach to criticality was observed-to-be
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cautiouo.
The inspectors noted that control room operators exhibited an excellent
questioning attitude and took their time during both startup and shutdown No
schedule pressure was apparent dur'ng shutdown or startup. The inspectors
considered that the pre,ance of 1; censed operator trainees participating in
, control room operations for the first time during these evolutions contributed ,
positively to crew performance. The inspectors observed excellent trainee i
control and formal communications. The NSS and NASS clearly stated their !
expectations in this regard, and were observed to be prompt in cori; ting any l
deviations from these standards. Licensee senior management we present
during both plant startup and shutdown. In addition, Nuclear Quality
Assurance (NOA) provided extensive plant restart coverage.
c. ConclusioJa
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l Both startup and shutdown evolutions were performed withuut error,
i Licensed operator trainces in the control room were properly supervised and
contributed positively to crew p:,rformance. Briefings were frequent and
effective.
01.3 Reactor _.P_assum3asssLLElP_V) Pressure Test Observations
a. inspection Jcgae ( 71707. 61726 )
The inspectors revie'Ned Infrequently Performed Test / Evolution 97 05, "RPV
Prossure Test Following the October 1997 Fuel Inspection Outage," and
associated Safety Evaluation 97-0117. The inspectors then observed the
briefing and performance of the RPV pressure test on October 15.
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b. Observations and Fintljem
in preparation for the outage, the licensee reccgqized that plant conditions
would be more challenging than during a normal refueling outage. The core
decay heat load was expected to be relatively high because almost no fuel
was expected to be replaced and because of the short outage length. As a
result of the higher decay heat load, the plant conditions required for the RPV
pressure test after reassembling the reactor vessel were examined in detail to
ensure they could be satisfied throughout the test,
in order to avoid the possibility of an inadvertent change of operational mode
due to heatup during the test, which required securing shutdown cooling flow,
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a number of changes wore made to the process. The licensee obtained the
O'fice of Nuclear Reactor Regulallon (NRR) approval of new special test
exception (TS 3.10.7) to allo'N plant temperatures of up to 212*F during the
test. Also, NRR approved a relief request to allow testing at reduced
pressure. Finally, the licensee revised the test procedure based on simulator
testing and predictive modeling.
Simulator testing was performed to allow operators to become proficient with
the use of the procedure, to test procedure enhancements based on the
results in the simulator, and to deterrnine the time required to perform the
! test. The same operators were then assigned to perform the actual test in
l the plant. Improved methods of plant temperature control and higher fill rate
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were successfully validated in the simulator.
The inspectors observed that the actual test was s.all briefed. Staffing for the
l test was appropriate. Coordination was very good among groups involved
l which allowed the time spent with shutdown cooling secured to be minimized.
l Throughout the test, the inspectors observed that engineering personnel
constantly verified that plant response matched predicted values.
l Licensed operators were distracted by several balance of plant annunciators
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which were received repeatedly. When the NASS permitted the repetitive
alarms to be left flashing, operators had to use the Sequence of Events
Recorder to determine the source of new alarms because up to seven
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annunciators were already flashing. Also, just after reaching test pressure,
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a licensed operator not associated with the test conducted two switchyard
breaker manipulations. This was done without a control room briefing and
required the attention of the NASS at a time when the test in progress was at
l its most important stage. The inspectors concluded that these distractions
were not effectively minimized,
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c. Conclusions
The RPV pressure test was performed expeditiously in a coordinated and
controlled manner. Preparations were effective in minimizing the time spent
with shutdown cooling secured during a high decay heat condition. However,
the inspectors concluded that control of annunciators and performing
switching operations during this brief test distracted control room operators
from the test.
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01.4 Missed TS Situational Surveillance Reauirement
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a. Inspection Scope (71707)
The inspectors performed an independent followup on the licensee's self-
identified violation of a TS situational surveillance requirement. The
inspectors reviewed corrective actions for the event with senior plant
management, and attended small group sessluns for operators.
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b. Findinas and ObservatioDE.
On September 25, the licensee declared Emergency Diesel Generator (EDG)
14 Inoperable due to miner load oscillations observed during surveillance
testing. Technical Specification 3.8.1.1.b, required that with one EDG
inoperable, the remaining offsite power sources must be verified to be
available every eight hours. However, on September 27, the licensee
identified that operations personnel failed to complete this verification until
eight hours nine minutes after completing the previous check. A prompt
critique determined that the situational surveillance was discussed at the shift s
turnover briefing, assigned to a specific licensed operator, and scheduled to
be completed an hour early. The licensee determined that the assigned
operator forgot, and there was no backup by other members of the shift until
five minutes before the verificatiun check was due. This event was of
additional concern due to an recent, similar, violation of TS 3.8.1.1.b. The
circumstances of the earlier violation were discussed in Inspection Report 50-
341/97007. Failure to perform verification of the availability of offsite power
was a violation of TS 3.8.1.1.b. (VIO 50-341/97014 03)
In response to this event, senior licensee management promptly conducted
small group sessions with all operators to discuss performance and
responsibilities in regard to assuring TS compliance. Management
expectations and regulatory requirements were clearly presented. The
inspectors observed excellent participation by all present and noted that
operators provided many suggestions for improving performance and tracking
of TS actions.
Among the measures impiemented was a shiftly " reflection time" meeting.
Midway through each shift, as a group, the entire operating shift reviewed
important work in progress or planned for the remaining part of the shift for
TS impact. The inspectors observed several of these meetings and
determined that the intended focus on TS actions was effectively achieved.
The meetings also had the benefit ofinvolvinn the non-licensed operators in
TS issues.
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The inspectors also determined that shift turnover briefs were more complete
in their discussion of LCOs which were in effect and were better in ensuring
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that situational surveillance requirements were discussed. However, the
Inspectors identified that turnover briefing discussions of LCOs did not include
the actions required in many cases. This was often done at the more
focussed reflection time meetings.
Additionally, the licensee modified the software on personal computers used
for log taking to include a user set alarm program for reminding operators of
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situational surveillances with short time durations,
c. p_onclusions
The inspectors concluded that the licensee took prompt corrective cctions for
the missed TS verification requirements. The involvement by senior
management in the small group sessions and the solicitat!on of suggestions
added to individual buy in by operators. Prompt corrective actions
significantly raised the visibility of TS actions among operators.
O2 Operational Status of Facilities and Equipment
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O2.1 fagirmg. red Safety Feature System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible
portions of the folicwing Engineered Safety Feature systems:
- Standby Liquid Control System
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Standby Feedwater
EDG 11,12,13 and Support Systems
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130/260V Battery Support Systems
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Reactor Protection System Power
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Combustion Turbine Generator (CTG) 11-1
Emergency E.iulpment Cooling Water System
Equipment operability, material condition, and housekeeping were acceptable
in all cases. Several minor discrepancies were brought to the licensee's
attention and were corrected. The inspectors identified no substantive
concerns as a result of these walkdowns.
The licensee continued work to improve the reliability of CTG 11-1. Because
this station blackout generator was out-of service for several months, the
licensee installed a temporary modification to provide blackstart capability to
the other CTGs and stationed a full time operator at the CTG yard. Additional
operators were also assigned to support work on CTG 11-1. Licensee
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management was sensitive to this manpower drain on operations, and
increased oversight of the project. At the conclusion of this inspection period, .
the licensee began a series of 50 runs of CTG 111 to demonstrate reliability
of the machine, which was expected to last a few weeks.
Equipment performance was good following the outage. The licensee was
able to maintain TS related equipment in service, resulting in o very low
number of LCOs each day. The inspectors noted that this improved
performance was due to operations personnel actively pursuing resolution of n
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all LCO issues and holding organizations accountable for timely resolution.
08 Miscellaneous Operations lasues (92700; 92701)
08.1 (Closed) Licensee Event Report 50-341/96QQ2;. Engineered Safety Fecture
actuation of torus to drywell vacuum breakers due to improper system lineup.
An operator used the wrong hydrogen recombiner system lineup during a
surveillance test such that drywell gases were pumped to the torus until a
vacuum breaker actuated. This was not immediately recognized because no
alarm function is associated with the vacuum breakers, so two actuations
occurred. The cause was personnel error due to inattention to detail by the
operator. Additionally, the licensee determined that the procedure was not
human factored well in defining preferred and non-preferred lineups. System
Operating Procedure (SOP) 23.409, " Thermal Recombiner System," was
revised to improve human factoring and clarity. Training was completed on
the event and the operator received discipline. The inspectors verified that
training was completed and that SOP 23.409 was revised to clarify the normal
and emergency system lineups. Corrective actions appeared to be adequate.
The licensee's analysis of this event identified that the operato;' inadvertently
established a system lineup that created a suppression pool bypass leakage
path for approximately one hour, in the event of a loss of coolant accident,
steam in excess of that allowed in the Updated Final Safety Analysis Report
(UFSAR) could bypass the normal blowdown path to the torus and l ail to be
condensed. The hydrogen recombiner system piping was 4 inch piping, but
TS 3.6.2.1.b, required that the total leakage between suppression chamber
and drywell be less than the equivalent of a one inch orifice at 1 psid. The
inspectors determined that the safety significance of the additional bypass
leakage flow area for the brief period it occurred was minor because it
remained within the UFSAR analyzed maximum allowable bypass leakage
area of a 7 inch pipe. Failure to meet the requirements of TS 3.6.2.1.b, was
a violation. However, this non repetitive, licensee-identified and corrected
violation is being treated as a non-cited violation (NCV), consistent with
Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-04)
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08.2 (Closed) Violation 50-341/96002 01: Failure to follow hydrogen recombiner
system operating procedure (SOP). This item in discussed in detail in
Section 08.1. Corrective actions appeared adequate to prevent recurrence.
This item is closed.
08.3 (Closed) Violation 50-341/94016-01: Failure to verify alternate decay heat
removal method. Operators failed to recognize that removal of a residual
heat removal service water pump from service necessitated entry into a TS-
required situatiotial surveillance to verify availability of an alternate decay heat
removal method within one hour and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. The safety
significance of tho event was low because reactor decay heat was very low at
the time, and alternate methods of decay heat removal were avaHable. The
NSS and NASS involved were removed from shift duties, counseled, and
were assigned to conduct training for operators on the event. The event was
caused by three licensed operators relying on memory to determine the
applicable TS actions required, with each incorrectly concluding that no act;on
was required, in response to this event, the licensee formeri the Operations
Work Control Group to ensure appropriate categorization of work dc;uments
regarding TS impact during the work planning stages, which would then be
verified by the operating shift when work was approved to start. Shift
technical advisors were added to thn review chain for final approval of work.
Plant management communicated expectations for operator communications
and TS impact reviews to all operations personnel. Corrective actions were
completed and considered adequate This item is closed.
08.4 (Closed) Licenseo Event Report 50-341/94008: Failure to verify alternate
decay heat removal method. This was subt.1itted as a voluntary licensee
event report. This item is discussed in Section 08.3. Corrective actions
appeared adequate. This item is closed.
08.5 LClosed) Insocction Followuo Iteqd50-341/94016 04: Performance of
troubleshooting and corrective mi tenance
i during surveillance activities.
Inspectors identified that numerous fastener problems were identified and
corrected in the source rangerintermediate range monitor cabinet during a
surveillance test as a result of on the spot troubleshooting. The condition was
later evaluated and reported as being outside the design basis of the plant
because the seismic qualification was not maintained with the loose
fasteners, for which an NOV was later issued. This licensee-identified
example of loose fasteners involved several process radiation monitoring
instrumentation cabinets, and each cabinet's fasteners were subsequently
corrected through an appropriate work request. The inspectors reviewed
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troubleshooting procedures, observed troubleshooting in the field, and
discussed troubleshooting practices with various plant personnel. The
inspectors also reviewed numerous closed work packages. No additional
examples of troubleshooting or corrective maintenance during surveillance
activities were identified. The inspectors concluded that procedures
governing troubleshooting clearly required separate approval and
documentation. Based on the correction of the original loose fasteners issue
and lack of additional occurrences, this item is closed. '
08.6 (Closed) Licensee Event Report 50 341/97012 00: Automatic reactor scram
on high scram discharge volume during shutdown conditions. A licensed
operator performing a surveillance procedure prematurely reset a manual scram without referring to the scram abnormal operating procedure, which
caused an unplanned scram when the scram discharge volume subsequently
filled 00. All control rods were already fully inserted at the time of the event.
Training was conducted for all operators on this event, and the operator
involved received discipline. The Inspectors verified that training was
completed, in addition, the licensee added steps to the surveillance
procedure (24.623) to ensure the scram was properly reset per Procedure
23.010, " Reactor Protection System (RPS)." This item is closed.
08.7 C 3d) Violation 50-341/96013 01;. Failure to follow procedures for resetting
a reactor scram resulted in an unplanned scram. This event is discussed in
Section 08.6. This item is closed.
08.8 (Closed) Violation 50-341/96002-04: Improper return of EDG 14 to a standby
condition. This event was caused by improper independent verification and
failure to list all components out of the standby lineup on the tagout sheet
restoration section. The licensee conducted training on the event, proper
methods for performing independent verification, and proper methods for
equipment removal and return to service. This training included pratucal
demonstrations. Additionally, operations management created the position of
shift foreman to provide increased oversight of non-licensed operators by a
licensed operator. The foreman was expected to brief each job when
assigned. The inspectors reviewed the event critique and corrective actions.
Based upon the corrective actions and lack of repeat problems in equipment
restoration, this item is closed.
08.9 (Closed) Inspection Followuo item 50-341/97002-03: Troubleshooting
practices prirr to writing a work request. The inspectors were concerned with
the variety of methods of implementing troubleshooting under the Conduct of
Operations administrative procedure, and with the lack of documentation for
troubleshooting activities. The licensee revised Operations Conduct Maneal
Procedure 04 to add additienal requirements for documentation of the
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planned steps befo6e performing any troubleshooting activity. The inspectors
noted that this was applied to troubleshooting conducted by all personnel, not
Jbst to operations personnel. The completed troubleshooting document was
retained as part of the CARD reporting the problem and listed as a reference
in any work requests initiated to correct the problem. The inspectors
reviewed several completed troubleshooting packages, and noted that checks
and approval were clearly documented. The inspectors observed that
operations, maintenance and system engineering personnel involved in recent
troubleshooting efforts used the new method, and were enthuWastic about the ,
process and sesults. The inspectors did not identify any other concerns. This
item is closed.
08.10 (Closed) Violation 50-341/96016-02: Operators did not adequately
respond to high level in the fuel pool. Operators did not verify that the
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fuel pool manual fill valve was shut, as required in the annunciator
response procedure, because they had not ordered it open during their
shift. /he valve was found to be two turns open after the fuel pool
started overflowing into ventilation ducts. Operators were trained on
this event, including management expectations for annunciator
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response, to stress the need for determining the cause of alarms and
ensur!ng that the steps taken in response correct the condition. The
inspectors observed improved annunciator response during routine
control room obsermons and verified that training was completed.
This item is closed,
ll. Maint.spance
M1 Conduct of Maintenance
M1.1 _Qeneral Comments
a. insoection Scooe (62707)
The inspectors observed all or portions of the following work and surveillance
activities. Work practices and procedure adherence were assessed. Tagout
isolation and administration were observed and reviewed. Radiological work
practices and RP support'of work were observed. Work packages were
reviewed for completeness and adequacy as well as plant impact and TS
action implementation requirements. Surveillance procedures were reviewed
and compared to TS, the UFSAR, and system design basis documentation to
, ensure requirements were being properly tested.
'
-
Troubleshooting of Reactor Water Cleanup Pump B
-
Scram Time Testing of Control Rod Drives
14
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+
Shutdown Margin Surveillance Testing
In core Sipping and Vacuum Sipping of Fuel Bundles
Reactor Vessel Head Tensioning Activities
+
Bus 72F.C Undervoltage Surveillance Testing
Safety Relief Valve Surveillance Testing
Drywell Torus Vacuum Breaker Operability Surveillance Testing
Control center heating, ventilation, and air colditioning (CCHVAC) Duct
LeakageTesting
-
Flux Suppression Testing
Emergency Diesel Generator (EDG) 14 Governor Troubleshooting
High Pressure Coolant Injection (HPCI) Pump and Valve Operability
Surveillance
+
Preheater Drain Cross-Tle Valve Repalts
Logic System Functional Test of Bus 72EA and 72EB Undervoltage
Circuits
+
Feedwater Suction Strainer inspections
+
Reactor Pressure Vessel (RPV) Testing
- Core Shutdown Margin Verification
Corrective Maintenance Breaker Disconnect Hot Spot Repairs
Standby Liquid Control (SLC) Pump and Valve Operability Surveillarce
Test
.
Emergency Diesel Generator (EDG) 11 Surveillance Test
+
General Service Water Sluice Gate Repairs
Emergency Diesel Generator (EDG) 12 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run
Control Rod Drive Housing Support Visual Inspection
+
Control center hcating, ventilation, and air conditioning (CCHVAC)
Chlorine Detection Division 1, Channel Functional Test
Shutdown Margin Verification Testing
Control Rod Scram Time Testing
-
Combustion Turbine Generator (CTG) Ground Isolation
Troubleshooting
b. Observations and Findinos
The irispectors noted an increased questioning attitude among maintenance
workers during this inspection period. Workers increasingly utilized the CARD
process to report problems that were not directly related to the work in
nrogress.
While observing the SLC pump and valve operability surveillance, the
inspectors noted that the system configuration complicated test performance.
The valve throttled to control pressure was located 15 feet above the pumps.
The gauge used for setting the throttle valve could not be seen by the
operator, so a second operator reported pressure readings to the operator on
15
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.
a ladder. However, as the pressure increased, the pump noise and throttling
noise increased to the point where communications became difficult. Also,
the inspectors noted that operators were unable to properly set up the step .
ladder used because the "A" pump prevented using all four legs. The ladder
was propped against a concrete lip at the bottom and leaned against a pipe
support at the top. Also, the length of the ladder made it difficult for the
operator to reach the valves.
During the HPCI Surveillance (24.202.01) on September 29, the inspectors
noted that operators operated the torus water management system to pump
down the suppression pool at 450 ppm in order to maintain suppression pool
level within TS level limitn with the HPCI system running. The inspectors
v. ele concerned that HPCI valve seat leakage could be contributing to the
suppression pool water input. The inspectors discussed this observation with
a performance engineer, who was able to demonstrate by rough calculation
that the steam input to the torus closely matched the pumpdown rate, so
valve seat leakage into the torus was unlikely. However, the inspectors noted
that surveillance 24.202.01 did not specify running the torus water
management system in order to contral suppression pool water level. The
inspectors also noted that the surveillance test was delayed two hours
because test equipment problems were not identified until just before the test
was to start.
During routine oil analysis on EDG 12 following a 41 hour4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> surveillance run,
the licenses identified a marked increase in the severe wear index for the
outboard generator bearing. Vibration monitoring and temperature trending
for the bearing indicated normal bearing performance. The licensee
conducted a bearing inspection with the vendor present and conservatively
decided to replace the bearing due to observed minor but unexpected wear,
even though the bearing had only accumulated about 100 run hours since it
was last replaced.
During the mid cycle outage, the licensee was able to correct a number of
challenges to operators, inc* "ag replacing the seal on the "A" reactor ,
recirculation pump, several e ol rod position indication probes, and
Intermediate Range Monttor ' However, the licensee did not correct seat
leakage in the reactor water cleanup blowdown valve, so operators continued
to respond to repeated high pressure alarms for the blowdown line. Also, the
south reactor water cleanup pump seal and impeller were replaced during the
outage, but pump problems mntinued to challenge operators. The pump
capacity was reduced, and ne seal was runninp above its clarm temperature.
Shortly after the alarm setpoint was raised, the temperature indication failed.
System engineering and inaintenance personnel continued to work to resolve
these issues at the conchslon of this inspection.
_ __
16
.
!
Fonowing generator synchronization at the conclusion of the outage, the
licensee identified that several of the high temperature connections in the
Division 2,345 kV switchyard were utill present. A licensee investigation
revealed that offsite personnel assl0ned to refurbish the connections had only
worked connections with more than 1 mV drop for an applied 100 amp
current. As a result, the licensee reduced power on October 28 29 in order to
correct the remaining high temperature connections. The licensee
determined that inadequate control of work between the site staff and offsite
work group contributed to workers deciding the connections were acceptable
even though they had been identified as operating at high temperature under
load. As discussed in inspection report 50 341/97013, coordination of
switchyard maintenance with offsite organizations had improved over the last
several months.
While observing leakage testing of CCHVAC ductwork on October 6, the
'
inspectors observed that test engineers did not comply with work request
precautions. Specifically, Work Request 000Z971023 directed workers to
hang a safety caution sign over open duct access plates and reinstall eccess
plates when work was delayed or stepped. The inspectors observed that
signs were not hung and access plates were not reinstalled during work
stoppages until the omissions were pointed out by the inspectors. These
deficiencies were observed to have been corrected during subsequent
observations of the work. During testing, the licensee identified that one of
the dampers tested had a loose set screw on the positioner. The inspectors
observed that the licensee promptly inspected all eppropriate system dampers
and did not identify any similar problems.
The inspectors reviewed documentathn from the recent turbine building
heating, ventilation, anri air conditionir g (HVAC) system outage. The non-
safety system outage was terminated when excessive temperatures were
identified in the turbine building , " tunnel area. Later, as a result of
inspector questioning, the licensee G+ 'ined that resistance temperature
detectors used to provide a Main Sterm isolation Valve (Group I) closure
were affected by the high temperatures. An operability evaluation by the
licensee determined that the original environmental qualification life o' the
components had been considerably shortened as a result of operating at
higher ambient ten.peratures than analyzed, in response, the licensee
performed additional analysis that demonstrated that the affected components
remalt.ed operable with a reduced life. At the inspectors' request, NRR
reviewed the licensee's operability evaluation and agreed with the licensee's
operability conclusion. The inspectors further reviewed a safety evaluation for
the high temperatures in the turbine building. The inspectors noted that the
safety evaluation did not recognize that safety related equipment in the
turbine building could be adversely affected by the high temperatures. The
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licensee agreed with this observation and corrected the evaluation. The
licensee also agreed with the inspectors' conclusion that additional emphasis
is needed in the assessment of operational and safety impact resulting from
non safety system outages. The
inspectors will follow the licensee's conective act!ons to address the
assessment of non safety system outage impact. (IFl 50 341/97014-05)
Further discussion on the conduct of maintenance activities can be found in
Section M1.2.
c. Conclusions
The licensee improved plant material condition and corrected a number of
operator chall"nges due to equipment proibms. However, severat
equipment related challenges remained. The inspectors identified that the
SLC system configuration challenged operators while performing surveillance
testing and that the HPCI surveillance test prncedure did not include guidance
to pump down the suppression pool despite the significant inventory added to
the pool Coordination of switchyard maintenance with offsite personnel,
though improved over the last several months, continued to need additional
improvement.
The inspectors noted that during the turbine building HVAC system outago,
turbine building temperatures rose to within 10 degreet of the trip setpoint for
Main Steam Isolation Valve (Group 1) closure. The licensee also agreed with t
the inspectors' conclusion that additional emphasis was needed in the
assessment of operational and safety impact that re: nit from non safety
system outages. This will be tracked as an inspection followup item pending
further review of corrective actions. (IFl 50 341/97014-05).
M1.2 Outage Observations
a. Inspection Scope (62707. 60710)
The inspectors reviewed the outage schedule and work scope, defense in
depth plan, and an Independent Safety Engineering Group (ISEG) evaluation
of the outage plan. Licensee adherence to the defense in depth plan was
verified daily by control room observations and attending outage meetings.
Work and refueling / sipping activities listed in Section M1.1 were observed and
are discussed further.
b. Observations and Findinas
z b.1 Refuel Floor Activities
18
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- _ _ _ _ _ _ - _ _ _ - .
Refueling floor activities were planned in detail. This critical path sequence
included sipping all fuel bundles in the core to identify and replace leaking
bundles. The inspectors observed that although refueling activities had never
been critical path during previous outages, the licensee was able to complete
all activities in record time without error.
Supervision of activities was improved by using two refuel floor coordinators
and two senior reactor operators on each shift. Additionally, ona of the
refuelmg floor coordinators was assigned to frequently assess foreign material
exclusion practices. Coordination was observed to be excellent on the
refueling floor and with the control room. Refueling floor work was delayed
only once due to other plant activities.
The inspectors observed that appropriate radiological precautions were taken
for the fuel leaks. These included venting the reactor vessel through a high
efficicncy particulate air filter unit to the standby gas treatment suction,
limiting the number of personnel on the refueling floor when moving the
leaking fuel bundles, and planning the response to the potential airborne
release on the refueling floor. When a slight airborne release occur ed at the
start of sipping one of the leaking bundles, RP personnel 8-mpled the air,
_
promptly calculated the dose from the airborne release, and notified each
person present about the results (less than 1 mrem each). Radiation
protection support of refueling floor work was observed to be excellent, and
was further documented in Inspection Report No. 50-341/97015.
The licensee planned to further review the refueling process to identify
additional ennancements and opportunities for dose savings. The licensee
extensively recorded video observations of work in progress. The inspectors
noted that the licensee utilized high quality cameras to monitor work progress
and reduce dose. This, however, did not reduce the direct supervision.
The inspectors observed that fuel moves were proparly communicated to and
tracked by control room personnel. The senior reactor operator directing the
core alterations was present on the refueling bridge. Communications and
conduct on the refueling bridge exceeded the standard observed in the
control room.
The inspectors observed that licensee corrective actions for problems
involving refuel floor activities during the previous refueling outage were
uniformly effective. The entire evolution was conducted without a personnel
error or procedure adherence problem. Dose was considerably lower than
predicted for the evolution. Fuel pool level and water inventory were carefully
19
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. _ _ _ _ - _ _ - - _ - _ _ _ _ _ _
monitored by operators. Head tensioning and subsequent operational mode
change were very controlled. This issue is iJrther discussed below in
Sections M8.1 and M8.2. Refueling bridge reliability was effectively improved
under the Maintenance Rule system improvement plan, and the reliability was
clearly established before the outage began. There were no schedule
interruptions due to refueling bridge problems during this outage.
b.2 Work Control
Outage management effectively limited the outage work scope, with emergent
work added on a strictly controlled basis. The inspectors observed that
virtually all of the work scope additions were handled by the Fermi Integrated
Resource Support Team; therefore, the work additions did not impact any of
the planned work.
The inspectors noted that the outage schedule was planned in greater detail
than in previous outages. All surveillance tests were scheduled prior to
starting the outage, in contrast to past practice where the tests would be
added to the schedule only a few days ahead of the work. The new practice
resulted in cetter scheduling of manpower, particularly in operations. The
inspectors noted that the late addition of surveillance tests had previously
challenged ISEG's abikty to review surveillance tests to determine their impact
on the defense in depth plan. The inspector's review of overtime identified
that the operations department had virtually no unscheduled overtime during
the outage, an issue which has been a challenge in the past. The better
scheduling also resulted in virtually eliminating problems in meeting required
plant conditions for surveillance tests, which wa9 a problem that was
observed a number of times during the last refueling outage, as documented
in Inspection Report No. 50-341/96013(DRP).
Outage preparations included a new practice of preparing all tagouts and
scaffnld requests prior to the outage. The inspectors did not identify any
scaffold location or approval discrepancies during this outage, compared to
numerous problems identified during the previous outage. Few tagout
problems occurred during the outage.
b.3 Risk Management
The inspectors reviewed ISEG Report 97-014 on the mid-cycle outage scope
and schedule review. The ISF.G review was detailed and properly focussed
on safety. The ISEG identified a number of concerns in their initial review,
which were adequately resolved by the licensee staff. The inspectors' review
of the schedule and the resolution of ISEG's concerns did not identify any
additional concerns. Due to the limited work scope, the licensee was able to
20
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_ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
maintain nearly allimportant power sources, decay heat removal systems,
and reactor vessel fill systems available throughout the outage. This resulted
in excellent defense in depth coverage, and fulfilled the guidelines set forth in
Operations Department Instruction (ODI) 44," Operations Outage Philosophy."
The inspectors observed that ISEG and outage management personnel were
proactive in keeping the licensee staff aware of the impact of the higher
decay heat loads than during a normal refueling outage. This was of
paiticular concern for the reactor vrssel pressure test and is discussed in
Section 01.3.
The ilcensee utilized a software program for evaluating shutdown risk,
Operational Risk Assessment and Management (ORAM), en a trial basis
during this outage. This was performed in parallel with normal manual risk
assessment. The results of this trial were generally positive and resulted in a
number of plant model refinements. Outage management personnel
effectively communicated the results of the ORAM analyses to the entire site
by posting color graphs and brief discussions of the critical work impact on
defense in depth at various locations throughout the site. The licensee
planned to continue to seek industry experience with this risk acsessment tool
before further implementation of ORAM.
The inspectors reviewed the new ODI 44. This document formalized past
practices and delineated operations management expectations in detall. The
inspectors considered this document to be a significant addition that
adequately covered the topic. The inspectors observed that adherence to
ODI 44 was good, although adherence in one minor inspector identified case
was not possible due to the ODI being overly restrictively worded. ,
b.4 Conttactor Control
During the previous refueling outage, the licensee had a number of contractor
control problems. During this outage, the licensee relied almost exclusivq
on site personnel to perform scheduled work, with refueling and fuel sipping
being the significant exceptions. The licensee utilized a number of offsite
Detroit Edison personnel to supplement the site work force. The inspectors
observed that the control of visiting workers was excellent during this outage.
Site supervision for visiting workers was observed to be very active at work
sites. Site access training was modified to include contractor control issue
lessons leameo from the previous refueling outage. Pre-job briefs for visiting
21
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workers were observed by insprctors to stress the need to ask questions of
. site personnel when in doubt. '
b.S Plant Equipment Walkdowns
The inspectors nr 3d that the licensee effectively utilized seve ral teams
designated to coudcct equipment walkdowns, particularly in 'ormally
inaccessible areas of the plant. These walkdowns were scheduled ~at
appropriate times during both startup and shutdown sequences when ri- -
'N9s acceptably low but the systems of concern were hot and ~
>
During startup, this effort included a vacuum leak team whic' m + a in
ensuring the plant retumed to operation with a low air inlea' +
.cse
walkdnwns were performed jointly by operators, system eng . ., and RP
personnel. Deficiencies identified by the teams were documented on CARDS,
b.6 Excessive Safety Relief Valve (SRV) S6tpoint Jrift Raported
On October 13, the licensee identified that the SRV oilot valve setpoint testing
of pPot valves used during the first part of the cycle indicated that 11 of 15
SRVs had a setpoint that was outtide the +/- 1 percent setpoint tolerance i
specified in TS 3.4.2.1. Al! SRVs were replaced during the mid-cycle outage.
This condition was reported per 10 CFR 50.72.(iii)(D). The inspectors will
review the plant impact of this condition under 1.icensee Event Report 50-
341/96017, Revision 3.
c. Conclusions
The mid-cycle outage was planned in greater detail than past outages,
resulting in better reviews, more cemnlete preparations, and few schedule-
related problems. Problems observed during the previous refueling outage
, were observed to have been effectively corrected. Teamwork and
coordination were evident in identification of equipment problems and
performance of refueling floor activitas. Outage management personnel
effectively communicated the results of risk analyses to the entire site. These
improvements resulted in :ompleting an aggressive outage schedule slightly
ahead of schedule with a minimuni of problems.
> -
M8 Miscellaneous Maintenance issuco (32902)
M8.1 (Closed) Violation 50-341/96f17-018: Inadvertent operational mode change
due to detensioned isactor head bolt. IEs event was directly caused by a
data recording error during initial tensioning and compounded by weak
commurdcations. The licensee deterrnined that a procedural deficiency
, 22
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__ _ _--_______ _
v
existed, in that, the procedure for tensioning the reactor vessel head directed
an operational mode change from refueling to cold shutdown before
completing head tensioning verification. The procedure was changed to
correct this deficiency. The inspectors observed improved communication
and verification of head tensioning data during the mid-cycle outage.
Potential data discrepancies were observed to be appropriately questioned
and resolved by the refueling floor coordinators and work group. The
inspectors also observed improved communication of head tensioning status
to the control roam and a mode change conducted at the appropriate time in
the sequence. Corrective actions were observed to be appropriate and
effective. This item is closed.
M8.2 (Closed) Licensee Event Report 50-341/96018: Inadvertent operational mode
change due to detensioned reactor head bolt. As discussed in Section M8.1,
the inspectors determined that corrective actions were ade quate to address
the root causes of the event. This it' m is closed,.
M8.3 (Closed) Inspectico Foliqwuo item 50-341/95014-01: Primary containment
airlock test connection p:pe cap untested following restoration from airlock
testing. At Region Ill's request, NRR performed a formal review of the
licensee's practices of using administrative controls to ensure the cap was
reinstalled properly and not performing a local leak rate test (LLRT) after
reinstalling the cap. The NRR response concluded that the licensee's
practice was consistent with the staff's position for LLRTs for test, vent and
drain connections under Option A et 10 CFR 50, Appendix J. Thus, no
violation was considered to have existed at the time of the inspection.
. Subsequent to the inspection, the licensee adopted Option B of Appendix J.
Under that option, the cap must be tested. The inspectcrs determined that
the licensee changed the surveillance test procedure for airlock LLRTs
(43.401.206) to use a different test connection which included an additional
isolation valve Sat was Type B tested. This avoided disturbing the above
cap, so the cap was also tested during the airlock LLRT. Therefore, the -
current licensee practices were determined to be in compliance with the
applicable wRC requirements. This item is closed.
M8.4 (Closed) Violation 50-341/96013-02: Non-operations personnel operated
valve without permission, resulting .in overfilling the spent fuel pool (SFP).
'
,
The inspectors reviewed changes to Operations Conduct Manual 05, ' Control
of Equipment," and observed that the procedure strengthened the
requirements for the approval of non-operations personnel manipulation of
equipment and requiring that any exceptions be approved and logged by the
NSS. The inspectors observed that a specific briefing for refueling floor
workers was held prior to the recent mid-cycle outage, which stressed
23
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_ - __-
__
controls placed on operating equipment. The inspectors verified that -
operators exhibited increased sensitivity and frequent monitoring of fuel pool
skimmer surge tank levels, and all SFP fill!ng operations were performed only
by operators. In cddition, the licensee performed training for operators,
system engineers and chemistry personnel on the Operations Conduct
Manual 05 changes discussed above. The inspectors determined by
discussions with selected individuals in these groups that the training was
effective. This item is closed.
JI1_. Enaineerina
o
E1 Conduct of Engineering
E1.1 Solenoid Operated Valve (SOV) Investiaation Update
a. Inspection Scoce (92902. 92903) ~
The inspectors reviewed the licensee deviation event report; held
conversations with maintenance and engineering personnel; reviewed
technical, industry and vendor manual information for SOVs; and held
discussions with NRR and region specialists,
b. Observations and Fitdinas_
The inspectore continued to review issues with the solenold valves discussed
in Inspection Report 50-341/97013(DRP). The inspectors reviewed the
licensee's justification for the continued o;;erability of solenoid valves that
were not planned to be replaced prior to plant restart. The licensee identified
, 14 SOVs for replacement during the mid-cycle outage, schedulad system
outages, and the following refueling outage. The SOVs were chosen based i
on mndel number, service conditions, and risk significance. The inspectors
were concerned that the licensee did not formally evaluate and docaent the
operational impact of the pc'ential failure of the valves remair.Mg in service.
Based or. NRC concerns, the licensee decided to perform increased
frequency testing of the affected SOVs to verify ongoing operability. Region-
based inspectore and NRR personnel determined that the additional
corrective aciion was sufficient to determine operability.
,
c. Concluuons
"
The inspectors were conemed that the licensee did not formally evalu ete
and document the operational impact of the potential failure of the valves
remaining in service. Consequently, the licensea implemented additional
measures to periodically verNy operability of the affected valves. The
l 24
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- _ - _ _ ___ _ _ _-__ ____ __ __ _-_____-____-__
licensee's corrective action of increasing surveillance of selected systems
addressed the inspector's concerns.
E8 Miscellaneous Engineering issues (92902)
E8.1 (Closed) Licensee Event Report 50-341/90008: Auxiliary building basement
not fully meeting divisional separation criteria. During a plant walkdown, the ,
licensee identified that electrical cables from Division 1 Non-Interruptible Air
System did not have adequate separation from a Division 2 instrument rack.
A continuous fire watch waa posted until the Division 1 cabling could be
protected with fire wrap. The inspectors reviewed the plant modification,
walked down the completed fire wrap modification, and discussed the ,
protection methodology with a fire protection engineer. The modification
appeared to adequately restore the required divisional separation. The
licensee also performed an evaiuation to determine if additional areas existed
whare divisional separation of cables was inadequate, and none were
identified. Failure to maintain adequate separation between divisions o"the
safety related air system was a violation of 10 CFR 50
Appendix R. However, this non-repetitive, licensee-identified and corrected
violation is being treated as a non-cited viciat'on, , consistent with Section
Vil.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-06)
E8.2 (Closed) Licensee Event Report 50-341/97004-0 * Calibration of primary
'
containment oxygen monitor in de-inerted environment challenging operability
of monitor in inerted environment. The licensee determined that the TS limit
of 4 percent oxygen inside containment duriig power operation was never
,
violated because the maximum observed insrument error was based on a .
review of the nine occasions when an unanticipated non-conservative error
was introduced. The licensee's response to this discovery was discussed
with licensee senior managernent at a pre-decisional enforcement conference
on August 8,1997. As a result, it was determined that a violation occurred
due to failure to report the problem in the 'icensee's c~rective action process
and violation 50-341!97013-02 was issued. This item is closed based on the
issuance af the violation.
E8.3 (Close violation 50-341/97013-02: Failure to write a Deviation Event
Report for a non-conservative error introduced in primi y containment oxygen
monitor calibration. The licensee implemented a new corrective actions
reporting program which encompasserl a greater scope of problem reporting.
The inspectors observed that this process effectively lowered the threshold for
reporting potential problems since its impleraentation in September 1997. As
25
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,
>'
a result of not reporting this problem, past system operability was not
investigated in a timely manner and corrective actions were initially
incomplete. The inspectors noted that the licensee completed a special test
to determine the conditions under which the error was introduced. The
licensee then developed a proced re to accurately calibrate the oxygen '
l
monitor under either inerted or deinerted conditions. Training for operators
end system endneers on the event stressed the need to question and report
anomalous wjications. Corrective actions appeared to be adequate. This
item is closed.
E8.4 (Closed) Unresolved item 50-341/06010-11: Inverted Boraflex panels in SFP
storage racks not accounted for in calculation of impact of possible Boraflex
gaps. The licensee commissioned a calculation of the combined effects of
these two conditions. The inspectors reviewed License Change Request 97-
128-UFS and safety evaluation (SE 97 0112) approving the change to the ,
UFSAR to incorporate the combined calculation. The licensee analysis
concluded that under design cor. . ms, TS 5.6.1 requirements for margin to
criticality of the fuel in the SFP stc. age racks were met. The inspectors
determined that the conclusions of the analysis appeared reasonable and
a
were baseo upon conservative assumptions. This item is closed.
E8,5 (Closed) Inspection Fo!!owuo item 50-341/96010-12: Inverted Boraflex panels
in SFr- storage racks not documented in UFSAR. Th7 licensee determined
that the combined ef'ects of the two conditions dis.;ussed in Section E8.4
'
were not accounted for because the results of the eight storage cells with H
inveded pcnels were not documented in the UFSAR. Failure to maintain the
UFSAR updated with the current configuration of the SFP storage racks was
i a violation of 10 CFR 50.71. However, this non-repetitive, licensee-identified
and correctec' violation is being treated as a non-cited violation, consistent
with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-07)
V. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on November 10,1997. The
licensee acknowledged the findings presented. Th3 inspectors asked the licensee
whether any materials examined during the inspection should be considered
proprietary. No proprietary information was identified.
X3 Management Meeting Summary
On November 6-7, J. Jacobsor., acting Deputy Director, Division of Reactor Safety,
26
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Region lli visited the site to observe the plant condition-and discuss licensee
' performance in preparation for the upcoming SALP, During this visit, he met with ,
various members of the licensce's staff.
I
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27
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PARTIAL LIST OF PERSONS CONTACTED -
.
Licensee
S. Booker, Electrical Maintenance Superin'endent _
D. Cobb, Operat!cas Superintendent
W. Colonnello, Work Week Manager -
'
R. Delong, Superintendent, System Engineering
T. Dong, NSSS, Technical Engineering -
P. Fessler, Plant Manager
J. Greene, Superintendent of Maintenance Support
K. Howard, Superintendent, Flant Support Engineering
E. Kckosky, Superintender.t, RP and Chemistry
J. Korte, Director. Nuclear Security
R. Laubenstein, Mechanical Maintenance Superintendent
P. Lynch, NSS, Operations
R. Matthews, I&C Maintenance Superintendent
W. Miller, Work Week Manager
J. Moyers, NQA Director
N. Peterson, Acting Director, Nuclear Licensing
J. Plona, Technical Director
T. Schehr, Operating Engineer
J. Sweeney, Supervisor of Audits, NQA
NRC
J. Pulsifer, NRR Systeins Branch
A. Kugler, Project Manager, NRR
H. Ornstein, AEOD
R. Gardner, DRS, Rlli
D. Butler, DRS, Rlll
1
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. _ _ . _ _ _ _ _ _ _ _
_ - _ - _ _ - _ - _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _
INSPECTION PROCEDURES USED
IP 60710: Refueling Activities
IP 61726: Surveillance Observations
IP 62707: Maintenance-Observation
IP 71707: Plant Operations
IP 71711: Plant Startup from Refueling
IP 92700; Onsite Followup of Written Reports of Nonroutine Events at
Power Reactor Facilities
IP 92901: Followup - Operations
IP 92902: Followup - Engineering
IP 92903: Followup - Maintenance
ITEMS OPENED, CLOSF.D, AND DISCUSSED
Opened
50-341/97014-01 IFl TSs Entered into Without Documeatation
50-341/97014-02 IFl Adequacy of Load List Documentation
50-341/97014-03 VIO Failure to Perform Verification of Availebility of Offsite
Power
[ 50-341/97014-04 NCV Failure to Meet Requirements of TS 3.6.2.1.b
50-341/97014-05 IFl Non-Safety System Outage Impact Assessment
50-341/97014-06 NCV Failwe to Maintain the Divisional Separation in Air System
50-341/97014-07 NCV Failwe to Maintain the UFSAR Updated with Current
Configuration of the SFP Storage Racks-
Clos,ed
50-341/94008-00 LER Failure to Verify Alternate Decay Heat Removal Method
50-341/94016-01 VIO Failure to Verify alternate Decay Heat Removal Method
50-341/94016-04 IFl Performance of Troubleshooting and Corrective
Maintenance During Surveillance Activities
50-341/95014-01 IFl Primary Containment Airlock Test Connection Untested
50-341/96002-00 LER ESF Actuationi to Torus to Drywell Vacuum Breakers Due
to improper System lineup
50-341/96002-01 VIO Failure to Follow Hydrogen Recombiner SOP
50-341/96002-04 VIO Improper Return of EDG 14 to Standby
50-341/96008-00 LER Auxiliary Building Basement not Fully Divisional
Separation Criteria
50-341/96010-11 URI inverted Boraflex Panels in Spent Fuel Pool
50-341/96010-12 IFl Inverted Boraflex Panels in SFP Storage Racks not
Documented in UFSAR
29
.. . ..
.
- ____ -____-___-______
- _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _
50-341/96013-01 VIO Failure to Follow Procedures for Resetting a Reactor
50 341/96013-02 VIO Non-Operations Personnel Operated Valva Without
Permission, Resulting in Overfilling the Spent Fuel Pool
50-341/96016-02 VIO Operators did not adequately respond to high level in the
Fuel Pool
50-341/96017-018 VIO Inadvertent Operational Mode Change Due to
Detensioned Reactor Head Bolt
50 341/96018-00 :R Inadvertent Operational Mode Change Due to
'
Detensioned Reactor Head Bolt
50-341/97002-03 IFl Troubleshooting Practices Prior to Writing a Work Request
50-341/97004-01 LER Calibrntion of Primary Containment Oxygen Monitor in De-
inerted Environment Challenglng Operability of Monitor in
Inerted Environment
50-341/97012 00 LER Automatic Reactor Scram on High Scram Discharge
Volume During Shutdown Conditions
50-341/97013-02 VIO Failure to Write a Deviation Event Report for a Non-
Conservative Error Introduced in Primary Containment
- Oxygen Monitor Calibration
t
T
30
- _ _ - _ _ _ _ _ _
_ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ ___ _ _ _ _ _ _ _ _ ._ _
t
)
LIST OF ACRONYMS USED
CARC,
CTG
EDG Combustion Turbine GeneratorCondition Asse
ISEG High Pressere Coolant injection
3 LCO Independent Safety Engineering Group
LLRT Limiting Condition for Operation
NASS Local Leak Rate Test;ng
NCV Nuclear Assistant Shift Supervisor
NOA Non-Cited Violation
Nuclear Quality Assurance
NRC
NRR Nuclear Regulatory Commission
NSS Office of Nuclear Reactor Regulation
Nuclear Shift Supervisor
ODI
ORAM Operations Department instruction
RP Radiation ProtectionOperational R!sk Assessment and Managemen
Spent Fuel Pool
Standby Liquid Control System
O SOP
SOV System Operating Procedure
Solenoid Operated Valve
TS
Technical Specifications
- UFSAR
VIO Updated Final Safety Analysis Report
Violation
31