ML20197G619
ML20197G619 | |
Person / Time | |
---|---|
Site: | River Bend ![]() |
Issue date: | 12/24/1997 |
From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
To: | |
Shared Package | |
ML20197G599 | List: |
References | |
50-458-97-17, NUDOCS 9712310074 | |
Download: ML20197G619 (19) | |
See also: IR 05000458/1997017
Text
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV -
Docket No.: -50-458
Ucense No.: NPF 47
Report No.: 50-458/97 17
Licensee: Entergy Operations, Inc.
Facility: River Bend Station
Location: 5485 U.S. Highway 61
St. Francisville, Loulslana
Dates: October 12 through November 29,1997
G. D. Replogie, Senior Resident inspector, incoming :
Inspectors:
W. F. Smith, Senior Resident inspector, outgoing
' Approved By: E. E. Collins, Chief, Bra'e.h C 3
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Divisioti of Reactor Projects
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Attachment: Supplementalinformation
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EXECUTIVE SUMMARY
River Eend Station
NRC Inspection Report 50-458/97-17
This inspection included aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a 7 week period of resdent inspection.
QDEah0D3
- The plant startup on October 19,1997, was conducted iri an ordedy manner and in
accordance with proceuural requiren,0nts. The control room supervisor demonstrated
good command and control during the evolution (Section 01.1).
- A nuclear equipment operator misoperated the system. Consequently, the suppression
pool cleanup system was damaged. This condition ultimately resulted in aggravating a
p: ant conductivity excursion. Other contributing factors to the event included inadequate
training, validation of the system operating procedure, and information turnover
processes. A poor questioning attitude and a lack of safety focus on the part of the
nuclear equipment operator were ad htional contributing factors to the event. The
inspectors deter:nined that the licensee's investigation into the conductivity excursion
failed to Mentify the operations related issues (Section 04.1).
- ,9ubsequent to the failure of a containment sir lock overallleak rate test, the operations
shift superintendent (OSS) entered the wrong Technical Specification (TS) ACTION
Statemeht (Section M1.4).
- After the appropriate ACTIGN Statement was enterev ' ir an inoperable air lock,
operators failed to initiate actions to ensure that the os. rall containment leakage rate
(using air lock test results) did not exceed that permitted by TSs (Section M1.4).
Maintenance
- The inspectors r sted multiple instances where maintenance and/or surveillance activities
were delayed or had to be rept sted. The causes for these problems were (1) poor
coordination and preparation for maintenance and/or testing; (2) questionable
understanding of design; (3) a less than expected questioning attitude; or (4) failure to
adhere to procedural requ;rements. This has been noted to be a continuing problem
(Section M1.2).
- Some procedures governing localleak rate testing for containment isolation valves were
inadequate because testing was specified with lift check valves in the air pathway. In
some cases, the test configuration resulted in unacceptably low test pressures, while in
other cases the effects of the test configurations were not known. Corrective actions to
address this finding were coroprehensive (Section M1.3).
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- During local leak rate testing, maintenance technicians failed to vent the leak rate ,
monitor bypass manifolds, as specified by the procedure. This was the second time that
a leak rate monitor bypass manifold venting problem was identified in the past 2-months 3
(S6ction M1.4). .
- Mechanical maintenanca department personnel inappropriately deferred the overall air ,
lock leak rate test until after startup without considering how the use or maintenance of
the air lock could have affected its operability. This was an example of poor change
management, as this responsibility was recently transferred from engineering to
maintenance (Section M1.4),
Plant material condition was generally acceptable. Concems were identified with
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damaged drywell insulation, the inoperable SPC mode of the alternate decay heat
removal (ADHR) system, an inoperable postaccident sampling system, excessive main
generator hydrogen leakage, an inoperable spent fuel cooling pump, and t, degraded
control rod drive (CRD) pump (Section M2.1).
a Magne-blast breakers, associated with the high pressure core spray (HPCS) diesel
generator switchgear, were not refurbished on a periodicity consistent with industry
recommendations. Planned corrective measures were acceptable (Section M8.2).
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Enginitttdag
- The engineering disposition of the residual heat removal (RHR)line break annunciation
under maximum extanded load line allowance (MELLA) conditions was acceptable
(Section E2.1),
Plant Sucoort ,
. Health physics personnel did not meet management expectations because drywell
entries were permitted while the traversing in-core probe system was not danger tagged
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off (Section R1.1).
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Report Details
Summarv of Plant Status
At the beginning of this inspection period, the plant was in Cold Shutdown (Mode 4), nearing
completion of Refueling Outage 7. On October 21,1997, at 6:33 p.m., the main generator was
synchronized to the power grid, signifying the end of the 39-day refueling outage. By
October 25, power was retumed to 100 percent where it essentially remained through the end of
the inspection period.
I.Qgerations
01 Conduct of Operations
01.1 Ettactor Star. tup
a. Insoection Scone (71707)
The inspectors observed the reactor startup to criticahty on October 19.
b. Observations and Findinas
The startup was conducted in an orderly manner and in accordance with procedural
requirements. The control room supervisor demonstratea goo <1 command and control
during the startup. Criticality was achieved consistent with the estimated critical rod
position predicted by reactor engineering.
c. Conclusions on Conduct _of OoeratiQDS
The plant startup was conducted in an orderly manner with the control room supervisor
demonstrating good command and control during the evolution.
02 Operational Status of Facilities and Equipment
02.1 Enoineered Safety Featt.re System Walkdowns (71707)
The inspectors walked down accessible portions of the following
safety-related systems:
- HPOS System
- Diesel Generators 1,2, and HPCS
- RHR System, Trains A and B
+ Containment, including the drywell
- Reactor Core Isolation Cooling (RCIC) System
The systems were found to be properly aligned for the plant conditions and in acceptable
material condition,
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' Prestartup Drywell Walkdown: The inspectors accompanied a reactor operator during :
the performance of the drywell closeout inspection. The operator performed the 1
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inspection in accordance with procedural requirements in a satisfactory manner. The
inspectors noted that the drywell cleanliness was acceptable.' Some minor
items were noted during the walkdown (paint chips and tie wraps), however, the ,
inspectors considered the amount of debris minimal and not sufficient to affect the ;
operability of emergency core cooling systems (ECCSs). The licensee removed the '
identified items prior to startup.
04 Operator Knowledge and Performance t
- 04.1 Nuclear Eauloment Ooerator (NEO) Performance l
a. lasoection Scone (71707)
The inspectors performed a review to determine the causes related to a damaged valve
used in the SPC mode of the ADHR system (SPC AOV 51, SPC backwash valve). The
inspection identified several NEO training and performance issues not previously
addressed by the licensee,
b. ' Observations and Findinas - f
On October 23, an NEO attempted to perform a manual backwash of the SPC filter in
accordance with System Operating Procedure 0140, " Suppression Pool Cleanup and
Alternate Decay Heat Removal," Revicion 3. The NEO was unable to accomplish the
task in accordance with the system operating procedure because Valve SPC-AOV 51 ,
_ (SPC filter to backwash tank outlet valve) was interlocked closed. Instead of stopping
when confronted with an unexpected condition and contacting his supervisor, the NEO
proceeded to open Valve SPC AOV 51 ten different times (each time it immediately
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closed after it opaned) until the backwash was accomplished. After the evolution, a
" backwash tank not dry" alarm occurred, indicating that the backwash tank was not empty
(it should have been empty). The NEO assumed that the alarm was due to an instrument
problem and did not implement Annunciator Procedure AOP SPC-PNL200, Revision 0,
which required the opening of backwash Tank Drain Valve SPC-AOV-79.
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Subsequent to the backwash, Valve SPC-AOV 51 was leaking at a substantial rate.
Furthermore, since Valve SPC-AOV 79 was closed, water flooded the backwash tank,
demister, and portions of the radwaste ventilation system ducting. This problem was not
identified until operatois attempted to operate the radwaste ventilation system in support
of a reac'or water cleanup (RWCU) demineralizer backwash on October 24. The
, ventilation system repeatedly tripped off, on high vacuum, and delayed replenishment of
the A RWCU demineralizer. This delay aggravated a reactor vessel conductivity
excursion, with conductivity peaking at approximately 8 uS/cm (normal conductivity is less
than 1 uS/cm).
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The inspector considered the following to be contributors to the events:
- The NEO had not been given hands-on training prior to being asked to operate the
system. Whe the NEO had completed the classroom portion of the training, the
'nds-on training was not conducted until October 27,4 days after the NEO
atiempted the backwash.
- The system operating procedure was not appropriately validated before it was
provided to the operations department for use.
- A condition report (CR) concerning the problem with the procedure
(Valve SPC AOV 51 interlocked closed) was written 5 days prior to the
NEO's attempt at a backwash, but the NEO was not provided this information
during shift tumovers. Additionally, the licensee had no process in place to ensure
that the NEO would have become aware of the problem prior to attempting a
backwash.
- The NEO did net stop when he found tha' he couldn't proceed in accordance with
the procedural requirements. His decision to continue was in direct conflict with
his training and demonstrated a poor questioning attitude and safety focus.
. The NEO mistakenly assumed that the " backwash tank not dry" alarm was caused
by an instrument problem and did not follow the requirements of the annunciator
procedure.
The licensee had also investigated the event, but focussed only on the adequacy of the
system operating procedure and on making repairs to Valve SPC-AOV-51. The NEO's
actions were not specifically addressed. Furthermore, prior to the inspectors questioning
the NEO's actions, late in the report period, Operations management was unaware of the
NEO's contribution to the valve failure.
Since the SPC mode of the ADHR system is not safety related, ro violation of NRC
requirements occurred. However, the inspectors had concerns with the performance of
operations with respect to procedure compliance, adequacy of training, and procedure
validation,
c. Conclusions
An NEO misoperated the SPC system. His actions resulted in damage to a system valve
adversely affecting the SPC mode of the ADHR system and aggravating a plant
conductivity excursion. Other contributors to the event included inadequate training,
inadequate validation of the system operating procedure, inadequate information turnover
processes, and a poor questioning attitude and safety focus on the part of the NEO.
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ll, Maintenance
M1 = Conduct of Maintenance
- M1,1 General Comments
a. Inmaaction Se (61726. 62707)
The inspectors observed portions of the following maintenance and surveillanos activities
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+ .-. STP 110-0101, " Turbine Overspeed Protection System Operability Test"
-+ . mal 314541, " Containment Air lock Door Equaliang Valve Repairs"
+. . STP-057 3704, " Primary Containment Air Locks Overall Leakage Rate Test"
+ STPs 209-3807,' 209-3818,200 3854, and 403 7301, various localleak rate tests
(LLRTs)(documentation review). .,
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- STP-050-0702i" Refueling Outage Reactor Pressure Vessel inservice Leakage
Test "(documentation review) _
+ STP-309 0602, " Division ll ECCS Testing"
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+ STP-204 4802,"RHP System Isolation Logic System Functional Test,"
(documentation review)
+ . OSP-0501, " Turbine Testing," (documentation review)
+ SOP 0140, " Suppression Pool Cleanup and Altemate Decay Heat Removal,"
(documentation review)
+ STP-209 6310, "RCIC Quarterly Pump and Valve Operability Test,"
- (documentation review)
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+ STP 203-6305,'*HPCS Quarterly Pump and Valve Operability Test,"
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' Maintenance and surveillance implernentation and coordination problems are discussed
- in Section M1.2, Adstionally, local leak rate testing issues are addressed in Sections
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M1,3 and M1,4.10perational problems associated with the HPCS system mirimum flow
valve are documented in Section M1.5.
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M1.2 Assessment of Outage Maintenance and Surveillance Activities
a. Insoection Scope (61726)
The inspectors performed an assessment of the maintenance and surveillance activities
_ performed during the outage and startup.
b. - Observations and Findings
During the outage, the inspectors noted multiple instances where maintenance and/or
surveillance activities were interrupted, delayed, or had to be repeated due to: (1) poef
coordination and preparation for maintenance and testing; (2) questionable understanding
of design; (3) a less than expected questioning attitude; and (4) failure to adhero to
procedural requirements. Examples are provided below:
- While establishing initial test conditions for Procedure STP 050-0702, " Refueling
Outage Reactor Pressure Vessel inservice Leakage Test," Revision 1, operators
experiencr'd two problems. First, operators were having difficulty achieving
the specified test temperature in the reactor vessel head. Through further
investigation, the licensee found that much of the head insulating material had not
yet been instailed. After the insulation material was installed, the correct head
temperature was achieved. Second, operators were not able to establish letdown
flow through the RWCU system because a downstream valve (Valve DTM V 279,
a manual letdown isolation valve) was tagged in the closed position for
maintenance. When initially attempting to establish letdown, Relief
Valve G33-RV036 lifted due to condensate piping system pressure. Operators
- rerouted the letdown to the radwaste system until an appropriate relief pathway
was established.
Revision 12 (ECCS/ Loss of Power / Loss of Coolant Accident Test Initiation), an
instrument and controls technician failed to reposition two undervoltage test
switches in accordance with the procedural requirements. The procedure required
the test switches to be opened (which was accomplished) and then immediately
reclosed (which was not accomplished). Consequently, loads did no! sequence
onto the diesel generator and the test had to be reperformed. in response to the
failed test, the licensee identified that the technician did not have the procedure
with him during the test (and did not remember the appropriate sequence of test
switch manipulations).
As corrective measures, the licensee, in part: (1) counseled the technician
regarding the requirement to have procedures in-hand during the performance of
surveillance; (2) reinforced the proper use of procedures with all site personnel;
and (3) counseled the ECCS test director concerning the importance of discussing
key steps during pretost briefs. The corrective measures were acceptable. The
failure to perform the surveillance in accordance with the procedural requirements
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was a violation of TS 5.4.1.a. which requires the licensee to implement procedures
recommended by Appendix A of Regulatory Guide 1.33. The Regulatory Guide
recommends procedures for surveillance testing. However, this nonrepetitive,
licensee identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of the "NRC Enforcement Policy "
. (NCV 50-458/9717-01).
Functional Test," Revision 7, which, in part, ensured that certain containment -
isolation valves would isolate upon initiation of a test signal, two containment
isolation valves in the ADHR system unexpectedly isolated (Valves RHS AOV 63
and RHS AOV 64). These containment isolation valves were part of the ADHR
system modification that was recently made operational. The licensee later
determined that the valves operated as designed but the pro:.edure had not
appropriately included the valves within the scope of testing. The steps necessary
to test the valves had been inappropriately included in Procedure STP 309 0602,
" Division ll ECCS Testing " which was not the appropriate procedure for these
particular tests; At the conclusion of the report period, the licensee had not
determined the root cause of the procedural oversights. This is considered an
unresolved item penjing further NRC review of the licensee's root cause
evaluation (URI 50-458/9717 02).
. While establishing initial conditions for Procedure OSP 0501, " Turbine Testing,"
- Revision 40, operators reported difficulty achieving the required test conditions
(Iow pressure turbine exhaust temperature of at least 100'F). The test was
delayed for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before a waiver to the requirement was
obtained from General Electric. This was considered an example of poor planning
because the came problem occurred during Refueling Outage 6.
- When an operator repositioned to open the RCIC injection valve during stroke
time testing, the valve automatically repositioned closed, which surprised the
operator. The RCIC valve had operated as designed (isolate on high reactor
water level) but the operator was not aware that plant conditions would cause this
to occur during the test.
Additionally, during the previous inspection report period, the inspectors had noted other
problems that were also attributable to similar performance deficiencies as provided
below:
- - Scram time testing of control rods was performed with a 1/2 scram signalin. At
the time of the testing, operators did not consider, or question, the effect of the
1/2 scram signal on the test. After testing was compW, the licensee determined
that the testing was invalid and would have to be reperformed (See NRC
Inspection Report 50-458/9714).
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- Engineering and operations personnel failed to consider information on the " time
to aci!" curves when performing initial testing of the ADHR system Additionally,
several of the procedures were found to be inadequate. As a result, Operational
Mode 3 was inadvertently entered while several TG limited condition of operation
(LCOs) were not met (See NRC inspection Report 50-458/97-15).
- Operatins inappropriately re-energized the breaker for Valve RHR-V 9, (while
performing a breaker alignment in accordance with an approved breaker
alignment sheet). As a result, shutdown cooling was inadvertently secured when
the valve automatically repositioned to the closed position (See NRC Inspection
Report 50-458/9715).
c. C.G[usions
c The inspectors noted multiple instances where maintenance and surve91ance activities
were interrupted, delayed, or had to be repeated due to: (1) poor coordination and
preparation for maintennce ano testing; (2) questionable, inderstanding of design; (3) a
less than expected questioning cttitude; and (4) failure b adhere to procedural
ree:virements. One noncited violation was identified for the failure to follow ECC9 '*st
proceduren. One unresolved item was opened addressing ths unexpected, but
appropriate, isolation of two ADHR valves during containment isolation valve tt. u 3
M1.3 LLRTs
a. Innection Scoce (61726)
The inspectors performed a review of the licensee identified findir.g that certain LLRTs
may have been invalid due to an ineppropriate test configuration.
b. Observations and Ein@gs
As documenteo in CR 97-1727, da%d October 3,1997, the licensee identified that a Lift
Check Valve E12 VF061 was in the test pathway for Valve E5 eMOV-F013,"RCIC
Inbetion Valve and Containment Isolation Valve." Further investigation identified that
similar test configurations were also utlized for Valve G51-MOV-F077, "RCIC Steam
Line Evhaust to Suppression Puol isolation Valve," and Valve 1E51-MOV-F019,
" Minimum Flow Line Return to Suppression Pool." The test consguratii n was of potential
concern because the resultant differential pressure (dp) drop across t"e check valves
could result in unacceptably Icw test pressures at the valve seats (potentially reducing the
pressure at the valves to less tbm P ,7.6 psig).
The licensee a,sa identified that Valves E51-MOV-F077 and E51 MOV-F019 were
incorrectly tested during the last six refueling cutages while Vat e E51-MOV-F013 had
been incorrectly tested during the previous two outages. !n oice; to assess the validity of
some of the previous tests, the licensee performed testing to determine the cctual loss
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- across the check valves For Valve 1E51 MOV-F077, the dp across the check valves
(two in this case) was approximately 3.4 psig. As such, the test pressure at
the valve was only 4.6 psig, which was unacceptable. The actual test pressure at
Valves 1E51-MOV-F013 and E51-MOV-F019 could not be determined, so the licensee
consideted previous tests invalid The cause of the deficient procedural guidance was
determined to be inadequate technical knowledge on the part of procedure writers,
reviewers, and test engineers.
In response to the findings, the licenke changed the test procedures to specify a more
appropriate test pathway for the affected valves. Addnionally, the tests were reperformed,
where necessary, and all valves were found to have acceptable leakage rates. Finally,
procedure writers, reviewers, and test engineers invalved with LLRTs were appropriately
sensitized to the identified problems.
The inspectors considered the licensee's corrective measures to address CR 97-1727 to
be acceptable but noted that a similar issue was identified previously. Specifically, on
July 22,1997, with tne plant at 100 percent power, the licensee identified that the test
configuration for Valves HVR AOV-123 and HVR-AOV-165 included a lift check valve in
e the test pathway, in response to that finding, the licensee reperformed the LLRTs in an
z. appropriate manner end found leakage to be acceptable. Additionally, tests were
JC conducted to determine the actual dp across the suspect check valve. The dp across the
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check valve was sufficieritly low so that the previous test remained valid. Finally, the
i licensee performed a cognitive review of valve line-ups for approximately 50 percent of
the containment isolation valve t LRTs. Based on the results of the sample, the licensee
had concluded tnat r,o similar problems existed. ,
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Although the licensee had not performed a comorehensive review of all of the LRT
procedures after initially finding an inappropriate test configuraticn on July 22,1997, the
inspectors considered the licensee's review and corrective measures to be reasonable at
the time. Additionally, the licensee maintained an awareness of tae potential problem and
continued to scrutinize tests as they were peiformed. When additional problems of the
sarne nature were found, the licensee appropriately expanded the scope of the corrective
actions and effectively addressed the problem. The time delay between the initial finding
and subsequent findings was considered minimal and, overall, corrective actions were
acceptable,
The procedures associatad with the above tests were considered inadequate, as they
specified testing in an inappropriate test configuration. This was considered a violation of
TS 5.4.1, which requires the licensee to have and implement procedures for all programs
specified in TS 5.5. TS 5.5.13 requires the licensee to have a " Primary Containment
Leakage Rcte Testing Program." However, this licensee-identified eld corrected violation
is being treated as a noncited violation, consistent with Section Vll.B.1 cr the "NRC
Enforcement Policy,"(NCV 50-458/9717-03).
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c. Conclusions
A noncited violation regarding inadequate LLRT procedures was identified. The
corrective measures to address the problems were acceptable.
M1.4 C&Dlainment Air Lock Reoairs and Testino
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a iticection Scoce (62707)
The inspectors observed the repr end postmaintenance test of the 113-foot elevation
(lower) primarj containment air ' ,k outer door equalizing valves.
b. Qbiervations and Findincs
Backgrouno: On October 30,1997, the licenseo performed the iower containment air
lock overall leakage test pursuant to TS Surveillance Requirement (SR) 3.6.1.2.1 and in
accordance with the licensee's primary containment leakage rate testing program. The
results were unsatisfactory to the extent that the leakage exceeded the acceptance
criteria and the capacity of the leak rate monitor (LRM). The control room operators wera
notified of the test failure and were also informed that the equalizer valves in the outer
door were leaking. The OSS declared the outer door inoperable and entered
TS ACTION 3.6.1.2.A, which required the operable (inner) door to be verified closed
in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and locked within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Failure to Enter Appropriate TS ACTION Statement: The inspectors identified that the
OSS had entered tha wrong T3 ACTION Statem.nt. Specifically, TS SR 3.0.1 states,
" failure to meet c Surveillance, whether such failure is experienced during the
performance of the SurveiMance or between performances of the Surveillance, shall La
failure to meet the LCO . " In this case, the surveillance for the entire air lock had failed
(not just the door) Therefore, the licensee was required to declare the LCO associated
with the air lock not met, which required entry into TS ACTION 3.6.1.2.C. Although the
inspector acknowledged that at least one known leak through one door was identi'ied, the
licensee had not demonstrated that no other leaks were present. The licensee agreed ,
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with the inspectors' assessment and entered the appropriate ACTION Statement.
Failure to Complete All Required TS ACTIONS: During subsequent reviews, thd
inspectors identified that after the licensee entered ACTION Statement 3.6.1.2.c, they
failed to comply with TS ACTION 3.6.1.2.C.1, which required the licensee to immerh tely
initiate action to evaluate primary containment overallieakage rate per TS LCO 3.6.1.1,
using current air lock test results. Although the OSS called engineering to inquire about
such an evaluation, no efforts were made to quantify leakage so that the evaluation could
be performed. The faiiure to implement all of the actions required by TS LCO 3.6.1.2.C
was a violation of TSs (VIO 50-458/9717 C4).
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Melntenance: Later on October 30, the inspectors observed mechanical maintenance
personnel replacing the inte.rnals on the outer door equalizing ball valves in accordance
with Frocedure MAI 314541. The inst.ectors examined the old balls and seats removed
from the valves and noted heavy scoring from dust and grit, which explained the leakage.
Postmaintenance Testing: The inspectors observed the postmaintenance test for the
repair work, conducted in accordance with Surveillance Test Procedure STP-057-3704,
" Primary Containment Air Locks Overall Leakage Rate Test," Revision 9, Section 7.1.5.
This section of the procedure leak tested the air lock door equalizer valves.
The inspectors ider.lified that the LRM bypass manifold w&s not vented in accordance
with Procedure STP-057-3704, Attachment 17. The bypass manifold was installed to
expedite pressurization of the overail air lock volume but was required to be isolated and
vented during the LLRT to ensure that potentialleakage past the manifold isolation valves
would not affect the test in a nonconservative manner. The inspector noted that the
bypass manifold was isolated but not vented. In response to the inspectors' concern, the
maintenance mechanics vented the bypass manifold. The inspectors had intervened
prior to the taking of test data, so valid test results were assured.
This was tho second time over a 2 month period where the LRM Lypass was not
appropriately vented dur9 leak rate testing. NRC Inspection Report 50-458/97-14
discussed a similar prob, where an LRM bypass manifold did not have a vent. The
establishment of the bypass manifold vent was considered skill of the craft, so no
procedural instructions were provided at that time, in the instance identified in the current
report, mechanics had adequate instructions but failed to vent the manifold properly.
Deferral of Surveillance: The inspectors identified that mechanical maintenance
personnel inappropriately deferred the overall air lock bak rate test until after startup ,
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without first considering possible use or maintenance that could have affected air lock
operability. Technical Requiremants Manual TSR 3.6.1.2.1.b requires the overall air lock
leak rate test to be performed every 30-months and " . prior to entry into Modes 2 or 3
from Mode 4 when the air lock has been used or maintenance has been performed that
could affect air lock sealing capability." The licensee had originally scheduled this
surveillance to be performed during Refueling Outage 7, which ended on October 21.
Mechanical maintenance personnel deferrsd the test after startup based on the frequency
requiren ent alone and failed to consider uss or maintenance that could have affected
operability,
l.1 response to the inspectors' concern, the licensee reviewed the use and maintenance
history for the air lock and determined that deferral of the surveiliance would have been
acceptable. Nonetheless, the licenses acknowledged that the personnelin question did
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not have an appropriate understanding of requirements prior to deferring the airlock leak
rate test. Additionally, the responsibility for the surveillance was recently transferred from
enginesing to maint3 nance and personnel involved had not effectively managed this I
change in ownership.
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c. Conclusiom
Subsequern to the failure of a containment air lock overall leak rate test, the OSS entered
the wrong TS ACTION Statement. The OSS an.ered the ACTION Statement for an
inoperable air lock door when he should have entered the ACTION Statement for an
inoperable air lock.
After the appropriate ACTION Statement was entered for an inoperable air lock, operators
failed to initiate action to ensure that the overall containment leakage rcte (usina air lock
test results) did not exceed that permitted by TSs. The failure to initiate this action was a
violation of TS 3.6.1.2.C.1.
Mechanical maintenance personnel inappropriately deferred the overall air lock leak rate
test until after startup without first considering possible use or maintenance that could
have affected air lock operability. This was an example of poor change managemen' as
this responsibility was mcently transferred from engineering to maintenance.
Maintenance technicians failed to vent the LRM bypass manifolds during local leak rate
testing. This is the second time in the past 2-months that a LRM bypass manifold venting
problem was identified (Section M1.2).
M1.5 HPCS Inservice Testing: During the performance of Procedure STP 203-6305,"HPCS
Quarterly Pump and Valve Operability Test," Revision 6, the HPCS Minimum Flow Valve
E22-MOV F012 unexpectedly closed when the suction was swapped from the
suppression pool to the ccodensate storage tank. Additionally, later in the curvel!!ance,
the valve failed to open when the test return valve was closed (dead heading de HPCS
pump). In response to the anomalous operation of the minimum flow valve, orierators
declared HPCS inoperable and entered the appropriate TS ACTION Stater v
While troubleshooting, maintenance personnel found air in the instrument lines to Flow
Transmitter E22-FAN-056. Engineering determined that air in the lines caused the
malfunction of the valve but had not determined the cause of the air intrusion into the
instrument lines by the close of the inspection period. The inspectors reviewed the
maintenance history for the flow transmi ter and noted that it was replaced in May 1997.
Just prior to that work, the minimum flow valve had failed to open during testing. This is
considered an unresolved item pending further NRC review of the licensee's root cause
evaluation (URI 50-458/9717-05).
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M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Review of Material Condition Durino Plant Tours
a. Inspechon Scoce (62707)
During this inspection period, the inspectors conducted routine plant tours to evaluate
plant material condition.
b. Observations and FindD23
- Drywell Insulation: During a prestartup walkdown of tne drywell, the inspectors
noted that some of the metalinsulation covers were in poor material condition. In
some cases, the cover fasteners were missing while in other cases the covers
were badly deformed. The material condition of the insulation covers v;as a
concem because, during a loss of coolant accident, the covers help to keep the
insulation in place and out of the suppression pool. The inspectors discussed this
observation with plant engineering and was informed that some of the feedwater
and main steam piping insulating material (including covers) was replaced during
Refueling Outage 7 and additional work was planned for future outages. The
inspecters considered the licensee's planned corrective measures to be
acceptable.
- CRD Pump 14: CRD Pump 1 A was experiencing higher than normal vibration,
which was believed to be caused by a damaged coupling. The licensee
considered the pump degraded but operable and maintained the pump in a
standby status. The pump may be utili' zed during emergency operating procedure
implementation for manual control rod movement and as a backup source of
primary coolant.
- Main Generator tiydrogen Leakage: Main generator hydrogen leakage was
approximately four times normal. The identified leakage pathway was through the
collector end generator seal ad out the roof vent (the normal hydrogen vent for
the system). A worsening of this condition could require a plant shutdown to
support repairs. The licensee planned to replace the seal during the next outage.
+ Postaccident Sampling Sgtem (PASS): The PASS was found inoperable on
November 12,1997, when two system fuseu view during a surveillance. Repairs
on the system were not complete at the close of the inspection period.
-
Spent Fuel Pool Cooling (SFC) Pump 18: SFC Pump 1B was repaired recently
(new impeller) but during testing a sealleak was found. The pump remained in a
degraded condition until replacement parts could be ordered and installed. This
pump remained inoperable, but available, pending completion of the repairs.
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- ADHR, SPC Mode: The SPC mode of ADHR was rendered inoperable when an
NEO inappropriately operated the system and damaged a backwash valve. The
loss of SPC was of concern because suspended material and biological growth
from the suppression poc! has caused significant fauling in the RHR heat
exchangers.
c. Conclumond
Plant material condition was generally acceptable. The inspectors noted material
condition concerns with drywellinsulation, the SPC mode of ADHR, the PASS, main
generator hydrogen leakage, SFC Pump 1B, and CRD Pump 18.
M8 Miscellaneous Maintenance issues (92700)
M8.1 (Closed) Licensee Event Reoort (LER) 50-458/97-009: " . . inadequate pressure test
performances due to pressurizing through check valves." The issues contained in this
LER are discussed in Section M1.3 of this report. This LER is cbsed based on those
inspection efforts.
MS.2 Maane-Blast Breaker Refurbishment: The insp6ctor noted that three of the five
4160 Volt breakers in the HPCS switchgear had not been refurbished since initial plant
startup and had been in service approximately 13 years. This practice was inconsistent
with guidance from the Electrical Power Research Institute, whicn indicated that the
breakers should be refurbished, at most every 12 years. The licensee had planned to
refurbish the three subject breakers over the next 9 to 12 months.
lit f.ngine.edag
E2 Engineering Support of Facliities and Equipment
E2.1 EHR A Line Break Alarm Failed to Clear Durina and After Startuo
a. Insoection Scoce (37551,
The inspectors reviewed the engineering resolution of CR 97-1915, which identified the
control room annunciation of a " Division I RHR system ' . operative alarm" coincident with
an *RHR A line break" status light.
b. Observations and Findinas
On October 25,1997, while operating the plant for the first time in accordance with
MELLA conditions, the control room alarm for " Division l RHR system inoperative"
annunciated coincident with the "RHR A line break detected" status light. This alarm was
unexpected and was provided to inform operators of a potential RHR A or low pressure
core spray line break. Operators verified that line break conditions did not ex.st, but the
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alarm remained sealed in for several days. Eventually, with power stable at 100 peicent >
and core flow at 88 percent, the alarm cleared.
Engineering evaluated the annunciator problem and determined that the change in steam
quality in the reactor vessel (caused by the recen~'y initiated MELLA operating conditions)
.
affected the density of water ;.1 the subject instrument lines sufficiently to bring in the
alarm. The licensee noted that, historicalh', during plant startups (at less than
100 percent power), the alarm normally comes in for similar reasons. The alarm setpoint
is consistent with the steaoy state full power / full flow conditions (but not MELLA
,
conditions). The inspectors consulted vith experts in the Office of Nuclear Reactor
Regulation and determined that the licensee's conclusions were credible and well
- supported.
At the close of the inspection period, the licensee had not developed the corrective
actions necessary to ensure that the subject annunciators would continue to provide
meaningful indications under both MELLA and non-MELLA operating conditions.
However, the licensee did not expect further false indications from the annunciators for
the remainder of the operating cycle.
c. Conclusions
The inspectors concluded that the engineering disposition of the RHR line break
annunciation under MELLA conditions was acceptable.
IV. Plant Suonort
R1 Radiological Prostion and Chemistry Controls
R1.1 Radiological Controls Associated with the Traversing incore Probe (TIP) System
a. Insoection Scooe (71750)
The inspectors reviewed compliance with radiological controls associated with the TIP
system,
b. Observations and Findings
Upon exiting the drywell on October 17,1997, the inspectors observed that the TIP i
system was secured but was not danger tagged. The inspectors questioned the lack of
danger tags because Procedure RSP-0212 "Drywell Entry," states, "The Traversing
incore Probe Drive System should be tagged out with the TIPS stored in the Lower
Plenum or in the Reactor Vessel for all entries into the dn/well." The radiation protection
personnel were responsible for proper implementation of Procedure RSP-0212.
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Additionally, the procedural recommendation was annotated as being responsive to
concerns identified in NRC Information Notice (lN) 88-63, "High Radiation Hazards from
Irradiated incore Detectors and Cables." NRC IN 88-63 discussed severalinstances
where inadequate TIP system controls resulted in several over-exposure events at other
facilities.
The licensee agreed with the inspectors observation and determined that health physics
personnel had mistakenly come to believe that this management expectation only applied
to initial drywell entries, in response to the finding, the licensee briefed appropriate health
physics personne' regarding the appropriate interpretation of Procedure RSP-0212. The
licensee further stated, however, that tagging the TIPS out of service for all drywell entries
was overly restrictive and that the controls would be revised. The issues discussed in
NRC IN 88-63 would be properly considered when the new contrals were developed.
c. Conclusions
The inspectors identified that health physics personnel did not meet management
expectations with regard to ensuring that the TIP system was danger tagged off when
drywell entries were made.
V. Management Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on December 1,1997. The licensee acknowledged the findings
presentad.
The inspectors asked the licensee w' n'her any materials examined during the inspection should
be considered proprietary. No prnpr etary information was identified.
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AIJACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensen
J. P. Dimmette, General Manage, Plant Operations
M. A. Dietrich, Director, Quality Programs
D. T. Dormedy, Manager, Svstem Engineering
T. O. Hildebrandt, Manager, Maintenance
J. Holmes, Superirtendent, Chemistry
H B. Hutenens, Sgerintendent, Plant Security
D. N. Lorfing, Supervisor, Licensing .
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J. R. McGaha, Vice President Operations
M. G. McHugh, Licensing Engineer lil
W. P. O'Malley, Manager, Operations
D. L. Pace, Director, Design Engineering
A. D. Wells, Superintendent, Radiation Control
INSPECTION PROCEDURES USED
IP 37551: Onsite Engiaeering
IP G1726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support
P 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
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s lTEMS OPENED AND CLOSED : - --
QNtoed
50 4 58/9717-01- NCV : Failure to Follow ECCS Test Procedure
50-458/9717-02 URI -- Uneyected Isolation of ADHR Valves
50-458/9717-03 .NCV inadequate LLRT Prxedures:
.50-458/9717-04-
VIO Failure to Comply with TS ACTION 3.6.1.2.C.1 after Air Lock -
Surveillance Failure
,.
[50-458/9717-05- URI -Air in HPCS Instrument Line Causes SuNeillance Failure
Closed
-50-458/9717 01 'NCV Failure to Follow ECCS Test Procedure
50-458/9717-03 -NCV Inadequate LLRT Procedures
'50-458/97-009: LER Inadequate Pressure Test Performances due to Pressurizing
_
Through Chack Valvas
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LIST OF ACRONYMS USED
ADHR alternate decay heat removal
CR condition report
CRD: control rod drive
differential pressure
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ECCS- emergency core cooling system
-HPCS high pressure core spray i
IN - - Information Notice --
,LCO- limited conditio_n of operation
4 LER -- : licensee event report.
LLRT' localleak rate test
LRM: <
leak rate monitor
- MELLA L maximum extended load line allowance
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sNCV' Noncited violation ~
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NEO" Nuclear Equipment Operator :
U.S Nuclear Regulatory Commission
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NRC- =
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3. - operations shift superintendent 4
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,JPASS)
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postaccident sampling system
1RCIC f reactor _ core isolatwn cooling 4
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residual heat ramoval
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SFC spent fuel cooling
SPC suppression pool cleanup
SR surveillance requirement
TIP traversing in-core probe
TS Technical Specifications
URI unresolved item
RBS River Bend Station
VIO violation
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