ML16342A694
| ML16342A694 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/19/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342A693 | List: |
| References | |
| 50-275-98-20, 50-323-98-20, NUDOCS 9902250315 | |
| Download: ML16342A694 (52) | |
See also: IR 05000275/1998020
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
'pproved
By:
50-275
50-323
DPR-82
50-275/98-20
50-323/98-20
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units 1 and 2
7 ~/~ miles NW of Avila Beach
Avila Beach, California
December 6, 1998, through January 23, 1999
D. L. Proulx, Senior Resident Inspector
D. G. Acker, Resident Inspector
I. A: Barnes, Technical Assistant, Division of Reactor Safety (DRS)
C. A. Clark, Reactor Inspector, Engineering and Maintenance Branch,
L. J. Smith, Acting Chief, Project Branch E
ATTACHMENT:
Supplemental Information
99022503i5 9902i9
ADQCK 05000275
8
0
EXECUTIVE SUMMARY
'iablo
Canyon Nu'clear Power Plant, Units 1 and 2
NRC Inspection Report 50-275/98-20; 50-323/98-20
This inspection included aspects of licensee operations, maintenance,
engineering and plant
support.
The report covers a 7-week period of resident inspection.
~Oerations
The inspectors monitored portions of each reactor startup and power ascension and
determined that operators manipulated both units in a careful manner in accordance
with procedures (Section 01.1).
Operator identification of increasing Unit 1 unidentified leakage and shut down of Unit 1
was an example of good attention to detail and conservative decision making. The root
cause analysis, repairs, and retesting of a leaking threaded joint on Reactor Coolant
Pump (RCP) 1-3 were performed well (Section 01.2).
Overall, Unit 1 operators responded well to two failures of expansion joints. However,
operators initiallycross-connected
intake cooling system trains upon rupture of an
expansion joint that could have resulted in loss of both Unit 1 circulating water pumps.
Operators recognized and corrected this error before any adverse impact occurred
(Section 01.3)
Maintenance
With the exception of corroded instrument lines associated with the outside tanks, the
external condition of plant components observed during tours was good (Section 02:2).
Routine maintenance and surveillance tasks observed were performed satisfactorily
(Sections M1.1 and M1.2).
The inspectors concluded that vendor information provided to ensure acceptable
installation arid maintenance of elastomeric expansion joints was not properly
implemented into the maintenance program. The licensee's failure to replace expansion
joints in a timely manner led to failure of two joints and caused partial flooding of the
intake structure and loss of a circulating water pump. These failures required operators
to quickly reduce power to preclude a reactor trip. The operability assessment
supporting the operability of the safety-related expansion joints failed to reference
vendor recommendations
on replacement frequency and seismic interactions.
As
a'esult,
the licensee did not identify an inoperable elastomeric joint, until challenged by
the inspector.
Further NRC review of the licensee's evaluation of this degraded
condition and application of the Maintenance Rule program to expansion joints is
required (Section. M2.1).
0
'I
Encnineering
The prompt operability assessment
associated with the Unit 1 condensate
storage tank
leak was an example of good engineering support for operations (Section E2.1).
The licensee had implemented comprehensive actions in both units to increase tubing
stress corrosion resistance and minimize steam generator tube degradation
(Section E8.3).
Housekeeping
in the Unit 1 containment building was excellent in that the area near the
containment recirculation sumps was clear, the containment building was free of loose
work material and debris, and only minor leaks existed in pump and valve packing
(Section 02.1).
~
A noncited violation of 10 CFR 20.1902(b), consistent with Section VII.B.1 of the
Enforcement Policy,'was identified for failure to properly post a high radiation area.
Radiation protection personnel failed to post a back entrance to Residual Heat Removal
Pump Room 1-2. Although the root cause analysis was inconclusive, corrective actions
were satisfactory (Section R1.1).
The inspectors noted that the licensee had inappropriately stored compressed
gas
cylinders in the auxiliary building. Contrary to plant procedures,
personnel had not
obtained a transient combustible permit, as required for storing flammable material,
which resulted in a violation of Technical Specification 6.8.1.h. The licensee
demonstrated that this instance involved low likelihood of a fire involving hydrogen gas.
. The licensee determined the cause of the violation, identified other examples, and took
appropriate corrective actions; therefore, no response was required (Section F1.1).
0
Re ort Details
Summa
of Plant Status
Unit 1 began this inspection period at 100 percent power.
On December 17, 1998, Unit 1 was
shut down because of a weld leak on the component cooling water side of the RCP 1-3 lube oil
cooler.
Following replacement of the lube oil cooler and resolution of boric acid wastage
concerns on RCP 1-3 carbon steel bolts, operators increased Unit 1 power on December 24.
Operators synchronized the plant to the grid on December 25 and returned power to
100 percent on December 26. Unit 1 continued to operate at essentially 100 percent power
until the end of this inspection period.
Unit 2 began this inspection period at 8 percent power, with power ascension
in progress
following a forced outage.
Unit 2 was synchronized to the grid on December 8 and achieved
100 percent power on December 9. Unit 2 continued to operate at essentially 100 percent
power until the end of this inspection period.
I. ~Oerattons
01
Conduct of Operations
01.1
General Comments
71707
The inspectors visited the control room and toured the plant on a frequent basis when
on site, including periodic backshift inspections.
In general, the performance of plant
operators reflected a focus on safety, evidenced by self- and peer-checking.
The
utilization of three-way communications continued to improve, and operator responses
to alarms were observed to be prompt and appropriate to the circumstances.
The inspectors monitored portions of each reactor startup and power ascension and
determined that operators manipulated both units in a careful manner in accordance
with procedures.
In addition, on December 17, the inspectors witnessed portions of the
Unit 1 reactor shutdown and determined that operators manipulated Unit 1 in a careful
manner in accordance
with procedures.
01.2
Shutdown of Unit 1 because
of Weld Leak
a.
Ins ection Sco
e 92901
93702
The inspectors evaluated the response to an increase in unidentified leakage and
subsequent
reactor shutdown.
Observations and Findin s
On December 16, 1998, during daily sump calculations, operators detected an increase
in unidentified leakage in Unit 1. The unidentified leakage rate had increased from
essentially 0 to 0.21 gpm over the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Because 'of the high radiation
0
-2-
levels, operators reduced Unit 1 power to 50 percent to allow entry into the RCP 1-3
area.
Upon examination, the licensee identified a weld leak on the component cooling
water side of the RCP 1-3 upper bearing lube oil cooler.
The licensee replaced the cooler with a spare from the warehouse and performed an
operational pressure test to ensure th'e leakage was corrected.
The failure analysis of
the weld failure revealed that vibration induced high cycle fatigue caused the failure.
The licensee identified that the vibration of the lube oil cooler for RCP 1-3 was
significantly higher than the other three Unit 1 RCPs.
t
On December 18, during routine inspections of the RCP 1-3 work area, a buildup of
boric acid on the pump was identified. The licensee determined that the leakage was
reactor coolant system pressure boundary leakage from a RCP 1-3 lower radial bearing
resistance temperature detector thermowell. Consequently, the licensee cooled down
the plant and entered Cold Shutdown on December 19, as required by the Technical
Specifications.
Mechanics repaired the leak by replacing the threaded resistance
temperature detector on December 20.
Following the leak repair, the licensee consulted with the vendor as to the effects of the
boric acid on RCP 1-3. The vendor noted previous problems with Westinghouse plants
associated
with boric acid wastage of the RCP motor stand base bolts. The licensee
inspected these bolts on December 20 and noted that 6 of 24 bolts exhibited significant
wastage.
The licensee examined all of the motor stand bolts associated
with RCP 1-3
to determine if further action was required.
Based on these inspections, the licensee
replaced all of the RCP 1-3 motor stand bolts. No other significant boric acid wastage
was identified on the other RCPs.
The inspectors visually confirmed that the licensee
properly assessed
the condition of RCP 1-3.
The licensee determined the root cause of the leak to be incorrect thread engagement
of Thermowell TE-168. The inspectors found the root cause assessment
satisfactory.
Conclusions
Operator identification of increasing Unit 1 unidentified leakage and shut down of Unit 1
was an example of good attention to detail and conservative decision making. The root
cause analysis, repairs, and retesting of a leaking threaded joint on RCP 1-3 were
performed well.
0 erator Res
onse to Ex ansion Joint Failures
Ins ection Sco
e 92901
93702
The inspectors evaluated operator response to two failures of expansion joints in the
intake structure.
This inspection included observation of operator response and review
of licensee evaluations.
-3-
Observations and Findin s
On December 1, 1998, with Unit 1 at 50 percent power and Unit 2 in Hot Shutdown, an
expansion joint failed that partially flooded the intake structure.
Approximately 3 feet of
water accumulated
in the area near the Units 1 and 2 circulating water pumps. This
expansion joint was associated with the cross-connect
line between the Unit 1 screen
wash header and the Unit 2 service cooling system.
Upon notification, operators
ramped Unit 1 reactor power in a controlled manner to 40 percent, in anticipation of
having to secure the operating circulating water pump if the flooding worsened.
Once
the source of the leak was identified, operators terminated the power decrease
and
isolated the cross-connect
line.'quipment
damage was limited to intake structure sump pumps and light fixtures. The
licensee pumped the excess water out of the intake structure and inspected the area for
further damage.
No safety-related equipment was affected.
The inspectors responded to the control room, witnessed the operator response to this
event, and determined that operators carefully manipulated Unit 1 and took prompt
action to mitigate the event.
In addition, the inspectors examined the flooded areas and
concurred with the assessment
of the impact of flooding. The root cause of the
expansion joint failure is discussed
in Section M2.1 of this report.
On December 2, with Unit 1 at 97 percent power, the Unit 1 intake cooling system
(which cooled the pump motor windings) expansion joint for Circulating Water Pump 1-2
began leaking. Operators noted that the leakage was minor and intake cooling head
tank level could be maintained by the makeup system.
As the shift progressed,
the leak
through this expansion joint worsened, and operators could no longer maintain head
tank level. Also, mechanics were unable to affect temporary repairs to mitigate the leak
. from the expansion joint.
Subsequently,
the failure of the expansion joint progressed to the point that a low
pressure alarm occurred in the intake cooling system header for Circulating Water
Pump 1-2.
Because this low pressure condition initiated a timer that automatically trips
the circulating pump after 5 minutes, operators decreased
Unit 1 power to 50 percent,
then secured Circulating Water Pump 1-2.
One of the initial actions had the operators open the two cross-connect valves between
the intake cooling headers for Circulating Water Pumps 1-2 and 1-1. This action
propagated the expansion joint failure leakage to the other intake cooling system and
could have resulted in a similar low pressure condition and subsequent
trip of Circulating
Water Pump 1-1. Shortly after taking this action, operators recognized the
inappropriateness
of the action, closed the cross-connect valves between the two intake
cooling headers,
and isolated the fault. The leakage was contained in the small vault
associated
with the expansion joint and no other equipment was affected by the
presence of the standing water.
Procedure AR PK13-12, "[Circulating Water Pump] CWP 1-2 Cooling Water Low
Pressure," Revision 5, provided direction for operator response to a low pressure
-4-
condition for the intake cooling header.
Step 5.1 of Procedure AR PK13-12 required
operators to open cross-connect valves as an initial action to determine if the condition
clears.
Step 5.3 stated that, if the low pressure alarm does not clear and there is a
subsequent
tow head tank level alarm, ~sus
ect a rupture and reclose the cross-connect
valves.
On December 2, the operators knew that an expansion joint rupture and low
intake cooling head tank level condition existed prior to the receipt of the low header
pressure alarm, yet took procedural actions contrary to this knowledge.
The inspectors responded to the control room and witnessed operator recovery of the
leak. The inspectors concluded that operator response was satisfactory with the
exception of initiallycross-connecting
the intake cooling headers.
In addition, the
inspectors examined the area of the expansion joint failure and noted that no other
equipment was affected.
The root cause of failure of the expansion joint is discussed
in
Section M1.2 of this report.
The Operations Director obtained personnel statements with respect to the operator
response.
The licensee concurred that operator response was satisfactory with the
exception of the initial cross-connecting
of the intake cooling system headers.
The
licensee briefed the shift foreman on thoroughly understanding the consequences
of
taking actions prior to proceeding.
In addition, the licensee stated that they would
evaluate the need to enhance Procedure AR PK13-12.
c.
Conclusions
Overall, Unit 1 operators responded well to two failures of expansion joints. However,
operators initiallycross-connected
intake cooling system trains upon rupture of an
expansion joint that could have resulted in loss of both Unit 1 circulating water pumps.
Operators recognized and corrected this error before any adverse impact occurred.
02
Operational Status of Facilities and Equipment
02.1
Unit 1 Containment Tour
a.
General Comments
71707
On December 21, 1998, during a forced outage of Unit 1, the inspectors toured the
containment to assess
readiness for restart.
The inspectors noted that the area near
the containment recirculation sumps was clear, the containment building was free of
loose work material and debris, and only minor pump and valve packing leaks existed.
The inspectors concluded that the licensee had satisfactorily restored the Unit 1
containment materiel condition such that the plant was ready for restart.
-5-
02.2
Plant Materiel Condition
a.
General Comments
71707
The inspectors toured both units on a frequent basis to assess
the materiel condition of
safety-related areas.
The inspectors identified minor housekeeping
items, such as
loose tools and unattended ladders, that were brought to the attention of the shift
supervisor and immediately corrected.
With the exception of corroded outside tank
instrument lines {refer to Section E1.1), the external condition of components observed
during plant tours was good.
II. Maintenance
M1
Conduct of Maintenance
M1.1
General Comments on Maintenance Activities
a.
Ins ection Sco
e 62707
The inspectors observed portions of work activities covered by the following work orders
and procedures:
R0187104, "Lubricate [AuxiliaryFeedwater] Turbine Over speed Trip Linkages"
(Unit 1)
~
MP M.3.7A, "Terry Turbine Throttle Trip Valve Preventive Maintenance,"
Revision
1 (Unit 1)
~
R0133000, "MS-1-RV-57 [AuxiliaryFeedwater Turbine Casing Relief Valve],
Test, Stage, and Replace" (Unit 1)
The inspectors concluded that each of these routine work activities were performed
satisfactorily.
M1.2
Surveillance Observations
a.
Ins ection Sco
e 61726
The inspectors observed performance of all or portions of the following procedures and
reviewed completed data.
Procedure R-3A, "Use of Flux Mapping Equipment," Revision OA (Unit 2)
Procedure STP R-3D, "Routine Monthly Flux Map," Revision 18 {Unit2)
Procedure STP R-27A, "Monthly Incore Thermocouple Evaluation," Revision 3
(Unit 2)
0
-6-
Procedure STP R-13B, "Nuclear Power Range Incore/Excore Single-Point
Calibration Data," Revision 2 (Unit 2)
~
Procedure STP M-81A, "Diesel Engine Generator Inspection (Every Refueling
Outage)," Revision 13 (Unit 1)
b.
Observations and Findin s
The surveillance tests were satisfactorily performed.
For the procedures related to
incore/excore detector calibration, the data indicated no abnormal axial offset. For
Procedure STP M-81A, the licensee performed an engine analysis on Diesel Engine
Generator 1-2. The procedure allowed this analysis to be performed prior to the outage,
which is scheduled to start February 7, 1999. The inspectors reviewed the licensee's
justification for performing this task on-line and determined that it was satisfactory.
Conclusions
The inspectors concluded that surveillances observed during this inspection period were
performed satisfactorily.
M2
Maintenance and Materiel Condition of Facilities and Equipment
~
~
~
~
M2.1
Failure to lm lement Vendor Instructions for Elastomeric Ex ansion Joints
Ins ection Sco
e 37551
62707
The inspectors reviewed the circumstances surrounding two recent failures of flexible
rubber/elastomeric expansion joints. An elastomeric expansion joint was a specially
designed section of pipe inserted within a rigid piping system to provide flexibility. The
inspectors reviewed action requests (AR) and work packages and interviewed system
engineers,
maintenance personnel, nondestructive examination personnel, and
management.
The inspectors observed licensee corrective actions in response
to the
recent expansion joint failures.
b.
Observations and Findin s
Two recent expansion joint failures are discussed below:
On December
1, 1998, as noted in AR A0472252, the screen wash auxiliary
header expansion joint failed, resulting in flooding at the intake structure.
The
expansion joint was 24-inch inside diameter by 12-inch long.
On December 2, the Circulating Water Pump 1-2 motor cooling inlet-outside
housing flexible elastomeric expansion joint (SW-1-EJ21) failed. The expansion
joint inside diameter was 6 inches and it was 6 inches long.
-7-
b.1
Vendor Information
The inspectors were informed by the system engineers that Uniroyal had provided the
original elastomeric expansion joints installed at Diablo Canyon.
1Nhen Uniroyal
stopped manufacturing elastomeric expansion joints, replacement elastomeric
expansion joints were obtained from Goodall, RM-Holz Rubber Company, Proco,
Uniflex, and Garlock.
The two expansion joints that failed were manufactured in 1972 by Uniroyal and had
been installed for approximately 26 years.
The replacement expansion joints were
manufactured by Garlock.
The inspectors reviewed the equipment specification and vendor documents for the
various expansion joints installed. These documents provided detailed expansion joint
information related to installation, disassembly, shelf life, and replacement schedule.
The documents reviewed included:
Vendor Manual DC 663323-19-2, "Gartock Expansion Joints, Installation &
Maintenance," Revision 4, dated September 1995.
Vendor Manual DC 663323-11-1, "RM-HolzTechnical Handbook - Fifth Edition,"
Revision 1, dated October 1980.
Vendor Manual DC 663323-29-1, "How to Install a Garlock Expansion Joint,"
dated 1995.
Specification 8725, "Furnishing and Delivery of Elastomeric Expansion Joints for
Units 1 and 2 Diablo Canyon Site - Uniroyal Inc.," dated December 22, 1971.
An April 7, 1994, Garlock supplier (Pacific Mechanical) letter referenced
P.O. 42932.
The vendor manuals provided detailed instructions to disassemble
the expansion joints,.
including critical measurements;
to install the expansion joints, such as measuring the
bolt tightness
1 week after installation and periodically thereafter; and to install control
units. Other vendor manual information included the life expectancy of the elastomeric
joints. The documents clearly established a life expectancy of 5 years for service
conditions that were not severe, which included no misalignment and proper installation
and storage.
The documents indicated that the elastomeric expansion joints had a
5-year shelf life from the date of manufacture and that the elastomeric joints should be
replaced every 5 years.
Manual DC 663323-19-2 specifically states, "If no
physical/visible signs of distress are present, the expansion joint should be replaced
every 5 years.
The strength of the expansion joint is in the internal structuring of its
layers - deterioration of these strengthening joints is not always apparent."
Other
information indicated that, although the service life was 5 years, inspections should take
place on a yearly basis to check for signs of fatigue or wear.
0
-8-
b.2
Followup on Other Uses of Elastomeric Expansion Joints
System engineers identified approximately 120 elastomeric expansion joints installed in
both units and that 13 elastomeric expansion joints were safety-related.
On
December 8, the inspectors toured various areas of the plant to evaluate elastomeric
expansion joint installations in various systems and identified the following:
Five Uniroyal elastomeric expansion joints had each accumulated approximately
26 years of service.
The other elastomeric expansion joints had been in service
for 10 years or more.
A nonsafety-related elastomeric expansion joint on the discharge of Screen
Refuse Pump 0-1 was incorrectly installed. Some of the expansion joint flange
bolts were installed backwards (the bolt was in contact with the rubber arch
section of the joint) and half of the triangular plates of the control units were
installed on the wrong side of the expansion joint flanges. The system engineer
documented the inspector's observations
in AR A0472743 and implemented
corrective actions for the installed expansion joint.
Three as-found elastom'eric expansion joints that might have had piping
misalignments in excess of the vendor's recommendations for maximum
allowable piping misalignment.
Two of the expansion joint installations (motor
cooling lines for the Unit 1 circulating water pumps) identified with possible piping
misalignment problems had similar configurations to the failure of Expansion
Joint SW-1-EJ21.
The inspectors noted that vendors recommended that, whenever excessive
piping misalignment existed prior to installing an expansion joint, either the piping
had to be realigned or a special offset expansion joint had to be supplied by the
vendor. The inspectors noted that acceptable piping alignment is critical to
ensure elastomeric expansion joints have freedom of movement within specified
design limits. The system engineer informed the inspectors that engineering
personnel were reviewing all existing elastomeric expansion joint installations as
part of the corrective actions implemented for the expansion. joint failures.
After replacing failed Expansion Joint SW-O-EJ2, the flange on the east side of
the expansion joint had a crack, which leaked approximately 10 gallons per hour.
The crack extended from the edge of a flange bolt hole into the flange neck
area.
The licensee documented this deficiency in AR A0472629. The licensee
determined that the leak resulted from a flaw in the flange, not from maintenance
activities.
b.3
Generic Letter 89-13 Commitments
The inspectors reviewed the licensee's November 25, 1991, response to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment."
The licensee had established a routine inspection and maintenance program to ensure
that auxiliary saltwater system performance was not adversely impaired. The inspectors
-9-
reviewed AR A0043296 and noted that it identified 13 safety-related expansion joints
that were to be inspected every 24 months to satisfy the commitment to Generic Letter 89-13. These expansion joint inspections were performed in accordance with
various recurring task activity work orders under the preventive maintenance program.
During these inspections engineering personnel performed a visual inspection of
expansion joints for cracks, bulges, leaks, or visible indications of past leakage.
The
inspectors concluded that the licensee's actions met the Generic Letter 89-13
commitments with respect to elastomeric joints.
b.4
Preventive Maintenance Program Adequacy for Elastomeric Joints
At the completion of the inspection, the licensee had not determined whether the initial
two failures were maintenance preventable functional failures or completed their plans
for upgrading the preventive maintenance program.
The inspectors reviewed various vendor documents supplied to the licensee, work
orders, ARs, and expansion joint installations and, after conducting discussions with
maintenance and system engineering personnel, the inspectors noted that as of
January 6, 1999:
Approximately 10 of the 13 safety-related elastomeric expansion joints currently
installed in the plant had been manufactured by Garlock, and some of these
expansion joints had been in service in excess of 5 years.
While Garlock vendor information identified that the typical service life
expectancy of an elastomeric expansion joint was 5 years and that preventive
maintenance schedules should be enacted accordingly, the licensee had not
implemented this information into the applicable maintenance programs or
schedules or provided the technical basis for not accomplishing this
recommendation.
Engineering personnel had not identified the service life expectancy for the
various other nonsafety-related
elastomeric expansion joints currently installed in
the plant.
The inspectors determined that existing maintenance procedures and work
documents did not include various vendor recommendations for elastomeric
expansion joint installations, which included:
(1) Retighten the expansion joint
flange bolts after 7 days of system operation; (2) recheck bolts for tightness
periodically, or every 6 months, after placing the system into service; and
(3) check bolts for tightness after any extended system outage.
Vendor documentation also stated that, prior to replacing an existing expansion
joint, dimensions must be verified. As a result of settlement, misalignment, or
improper design, many elastomeric expansion joints may be overstressed
beyond their performance limitations. It is critical, therefore, that all
measurements
(overall flange-to-flange, lateral, torsional, and angular
misalignment) be checked against original specifications/drawings.
-10-
The inspectors noted that these measurements
were not documented for the
replacement of the two failed joints and, based on a sample review, had not been
documented during replacement of other expansion joints over the last 2 years.
b.5
Engineering personnel implemented actions to have vendor representatives
(Garlock)
perform onsite evaluations of the condition of all installed expansion joints and perform
onsite elastomeric expansion joint training for plant personnel the week of January 11.
The vendor representatives
informed the inspectors that they would be providing the
licensee with a trip report and recommended actions.
The licensee representatives
stated that they would evaluate the vendor information for any needed changes in their
maintenance
program.
The licensee representatives
also stated that the vendor
identified two other nonsafety-related
expansion joints that showed indications of
potential failure. The licensee initiated actions to replace these expansion joints.
Operability Assessment of Safety-Related Expansion Joints
During review of the safety-related expansion joints, the licensee identified three
expansion joints in the auxiliary saltwater system that had been in service longer than
15 years.
The licensee determined that two expansion joints had been installed for 15
years and that one expansion joint had been installed for over 26 years (same
manufacturer and age as the failed expansion joints). The licensee concluded by
engineering judgement that these expansion joints remained acceptable for use until the
Unit 2 outage in September 1999. The licensee based this decision on: (1) external
visual inspections of all three expansion joints; (2) internal inspections of the oldest
Uniroyal expansion joint; and (3) an analysis that indicated that these joints, located at
the high point in the system, were subject to very little differential pressure.
Because the licensee had not thoroughly consulted the vendor manual with respect to
expansion joints, the licensee wrote a prompt operability assessment
in AR A0472506
that had questionable reasoning.
The assessment
stated that the expansion joints had
only slightly exceeded their service life of 15 years, even though the vendor manual
recommended
replacement every 5.years.
In addition, the assessment
stated that
external visual inspections were satisfactory.
However, the vendor manual indicated
that external inspections did not provide useful information because the integrity of the
expansion joint was based on the material condition of the internals.
The licensee
correctly noted that the aging expansion joints in the auxiliary saltwater system were
subjected to pressures
substantially less than the design pressure
(3 versus 100 psig).
The inspectors visually inspected the external surface of the three older auxiliary
saltwater expansion joints and did not note any damage.
In addition, the inspectors
inspected the internal surface of the 26-year old expansion joint during routine
component cooling water heat exchanger cleaning and did not note any degradation.
However, the inspectors noted that Garlock technical information indicated that visual
inspections did not always indicate impending failure. In addition, the inspectors
determined that the licensee had not yet addressed
the potential common-mode failure
of both Unit 2 component coolin'g water heat exchangers
because
of age hardening
failure of the auxiliary saltwater expansion joints during a seismic event.
S
-11-
Subsequently,
the licensee calculated the magnitude of the displacement of the
safety-related expansion joints during a seismic event.
Calculations revealed that total
displacement (including thermal expansion) of the Component Cooling Water Heat
Exchanger 2-1 inlet expansion joint was approximately 0.75 inches.
The licensee
contacted the vendor with this information. The vendor representative stated that
operability of this expansion joint could not be assured given the age-related hardening
and maximum displacement.
On January 28, 1999, the licensee declared Expansion
Joint SW-2-EJ3 inoperable and replaced it immediately. The vendor evaluated the other
.
two questionable auxiliary saltwater expansion joints and determined that they would
remain operable because of considerably less displacement during a seismic event.
The inspectors concluded that the licensee's operability determination of the oldest
safety-related expansion joints was weak, because
it failed to accurately reference
vendor recommendations
on replacement frequency and had not considered seismic
interactions.
Further NRC review of compliance with 10 CFR 50.65, "Requirements
for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"
(Maintenance Rule) in regard to expansion joints is required, pending completion of the
licensee's maintenance preventable functional failure evaluation.
This issue is
unresolved (50-275; 323/98020-01).
Conclusions
The inspectors concluded that vendor information provided to ensure acceptable
installation and maintenance of elastomeric expansion joints was not properly
implemented into the maintenance program. The licensee's failure to replace expansion
joints in a timely manner led to failure of two joints and caused partial flooding of the
intake structure and loss of a circulating water pump. These failures required operators
to quickly reduce power to preclude a reactor trip. The assessment
that supported the
operability of the safety-related expansion joints failed to reference vendor
recommendations
on replacement frequency and seismic interactions.
As a result, the
licensee did not identify an inoperable elastomeric joint; until challenged by the
inspector.
Further NRC review of the licensee's evaluation of this degraded condition
and application of the Maintenance Rule program to expansion joints is required.
MS
Miscellaneous Maintenance Issues (92903)
M8.1
Closed
Violation 50-275 323/96021-04:
failure to establish appropriate performance
criteria for the main steam safety valves (MSSVs)
This violation reported that the licensee had set system level performance criteria for the
MSSVs at too high a threshold to provide a true indication of component reliability.
Although a number of MSSVs had failed to meet the Technical Specification criteria, the
licensee had not considered any of these failures to be maintenance preventable
functional failures.
As corrective action, the licensee also performed an audit of Maintenance Rule
compliance and found other program deficiencies.
However, the licensee did not
-12-
resolve these program deficiencies in a timely manner, which resulted in Violation 50-
275; 323/97004-01 as documented in the NRC Maintenance Rule baseline inspection.
Because the programmatic corrective actions were subject to review during the
Maintenance Rule baseline inspection, the inspectors reviewed the corrective actions
specifically associated with the MSSVs.
The inspectors determined that the Maintenance Rule program included specific
performance criteria for the MSSVs, including meeting the Technical Specifications
requirements.
The inspectors reviewed recent MSSV testing and determined that most
valves had met the Technical Specifications criteria during the most recent testing even
though the MSSVs were still in 10 CFR 50.65 (a) (1), goal setting. The inspectors also
determined that recent individual failures to meet the Technical Specifications criteria
were properly considered to be maintenance preventable functional failures and that the
testing program included performance of additional testing, if any one valve failed to
meet the Technical Specifications criteria.
Closed
Violation 50-275 323/96023-02:
failure to take corrective action to preclude
failure of first level undervoltage relay to meet Technical Specification requirements.
This violation resulted because 8 of 18 surveillance tests of first level undervoltage
relays had failed to meet Technical Specifications requirements.
They had not
determined the root cause or taken actions to preclude recurrence.
The licensee later
determined that many of these failures resulted from personnel error in setting the
relays different than recommended by the manufacturer.
During observations of secondary level undervoltage relay testing, discussed
in NRC
Inspection Report 50-275; 323/98-16, the inspectors reviewed recent first level
underyoltage relay data and determined that the performance had improved.
In
addition, the licensee had submitted Licensee Amendment Request 98-08 to obtain
NRC approval to change the specific model of the relay and slightly modify the relay
setpoints.
The inspectors considered that the licensee corrective actions to resolve this
violation were appropriate.
Closed
Violation 50-323/96023-03:
failure to properly restore a temporary
modification.
The inspectors identified that, following removal of a temporary pressure gage from the
Unit 2 chemical and volume control system, maintenance personnel failed to remove the
jumper tag and correct the control room drawings, which violated procedures.
For corrective actions the licensee:
(1) removed the information tag; (2) corrected the
control room drawing; (3) discussed the violation with the personnel involved
and'rovided
shift orders to the operating crews to emphasize operator responsibilities with
respect to lifted leads and jumpers; (4) revised Procedure CF4.ID7, "Temporary
Modifications - Plant Jumpers and M&TE"to provide added tracking mechanisms for
closure of lifted lead and jumper entries; and (5) performed a review of the jumper logs
to ensure that no other discrepancies
existed.
-13-
The inspectors reviewed licensee documentation that demonstrated
that these items
were completed and concluded that the documentation was satisfactory.
M8.4
Closed
Licensee Event Re ort50-275 323/96-018-01:
4kV bus undervoltage
protection relays out of specification because of personnel error.
This LER revision is closed as discussed
in Section M8.2.
E1
Conduct of Engineering
E1.1
Condensate
Stora
e Tank CST Leaka
e
Ins ection Sco
e 37551
The inspectors evaluated the engineering response to leakage from the Unit 1 CST, in
accordance with AR A0474556.
Observations and Findin s
On January 11, 1999, the licensee noted water leaking from the area of the Unit 1 CST.
Inspection revealed that the leak was from a 1-inch instrument line for Level
Transmitter LT-40 that penetrated the side wall near the bottom of the CST. Level
Transmitter LT-40 provided level indication at the hot shutdown panel for the CST. This
carbon steel line had corroded because of rainwater seepage
into the area, resulting in
the through-wall leak. The licensee declared Level Transmitter LT-40 inoperable and
initiated an AR to enter this item into the corrective action program.
Because of the through-wall leak, the licensee determined that the seismic qualifications
of the instrument line could not be justified. Consequently, the licensee postulated a
complete failure of the instrument line and initiated a prompt operability assessment.
'The licensee evaluated whether the CST had adequate capacity to support auxiliary
feedwater operation for the required 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in hot shutdown, with the additional water
loss from the 1-inch instrument line break and assumed that the CST was 83 percent
full. The licensee used guillotine breaks of the single 12-inch and four 4-inch Class 2
lines'and calculated the amount of time it took for the CST to drain below these
Using this methodology, the licensee determined that the CST remained
The inspectors reviewed the licensee calculations and agreed with the
conclusions.
For a temporary repair, divers entered the CST and installed an expandable plug in the
- affected penetration for the instrument line. Technical Specifications require Level
Transmitter LT-40 to be returned to service within 30 days or place the unit in hot
shutdown.
However, since this leak was discovered 26 days before Refueling
Outage 1R9, the licensee delayed the permanent repair of the instrument until the
outage.
-14-
The inspectors questioned the generic implications of this issue.
The Unit 1 CST had
two other safety-related instrument lines. The licensee inspected these lines and noted
some degradation of the wall thickness but no through-wall leakage.
In addition, the
licensee inspected similar penetrations on Unit 2 and identified no additional concerns.
The inspectors also examined these areas and concurred with the conclusions.
The
licensee stated that they had also planned to inspect the penetrations associated with
the other outside storage tanks (refueling water storage tanks, primary water storage
tanks, and fire water storage tank). The inspectors considered the scope of the
inspections satisfactory.
The inspectors questioned the licensee as to why the maintenance
rule program for
periodically examining safety-related structures had not identified this issue.
The
licensee stated that the outside tanks and associated
penetrations were in the scope of
the inspections but had not yet been scheduled.
The inspectors willperform further
review of the adequacy of the maintenance
rule program for assessing
structures.
This
issue will be tracked as an inspection followup item (50-275; 323/98020-02)
~
Conclusions
The prompt operability assessment
associated with the Unit 1 CST leak was an example
of good engineering support for operations.
Review of the adequacy of the
maintenance
rule program to assess
safety-related structures required further review.
Miscellaneous Engineering Issues (92700, 92903)
Closed
Licensee Event Re ort 50-275 323/96-014-00:
Steam Generator primary
coolant tubes were locked in tube support plates.
This licensee event report is administratively closed based on issuance of Revision 1.
Closed
Violation 50-275 323/96024-02:
Design criteria memoranda revised without
proper evaluation.
The inspectors identified that Design Criteria Memorandum S-9, "Safety Injection
System," was revised without evaluating the changes
in accordance
with
Procedure CF3.ID2, "Design Criteria Memoranda," Revision 2, which required changes
to the design criteria memoranda to be evaluated for impact on the plant licensing basis.
For corrective actions the licensee:
(1) incorporated the proper calculation into Design
Criteria Memorandum S-9, (2) discussed the improper changes with the personnel
involved, (3) performed a separate
calculation to verify that the proper amount of water
existed in the refueling water stowage tank, and (4) performed additional reviews of other
design criteria memoranda.
The inspectors performed a review of documentation supporting completion of the
corrective actions and concluded that the licensee actions were satisfactory.
-15-
E8.3
Closed
Licensee Event Re orts 50-275/97-007-00and50-323/98-002-00:
greaterthan
1 percent steam generator tubes defective.
In accordance with Technical Specification 4.4.5.5c, the licensee reported that greater
than
1 percent of the tubes inspected in Steam Generators
1-1 and 1-2 during Refueling
Outage 1R8 and Steam Generator 2-2 during Refueling Outage 2R8 were defective.
The inspectors ascertained from review of the Refueling Outage 1R8 examination history
that the number of tubes found to contain defects in Steam Generators 1-1, 1-2, 1-3,
and 1-4 were, respectively, 46, 125, 10, and 18. Alldefective tubes were removed from
service by plugging. The defective tube totals for Steam Generators
1-1 and 1-2
represented,
respectively, 1.36 percent and 3.69 percent of the 3388 tube population in
an individual steam generator.
The most significant tube degradation mechanism was
primary water stress corrosion cracking at hot-leg side dented tube support plate
intersections, which resulted in a total of 128 tubes being removed from service in the
four steam generators.
The second greatest detected tube degradation mechanism was
. outside diameter stress corrosion cracking at nondented tube support intersections,
which resulted in the removal of 45 tubes from service in the four steam generators.
Actions taken by the licensee to increase tubing stress corrosion resistance and minimize
steam generator tube degradation were reviewed during a 1995 steam generator tube
integrity inspection (NRC Inspection Report 50-275; 323/95-10).
Specific initiatives
implemented by the licensee included the following:
Thermal stress relief of Rows
1 and 2 low radius U-bends to minimize the tubing
susceptibility to primary water stress corrosion cracking; implement boric acid
additions to the secondary side to arrest tube denting and limitinitiation of outside
.diameter stress corrosion cracking; and replace copper alloy tubes in the
feedwater heaters with stainless steel, in order to eliminate copper transport to
the steam generators and minimize its contribution to,development of outside
diameter stress corrosion cracking and pitting in the steam generator tubes;
Shot peening the inside diameter surface of the tubes in the tube sheet region to
minimize development of primary water stress corrosion cracking at this tubing
location;
Adopting Electric Power Research
Institute secondary water chemistry
recommendations
to increase hydrazine additions to 100 parts per billion, in order
to reduce electrochemical potential in the steam generators and thereby minimize
development of outside diameter stress corrosion cracking;
Initiating the use of ethanolamine (for pH control) to reduce iron transport to the
steam generators, which minimizes its contribution to development of outside
diameter stress corrosion cracking;
Adopting Electric Power Research
Institute secondary water chemistry-
recommendations
for use of molar ratio control (using ammonium chloride
(I
-16-
injection), as a means of eliminating alkaline crevice chemistry conditions that
promote initiation of outside.diameter stress corrosion cracking;
, Using eddy current examination practices that are consistent with the latest
guidance contained in Electric Power Research institute Document "PWR Steam
Generator Examination Guidelines" and the WEXTEXowners group guidelines;
Adopting a policy of maintaining steam generator blowdown at 1 percent of the
'ain
steaming rate, in order to minimize steam generator contaminate levels.
In June 1998, the licensee initiated injection of zinc acetate into the Unit 1 reactor coolant
system to maintain a zinc concentration of 35-40 ppb.
Ionic zinc has been found by
laboratory testing and analytical programs to reduce general corrosion of primary system
materials and to partially inhibit primary water stress corrosion cracking of Inconel 600.
The inspectors ascertained from review of the Refueling Outage 2R8 examination history
that the number of tubes found by eddy current examination to contain defects in Steam
Generators 2-1, 2-2, 2-3, and 2-4 were, respectively, 8, 34, 26, and 23. Allof the
defective tubes were plugged.
These totals reflected the initial use by the licensee of
voltage-based
alternate repair criteria for outside diameter stress corrosion cracking at
tube support plates.
Use of the voltage-based
alternate repair criteria for Unit 2 steam
generators was approved by the issuance of License Amendment 122. Without the
voltage-based
alternate repair criteria, the respective plugging totals for Steam
Generators 2-1, 2-2, 2-3, and 2-4 would have been 29, 48, 33, and 99 tubes.
Accordingly, the use of voltage-based alternate repair criteria made only Steam
Generator 2-2 reportable in accordance with Technical Specification 4.4.5.5c, with
slightly over
1 percent of the tubes being plugged.
R1
Radiological Protection and Chemistry Controls
R1.1
Inade
uate Hi h Radiation Area Postin
a.
Ins ection Sco
e 71750
The inspectors evaluated the licensee's response to AR A0473925, which described an
inadequate high radiation posting.
b.
Observations and Findin s
On December 23, 1998, during a routine radiation protection tour of the facility, radiation
protection personnel identified that the Residual Heat Removal Pump Room 1-2
recirculation chamber door was posted as a radiation area while the main double-door
entry into the room was posted as a high radiation area.
Radiation protection personnel
corrected this posting error immediately and initiated an AR. A high radiation area sign
and yellow and magenta rope were found staged near the improper posting.
e
-17-
Licensee investigation revealed that, on December 18, high radiation area signs and rope
were staged at all entrances to both Unit 1 residual heat removal rooms. This was done
in anticipation of initiating the residual heat removal system to cool down the plant for
repairs of a primary pressure boundary leak. On December 20, radiation protection
technicians performed surveys that established that the residual heat removal pump
rooms required upgrading to high radiation area postings.
A radiation protection
technician stated that he properly posted each room at this time. No other surveys of the
room were performed subsequently, and no other personnel in the area could recall the
area being reposted as a radiation area.
Therefore, the licensee concluded that the root
cause was indeterminate.
Although the licensee did not identify a definitive root cause, the licensee recommended
several corrective actions.
Corrective actions included:
(1) properly posting Residual
Heat Removal Pump Room 1-2, (2) initiating an expectation that changes
in postings be
documented on the survey forms and that personnel reviewing surveys check the
postings, (3) recommending that radiation protection foremen walk down areas that have
changes to postings, and (4) discussing this event with all radiation protection technicians
and foremen.
The inspectors considered the corrective actions to be satisfactory.
Failure to properly post an area containing radiation doses in excess of 100 millirem per
hour as a high radiation area is a violation of 10 CFR 20.1902(b).
However, this
nonrepetitive, licensee-identified and corrected violation is being treated as a noncited
violation, consistent with Section VII.B.Iof the Enforcement Policy
(50-275; 323/98020-03).
'onclusions
A noncited violation of 10 CFR 20.1902(b), consistent with Section VII.B.Iof the
Enforcement Policy, was identified for failure to properly post a high radiation area.
Radiation protection personnel failed to post a back entrance to Residual Heat Removal
Pump Room 1-2. Although the root cause analysis was inconclusive, corrective actions
were satisfactory.
Conduct of Security and Safeguards Activities
General Comments
71750
During routine tours, the inspectors noted that the security officers were alert at their
posts, security boundaries were being maintained properly, and screening processes
at
the Primary Access Point were performed well. During backshift inspections, the
inspectors noted that the protected area was properly illuminated, especially in areas
where temporary equipment was brought in.
I
- 18-
Control of Fire Protection Activities .
Control of Combustibles
Units 1 and 2
Ins ection Sco
e 71750
The inspectors toured safety-related areas to ensure that licensee procedures
concerning the control of combustibles were implemented.
Observations and Findin s
On October 20, 1998, the inspectors identified that 2 hydrogen compressed
gas cylinders
were located on the 85-foot elevation of the auxiliary building. These cylinders were
sized to contain 7.1 cubic feet of 10 percent hydrogen at 2200 psig. The inspectors
expressed
concern because
hydrogen is flammable. -Further, the fire protection program
required a permit to bring combustible materials into vital areas, including the power
block. Subsequently,
the licensee removed the cylinders from the power block and
initiated AR A0470209 to enter this item into the corrective action program.
On
October 29, the licensee performed walkdowns of both units and noted 5 other
compressed
gas cylinders of similar size that were improperly stored, and which
contained flammable gasses.
These items were also removed from the power block.
Licensee investigation revealed that maintenance personnel had brought these
compressed
gas cylinders into these vital areas.
Compressed
gas cylinders containing
argon were approved for use in the power block on the 85-foot elevation of the auxiliary
building in accordance with Design Change Notice DCN-EM-39613. Personnel believed
that this document allowed compressed
gas cylinders in the area without regard to
content. This misconception was discussed with maintenance personnel because the
design change did not exempt the licensee from fire protection requirements.
The.
licensee evaluation further revealed that this issue was of low potential safety
significance.
Although hydrogen, a flammable gas, was introduced into areas containing
safety-related equipment, a scenario involving a fire associated
with the hydrogen gas
was considered unlikely.
In addition, the licensee performed calculations that revealed
that, because
of the size of the space, if all of the gas was released to the 85 foot
elevation, a combustible mixture would not result.
Procedure OM8.ID4, "Control of Flammable and Combustible Materials," Revision 7,
Section 4.2.3, required issuance of a transient combustible permit when flammable
materials were brought into the power block. Therefore, the introduction of compressed
gas cylinders containing hydrogen without a transient combustible permit is a violation of
Technical Specification 6.8.1.h.
However, because the licensee took satisfactory
corrective actions in AR A0470209 in response to this issue, no response was required
(50-275; 323/98020-04).
0
0
c.
Conclusions
-19-
The inspectors noted that the licensee had inappropriately stored compressed
gas
cylinders in the auxiliary building. Contrary to plant procedures, personnel had not
obtained a transient combustible permit, as required for storing flammable material,
which resulted in a violation of Technical Specification 6.8.1.h. The licensee
demonstrated that this instance involved low likelihood of a fire involving hydrogen gas.
The licensee determined the cause of the violation, identified other examples, and took
appropriate corrective actions; therefore, no response was required.
V. Mana ement Meetin s
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on January 30, 1998. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection should
be considered proprietary.
No proprietary information was identified.
T
A%IACHMENT
SUPPLEMENTAL INFORMATION
PARTIALLIST OF PERSONS CONTACTED
Licensee
J. R. Becker, Manager, Maintenance Services
W. G. Crockett, Manager, Nuclear Quality Services
R. D. Gray, Director, Radiation Protection
T. L. Grebel, Director, Regulatory Services
D. B. Miklush, Manager, Engineering Services
J. E. Molden, Manager, Operations Services
D. H. Oatley, Vice President and Plant Manager
L. F. Womack, Vice President, Nuclear Technical Services
IP 61726"
IP 71707
IP 92700
IP 92902
IP 93702
INSPECTION PROCEDURES (IP) USED
Onsite Engineering
Surveillance Observations
Maintenance Observation
- Plant Operations
Plant Support Activities
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
Followup - Operations
Followup - Maintenance
Followup - Engineering
Prompt Onsite Response
to Events at Operating Power Reactors
ITEMS OPENED AND CLOSED
~Oened
50-275; 323/
98020-01
50-275;323/
98020-02
URI,
Evaluate adequacy of maintenance
rule program for
expansion joints (Section M2.1)
IFI
Evaluate adequacy of maintenance
rule monitoring of
outside tanks (Section E1.1)
0
0
-2-
Closed
50-275; 323/
96021-04
50-275; 323/
96023-02
50-275; 323/
96023-03
VIO
Failure to establish appropriate performance criteria for
MSSVs (Section M8.1)
Failure to take corrective actions to preclude first level
undervoltage relay failures to meet Technical Specifications
requirements (Section M8.2)
Failure to restore a temporary modification (Section M8.3)
50-275; 323/
96-018-01
LER
4kV bus undervoltage protection relays out of specification
because of personnel error (Section M8.4)
50-275; 323/
96024-02
Design criteria memoranda revised without proper
evaluation (Section E8.1)
50-275; 323/
96-014-00
50-275/97-007-00
50-323/98-002-00
LER
Steam generator primary coolant tubes were locked in tube
support plates (Section E8.2)
LER
Greater than
1 percent steam generator tubes defective
(Section E8.3)
LER
Greater than
1 percent steam generator tubes defective
(Section E8.3)
0 ened and Closed
50-275; 323/
98020-03
50-275; 323/
98020-04
Failure to properly post a high radiation area (Section R1.1)
Failure to obtain transient combustible permit for
compressed
gas cylinders containing hydrogen
(Section F1.1)
-3-
Procedure
LIST OF LICENSEE DOCUMENTS REVIEWED
MA1 ~ID17
"Maintenance Rule Monitoring Program," Revision 5
S ecification
8725
"Furnishing and Delivery of Elastomeric Expansion Joints for Units 1 and 2 Diablo
Canyon Site - Uniroyal Inc" dated December 22, 1971
Vendor Manuals
DC 663323-10-2
DC 663323-11-1
DC 663323-19-2
DC 663323-29-1
Action Re uests
"Expansion Joints and Vibration Dampeners Installation Instructions Unit
One &Two,"Revision 2
"RM-HolzTechnical Handbook - Fifth Edition", Revision
1
"Garlock Expansion Joints, Installation 5 Maintenance," Revision
4'How
to Install a Garlock Expansion Joint," dated 1995
A0043296
A0336216
A0472252
A0472458
A0472506
A0472629
A0472743
Q~i
A0472288
Nonconformance Re ort
N0002079
Work Orders.
C0140103
C0143142
C01 59711
C0159751
R0078760
R0078800
R0165894
R01 65917
t
-4-
LIST OF ACRONYMS USED
CFR
IP
LER
NRC
jo
Action Request
Code of Federal Regulations
Condensate
Storage Tank
Circulating Water Pump
Inspection Procedure
licensee event report
Noncited Violation
Nuclear Regulatory Commission
Public Document Room
Reactor Coolant Pump
Surveillance Test Procedure
Unresolved Item
Violation
e