ML20151E239
| ML20151E239 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 07/14/1988 |
| From: | Chamberlain D, Will Smith, Staker T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20151E230 | List: |
| References | |
| 50-382-88-13, NUDOCS 8807250423 | |
| Download: ML20151E239 (22) | |
See also: IR 05000382/1988013
Text
p
,;
--
L
.' -
- ,-..,.
.
.g
-
.
/
l
APPENDIX B
U. S. NUCLEAR REGULATORY COMMISSION
REGION IV
!-
NRC Inspection Report: 50-382/88-13
License:
Docket: 50-382
Licensee: Louisiana Power & Light Company (LP&L)
142 Delaronde Street
New Orleans, Louisiana 70174
Facility Name: Waterford Steam Electric Station, Unit 3
Inspection At: Taft, Louisiana
Inspection Conducted: May 1 through June 17, 1988
Iitspectors:
19
kV
?-N-8$
'
,
W. F.(/5mith, SenTor ResEdent Inspector
Date
2-/b88
i
T. R.&Staker, Resident Inspector
0
Date
7-/'/88
Approved:
D. D. Ghamberlain,"Chief,' Project Section A
Date
Division of Reactor Projects
!!k
kDOOk 00000002
O
PNU
,
u
P
~ ~ '
,
,
,
._
,.).
.
W
,
.
~
'
2
v.
Inspection Sumary
-
-Inspection Conducted May 1 thro' ugh June 17. 1988 (Report 50-382/88-13)
~
Areas Inspected: Routine, unannounced inspection consisting of: (1) monthly
maintenanceobservation.(2)verificationofcontainmentintegrity,(3)onsite
followup.of events, .(4) operational safety verification, (5) monthly
' surveillance observation, (6) followu of previously identified items,-
licensee event report followup, ( ) containment integrated leak rate test,
<
refueling activity. observations, 10)'startup testing observations,
) emergency diesel generator inspection, and (12) plant status.
Results: ,Within the areas-inspected, three violations were identified. The
first Wolation involved inadequate maintenance work instructions
(paraoraph2). The second violation involved failure to implement quality,
assurance procedures (paragraph 3)(.
The third violation involved a failure to
identify and correct deficiencies paragraph 3).
- '
.
L
.
,
.
r
3
DETAILS
1.
Persons Contacted
Principal Licensee Employees
- R. P. Barkhurst, Vice President, Nuclear Operations
- N. S. Carns, Plant Manager, Nuclear
S. A. Alleman, Nuclear Quality Assurance Manager
P. V. Prasankumar, Assistant Plant Manager, Technical Support
D. P. Packer, Assistant Plant Manager, Operations and Maintenance
- J. J. Zabritski, Manager of Operations QA
L. W. Myers, Manager of Nuclear Operations Support and Assessments
J. R. McGaha, Manager of Nuclear Operations Engineering
W. T. Labonte, Radiation Protection Superintendent
D. E. Baker, Manager of Events Analysis Reporting & Responses
- L. W. Laughlin, Onsite Licensing Coordinator
- C. R. Gaines, Events Analysis Reporting and Response Supervisor
D. W. Vinci, Maintenance Superintendent
A. F. Burski, Acting Manager of Nuclear Safety and Regulatory Affairs
R. S. Starkey, Operations Superintendent
'
R. A. Legere, Plant Engineering
- Present at exit interview.
In addition to the above personnel, the NRC inspectors held discussions
with various operations, engineering, technical support, maintenance,
quality assurance, and administrative members of the licensee's staff.
2.
Monthly Maintenance Observation (62703)
The below listed station maintenance activities affecting safety-related
systems and components were observed and documentation reviewed to
ascertai. that the activities were conducted in accordance with approved
procedures, technical specifications, and appropriate industry codes or
standards,
a.
Work Authorization 01017878. While performing post maintenance
testing on Emergency Diesel Generator "B," it was observed that the
emergency diesel start air to the control air interface check
valve (EGA-4218) was leaking and preventing proper operation of the
control air system. The NRC inspector observed the replacement of
EGA-421B per the above work authorizetion which originally contained
instructions only to adjust a control air system pressure regulator.
The work authorization had been updated with additional instructions,
including the check valve replacement and a general statement to
troubleshoot. After the check valve was replaced, the control air
system was pressurized by attempting to start the diesel with the
starting air distributor disconnected from the engine.
The diesel
generator starting air distributor inputs had been disconnected and
1
-
.
.
.
4
I
the air filter output capped to allow start sequencing without
crankshaft rotation.
In addition, the field flash DC supply breaker
was opened. After performing-a successful simulated start, the
breaker was closed, and the air start system reconnected.
At that
point, the NRC inspector inquired as to what work authorization
instructions controlled these tasks. Supervisory personnel at the
worksite stated that such controls were not required because they
were "troubleshooting." After completion of the troubleshooting, the
diesel was started for the retest, and then a trip occurred on high
connecting rod bearing temperature. An iavestigation revealed that
the rod bearing temperature instrument isolation valve (EGA-432B) was
shut. Apparently, the valve had been shut during the above
troubleshooting activities. After repositioning Valve EGA-432B, the
diesel was started and subsequently ran, but more problems developed
during the cooldown cycle. Work was secured until further
instructions could be obtained. The NRC inspector later noted that
cleanliness control measures, as required by Procedure UNT-7-005,
Revision 2, "Cleanliness Control," were not established when opening
the diesel generator air system.
This system is referenced in
Attachment 2 of the procedure as a class "C" cleanliness system. The
cleanliness of the diesel generator air system should have been of
particular interest since a recent licensee investigation revealed
that dirt particles on a check valve may have contributed to a
previous problem with spurious low turbo lube oil trips on diesel
generator "A."
The inspector held a discussion with plant management personnel
regarding the degree of required procedural controls on
troubleshooting activities.
It was acknowledged that more stringent
controls would have been appropriate and that better guidance in this
area should have been implemented.
The extent of the work above appears to be extensive and outside of
the limitations stipulated in Regulatory Guide 1.33 for
"troubleshooting."
Further, the work authorization failed to
implement the cleanliness controls required by UNT-7-005.
Failure to
provide an adequate procedure is an apparent violation of Technical Specification 6.8.1.a which states, in part, written procedures
shall be established and implemented as recommended in Appendix A of
Regulatory Guide 1.33, Revision 2, February 1978(382/8813-01).
During the previous inspection period of March 16 through April 30,
1988, the resident inspectors identified a similar
violation (382/8808-03) where maintenance instructions were not
appropriate to circumstances while disassembling the "B" main steam
isolation valve.
In recent months, the licensee and the NRC have
identified several other deficiencies in the implementation of
As a consequence of the repeat nature of these
procedures.
deficiencies, the corrective actions taken in response to the
apparent violation in this area should reflect substantive efforts to
preclude recurrences.
L
-
>
.
.
.
5
b.
Work Authorization 01006550. The NRC inspector observed performance
of preventive maintenance on the 3B32 station service
transformer 4160 volt isolation breaker. Observations included
cleaning, inspecting, measurement of primary contact wipe, arcing
contact wipe, and primary contact gap. Two phases of primary contact
wipe were not within the acceptance criteria and were adjusted. Work
was performed per Procedure ME-04-131, Revision 5, "Maintenance
Procedure 4.16 KV G. E. Magne-Blast Breaker." The NRC inspector
identified the following minor typographical errors in
Procedure ME-04-131, Revision 5:
(1) Step 8.3.23.2 rec;uires continuation of the procedure starting at
Step 8.3.14.
The procedure must be continued at Step 8.3.24.
(2) Step 8.3.7.1 requires Steps 8.3.3 and 8.3.4 to be repeated.
Step 8.3.5 must also be repeated.
The licensee committed to correct these errors. The inspectors will
verify completion during a later inspection.
No formal followup is
requi red.
c.
Work Authorization 0108683. The NRC inspector observed the packing
replacement on the emergency feedwater header bypass isolation
valve (EFW-228A). The packing configuration included upper and lower
,
packing rings separated by a lantern ring. Attempts to remove the
lantern ring without valve disassembly were unsuccessful.
Appropriate changes were made to the work instructions, and only the
upper packing rings were replaced. This action appeared to be
adequate.
d.
Work Authorization 0101929. The NRC inspector observed the
replacement of a buffer amplifier circuit card in core protection
calculator channel "A."
Subsequent testing per Procedure MI-3-121,
Revision 3, "CEAC Functional Test," was also witnessed. The NRC
inspector noted that all data points met the acceptance criterion in
the procedure.
3.
Verification of Containment Integrity (61715, 71710, & 37700)
This inspection was performed to verify that the licensee had established
containment integrity prior to reactor coolant system heatup to above
200"F. The NRC inspectors verified the proper positioning of mechanical
and electrical barriers at selected containment penetrations. A system
designed to assure containment integrity was walked down by the NRC
inspectors.
In addition, the NRC inspectors witnessed cerformance of the
personnel air lock local leak rate test.
On May 24 and 25, 1988, the NRC inspectors verified the integrity of
containment penetration Nos. 61, 65, 66, 67, 70, 114, 115, 116, 119, and
146. No problems were identified.
L
-
,
-
.
. .
..
e
8
?
6
On May 27, 1988, the inspectors witnessed the leak test of the containment
personnel _ air lock inner and outer door seals. The test was done in
_
accordance with Procedure OP-903-111, Revision 0, "Containment Air Lock
Door Seal Leakage Test." The results were well within limits, and no
- problems were identified.
-The inspectors conducted a walkdown of the hydrogen analyzer system in
accordance with Inspection Procedure 717M, "Engineered Safety Feature
System Walkdown." .This effort was performed to accomplish two objectives.
The first was to walk down a system designed to maintain containment
Mtegrity in the event of a loss of coolant accident (LOCA), and the
seend was to independently verify the status of an engineered safety
featcre (ESF) system that had.been replaced, for the most part, during the
refueiing outage. -A review was performed to confirm that the licensee's
~
revise
7
(2) Several valve descriptions in the standby system valve lineup
were either wrong or inaccurate.
For example, Valve HRA-1251A
was described as the sample line isolation to analyzer "A."
Valve HRA-1251A.is either an auxiliary connection or a drain
valve.
c.
During performance of a system walkdown, all valves appeared to be
lined up correctly.
Problems with incorrect and inaccurate valve
. descriptions on the identification tags were noted.
The licensee was
aware 'of this and attempted to correct this~ problem by installation
of new valve identification tags. On a subsequent walkdown, the NRC
inspector found the hydrogen analyzer "A" sample supply and return
isolations and two vent valves labeled incorrectly.
This invalidated
~
the system operating procedure because the sample supply and return
isolation valves were now required to be shut. The licensee
subsequently corrected this deficiency by installing the correct
valve identification tags.
d.
System Operating Procedure OP-8-010, requires hydrogen analyzer local
control panel sample switch numbers one through seven to be in the
"0N" position when the analyzers are in the standby mode. Sample
switches two through seven were found in the "0MIT" position. This
alignment would not render the hydrogen analyzers inoperable. The
system would, when initdated, sample from one area (top of
containment) continuously instead of automatically sequencing samples
from additional locations.. The system operating procedure ~ alignment
for standby operation should be in agreement with the actual system
setup during this mode,
The system drawing for the hydrogen analyzers, LOV-1564-B-430-SP-01,
e.
only shows the "B" analyzer system. A drawing note states that
system "A" is similar. Several system "A" valves (auxilisry
connections) are not included. The licensee stated that because the
"A" train was not depicted on the drawing, the retultant confusion
led to operations personnel installing valve identification tags on
the wrong valves.
f.
The sample line supplying hydrogen analyzer "B" is heat traced and
insulated. Sections of the insulation were removed in order to
install Station Modification 983. During the system walkdown, the
NRC inspector noted that some sections of insulation were not
reinstalled and other sections were left hanging from supports.
No
condition identification tag was observed, and the SMP was cicsed
with the exception of cid cabinet removal and a system walkdown for
human factors and "touch up."
The NRC inspector noted that the
insulation was reinstalled prior to the end of the inspection period.
During review of the SMP for Station Modification 983, the NRC
g.
inspector noted from the documentation that during testing a
transistor was burned out and a pressure transmitter had been damaged
due to incorrect wire terminations. The installation had been
m
_
-_____-___
'
'
-
..: y
,
<
,
,
.,t
8
s
,
inspected and accepted by the licensee's quality assurance
-
inspectors. Quality Assurance Inspection Report 88-012, dated
= April 21,-1988, documented these findings. Quality Assurance
Procedure QAP-012, Revision 6, "Corrective Actions," requires-
= initiation of a Quality Notice (QN) when conditions adverse to
quality are identified.so that appropriate reviews and corrective
actions as to cause can be accomplished. The NRC inspector noted
.that no QN_ had been written on the above condition. = The NRC
inspectors discussed this with Itcensee management.
The issuance of
a QN for the above condition, as well as-the licensee's "threshold"
- for issuance of QN in general was addressed.
It was acknowledged
.
.that a QN should have been issued-for the condition above and that
~
~
the threshold;for the issuance of- QNs may be too high for some
licensee personnel.
The licensee then issued a QN on the incorrect-
_
termination described above.
Failure to issue a Quality Notice in
accordance with QAP-012.when the above condition was identified is an
apparent' violation (382/8813-02).
-
Previous valve identification tag and valve lineup deficiencies with the
hydrogen analyzer system were . identified in NRC Inspection
Rcport 50-382/88-22. Those deficiencies were subsequently corrected.
Previous deficiencies with equipment labeling and safety system operating
procedures (valve lineups) have been idantified in NRC Inspection
Reports 50-382/86-02,86-11,86-15,86-29,87-01,87-10,87-22,87-25,
l88-04 .and 88-08. The specific deficiencies of this type identified by
.the NRC inspectors appear _to be corrected by the licensee, but the
licensee does not appear to be taking adequate corrective action to
preclude recurrences or:to identify and correct similar problems in other
safety systems.
Failure of the licensee to promptly identify, correct,
and preclude recurrences of these deficiencies is an apparent violation of
the requirements of Criterion XVI of Appendix B to 10 CFR Part 50
(382/8813-03).
4.
Onsite Followup of Fvents (93702)
a.
Failure of Main Steam Isolation Valves
On April 9,1988, the plant was shut down and cooled down in
operational Mode 5 for the second refueling outage. When the No. 1
Main Turbine Throttle Valve was opened for routine inspection, the
licensee found a piece of steel about 33 inches long by 2 1/2 inches
wide by 1 3/8 inches thick which had been caught by the basket
strainer upstream of the throttle valve. The piece was broken nearly
in half and was slightly bent. A few broken fasteners were also
found. The piece of metal had a part number which identified it as
part of a gate guide assembly for one of the two main steam isolation
valves (MSIVs).
Since MSIV "B" (MS-1248) had a more direct
downstream path which was most likely to transport the debris to the
main turbine throttles, the licensee elected to inspect about 100 of
the 200 feet of main stream piping upstream of the turbine throttle
leading to MS-124B.
No additional parts were found. The MSIVs at
e-
.
.
9
Waterford-3 were manufactured by WKF Valve Division of
ACF. Industries. They are 40x30x40 Class 600 hydraulically opened,
nitrogen pressure closed, Model D-2 "Pow-R-Seal" gate valves. This
event was initially reported in NRC Inspection deport 50-382/88-08.
During this inspection period, the licensee fully disassembled both
MSIVs "A" and "B".
Tests and investigations were conducted to
determine the causes of the failure and to establish a viable
corrective action plan. The resident inspectors followed the
licensee's activities with assistance'and support provided by
Region IV engineering personnel and NRR technical project staff.
WKM, the valve manufacturer, performed a component failure analysis
and design enhancement study.
Kalsi Engineering, Inc., was
,
contracted by the licensee to perform an engineering
l
technical evaluation of the root cause and a worst case safety
analysis for MSIV operability with failed guide rails.
The licensee performed a material evaluation of the failed parts
which included an evaluation of the guide rail fasteners which had
not yet failed. The licensee has committed to provide the NRC with a
detailed report by June 24, 1988, on the results of these efforts
thereby documenting the root causes of _ the failures, the corrective
actions, the safety implications of having operated for the past
three years with the valves as-built, and the margin of safety
afforded by operation in the future after repairs and design
improvements had been implemented.
Resolution of these issues is
already being tracked by Unresolved Item 382/8808-01.
The failure mechanism appeared to be centered around the fasteners
which attached the guide rails to the guide rail skirts. These
fasteners appeared to fail in shear due to excessive stresses set up
by a combination of unfavorable conditions which are discussed in the
following paragraphs.
Typically, the gate in a standard gate valve withdraws into the upper
bonnet and is wedge shaped so that when it is shut the gate wedges
itself between the seats.
The WKM "Pow-R-Seal" gate is a longer
two-piece gate with parallel seating surfaces.
Rather than
disappearing into the valve bonnet, just the top half of this longer
gate moves up into the bonnet, and the lower half stays in the
process stream with a hole as large as the seat to allow process
flow. The gate halves are cut on diagonals so that when they move
relative to each other, they wedge apart and against the seats
providing a seal. There is a lever lock assembly on the gate which
keeps the gate from wedging itself while in transit. This assembly
,
I
rides between the guide rails until the end of the valve strokes
where the rails release the lever thus allowing the gate to wedge in
either the open or shut position.
Each time the valve begins to
stroke, the lever lock shoe impacts against the end of the rails.
Because of the angles of contact and sharp corners, the rails and
i
_
-
.,
.
.
10
lever lock shoes are galled at the contact points. This put a heavy
load on the fasteners that attach the guide rails to the guide rail
skirt, resulting in the eventual failure of the fasteners for
MSIV "B."
The licensee stated that the valve design (parts configuration)
resulted in excessive galling of the lever lock shoes and guide
rails, thus imparting large stresses to the guide rail fasteners.
Pre-existing cracks and corrosion on the fasteners may have weakened
the fasteners.
Rail and skirt misalignment during fabrication may
have placed additional stresses in the fasteners, as they were flat
head screws which are more vulnerable to bending stresses unless the
holes are carefully aligned.
The design ;;as enhanced by (1) changing the angle of contact between
the lever lock shoes and the guide rails, (2) stelliting the contact
surfaces between the lever lock shoes and the guide rails,
(3) changing the bolt material from low alloy steel to 17-4PH
stainless steel, (4) nondestructively examining the
fasteners for defects, (5) aligning the tapped holes in the guide
rails with the drilled holes in the guide rail skirts to within
0.005 inches axis to axis, and (6) verifying torque at 150 foot
pounds for each fastener.
The NRC inspectors witnessed portions of the reassembly process.
The
valve internals were installed with care and in the presence of a WKM
representative. When the valves were tested, some licensee operators
observed that the MSIVs operated smoother and quieter than in the
past.
By all observed tests and technical data provided to the
inspectors, the MSIVs appear to be adequate to perform their intended
safety function,
b.
Pressurizer Low Range Pressure Instrument Failure
On June 8,1988, a pressurizer low range pressure transmitter
(RC-IPT-0106) ruptured. When this occurred, unidentified reactor
coolant system leakage increased to 2.22 gallons per minute.
Additionally, the pressurizer safety channel "0" wide and narrow
range instruments and the Y-level control channel were indicating
incorrec tly. After isolating the leak, capping the failed instrument
line, and returning the safety instruments to service, the licensee
began an investigation to determine the cause of the failure of the
Barton Model 783 pressure transmitter (Range 0-750 PSI).
Later the
licensee determined that RC-IPT-0106 had been replaced during the
refueling outage (April 1 through June 1,1988), with a transmitter
rated for 150 percent of the maximum indication range or 1125 pounds
per square inch (PSI). The gauge was subjected to reactor coolant
system normal operating pressure (2250 PSI).
The licensee found that
the purchase documentation used to order the replacement transmitter
did not include adequate information to obtain the required pressure
rating. The licensee initiated a Quality Notice to follow up on the
i
L
_
.
,
-,-
.
11
inadequate purchasing documents.
Additionally, the licensee has
verified that all similar instruments meet the applicable design
requirements. This action appears to be adequate.
No violations or deviations were identified.
5.
Operational Safety Verification (71707, 71709, 71881)
The objectives of this inspection are (1) to ensure that this facility is
being operated safely and in conformance with regulatory requirements,
(2) to ensure that the licensee's management controls are effectively
discharging the licensee's responsibilities for continued safe operation,
(3) to assure that selected activities of the licensee's radiological
protection programs are implemented in conformance with plant policies and
procedures and in compliance with regulatory requirements, and (4) to
inspect the licensee's compliance with the approved physical security
plan.
When onsite, the NRC inspectors visited the control room daily.
Control
room staffing, access, operator behavior and shift turnovers were
observed. The NRC inspector reviewed operators' logs and control panels
to verify compliance with technical specification limiting conditions for
operation. No problems were identified.
The NRC inspectors toured accessible areas of the plant in order to
observe hausekeeping and equipment condition.
During the tours, the NRC
inspectors observed that fire impairments were identified and fire watches
were established as required. The NRC inspectors verified proper use of
dosimetry and anticontamination equipment in accordance with approved
radiation work permits.
In addition, condition of security barriers and
implementation of compensatory measures during impairments were also
observed.
Some minor housekeeping problems were identified in
paragraph 10 of this report.
No other problems were noted.
No violations or deviations were identified.
6.
Monthly Surveillance Observation (61726},
The NRC inspectors observed the below listed surveillance testing of
safety-related systems and components to verify that the activities were
being performed in accordance with the technical specifications. The
applicable procedures were reviewed for adequacy, test instrumentation was
verified to be in calibration, and test data was reviewed for accuracy and
completeness. The inspectors ascertained that any deficiencies identified
were properly reviewed and resolved.
a.
Procedure OP-903-032, Revision 5, "Quarterly ISI Valve Tests." On
fiay 21, 1988, the NRC inspector witnessed the quarterly cycling of
Main Steam Isolation Valve "A" and Main Feedwater Isolation
Valve "B."
Although the valves stroked satisfactorily, two
annunciators alarmed which the licensee's representatives considered
'
-
,
.
,
12
abnormal and requiring correction. They were "MSIV-1 TEST FAILURE
TROUBLE" and "MSIV-1 HYDRAULIC SYSTEM TROUBLE." The anomolies were
corrected by minor repairs to the electro-hydraulic actuator systems,
and the valves were subsequently retested satisfactorily,
b.
Procedure OP-903-033, Revision 7, "Cold Shutdown ISI Valve Tests."
On May 21, 1988, the NRC inspector witnessed a full stroke timing
test of Main Steam Isolation Valve "A" following the major
maintenance-discussed in paragraph 3.
The valve must shut within
three seconds -as required by Technical Specification 4.7.1.5.
The
inspector independently measured the stroke time at the value with a
digital stopwatch and noted the valve shut smoothly and well within
the time required. No other problems were noted.
No violations or deviations were identified.
7.
-Followup of Previously Identified Items (92701)
a.
(Closed) Violation 382/8602-03:
Failure to comply with Technical Specification 3.0.4 which prohibits changing modes while relying on
action statements to satisfy limiting conditions for operation. On
December 16, 1985, the licensee entered Mode 3 without containment
spray operable, as required, due to an isolation valve (CS-111B)
reach rod being disconnected. This condition misled the operator
into thinking he had opened the valve when in fact all he did was
turn the reach rod handwheel. Control room operators were further
confused by a typographical error in the Operations Annunciators
Response procedure. On May 16, 1986, the licensee's response to the
violations comitted to revise certain procedures, change the label
on the appropriate annunciator window, compile a list of all manual
valves operated by reach rods, and install warning tags on or near
all reach rod handwheels to instruct plant operators to verify actual
valve positions when using the reach rods. The NRC inspectors
verified that all of the above actions had been taken and noted,
after nearly two years, that most of the warning tags were still
installed. A few had broken off, and the licensee promptly
reinstalled them. None have been found broken off lately. The
inspectors expressed concern that the all-inclusive installation of
warning tags may have been carried out to excess. Many of the reach
rods were installed to reduce radiological exposure. To gain access
to the valve and verify position may involve worse consequences in
terms of radiological exposure than finding the valve out of position
later. The licensee committed to re-evaluate the list and take these
concerns into account, thus possibly reducing the list to only those
valves which are important to safety. This action would be an ALARA
improvement which need not be formally tracked.
This violation is
closed.
(Closed)OpenItem 382/8608-01: NRR evaluation of licensee's failure
b.
to perform the monthly logarithmic power level channel functional
test when at power. Table 4.3-1 of the Technical Specifications
,
_.
'
-
,
,
,
13
,
requires this test in Modes 1, 2, 3, 4, and 5.
Table 3.3-1 requires
the instrument to be operable while the reactor is critical, but when
above' 0.0001 percent power, the trip function may be manually
bypassed.
If it is not bypassed, the reactor will trip at about
0.25 percent power. The licensee's surveillance procedure, written
to satisfy the above technical specification requirement, takes
exception to performing the above functional test when the reactor is
'
critical, because the trip is bypassed above 0.0001 percent power and
to do the test would require disconnecting input cabling. Since the
Technical S)ecifications permit bypassing the trip function thus
rendering t1e instrument inoperable, it stands to reason that there
is no need to do a functional test while the instrument is
inoperable. However, the instrument should be tested promptly after
shutting down the reactor. A technical specification change request
has been submitted to this effect and is presently under review by
NRR. The purpos'e of this item was to track the licensee's actions to
initiate documentation to resolve the. issue. The change request
accomplished this, therefore, the item is. closed.
No violations or deviations were identified.
8.
Licensee Event Report (LER) Followup (92712)
The LERs listed below were reviewed and closed. The NRC inspector
verified that reporting requirements had=been met, causes had been
. identified, corrective actions appeared appropriate, generic applicability
had been considered, and that the LER forms were complete. The NRC
inspector confirmed that unreviewed safety questions and violations of
technical specifications, license conditions, or other regulatory
requirements had been adequately described.
a.
(Closed)LER 382/87-012. "Two Reactor Trips Due to Inadequate
Procedures."
b.
(Closed)LER 382/87-014. "Fire Hose _ House and Computer Halon System
Surveillance Intervals Exceeded Due to Personnel Error."
c.
(Closed)LER 382/87-026, "Containment Electric Penetration Backup
Protection Inoperable Due to Inadequate Construction Documentation."
d.
(Closed)LER 382/88-004, "Containment Isolation Valve Position
Indication Not Environmentally Qualified Due to Inadequate
.
Engineering Review."
'
No violations or deviations were identified.
9.
Containment Integrated Leak Rate Test (70313, 70307, & 70323)
The objective of this inspection was to ascertain through direct
observation, records review, and independent calculations whether the
containment Integrated Leak Rate Test (CILRT) was conducted in compliance
~
hI
.-
,
.
. et i
14
_
with the licensee's procedure and as required by the Waterford-3 Technical
Specifications, 10 CFR 50, Appendix J, and ANSI N45.4-1972, "Leakage-rate
Testing of Containment Structures for Nuclear Reactors."
l
The NRC resident inspectors witnessed portions of the preparations for,
and conduct of, the test.
Emphasis was placed on compliance with the
required plant conditions, test procedure requirements and administrative
requirements. The inspectors also performed rough calculations to
establish a confidence in the licensee's computer programs which were used
to determine the containment leak rate.
An NRC regional inspector was unavailable to witness the preparations for
the test and the actual test performance, but subsequently reviewed the
local leak rate test (LLRT) and CILRT data as discussed below.
The CILRT commenced on May 22, 1988, at 2:10 a.m. as pressurization of the
reactor containment began.
Preparation had been underway for several days
preceding the start of the test. The resident inspectors verified
accomplishment of prerequisites such as a general inspection of the
accessible portions of the interior and exterior containment surfaces; a
containment area survey for temperature differentials; closure of the
maintenance hatch; removal of fire extinguishers; and installation and
calibration of instrumentation. The inspectors reviewed Surveillance
Procedure PE-5-001, Revision 1, Change 2, "Containment Integrated Leak
Rate Test." All of the appropriate prerequisites, conditions, required
equipment, and valve / breaker lineups were satisfactorily completed and
signed off as required.
The resident inspectors conducted a walkdown of
the test air lines from the compressors to the point of entry into the
containment using the test procedure containment pressurization flow
diagram ( Attachment 10.8) and test instrument schematic (Attachment 10.9).
The equipment required for satisfactory completion of the test was
installed in a professional manner. There were a few minor disparities
identified by the inspector which the licensee's representative in charge
of the test explained to the inspector's satisfaction. They were as
follows:
a.
There was a portable process radiation monitor connected to
Valve LRT-112. This did not appear on Attachment 10.8.
It was
installed to monitor the effluent when the containment is vented
through LRT-105 at the conclusion of the test.
b.
The pressure and temperature indicators upstream of LRT-101 were not
present as shown on Attachment 10.8.
Since a dew point instrument
was installed at LRT-102 (also not shown on Attachment 10.8), there
was no need for these instruments. The air dryers and the air
compressors provided adequate and redundant pressure indication,
An absolute pressure instrument and some tubing and valves were
c.
connected at the sight glass flowmeter used during the verification
This was not shown on Attachaent 10.9 but is needed to obtain
test.
corrected flow readings from the flow meter.
. _ _
_ _ _ _ _ - _ _ _ _ .
'
-
.
.
.$
15
d.
The atmospheric vent valve shown at the Heise Gauge on
Attachment 10.9 was missing.
This might only be needed as a
convenience item to check the gauge.
The licensee's representative stated that he intended to improve
Attachments 10.8 and 10.9 for the next CILRT. This action is acceptable
and does not require followup.
'
~ The licensee elected to perfom the abbreviated leakage rate test in
accordance with Topical Report BN-TOP-1, Revision 1, "Testing Criteria for
Integrated Leakage Rate Testing of Primary Containment Structures for
Nuclear Power Plants," provided by Bechtel Corp (oration and currently
permitted by the NRC.
This is an 8-hour test afterstabilizing)in
lieu of the 24-hour test.
Containment pressurization was achieved at about I p.m. on May 22, 1988.
After stabilizing for about five hours, the 8-hour test period was
implemented at 6:00 p.m.
Data was taken using the plant monitoring
computer with 2 pressure indication transmitters,10 humidity measuring
devices, and 40 platinum element dry bulb resistance temperature
detectors.
For the eight hours that followed, the computer obtained and recorded
weighted average temperature and humidity, pressure and vapor pressure.
- dry air mass, and leakage rates every 15 minutes. At the end of eight
hours, the computer calculated a containment leakage rate of about
0.05 percent per day. Technical Specification 3.6.1.2 requires an overall
integrated leakage rate of less than or equal to 0.50 percent per day,
therefore, the results appeared well within the limit. Upon completion of
the CILRT, the licensee conducted the supplemental test required by
Technical Specification 4.6.1.2.c.
This is a 4-hour test where a known
leak is superimposed to verify the accuracy of the CILRT. The results of
the supplemental test were well within the acceptance criterion of
25 percent of the allowed leakage.
The resident inspector conducted independent rough calculations using a
programmable calculator and verified with reasonable confidence that the
licensee's results were accurate and valid.
The regional inspector later reviewed the completed copy of CILRT Test
Procedure PE-5-001, Revision 1, Change 2.
This review was performed to
verify that the signatures required throughout the test procedure were
present, and to verify that the post-test valve realignment had been
performed. The inspector verified that all the valves that had been
addressed in the pre-test valve alignment had been addressed again.
The regional inspector also interviewed the CILRT test director and other
personnel involved in the test. The purpose of the interviews was to
detemine how the test was performed, if any equipment was repaired that
,
'
, . .
-
,
t
16
,
might have affected the as-found conditions for the CILRT, and if there
were any other conditions that the NRC should be made aware of. No
problems were identified.
Finally, the inspector input the CILRT data provided by the CILRT test
director into the NRC computer program "CILRT 2" to verify the results
'that the licensee had calculated.
The results were satisfactory.
No ' violations or deviations were identified.
10.
Refueling Activity Observations (86700)
On May 9,1988, while lowering the in-core instrument (ICI) thimble
support plate into the upper reactor internals, the plate started rotating
and cocking. The licensee halted the' lowering operations.
ICI location
A-14 thimble tube end was observed to be bowed approximately 60 degrees
out of_line. Upon further inspection, it was. discovered that the ICI
thimble tube was missing from the lower end of the coupling with the ICI
protruding from the coupling and continuing into the upper internals. The
ICI coming out of the tube took a sharp bend back towards its tube in the-
upper internals. . Upon inspection of the discharged fuel assembly from the
A-14 location, the lower section of the ICI thimble was found protruding
4
above the top of the fuel upper end fitting. The upper section of the
thimble, from the ICI thimble support plate to the coupling nut along with
the ICI, was cut off and permanently removed from the upper internal
assembly.
Combustion Engineering prepared an evaluation report for the licensee.
,
The report postulated the failure to be an isolated manufacturing anomaly,
i.e., insufficient torque, cross threading, or improper lock pin
installation. The report stated that there are a total of 356 thimbles in
c
various plants with an accumulated 50 plant-operating years. This is the
first and only failure of this type reported. The report provided a basis
for continued operation without an ICI at position A-14, which appeared to
be sound.
Combustion Engineering recommended installation of a dummy ICI
to provide a dampening effect against vibration of the curved tubes, make
some physical and administrative adjustments to the movable in-core
detector system to prevent entry to location A-14, and to consider impact
on the core operating limit supervisory system (COLSS). The inspectors
discussed this with the licensee, and all of these recommendations were
followed. A copy of the Combustion Engineering report along with the
licensee's evaluation was forwarded to NRC Region IV for review.
On May 7, 1988, the inspector monitored cleanup activities and removal of
the reactor vessel ultrasonic test equipment in preparation for final core
mapping. Radiological work practices appeared to be adequate, however,
housekeeping, particularly in' the area of the refueling crane, was
degraded. Pieces of trash, loose hand tools, and other debris were
scattered about. This was a concern because the reactor vessel was still
apen, though no core alterations were in progress.
Based on other
.
_
..
. _ _
.
.
.--
.
_
..
-
17
observations, this was an isolated occurrence because housekeeping in the
'
'
refueling trea has been satisfactory.
Imediately upon identifying this
to the refueling supervisor, the area was cleaned up.
,
No violations or deviations were identified.
11. Startup Testing-Refueling (72700)
The objective 6f this inspection was to verify that facility operaticn
following refueling was in conformance with NRC requirements and licensee
procedures.
The NRC inspector ~ observed the withdrawal of the shutdown, part-length,
and regulating control element assemblies (CEAs) in preparation for
insertion time measurement per Procedure NE-2-020, Revision 1, "CEA
Insertion Time Measurement." When attempting to withdraw Regulatory
-
Group 3, Control Element Assembly 61 would not transfer from the lower to
upper gripper assembly. After repairs, all control elements were
withdrawn and then,successfully inserted within three seconds as required
by NE-2-020 and the Technical Specifications.
On May 28, 1988, the motor for containment cooling fan "C" failed.
The
plant was in Mode 3 (hot standby) with preperations underway to commence
the initial approach to criticality following refueling. Technical Specification 3.6.2.2 requires all four cooling fans to be operable during
Modes 1, 2, 3, and 4.
If one fan becomes inoperable in Mode 3, it must be
restored within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the plant cooled down within the following
30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The licensee obtained enforcement discretion to allow startup
and low power physics-testing while repairing or replacing the motor. A
justification for continued operation was submitted to the Region IV
Regional Administrator showing that it was safe to operate with the three
remaining fans at power levels below 0.1 percent power.
On May 29, 1988, at 8:35 a.m., the plant entered Mode 2, and at
10:57 a.m., reactor criticality was achieved.
The inspectors witnessed
the startup and portions of the following startup test procedures:
a.
NE-2-030, P.evision 0, "Initial Criticality Following Refueling." The
inspectors observed the initial approach to criticality by boron
dilution.
The reactor was observed to be critical with Control
Element Assembly Regulating Group 6 at 75 inches withdrawn and a
boron concentration of 1523 ppm.
b.
NE-2-003, Revision 0, "Post-Refueling Startup Testing Controlling
Document." On May 29, 1988, the inspectors witnessed part of the
establishment of base power level limits for low power physics
testing per Attachment 9.8 and then reviewed the completed data. No
problems were found.
,
NE-2-040, Revision 0, "CEA Group Watch and CEA Coupling Check." On
'
c.
'May 29, 1988, the inspectors witnessed the CEA coupling checks for
,
,
_-
- _ _
_
_.
_
_.
, .
.
'
,
18
about 15 CEAs. Subsequent review of the data confirmed that all CEAs
were in' fact coupled to the drive motors. On May 30, 1988, the
inspectors witnessed detennination of the reference group (Group B)
worth.
During this test, the amount of negative reactivity inserted
with Group B was plotted on the test recorder / computer as Group B was
driven into the core concurrent with compensating boron dilution.
This information will be used in the determination of the other CEA
group worths later.
On May 31, 1988, the licensee requested a tenporary waiver of compliance
from Technical Specification 3.6.2.2 to allow progress to full power based
on a re-analysis.that only one containment cooling fan per train is needed
for safe operation. This was granted by NRR in a letter dated June 2,
1988. Technical Specification 3.6.2.2 has since been permanently changed
to reflect the single fan requirement by Amendment 39.
No violations or deviations were identified.
12. Emergency Diesel Generator Inspection (62702)
A representative of NRR conducted an inspection of the licensee's
maintenance activities on Emergency Diesel Generators (EDG) A and B during
the period of May 23-26, 1988. The purpose of the inspection was to
evaluate the licensee's maintenance program in terms of how it would or
would not enhance EDG reliability.
The primary focus of the inspection
was.(1) a review of the five year inspection of EDGs, and (2) a review of
the licensee's implementation of recommendations contained in bulletins
issued by the EDG vendor.
In December 1987, an inspection of the licensee's vendor interface program
was conducted. This was documented in NRC Inspection Report 50-382/87-19,
dated May 12,.1988. Results of this inspection showed that the licensee
had not implemented a number of EDG vendor recommendations.
In early
1988, problems with EDG pneumatic shut down devices were identified.
Both
issues were compounded by questions regarding reportability of certain EDG
operational events. The combination of incidents served to create a
perception of poor EDG reliability.
A previous inspection of the problems
with EDG pneumatic devices showed that the licensee's EDG maintenance
program was in fact an excellent program, and that the perception of poor
EDG reliability was incorrect.
See NRC Inspection Report 50-382/88-08.
This inspection was conducted for the purpose of verifying the previous
findings and to assess the licensee's current position regarding vendor
recommendations.
The following documents were reviewed during the inspection:
Mechanical Maintenance Procedure MM-3-015. "Surveillance Procedure
a.
Emergency Diesel Engine Inspection."
b.
Work Package associated with implementation of MM-3-015 for EDG "A".
.
._ __ _
___
_.
.
. _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -
-
,
.
.
, ~ .C.
19
c.
LP&L Pre-Summary of EDG Outage During Refuel 2, dated May 17, 1987.
l
d.
LP&L Letter dated May 17, 1987, suggesting changes to inspection
procedures in Section 15'of EDG . technical manual.
e.
Cooper Energy Services (CES) letter dated June 23, 1987, in response
to LP&L suggested changes to.the EDG Technical Manual.
f.
CES letter dated March 21, 1988, supplementing CES letter of June 23,
1987.
, eport dated April 18, 1988, - Electronic Engine Analysis of EDG
R
g.
.
h.
Surveillance Procedure OP-903-069, "Integrated EDG/ESF Test."
1.
Vibration data for EDG A - April 15, 1988.
j.
Vibration data for EDG B - May 14, 1988.
k.
Section 15 of the EDG technical manual.
In addition to reviewing.the above documentation, the inspector discussed
the vibration monitoring program for EDGs with the licensee's
representatives. This discussion covered points on the engines and what
engine auxiliaries were monitored for vibration, the type of equipment
used, and the frequency of monitoring. The licensee also demonstrated how
the raw vibration data was processed and some of the different ways the
data can be retrieved from computer storage and displayed or printed out.
s
On the basis of the review of the above data and discussions with
cognizant personnel, the inspector found that the licensee is following
the EDG vendor's reconnended five year inspection program.
Procedure MM-3-015 includes all of the inspection steps called out in
Chapter 15 of the EDG technical manual as modified by agreement between
the licensee and the vendor.
The modifications to the technical manual
primarily cover deletion of certain requirements to disassemble the diesel
,
engines for the purpose of inspecting internal components for wear and/or
degradation. The agreement to delete certain inspection requirements is
made on the basis of the predictive maintenance program the licensee has
implemented. This program utilizes data from an electronic engine
analyzer, vibration data, trending of engine operating parameters, and
boroscope inspections as a substitute for physical disassembly to evaluate
engine condition. The modifications to the vendor reconnended inspection
program are acceptable because the licensee's predictive maintenance
'
program will provide adequate information to assess engine condition
witho;c major disassembly and the attendant possibility for incorrect
reassanbly. Results of the five year inspection, including electronic
engine analyzer data, show the diesel generators to be in excellent
condition except for the engine cylinder load balance.
...
.
-.
.
-.
.
.
y
4
.
A
. . .
I
20
In NRC Inspection Report 50-382/87-19 covering vendor interface, the
licensee was cited for not having implemented the recomendations
contained in 17 bulletins issued by the diesel generator vendor. This
inspection included a review of licensee actions since the vendor
interface inspection to' implement vendor recommendations with the
following results. Two of the 17 vendor bulletins were not applicable to
' Waterford-3 and required no action. Of the remaining 15, all have been
implemented as of this inspection.
It should be noted, however, that of
the above-15 vendor recommendations, 12 did not require any immediate
action because they involved such things as product improvements,
information, clarification, or modifications only if troubles had been
observed. Lack of implementation of these recommendations did/would not
impair diesel generator reliability._ The remaining three recomendations,
if_not implemented, could have impaired diesel generator reliability. The
most serious of the three concerns modifications to the turbocharger
supports. The turbocharger, however, is included in the vibration
monitoring portion of the diesel generator predictive ma1ntenance program,
and any problems arising from inadequate supports would have been noted
through a change in vibration data. Therefore, diesel-generator
reliability was not materially affected by failure to implement this
recommendation at the time it was issued. Viewed in perspective, there
are only two cases where the licensee was delinquent in implementing
vendor recommendations affecting diesel generator reliability or providing
compensating measures, as opposed to the 17 cases previously reported. As
of this inspection, all applicable vendor recomendations had been
implemented.
In conclusion, the results of this inspection confirm previous findings,
i.e., the licensee has developed and implemented a strong predictive
maintenance program for the diesel generators. On the basis of this
program, the licensee has completed an effective five year inspection of
the diesel generators in accordance with modified vendor recommendations.
In addition, the inspector verified that all applicable vendor
.
recomendations for dietel generator improvements had been implemented.
In sumary, the results of the five year inspection and the implementation
-
of vendor recomendations, when viewed in light of the ongoing predictive
maintenance program, provide assurance that the diesel generaters at
Waterford-3 are, and will continue to be, highly reliable.
,
On the basis of the inspection results, the following recomandations are
made:
The cylinder to cylinder load balance on the diesel engines should be
a.
brought within vendor recommendation tolerances at the earliest
opportunity. The degree of imoalance on the engines at Haterford-3
will have a detrimental effect on engine reliability if not
corrected.
<
v
,-w--
y
,
.
"h
U-
'
'
i
21
'
b.
The ' predictive maintenance progra'n could be improved by expanding the
vibration monitoring portion to include all diesel generator
l
auxiliaries.
No violations or deviations were identified.
13. Plant Status (71707)
The inspection period began with the core completely off-loaded and
-
reactor vessel inspection in progress. Core reloading was connenced on
May 3, 1988, and completed on May 6, 1988. The reactor head was placed
back on the vessel on May 12, 1988.
Reactor coolant system filling and
venting was completed on May 20, 1988. On May 26, 1988, the plant entered
Mode 3.
Reactor criticality was achieved on May 29, 1988. The plant
entered Mode 1 and was placed on the grid on June 1,1988. On June 9,
1988, the plant reached full power.
Power was reduced to 60 percent on June 10, 1988, to remove the "A" main
feed pump from service for an inspection because of high vibration
readings. After the inspection was complete, the main feed pump was
placed back in service.
Power was then maintained at 60 percent because
i
I
of low demand on the power grid.
On June 13, 1988,-the unit was shut down from 70 percent power because of
a reactor coolant system unidentified leak rate exceeding the Technical
Specification limit of one gallon per minute.
The source of excessive
l
leakage was determined to be through two series reactor coolant drain
valves. After torquing the valves in the shut direction and verifying
reactor coolant system leakage within the TS limit, startup was commenced
on June 14. 1988.
During the June 14 startup), _the reactor tripped from 17 percent power d
to low steam generator (SG water level. All systems appeared to respond
The licensee was conducting a main turbine overspeed protection
nonnally(.OPC) system test at 1800 RPM. This test is routinely done at
control
about 500 RPM.. When the operator enabled the turbine to recover, there
was a 'large speed error in the controls which caused the governor valves
to open rapidly, thus causing SG swell. This, in turn, tripped the
feedwater isolation valves shut on high SG 1evel. By the time the
operators restored feedwater flow, the reactor tripped on low SG level.
'
The licensee intends to add a caution to the procedure to prevent the
operator from introducing a high speed error in the future when the
turbine OPC test is done.
The reactor was critical again on June 15, 1988, and subsequently returned
to full power where it remained through the completion of the inspection
period.
No violations or deviations were identified.
- - -
_
[;
_ ..
...
,
-
-"
.
,. +
,
.
s
I
.
_
22-
.
14.. Exit-Interview
'
The inspection scope and findings were sumarizea on June 17, 1988, with
those persons indicated in paragraph 1 above. The licensee acknowledged
h
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.