ML20207J529
| ML20207J529 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 07/23/1986 |
| From: | Bundy H, Constable G, Luehman J, Staker T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20207J480 | List: |
| References | |
| 50-382-86-13, IEB-85-001, IEB-85-1, NUDOCS 8607290154 | |
| Download: ML20207J529 (13) | |
See also: IR 05000382/1986013
Text
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APPENDIX C
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-382/86-13
License:
Docket:
50-382
Licensee:
Louisiana Power & Light Company (LP&L)
317 Baronne Street
P. O. Box 60340
New Orleans, Louisiana 70160
Facility Name: Waterford Steam Electric Station, Unit 3 (W3 SES)
Inspection At:
Taft, Louisiana
Inspection Conducted: June 1-30, 1986
Inspectors:
MY
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J. G. Luehman, Senior Resident Inspector
Date
WY
7/M/TC
' ate
. R. Staker, Resi' dent Inspector
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7/M/tf
H. F. Bundy, Projecf Inspector, Project
Date
Section C, Reactor Projects Branch
(Pa,ragraphs 5, 6, 7, 8, and 9)
Approved:
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$.L. Constable, Chief, Project Section C,
D ate'
\\Reacdor Projects Branch
Inspection Summary
Inspection Conducted June 1-30, 1986 (Report 50-332/86-13)
Areas Inspected:
Routine, unannounced inspection of:
(1) Plant Status,
(2) Licensee Event Report (LER) Followup, (3) Monthly Surveillance, (4) Routine
Inspection, (5) Licensee Followup on Previously Identified items, (6) Monthly
Maintenance, (7) Potential Generic Problems, (8) License Conditions, and (9) IE
Bulletins.
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Results: Withintheareasinspected,twoviolations(failuretopreplanand
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perform station modifications in accordance with written procedures,
paragraph 6, and failure to take prompt corrective action, paragraph 8) and one
deviation (failure to fully implement commitments made in response to IE
Bulletin 85-01, paragraph 11)'were identified.
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DETAILS
1.
Persons Contacted
Principal Licensee Employees
G. W. Muench, Director, Nuclear Operations
- R. P. Barkhurst, Plant Manager, Nuclear
T. F. Gerrets, Corporate QA Manager
S. A. Alleman, Assistant Plant Manager, Plant Technical Services
- N: S. Carns, Assistant Plant Manager, Nuclear, Operations and Maintenance
J. N. Woods, QC Manager
A. S. Lockhart, Site Quality Manager
R. F. Burski, Engineering and Nuclear Safety Manager
K. L. Brewster. Onsite Licensing Engineer
G. E. Wuller, Onsite Licensing Coordinator
T. H. Smith, Maintenance Superintendent, Nuclear
- P. V. Prasankumar, Technical Support Superintendent
- Present at exit interviews.
In addition to the above personnel, the NRC inspectors held discussions
with various operations, engineering, technical support, maintenance, and
administrative members of the licensee's staff.
2.
Unresolved /Open Items
An unresolved item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or deviation.
No new unresolved items were identified during this inspection but two
previous items are discussed in paragraph 7.
3.
Plant Status
The inspection period began with the plant at full power. At 6:29 p.m.
(CDT) on June 5, 1986, with the plant at 100% power, a loss of the turbine
closed cooling water (TCCW) system occurred.
Immediately upon losing the
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system, the reactor operator began a turbine load reduction while attempts
were made to restore level in the system and restart the TCCW pumps.
Subsequently, the 0 TCCW Heat Exchanger was taken out of service due to
suspected tube leakage and the TCCW system was restarted using only the A
TCCW Heat Exchanger. At 9:09 p.m. the plant was stabilized at 60% power.
The licensee plugged seven tubes in the B TCCW Heat Exchanger. After the
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B Heat Exchanger was returned to service, the A Heat Exchanger was opened
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and inspected. With both heat exchangers back in service the plant began
the return to full power on the afternoon of June 6,1986.
At 10:28 p.m. on June 27, 1986, a plant power reduction from 100% power
was commenced due to concerns with the trends of various parameters on
the reactor coolant pumps.
Power was stabilized at about 70% and, on the
morning of June 28, 1986, licensee management decided that a slow return
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to full power could be accommodated.
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At 11:41 a.m. (CDT) on June 30, 1986, with the plant again at 100% power,
a reactor trip occurred and the plant responded normally.
LO-DNBR reactor
trip signals were received on the Core Protection Calculator (CPC)
Channels. The cause of the signals was apparently faulty reed switch
position indication from Control Element Assembly (CEA) 35 on Control
Element Assembly Calculator (CEAC) 1.
No violations or deviations were identified.
4.
Licensee Event Report (LER) Followup
The following LERs were reviewed and closed.
The NRC inspectors verified
that reporting requirements had been met, that causes had been identified,
that corrective actions appeared appropriate, that generic applicability
had been considered, and that the LER forms were complete. Additionally,
the NRC inspectors confirmed that no unreviewed safety questions were
involved and that violations of regulations or Technical Specification (TS)
conditions had been identified.
(Closed) LER 50-382/85-10, Automatic Actuation of the Reactor Protection
System. The licensee has completed all corrective actions including
Station Modification 814, revision of OP-3-031 and upgrading of OP-10-001
and OP-100-010.
(Closed) LER 50-382/86-02, Reactor Trip Due to Dropped CEA Number 88 and
Failure of Blowdown Isolation Valves to Close. The licensee has hung a
chain and sign across the entrance to the control element drive mechanism
control system (CEDMCS) area in order to reduce the possibilities of
future inadvertent operation of switches on controls by restricting area
access.
As short term corrective action for the problem with the blowdown isolation
valves, the licensee issued an instruction to operations personnel about
the event. The NRC inspector verified the long term corrective action was
taken by verifying OP-3-010, " Steam Generator Blowdown" had been changed to
ensure that proper removal of the gags is accomplished.
This change was
made to Sections 6.3, " Routine Processing of Steam Generator Blowdown";
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6.16, " Operation of Blowdown System with Steam Generator Tube Leakage or
Tube Rupture"; and 6.7, " Operation of Blowdown System with Main Condenser
Unavailable" of OP-3-010. Additionally, caution labels have been placed on
the valves to alert the operator to the valve gagging device.
(Closed) LER 50-382/86-06, Insufficient Tracking of Surveillance Resulted
in Mode Change Without Performing Surveillance on the Boric Acid Makeup
Tank. The chemistry technician who attempted to perform the sample on
March 17, 1986, made an error when he placed the surveillance notice back
in the file so that it would be performed on the normally scheduled day of
the following week. This led the person reviewing surveillances for the
mode change to assume all requirements had been met.
In order to ensure
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that future incomplete surveillances are carried over on a day-to-day
basis the chemistry supervisor has issued instructions to that effect in a
memorandum dated April 29, 1986. Additionally, in order to minimize the
probability of missing one of the many conditional surveillance require-
ments prior to a future mode change, Chemistry Department Standing
Instruction 17. "Startup Mode Change Check Sheet," has been issued.
(Closed) LER 382/86-09, Reed Switch Failure Results in Reactor Trip on Low
Departure from Nucleate Boiling Ratio.
The NRC inspector reviewed this
report and found that it adequately covers the event time frame chosen by
the licensee.
However, the report omits any description of the sequence
of CPC pretrips, and subsequent operator actions to determine their cause,
that occurred in the 20 minutes prior to receiving the reactor trip signals
on two channels at 2028. Additionally, the report fails to accurately
describe the generation of the CPC penalty factors.
If, as the report implied, position deviation was the only input to the
penalty factor generation, then the plant should have tripped the first
time the faulty reed switch ' closed.
But, penalty factors generated for a
given CEA are actually dependent on which CEA is deviating, how large the
deviation is, and how long the deviation exists.
In this report, the CEA
in question was a part-length CEA with one faulty reed switch position
indicator.
Each time the reed switch spuriously closed, a penalty factor
was generated and the longer the switch closed the larger the penalty
factor became.
Reactor trip signals finally occurred when the faulty reed
switch remained closed long enough for the penalty factors to increase
encJgh to generate not only the pretrips seen earlier in the event, but
the reactor trip signals first seen at 2028.
The NRC inspector's
observations were discussed with licensee management.
No violations or deviations were identified.
5.
Monthly Surveillance
The NRC inspectors observed / reviewed TS required testing and verified
that testing was performed in accordance with adequate procedures, that
test instrumentation was calibrated, that limiting conditions for operation
(LCO) were met, and that any deficiencies identified were properly reviewed
and resolved.
On June 23, 1986, the NRC inspector witnessed the performance of portions
of Procedure NE-2-002, Revision 2, " Variable Tavg Test."
This test was
conducted to meet the requirements of TS Surveillance 4.1.1.3.2.c.
A note
at the beginning of the procedure actio., steps advised the test engineer
that the load rate-of-change should be 2J0 MW/ min. for best results
(consistent with saf2 operating practice). At the start of the test there
was some discussion between plant operations personnel and the test
engineer as to the rate that would be used.
The operations personnel
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informed the test engineer that load changes would be performed at rates
substantially lower than he requested.
(The NRC inspector noted rates-of-
change from 0.3-6.0 MW/ min. used during the test.)
Discussions between the NRC inspector and operations personnel, including
the operations superintendent, revealed that the licensee would rarely, if
ever, conduct this test at the high rate-of-change recommended. Based on
that information, the NRC inspector recommended that the procedure be
changed to include a lower target load rate-of-change if such a lower rate
would not significantly impact the test results.
Such a change would
probably reduce future discussion and delays.
Additionally, during this inspection period, the NRC inspectors observed
portions of:
OP-903-005, " Control Element Assembly Operability Check"
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OP-903-007, " Turbine Inlet Valve Cycling Test"
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Performar.ce of the CHANNEL FUNCTIONAL TEST for containment radiation
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monitor ARM-IR-5400 AS per TS 4.3.3.1.
Demonstration of OPERABLE condition of each fire pump diesel starting
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12-volt battery bank and charger per TS 4.7.10.1.3.1.
No violations or deviations were identified.
6.
Routine Inspection
The NRC inspectors verified by observation that the control room manning
requirements were being met.
In addition, the NRC inspectors observed
shift turnover to verify that continuity of system status was maintained.
The NRC inspectors periodically questioned shift personnel relative to
their awareness of the plant conditions.
Through log review and plant tours, the NRC inspectors verified compliance
with selected TS and limiting conditions for operations.
During the course of the inspection, observations relative to protected
and vital area security were made including access controls, boundary
integrity, search, escort, and badging.
On a regular basis, radiation work permits (RWPs) were reviewed and the
specific work activity was monitored to assure the activities were being
conducted per the RWPs. Selected radiation protection instruments were
periodically checked and equipment operability and calibration frequency
were verified.
The NRC inspectors kept informed on a daily basis of overall status of
plant and of any significant safety matter related to plant operations.
Discussions were held with plant management and various members of the
operations staff on a regular basis. Selected portions of operating logs
and data sheets were reviewed daily.
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The NRC inspectors conducted various plant tours and made frequent visits
te the control room. Observations included: witnessing work activities
in progress; verifying the status of operating and standby safety systems
and equipment; confirming valve positions, instrument and recorder
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readings, annunciator alarms; and housekeeping.
The licensee's Potential Reportable Event (PRE-86-037) documents the
identification of a number of cracks in the nuclear plant island structure
(NPIS) foundation basemat found during performance of Procedure PE-5-033
(18-month requirement). Though these cracks had not been previously
identified, it appeared, upon observation by the NRC inspectors, that these
cracks have existed for a considerable length of time. The cracks that
were identified are located in the Diesel Storage Tank B and sanitary
equipment rooms, as well as both the east and west vault areas.
The licensee staff explained to the NRC inspectors that there are a number
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of probable reasons why these cracks were not identified either when
setting up the basemat surveillance program or during the first 18-month
inspection.
The initial 18-month inspection was considered complete based on the
nondestructive testing done on the basemat by Muenow and Associates, Inc.
during the period June to September 1984. This testing was an evaluation
of selected existing cracks with emphasis on those that appeared to be
continuous cracks running under the reactor containment, fuel handling, and
reactor auxiliary buildings.
The monitoring program set up to meet the requirements of TS 6.8.4.e does
require the monitoring of all significant cracks in the basemat and
adjacent walls.
However, prior to plant licensing, technical evaluation
of the NPIS basemat cracks concentrated on those cracks that appeared to
be continuous cracks running through the basemat below the reactor contain-
ment structure and even those were found acceptable.
These newly identi-
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fied cracks do not appear to fall into that category as they are considered
of less significance and therefore also acceptable.
The licensee plans to submit a special report to the NRC as outlined in
Procedure PE-5-033.
During a review of Procedure OP-9-001, " Containment Spray," following the
maintenance on the B Containment Spray Pump discussed in paragraph 8 of
this report, the NRC inspector noted one minor but apparently chronic
problem.
In Section 7 of the procedure, the title of one of the annunci-
ator windows (7.1.6) was changed as part of the licensee's continuing
annunciator upgrade program but this change has not been reflected in the
procedure. The NRC inspector discussed with the licensee the need to make
comprehensive changes to plant equipment and procedures for future
annunciator changes.
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On June 26, 1986, during a control room tour the NRC inspector questioned
the shift technical advisor (STA) about certain aspects of the operation
of the component cooling water (CCW) system. At one point, the STA
consulted the control room drawings to explain the function of the check
valve in the CCW surge tank vent line.
The control room drawing did not
indicate such a valve; however, the STA informed the NRC inspector that
this valve had been put in under a station modification (SM). That valve
and a second check valve designated to operate as a vacuum breaker had been
put in under SM 896. The SM documentation in the control room contained a
work completion notice (WCN) dated February 26, 1986, indicating the
completion of the modification. PE-2-006, Revision 7, " Station Modifica-
tions," requires, in section 5.9.5, that the action engineer redline any
control room drawings affected by the modification.
This was not done in
the case of this SM; the drawing had only been annotated to indicate that
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SM 896 did affect that drawing.
Concerns in this area were first brought to the licensee's attention in
NRC Inspection Report 382/85-20 and were reemphasized in the Systematic
Assessment of Licensee Performance (SALP) Board Report 382/85-30.
Further, paragraph 7 of NRC Inspection Report 382/86-08 discusses a
similar failure to update drawings and procedures which led to a number of
inadvertent radiological releases. The NRC inspector stressed to licensee
management that problems with the station modification program still exist
and that more aggressive action needs to be taken to both prevent future
problems and correct any past errors.
The failure to properly implement PE-2-006, Revision 7, is an apparent
violation and is identified as 382/8613-01.
7.
Licensee Followup on Previously Identified Items
(0 pen) Unresolved Item 382/8602-01 - This item involved apparent failure
to adequately document the investigation performed subsequent to the
inadvertent dropping of a control element assembly while the reactor was
at approximately 40% power.
The NRC inspector reviewed a number of docu-
ments which appear to be responsive to the problem including the following:
a.
Memo W3A86-0017 from the plant manager to various members of plant
management on the subject of determining accountability when
. investigating and reporting events.
b.
Various event reports documented by memos to file including one for
the dropped rod incident discussed abnve.
The NRC inspector discussed this documentation with the assistant plant -
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manager, operations and maintenance (APM, O&M) and stated the following
continuing concerns:
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It appeared that an independent review of the report would be
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appropriate in some instances. The APM, 0&M indicated that he would
forward a recent report involving a dropped subgroup of rods to the
independent safety engineering group-(ISEG) for evaluation.
It is not clear what the threshold is for initiating an event report
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in all instances. Also, the method of documentation (e.g., potential
reportable event, condition identification work authorization, -
quality notice, memo to file, etc.) required is not always clear.
The APM, 0&ll stated he would further address the above concerns.
(Closed)UnresolvedItem 382/8611-01 - In NRC Inspection Report 382/86-11
the procedural requirement to have a 15 F temperature difference across
the heaters in the shield building ventilation trains and the inability of
the system to meet this requirement was identified as Unresolved Item
50-382/8611-01. While reviewing the data being taken for Surveillance
Procedure OP-903-51, Revision 4, (TS 4.7.6.b) " Control Room Emergency
Filtration Unit Operability Check," for Train A, the NRC inspector
identified the same problem in this procedure as discussed in the
unresolved item.
In this case, a temperature difference of only 6.6*F
was recorded. Further review identified that the same 15 F temperature
difference is also specified in OP-903-52, Revision 4, " Controlled
Ventilation Area Section System Operability Check" (TS 4.7.7.a), and
OP-903-076, Revision 2, " Fuel Handling Building Ventilation System
Operability Check" (TS 4.9.12.a).
The performance of OP-903-076 for
Train A yielded a temperature difference value of 13.4 F.
The licensee has evaluated the 15 F temperature difference requirement and
determined that it is unnecessary.
The ventilation fans in the systems
discussed have a low temperature difference cut off of 5 F.
This temper-
ature difference is adequate to ensure the system filters and adsorbers are
properly maintained by running the 10-hour surveillance. The licensee is
in the process of deleting the 15 F temperature difference from the various
ventilation system procedures and Unresolved Item 50-382/8611-01 is
considered closed.
No violations or deviations were identified.
8.
Monthly Maintenance
-Station activities affecting safety-related systems and components were
observed / reviewed to ascertain that the activities were conducted in
accordance with approved procedures, regulatory guides and industry codes
or standards, and in conformance with TS.
Activities observed during this inspection period included the
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troubleshooting and repair of the valve operator for MS-401A (main steam
to emergency feedwater pump A/B turbine). This work was performed under
Condition Identification Work Authorization (CIWA) 027312 using Procedure
ME-7-00.8, " Motor Operated Valves."
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On June 18, 1986, the NRC inspector was reviewing the approved work in
progress on safety-related equipment. Work was being done on the B Safety
Injection Header to inspect and rewire, if necessary, certain valves that
possibly did not meet the requirements of the licensee's equipment quali-
fication program which implements the requirements of 10 CFR Part 50.49.
The NRC inspector noted that the plant operators had properly logged entry
into the applicable TS action requirement while the work was in progress.
The NRC inspector questioned the shift supervisor to ascertain why there
was environmental qualification (EQ) work still needing to be completed.
The shift supervisor told the NRC inspector that he only knew that the
electrical maintenance group had requested to do the work and that he was
not sure as to how or when the possible problems had been discovered. The
NRC inspector reviewed the applicable documentation and found that the
identification of the possible problems with wiring of the valve operators
for SI-121B [ low head safety injection (LPSI) Pump B upstream recirculation
isolation valve] and SI-228A [high pressure safety injection (HPSI)
Header A to Loop 2B cold leg injection valve] were identified April 9, 1986,
on CIWA 026203.
Similar possible problems with SI-225B (HPSI Header B to
Loop 1A cold leg injection valve) and SI-227B (HPSI Header B to 2A cold leg
injection valve) were identified on CIWA 026204 issued on the same date.
The inspections of the four listed valves on June 18 and 19, 1986,
revealed that only SI-2258 and SI-227B needed to be rewired in order to
comply with EQ requirements. This work was done at the time of the
inspection. The NRC inspector questioned licensee management as to the
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reason prompt corrective action had not been taken on these potential
problems identified over 2 months earlier.
Licensee management explained
that even though compliance with 10 CFR 50.49 had been required by
November 30, 1985, industry experience since that date had shown problem
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areas that had not been anticipated.
So, even though the Waterford 3
equipment qualification program was in place on the date required, it was
not unlikely that some future problems would be identified in a program of
such a large scope. The NRC inspector agreed that emergent problems were
not unlikely; however, in this case the possible deficiencies had already
been identified and timely actions to resolve them were not taken. The
failure to take prompt corrective actions to bring Valves SI-225B and 2278
into compliance with the EQ requirements is an apparent violation and is
identified as 382/8613-02.
The NRC inspector observed portions of bearing replacement work and
subsequent retesting for the B Containment Spray Pump.
The work was
performed in accordance with CIWA 024732 which appeared generally adequate
for the work to be performed. However, there appeared to be deficiencies
in work planning and/or training.
The pump to motor coupling was installed
backwards on the first attempt.
It had to be reheated for removal and the
first attempt failed. After the second failure, the lead mechanical
maintenance technician discovered specific instructions for preheating the
coupling in the technical manual (TM).
It would have been advisable for
the CIWA to specifically refer to these instructions.
Prior to reinstal-
lation of the pump, the NRC inspector and a licensee quality control (QC)
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inspector observed that the pump was attached to a chain hoist which was
attached to a pipe snubber. No pump weight had been transferred to the
snubber. Also, a metal platform was positioned across two electrical
conduits under where the pump was to be placed. The QC inspector advised
the mechanical maintenance technicians that it was improper to rig from the
pipe snubber and that the platform should be removed from the conduits.
The pump was subsequently placed by utilizing a ceiling chain hoist after
the platform was removed.
The NRC inspector discussed the above occurrences with the APM-0M and the
plant maintenance superintendent (PMS).
The NRC inspector emphasized that
continual effort is needed to ensure CIWA work instructions are clear and
detailed. Also, the NRC inspector suggested an evaluation of the
effectiveness of training for rigging and equipment protection may be
appropriate.
Containment Spray Pump B was successfully tested utilizing plant Procedure
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OP-903-035, Revision B, " Containment Spray Pump Operability Check," which
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satisfies TS 4.6.2.1.c and TS 4.0.5.
However, on the first start it showed
evidence of being potentially air bound. Operations shut it down and then
bumped it twice more before a sustained test run after the fourth start.
The NRC inspector expressed concern to the operations superintendent (OS)
regarding what appeared to be an excessive number of motor (300 hp) starts
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in a short period of time.
The OS stated that he also had this concern
prior to the starts and had researched the TM, but could find no restric-
tions on motor starts. The OS agreed to consider establishing plant
generic motor starting guidelines for motors that are not presently
addressed procedurally. During further discussions of this event between
the APM-0M, the PMS and the NRC inspector, the APM-0M stated that they
would consult the motor manufacturer to determine if excessive motor
temperature could have been experienced in this instance.
During testing of the containment spray pump two significant leaks (steady
streams) were observed at fittings connecting component cooling water to
the bearing oil cooler. When the NRC inspector asked the STA about the
leaks the following afternoon the STA discovered the leaks continued to
exist.
CIWA 027405 was initiated to request repair of the leaks. Though
the leaks did not appear to affect operability, in order to repair them
now, the pump must be taken out of service a second time. The NRC
inspector informed plant management that such maintenance practices are
not compatible with maximizing the availability of safety-related
equipment or with goals for keeping radiation exposure as low as
reasonably achievable ( ALARA).
Prior to performing work observation activities, the NRC inspector
reviewed the following procedures:
UNT-5-002, Revision 5, Change 1, Condition Identification and Work
Authorization
UNT-5-004, Revision 3, Change 2, Temporary Alteration Control
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Other maintenance activities observed included routine preventive
maintenance for the diesel fire pump and auxiliary diesel starting
batteries.
9.
Potential Generic Problems
The NRC inspector provided the licensee with a copy of a report regarding
detection of "intergranular attack" corrosion in the St. Lucie 1 steam
generators in the egg-crate tube support region. The corrosion was
detected during inspection of three representative tubes which had been
removed from the steam generator. This corrosion had not been identified
during eddy current tests which had been done on two previous occasions.
The NRC inspector also followed up on possible seismic interactions
between the movable incore flux mapping system and the seal table which
was first identified as a concern at Westinghouse designed facilities. The
concern does not appear to be applicable to Waterford 3 as the incore
instrument penetrations are attached to the reactor vessel head and do not
rely on a seal table and bottom penetrating design.
The NRC inspector made the licensee aware of a deficiency discovered in
the high energy line break (HELB) analysis for the Monticello facility.
In performing the analysis based on the " worst case" approach, the
architect / engineer (AE) failed to consider the effects of a HELB in certain
areas of the plant.
Further analysis demonstrated that a masonry wall
failure could occur which, in turn, results in a harsh environment in an
area where one was not previously presumed to exist. The NRC Region III
office believes similar deficiencies could exist in other HELB analyses and
has recommended that all other licensees for power reactor facilities
review their analyses.
No violations or deviations were identified.
10.
License Conditions
(Closed) Condition 2.C.14, Verification of Boraflex in Spent Fuel Storage
Racks.
In a letter dated June 6,1986, the licensee informed the Office
of Nuclear Reactor Regulation (NRR) that the storage rack Boraflex
verification had been completed during the period March 11-17, 1985. The
NRC inspector has reviewed the report documenting the testing made to the
licensee by National Nuclear Corporation and had no questions.
NRR, iri a
letter dated June 23, 1986, informed the licensee that this license
condition is considered closed.
No violations or deviation were identified.
11.
IE Bulletins
(0 pen) IEB 85-01, Steam Binding of Auxiliary Feedwater Pumps.
This
bulletin required, in part, that procedures be developed "for recognizing
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steam binding and for restoring the AFW system to operable status, should
steam binding occur." In a letter dated February 26, 1986, the licensee
described the procedures they had implemented to meet the above require-
ments.
In summary, the licensee's response stated that procedures had been
changed to require monitoring of emergency feedwater (EFW) discharge piping
temperatures and that upon these temperatures reaching 120 F, closer
monitoring would be required and possible corrective actions considered.
The response went on to say that, tpon reaching 230 F, control room
supervisors had been instructed that corrective actions were required to
vent, drain, and fill the system as reguired to reduce tamperature.
The reactor auxiliary building (RAB) radiologically controlled area logs,
which are an attachment to 01-004-000, " Watch Station and Shift Logs,"
require that temperatures on the discharge of the EFW piping be monitored
and specify 120 F as the maximum acceptable temperature. Additionally,
OP-903-001, the control room " Technical Specification Logs" record the EFW
,
discharge piping temperatures. A note accompanying that procedure requires
increased monitoring of the temperatures and outlines possible corrective
actions.
The NRC inspector could find no procedural requirement that would
implement the 230 F limit for initiation of corrective actions described in
the licensee's response to the IE Bulletin.
Further, the NRC inspector
asked a number of senior reactor operators (SR0s) about the existence of a
temperature limit above the 120 F discussed in the two station logs.
Though the SR0s were aware that the probability of steam binding of the
pumps would increase as the discharge piping temperature increased, they
were not familiar with the 230 F limit specified in the licensee's
February 26, 1986, letter.
The failure to fully implement the actions
committed to in response to IE Bulletin 85-01 is an apparent deviation
from a commitment to the NRC and is identified as 382/8613-01.
12.
Exit Interview
The inspection scope and findings were summarized on July 1, 1986, with
those persons indicated in paragraph 1 above. The licensee acknowledged
the NRC inspectors findings. The licensee did not identify as proprietary
any of the material provided to or reviewed by the NRC inspectors during
this inspection.
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