ML18066A410
| ML18066A410 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 02/05/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18066A408 | List: |
| References | |
| 50-255-98-22, NUDOCS 9902180065 | |
| Download: ML18066A410 (25) | |
See also: IR 05000255/1998022
Text
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U.S. NUCLEAR REGULATORY COMMISSION
Docket No:
License No:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
REGION Ill
50-255
50-255/98022(DRP)
Consumers Energy Company
212 West Michigan Avenue
Jackson, Ml 49201
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, Ml 49043-9530
November 26, 1998, through January 12, 1999
J. Lennartz, Senior Resident Inspector
B. Fuller, Resident Inspector - D.C. Cook
M. Holmberg, Reactor Engineer, Riii
Anton Vegel, Chief
Reactor Projects . Branch 6
-- -----
9902180065 990210
ADOCK 05000255
G
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EXECUTIVE SUMMARY
Palisades Nuclear Generating Plant
NRC Inspection Report 50-255/98022
This inspection included aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a 7-week period of resident inspection activities.
Operations
An oil leak on Primary Coolant Pump P-500 resulted in a forced outage. In addition,
several emergent equipment problems challenged plant operations during the forced
outage. The equipment problems included pressurizer power operated relief valve
position indication unreliability, main steam line isolation valves failure to fully close, and
control rod drive #2 housing leakage. The emergent issues were addressed in a
deliberate manner and the plant was manipulated in a conservative manner with a
positive focus on safety. (Section 01.1)
An operator work around was created by the inoperable pressurizer power operated
relief valve position indication lights. The work around had minimal impact on the
operators and the appropriate contingency actions were established. (Section 01.2)
The action taken by the licensee to place the plant in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in
response to the identified leakage from control rod drive #2 was conservative when
considering Technical Specifications and demonstrated a positive focus on safety.
(Section 01.3)
The licensee effectively promulgated new commitments regarding primary coolant
system leakage by revising procedures and control room data sheets. (Section 03.1)
Control room operator response to a loss of a safeguards transformer event was
effective. A positive questioning attitude and a pro-active initiative were demonstrated
by the operating crew and outage management regarding briefing the potential for a
loss of off-site electrical power because of ongoing activities for the plant conditions that
existed. This was considered as a positive attribute regarding operator performance
and contributed to the crew's exemplary performance while responding to a loss of the
safeguards transformer.- (Section 04.2)
A number of operator errors and operational problems occurred due to a lack of
consistent comprehensive pre-evolution briefings, and a lack of rigor regarding attention
to detail by the operators while performing assigned duties. Operator performance
deficiencies contributed to the cooling tower basin being overfilled twice, two instances
where primary coolant system pressure exceeded procedural limits, and not recognizing
------ -----------Technical-Specificationrequirementswhen-the-main steam isolation-valves-did not-go- -- -----
fully closed. In addition, an operator's failure to conduct self-checking activities while
manipulating equipment was a concern in that it directly resulted in placing a safety-
related system in a configuration that was contrary to procedural requirements which
was a Non-Cited Violation. (Section 04.5)
2
.*
Maintenance
Outage planning and scheduling personnel addressed the emergent issues in a
deliberate manner which demonstrated a positive focus on safety. Also, a positive *focus
on safety was demonstrated by having a shift outage manager stationed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from
the time the forced outage commenced until the plant was returned to full power.
(Section M1 .1)
The licensee missed an opportunity to identify the leak at the reactor coolant pump
P-50A cover to casing joint during the June 1998, system pressure test, which indicated
a lack of rigor in the conduct of this testing. Further, the licensee had failed to submit a
structural evaluation on the degraded pump joint to the NRC which was a violation of
regulatory requirements and demonstrated a poor understanding of the applicable Code
requirements. (Section M1 .2)
Engineering
Engineering personnel conducted thorough testing and performed an in-depth analysis
regarding the failure of the main steam isolation valves to close which was determined
to be a maintenance preventable functional failure. lnoperability of the main steam
isolation valves from May 29, 1998, until the condition was corrected on December 19,
1998, was a Non-Cited Violation. (Section E2)
Engineering personnel conducted extensive testing on the pressurizer power operated
relief valves and provided a thorough operability recommendation to operations.
However, an operator work around was created in that the position indication lights
remained inoperable pending required repairs prior to plant start-up following the next
time the plant is in cold shutdown. (Section E2)
System engineering personnel demonstrated a positive questioning attitude during the
outage that contributed to identifying that the primary coolant pumps' oil collection
system did not meet regulatory requirements. However, engineering personnel missed
an earlier opportunity to identify the deficiency during an engineering analysis that was
conducted in the early 1990's. The inadequate primary coolant pumps' oil collection
system was a Non-Cited Violation. (Section E4)
Plant Support
Effective dose management was demonstrated during the outage. Also, flush of the
shutdown cooling heat exchangers, a first time evolution, demonstrated a positive pro-
active initiative to reduce radiation dose rates in plant areas that were routinely toured
by plant personnel, the safeguards rooms. (Section R 1.1)
- --------------- --- *-----*--- *------------------- -
3
Report Details
Unless otherwise stated, "Coden as discussed herein, refers to the 1989 Edition no Addenda of
Section XI, of the American Society of Mechanical Engineers (ASME) Code.
Summary of Plant Status
The plant was at full power at the beginning of the inspection period. On December 13, 1998,
the plant was placed in hot standby to investigate a lowering level in the upper oil reservoir on
Primary Coolant Pump P-50D. An oil leak was confirmed and the plant was subsequently
placed in cold shutdown on December 15, 1998. The forced outage was scheduled for
6.5 days to complete the primary coolant pump repairs as well as to replace the seals on
Control Rod Drive #36 that had elevated leakage. The plant was returned to hot shutdown on
December 26, 1998; however, a leak on Control Rod Drive #2 seal housing was identified and
the plant was again placed in cold shutdown to conduct repairs. The Control Rod Drive #2 seal
housing leak as well as several other emergent equipment problems extended the forced
outage to a total of 25 days. The reactor was subsequently taken critical on January 7, 1999,
and the plant was synchronized to the grid on January 8, 1999. Power escalation to full power
was completed on January 10, 1999, where the plant remained during the inspection period.
I. Operations
- 01
. Conduct of Operations
01.1
General Comments (71707)
Forced Outage 985004 was commenced on December 13, 1998, due to the oil leak on
Primary Coolant Pump P-50D and was scheduled for 6.5 days. Control Rod Drive #36
seals were also scheduled to be replaced due to elevated leakage. The following
equipment problems emerged during the outage which challenged plant operations ..
Main steam isolation valves (MSIVs) failed to close fully during the plant
shutdown.
Position indication lights on the pressurizer power operated relief valves
(PORVs) appeared unreliable and extensive testing was conducted.
A casing leak on Primary Coolant Pump P-50A caused degradation of two bolts
on the pump casing. *
Safeguards transformer load tap changer failed that resulted in a momentary
loss of the safety-related electrical busses.
-- - -
~-------*---~---------.
~---Aleakwas Tden-tifrecionControl Rod Drive Mechanism #2 seal housing and the
plant had to be placed in cold shutdown a second time to conduct the repairs.
4
..
Elevated leakage from Primary Coolant Pump P-SOA pump seals was observed
during plant heat-up and the seals were subsequently replaced.
In response to these emergent issues, the plant was manipulated in a conservative
manner with a focus on safety as evidenced by: 1) safeguards transformer repair
activities in the switchyard were delayed until the plant was placed in a more stable
condition regarding pressure control; and 2) operations management self-imposed a
time limit of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to reach cold shutdown following identification of suspected
primary coolant pressure boundary leakage on Control Rod Drive #2 seal housing.
Also, plant management addressed all of the emergent issues in a deliberate manner
and consulted with safety assessment personnel to utilize risk assessment information
in their decisions when appropriate. For example, risk assessment information
regarding the systems that would be available for core cooling during a postulated loss
of all electrical power was utilized in the decision to conduct troubleshooting on the
safeguards transformer while in hot shutdown vice cold shutdown.
A positive focus on safety was also demonstrated by having reactor engineering
personnel onsite continuously during the plant startup and subsequent power escalation
to full power. Reactor engineering personnel periodically performed surveillances to
monitor reactor core parameters and immediately provided the operators information
regarding any power limits.
The inspectors concluded that, during the forced outage, all of the emergent issues
were addressed in a deliberate manner and that the plant was manipulated in a
conservative manner with a positive focus on safety.
01.2
Pressurizer PORV Inoperable Position Indication
a.
Inspection Scope (71707)
During the December 1998 forced outage, the licensee experienced problems with the
reliability of the PORV position indication lights. The technical resolution of this issue is
discussed in Section E2.2 of this report.
The inspectors reviewed the applicable Technical Specifications (TSs), the Updated
Safety Analysis Report, established contingency actions, and discussed the issue with
operations management.
b.
Observations and Findings
Technical Specification 3.17.6 required a minimum of one operable channel of position
indication per PORV. The inspectors verified that the temperature monitoring in the tale
pipe and the acoustic monitoring system were both operable for each PORV.
- .
Therefore, the requirements of TSs were_!'D_~t J:l9W~ver.Jhe_inoperable.position--* --- -----* -
indication-ligntsintfie controTroom created an operator work around.
The PORV block valves are normally closed to isolate the PORVs during operations at .
power because credit was not taken for operation of the PORVs in the plant transient
5
..
accident safety analysis. Therefore, inoperable PORV position indication, while at
power, had minimal impact on the operators.
The PORVs were designed to protect the primary coolant system from overpressure
during abnormal transients associated with low temperature (less than 430°F), water
solid system operations. The PORVs were also required to function for a "feed and
bleed" evolution as a contingency action to cool the primary coolant system during an
emergency shutdown if needed. Alternate position indication was available to the
operators if the PORVs had to be utilized for these functions.
The following contingency actions were established: 1) caution tags were hung on the
PORV handswitches in the control room to remind the operators that the position
indication lights were unreliable; 2) each crew was briefed regarding this condition and
the need to use alternate indications to determine PORV position if needed; and
3) operator's continuing training would reinforce the use of alternate indications. The
inspectors considered the contingency actions as appropriate.
c.
Conclusions
The inspectors concluded that the operator work around created by the inoperable
pressurize PORV position indication lights had minimal impact and that appropriate
contingency actions were established.
01.3
Control Rod Drive Mechanism #2 Seal Housing Leakage
a.
Inspection Scope (71707. 37551)
The inspectors reviewed applicable condition reports and the associated operability
recommendations: Also, the inspectors reviewed the event notification worksheet.
b.
Observations and Findings
On December 26, 1998, with the plant in hot shutdown, system engineering personnel
identified minor leakage in the autoclave area of Control Rod Drive #2 during a primary
coolant system pressure test. The boric acid residue was cleaned from the area in an
attempt to identify the source of the leak. The area was observed to be wet on a
subsequent walkdown and the autoclave studs were re-torqued with no apparent affect
on the indicated leakage.
The source of the leak could not be definitively determined while in hot shutdown and
the leakage was very minor; however, a build-up of boric acid indicated that the leak had
been active for some time. System engineering personnel suspected that it was primary
coolant system pressure boundary leakage. Consequently, the control rod drive
mech_~_lli.§m.h.o_i.Jsing_hadJo_be removed to-positively-determine-the source of the leak:- -----------
Therefore, the plant was returned to cold shutdown on December 28, 1998, to conduct
the repairs. This condition was appropriately reported to NRC in accordance_ with
1 O CFR 50. 72. Investigations while in cold shutdown revealed that the leak was from
the control rod drive seal housing which was subsequently replaced.
6
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c,
The inspectors noted that operations personnel imposed a time limit of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to
reach cold shutdown for the leak. Technical Specification 3.1.5, "Primary Coolant
System Leakage Limits,* required the plant to be in cold shutdown in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if
identified primary coolant system leakage exceeded 1 O gpm or if unidentified primary
coolant system leakage exceeded 1 gpm. The leakage from Control Rod Drive #2 was
much less than 1 gpm and TSs did not address pressure boundary leakage. Therefore,
the action that was taken to place the plant in cold shutdown in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was
conservative when considering TSs and demonstrated a positive focus on safety.
Conclusions
The inspectors concluded that the action taken to place the plant in cold shutdown within
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in response to the identified leakage from Control Rod Drive #2 was
conservative when considering TSs and demonstrated a positive focus on safety.
03
Operations Procedures and Documentation
03.1
Primary Coolant System Leakage Monitoring Commitment (71707)
The inspectors reviewed the revisions that were made to General Operating
Procedure (GOP) -13, "Primary Coolant System Leakage Calculation," Revision 12, to
address a licensee commitment (see Section M1 .2 of this report for details) regarding
primary coolant system leakage. The inspectors noted that the procedure was revised
to provide the three action levels discussed in the relief request including: 1) 0.2 gpm
rise in containment sump level; 2) 0.3 gpm calculated total unidentified primary coolant
system leakage; and 3) 0.5 gpm calculated total unidentified primary coolant system
leakage. The action steps associated with the various action levels provided adequate
procedural guidance to address the commitment requirements.
Also, the inspectors noted that the control room data sheet (hourly) was revised in that a
note was added that highlighted the commitment regarding containment sump
monitoring. The inspectors concluded that the revisions to GOP-13 and the control
room data sheet (hourly) provided adequate procedural guidance to address the
licensee's commitment regarding primary coolant system leakage.
04
Operator Knowledge and Performance
a.
-inspection s*cope (71707) *.*
The inspectors observed the controi room operators response to the loss of the
safeguards transformer as well as portions of the plant shutdown and subsequent plant
startup activities. In addition, the inspectors reviewed applicable condition reports, TSs,
and questioned operators regarding various evolutions.
---- ----
~--- --- -- -~ -- --* -------- ------------- -------- -----
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b.
Observations and Findings
04.1
General Comments
In general, operator performance during the forced outage was characterized by the
effective control of plant activities. The operators were challenged by the equipment
reliability problems that required entries into cold shutdown on two separate occasions.
Procedure adherence and self checking were effectively demonstrated during the plant
startup and plant shutdown activities. Reactivity manipulations were performed in a
deliberate and controlled manner with appropriate oversight from the control room
supervisor.
04.2
Operator Response to Safeguards Transformer Failure
A positive attribute regarding operator performance was identified this inspection period
during the loss of the safeguards transformer event. The safeguards transformer
normally supplies power to the safety-related electrical busses. The voltage control
system on the safeguards transformer failed in that contacts were sticking on the motor
that moved the tap changer to automatically adjust transformer voltage. The sticking
contacts caused the tap changer motor to decrease transformer output voltage to the
minimum setting and therefore reduced voltage on the safety-related busses.
Consequently, the supply breakers to the safety-related busses from the transformer
opened on undervoltage that resulted in a momentary loss of both safety-related
electrical busses. Both emergency diesel generators started and their output breakers
closed to supply power to the safety-related busses. Subsequently, all safety-related
components were started by the shutdown sequencer and were powered by the
emergency diesel generators. All plant systems operated as designed following the
event.
During the event, the primary coolant system was in a "solid" condition which challenged
the operators response because slight changes in system temperature and flow could
result in significant changes in system pressure. The operators responded to and
mitigated the event in an effective manner. Primary coolant system pressure was
effectively controlled to preclude exceeding any pressure limits associated with primary
coolant pump operations and any low temperature overpressure protection system
limits. Crew communications and senior reactor operator command and control were
effective. In addition, the cre_w correctly diagnosed the eventin a timely manner. - -
Shift outage management reminded the crews' shift supervisor, prior to start of the shift,
of the ongoing electrical system activities in the switchyard and that these activities
increased the potential for a loss of off-site electrical power. Based on that reminder,
the shift supervisor directed the crew to review the procedures and also held
discussions regarding contingency actions for a loss of off-site power. Consequently,
___________ _J_t:l~cre.w.was __ p(epared to_respondand effectively,.m itigated-the-transient with-various------
-- ------
plant systems in off-normal configurations. This demonstrated a positive questioning
attitude and a pro-active initiative by the operating crew and outage management that
contribut~d to the crews effectiveness in responding to the event.
8
04.3
Operator Error Because of Failure To Perform Self-Check
Standard Operating Procedure - 16, "Component Cooling Water System," General
Requirement 7.3~1.b, required two component cooling water (CCW) heat exchangers in
service anytime two CCW pumps are running. On December 22, 1998, while securing
shutdown cooling and with two CCW pumps running, an operator isolated CCW to the
"B" CCW heat exchanger instead of securing CCW to the shutdown cooling heat
exchanger. Consequently, the CCW system was placed in a configuration that was
contrary to procedure requirements. The adverse condition existed for approximately
10 minutes. The operators' failure to perform self checking during the evolution
contributed to the incident. Condition Report C-PAL-98-1986 was generated to
document this incident.
The procedure limitations preclude heat exchanger tube wear because of excessive
system flow rates through a single heat exchanger from two operating CCW pumps.
Engineering analysis EA-GAK-98-003 concluded that tube wear would not occur due to
high flows during short term (less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) operation. Therefore, this incident did
not result in adverse safety consequences. Also, there was no evidence of heat
exchanger degradation based on observed system parameters.
The operators failure to conduct self checking was a concern in that it directly resulted in
placing a safety-related system in a configuration that was contrary to procedure
requirements. The inspectors determined, based on discussions with the operations
manager, that failure to perform self checking did not meet management expectations.
Corrective actions included counseling and ongoing coaching of the individual operator
and all of the operating crews were briefed by operations management regarding this
incident. Self-checking expectations as well as expectations regarding prioritizing and
controlling activities in the control room were emphasized during the briefings.
Securing one CCW heat exchanger when two CCW pumps were operating placed the
CCW system in a configuration that was contrary to procedure requirements and: is a
Violation of 10 CFR Part 50, Appendix B, Criterion V, procedures. This non-repetitive, *
licensee-identified and corrected violation is being treated as a Non-Cited Violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy
(50-255/98022-01 (DRP)).
04.4
Failure to Follow Surveillance Procedure
Technical Specification Surveillance Procedure Rl-47, "Rod Withdrawal Prohibit
Interlock Matrix Check," was being performed in preparation for plant startup on
December 27, 1998. Procedure Rl-47, Step 5.5.1, required that operations bypass
reactor protection channel "A" variable high power and thermal margin low pressure
trips. Also, the procedure required that the instrument and control technician
- - _____ ---- --------independently-verify-completion-of the-step *. -The procedure-required-signatures-,- upon-- -----
step completion, from the individuals who performed and verified the step. The
inspectors noted that both the "performed by" and the "verified by" blocks contained
signatures.
9
However, during performance of Rl-47, Step 5.7.7, removal of bypasses installed during
Step 5.5.1, a second operator identified that the bypass key had not been installed for
the thermal margin low pressure trip. Consequently, the appropriate trips were not
bypassed as required by the procedure. A level 2 Condition Report (C-PAL-98-1997)
was generated to document this incident. A root cause evaluation was required for the
condition report.
The licensee's root cause evaluation for the incident was in progress and had not been
completed. Therefore, this item is being opened pending further review of the licensee's
root cause investigation and corrective actions (EEi 50-255/98022-02). The apparent
failure to follow procedures and apparent failure to conduct an independent verification
was a concern.
04.5
Operator Performance Deficiencies
Several operator performance deficiencies occurred during the outage that detracted
from the overall positive performance that was demonstrated during the plant shutdown
and the subsequent startup. The performance deficiencies included:
The cooling tower basin overflowed twice during the outage while performing
evolutions to change cooling tower system flow paths. Procedure weaknesses,
as well as an inadequate pre-evolution brief, contributed to the first incident. The
second overflow resulted because the level instrument that provided indication in
the control room was inoperable because it was frozen and the level was not
monitored long enough locally to preclude the incident. Non-conservative
decision making by shift management contributed to the second incident.
Consequently, water flooded two buildings (3 to 6 inches of standing water on
floor), and the surrounding area; that were utilized for storage of radioactive
waste during both incidents. Condition Reports C-PAL-98-1943 and
C-PAL-98-1957 were generated to document the incidents. Subsequent
evaluations regarding the radiological aspects of the incidents determined that
there was no release of radioactivity outside of the protected area and, therefore,
no threat to public health and safety.
The control room operators failed to recognize applicable TS requirements
following the failure of the MSIVs to fully close (see Section E2.1 of this report for
details). Technical Specification 3.5.1.f required the MSIVs to be capable of
closing in 5 seconds or less under no-flow conditions. The MSIVs did close,
based on control room indication, within 5 seconds when the operators closed
them during the plant shutdown on December 14, 1998; therefore, the operators
considered the valves operable. However, they did not go fully closed as was
discovered on December 15, 1998, by local valve position verification. A
cooldown to place the plant in cold shutdown was in progress when the MSIVs
were-discovered-partially-open. -- - ** -----*- ---- - - -- ----- ------ --
After the MSIVs were discovered partially open the operators referenced
TS 3.5.1.f but failed to recognize that the MSIVs were not operable in that they
did not go fully closed. Consequently, TS 3.5.3, required the plant to be placed
10
in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Technical Specification 3.5.3 requirements
were fortuitously met in that the plant was placed in a cold shutdown condition
within the required time limit.
Operators demonstrated difficulties in controlling primary coolant system
pressure during solid plant operations on two separate instances. In one
instance, primary coolant system pressure momentarily exceeded a procedural
limit. Standard Operating Procedure-3, "Safety Injection and Shutdown Cooling*
System, n Step 5.1.3, required that primary coolant system not exceed 270 psia
with the shutdown cooling system in service. Primary coolant system pressure
momentarily (less than a minute) reached 274 psia while securing shutdown
cooling on December 21, 1998, before the operators terminated the pressure
rise.
In the second incident, primary coolant system pressure momentarily
(1.5 minutes) decreased below the procedure limit for primary coolant pump
operations. This incident occurred when the operators were securing one of the
two operating charging pumps on December 16, 1998. The procedure limit was
based on sustained primary coolant pump operations and therefore decreasing
below the limit for 1.5 minutes had no adverse safety consequences. Also,
pressure was immediately restored. Condition Reports C-PAL-98-1985
and 98-1955 were generated for the incidents.
The inspectors considered both incidents as minor in that no adverse safety
consequences resulted. However, in discussions with the operators involved,
the inspectors noted that there was an apparent knowledge weakness regarding
system response when securing shutdown cooling while the primary coolant
system was solid. Also, in one instance, the pre-evolution brief did not address
contingency actions if the expected response was not observed. Consequently,
the control room supervisor did not identify specific contingency actions to
mitigate the unexpected response. In addition, the inspectors noted that ."just in
timen training (training prior to performance of the evolution) was not conducted
for solid plant operations during the forced outage. Training on solid plant .
operations was normally conducted for scheduled outages but not for forced
outages. The lack of "just in timen training on solid plant operations during the
forced outage contributed to the performance deficiencies.
An auxiliary operator identified an inoperable nitrogen station on December 24,
1998, when the plant was in a condition that required the nitrogen station to be
operable. Condition Report 98-1993 was generated for this instance. The
inspectors considered this incident as minor in that no adverse safety
consequences occurred and, fortuitously, the nitrogen station was returned to an
operable status prior to exceeding any administrative (standing orders) TS limits.
However, the-incident demonstrated-a-lack-of rigor-regarding-attention-to-detail------
by the auxiliary operators in that operator checklists that were applicable when
shutdown cooling was in service were being utilized after shutdown cooling was
secured. Also, none of the operations checklists verified that the nitrogen station
was operable prior to going above 300°F.
11
'*
- .
c.
On January 4, 1999, control room operators attempted to start Primary Coolant
Pump P-508 for post maintenance testing and the pump failed to start.
Subsequent investigation revealed that the pump's supply breaker was not
- racked in properly. Condition Report C-PAL-98-0015 was initiated. The pump
was started successfully after the breaker was racked in properly. The operators
failure to rack in the breaker properly demonstrated a lack of rigor regarding
attention to detail during performance of assigned duties.
The operator performance deficiencies described above were individually considered of
minor safety consequence. However, collectively they indicated that continued
management attention regarding operations procedure adherence and the rigor applied
regarding attention to detail by the operators while performing assigned duties was
warranted. At the exit meeting for this inspection, the licensee management staff stated
that they recognized these concerns and that action will be taken to assess and address
the causes for the inconsistent performance by operations staffs.
Conclusions Regarding Operator Performance
The inspectors concluded that, in general, operator performance during the forced
outage was effective overall. A positive questioning attitude and a pro-active initiative
were demonstrated by the operating crew and outage management regarding the
potential consequences for a loss of off-site electrical power because of ongoing
activities for the plant conditions that existed. This was considered as a positive
attribute regarding operator performance and contributed to the crew's effectiveness in
responding to a loss of the safeguards transformer event.
- The inspectors also concluded that continued management attention regarding the rigor
applied regarding attention to detail by the operators while performing assigned duties
was warranted. This was evidenced by the occurrence of a number of operator
performance deficiencies during the outage. An operators' failure to effectively conduct
self-checking activities while manipulating equipment was a concern in that it directly
resulted in placing a safety-related system in a configuration that was contrary to
procedural requirements which was considered a Non-Cited Violation.
08
Miscellaneous Operations Issues
08.1
{Closed Licensee Event Report CLER) 50-255/98-007: High Pressure Safety Injection -
System lnoperability. This event was discussed in detail in Inspection
Report 50-255/98007. A violation (EA 98-433) was subsequently issued in a letter from
the NRC to the licensee dated December 11, 1998. No new issues were revealed by
this LER. This item is closed.
-
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12
v
II. Maintenance
M1
Conduct of Maintenance
M1 .1
General Comments (61726 and 62707)
Portions of the following maintenance work orders and surveillance activities were
observed or reviewed by the inspectors:
Work Order No:
24814631, Primary Coolant Pump P-500 Oil Leaks
24814836, Power Operated Relief Valves
24814837, Power Operated Relief Valves
24814680, MSIV CV-0510
24813733, MSIV CV-0501
Surveillance No:
Q0-1, "Safety Injection System"
DWT-12, "Monitoring Reactor Parameters"
R0-22, "Control Rod Drop Times"
RIA-115, "Power Operated Relief Valves"
Q0-37, "Main Steam Isolation and Bypass Valve Testing"
Several emergent equipment problems challenged the maintenance organization.
Maintenance was effectively completed in a timely manner. Outage planning and
scheduling personnel addressed the emergent issues in a deliberate manner which
demonstrated a positive focus on safety. Also, a positive focus on safety was *
demonstrated by having a shift outage manager stationed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from the time the
forced outage commenced until the plant was returned to full power. The shift outage
manager provided timely support for emergent issues which reduced the burden on the
control room shift supervisor.
The work packages reviewed were well documented. Scheduled activities for the forced _____ _
outage_effectively_ repaired-known-equipment-problems *that had the potenfiallo ___ _
challenge plant operations (i.e., control rod drive #36 seals; boric acid heat tracing on
the gravity feed lines to the safety injection and refueling water storage tank). Based on
inspector observations, maintenance activities were planned and performed effectively
in accordance with procedural guidance .
13
M1 .2
Missed Opportunity to Identify Primary Coolant Pump P-50A Leakage
a.
Inspection Scope (73753)
The inspectors reviewed licensee activities related to the identified leakage from Primary
Coolant Pump P-50A.
The inspectors reviewed the following documents_: letter from N. Haskell to the NRC
. "lnservice Inspection Program-Submittal of Relief Request No. RR-13 For NRC
Approval," dated December 20, 1998, EA-C-PAL-98-1067-01 "P-50A Case to Cover
Stud Evaluation," dated May 23, 1998; EA-C-PAL-98-1939-01 "Evaluation of Corrosion
on Studs Between Casing and Cover of Pump P-50A," dated December 19, 1998.
b.
Observations and Findings
During an NRC inspection conducted in May, 1998, an NRC inspector observed
corrosion and wastage of a 2-inch component cooling water supply line flange to the
Reactor Coolant Pump P-50A (IR 50-255/98006). At that time, the licensee believed
that this condition and the nearby corrosion of two 4.5 inch nominal diameter ASME
Code Class 1 (Category B-G-1) pump case to cover bolts was caused by the leakage
from the mechanieal shaft seal on the pump. The 16 pump case to cover studs in each
of the four reactor coolant pumps were inspected and only the two studs in the
P-50A pump had significant wastage. The diameter of these studs had been reduced to
3.97 inches and 3.92 inches .. The licensee performed an analysis,
EA-C-PAL-98-1067-01, "P-50A Case to Cover Stud Evaluation," to accept the affected
pump casing joint for continued service.
However, the licensee failed to follow the requirements in Article IWB-3134(b) of
Section XI of the ASME Code which required the analytical evaluation (pursuant to
Article IWB-3142.4 requirements) used to accept the pump bolts for continued service,
to be submitted to the regulatory authority having jurisdiction at the plant site. As of
December 18, 1998, ttie licensee failed to submit the analysis EA-C-PAL-98-1067-01 to
.the NRC as required by Article IWB-3134(b) which is a violation of 10 CFR 50.55a(g)(4)
(50-2S5/98022-03(DRP)). The failure to submit this analysis to the NRC demonstrated
poor understanding of the applicable Code requirements.
On December 15, 1998, during a forced outage, the licensee identified a fine spray of
water from the P-50A pump cover to casing joint impinging on the previously identified
degraded studs. The licensee identified that the degraded studs had been further
reduced in cross section to 3.77 inches and 3.81 inches by the ongoing leakage and
boric acid attack. This leakage had not been previously identified during the system
pressure test and the Code VT-2 inspection performed in June 1998 during the outage.
The failure to identify this leakage during the June system pressure test, indicated a lac~ _______ _
---of-rigor-in-the-conduct-ofthe system- pressure* teisting. -The-licensee-performe"cran ---
additional structural analysis EA-C-PAL-98-1939-01 "Evaluation of Corrosion on Studs
Between Casing and Cover of Pump P-50A" to accept the degraded studs for continued
service. Following discussions with NRC inspectors, the licensee subsequently
14
submitted this evaluation to the NRC on December 20, 1998, to comply with
Article IWB-3134(b) requirements.
Article IWA-5250 of Section XI of theASME Code required disassembly of the leaking
joint to inspect and evaluate the bolting. However, the licensee considered the
disassembly of this pump casing joint to impose a hardship caused by the required plant
conditions to perform the work (reduced inventory configuration) which impacted the
forced outage schedule and increased outage radiation dose. On December 18, 1998,
the licensee discussed their plans to return to power operation with degraded pump
bolts on Pump P-50A, with the Office of Nuclear Reactor Regulation. On December 20,
1998, the licensee submitted a Code Relief Request No. RR-13 which requested
deferral of the repair to the leaking P-50A pump joint untilthe 1999 refueling outage
based on a structural evaluation, compensatory actions in place, and the dose
consequence to immediately comply with Code requirements. The relief request was
granted on December 21, 1998, following review by NRC technical experts.
The licensee, as documented in Relief Request No. RR-13, established seven new
commitments that will be in effect until the end of the 1999 refueling outage. The
commitments included:
A visual inspection of the pump flange area will be conducted for each forced
shutdown prior to the 1999 refueling outage which required the plant to be in hot
shutdown or below.
Ultrasonic testing inspections of the degraded studs will be performed. for each
forced shutdown requiring the plant to be in cold shutdown.
The degraded bolting will be replaced: 1) when data indicates degradation will
exceed the limits established by analysis; and 2) no later than the next refueling
outage scheduled to begin in October 1999.
Primary coolant system leakage will be administratively limited to 0.5 gpm versus
the 1.0 gpm that was allowed by TS 3.1.5.a.
With the plant at steady state power operations, if a primary coolant system leak
rate calculation indicated an unidentified leak rate in excess of 0.3 gpm, or the
containment sump level trend indicated by the Plant Process Computer-indicated--
a change in unidentified sump in-leakage rate in excess of 0.2 gpm, then a
confirmatory leak rate calculation will be performed as soon as possible.
The licensee's actions to implement these new commitments are discussed in
Section 03.1 of this report.
c.
Conclusions ___ ----------------------------------- -- -----------------------
The licensee had missed an opportunity to identify the leak at the Reactor Coolant
Pump P-50A cover to casing joint during the June 1998 system pressure test which
indicated a lack of rigor in the conduct of this testing. Further, the licensee had failed to
15
submit a structural evaluation on the degraded pump joint to the NRC which was a
violation of 10 CFR 50.55a(g)(4) and demonstrated a poor understanding of the
applicable Code requirements.
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1
Failure of MSIVs To Fully Close During Plant Shutdown
a.
Inspection Scope (37551. 71707. 61726)
The inspectors reviewed licensee actions in response to the failure of the MSIV's to fully
close and applicable control room logs, condition reports, surveillance procedures, and
TSs. Also, the inspectors observed portions of the troubleshooting activities and the
plant review committee meetings, and reviewed the root cause analysis.
b. *
Observations and Findings
The MSIVs (CV-0501 and CV-0510) were closed on December 14, 1998, at 2:00 p.m.
for the plant shutdown. Closed indication was received in the control room and, based
on that indication, the control room operators concluded that the MSIVs were closed.
Local verification was neither r~quired nor conducted at that time.
On December 15, 1998, at 1 :30 a.m., with the MSIV bypass valves and the MISVs all
indicating closed, the control room operators identified that secondary steam pressures
remained approximately equal to steam generator pressures. The MSIV bypass valves
were cycled opened and closed with no apparent change in the system parameters. At
that time, the operators suspected that the MSIVs were not fully closed which was
confirmed by local valve position indication verification. Both MISVs were partially open
(CV-0501 was approximately 7/8 inches from the fully closed position and CV-0510 was
approximately 5/8 inches from the fully closed position). The MSIVs subsequently went
full closed later that day, with no operator action, when steam generator pressures were
less than 600 psia. Condition Report C-PAL-98-1942 was generated to document the
deficiency.
The MSIVs were swing check valves that would "fall" into the process steam flow when
the air used to open the valves was vented off below the actuator piston. The
combination of the weight of the valve disc, spring pressure above the actuator piston,
and process steam flow would close the valves.
System engineering personnel conducted rigorous testing of the MISVs with the plant in
- ----cold-shutdown-and also-consulted*with*the*vendor. -r>uring the-testin-g~th*e-valves-were*-----
instrumented to show actuator cylinder air pressures and valve position in degrees of
rotation. The actuator cylinder air pressure indicated that a relatively low cylinder air
pressure was reached before the valves started to close and that a relatively high
cylinder air pressure was needed to get the valves to start to open. Based on these
16
results, system engineering personnel determined that the valves were sticking and, as
a corrective action, they reduced the torque on the valve stem packing glands.
Subsequently, system engineering personnel concluded that a slight vacuum was being
developed on the spring side (atmospheric side) of the actuator cylinder during the
closing cycle when using both vent paths simultaneously. Two independent vent paths
were available for each MSIV via redundant solenoids. System engineering personnel
determined that the vent on the spring side of the actuator was not large enough to
allow air to enter the actuator as fast as air was being vented from the piston side. An
Engineering Analysis (EAR-98-750) was completed prior to increasing the actuator
atmospheric vent size. Specifically the existing vent plug that had a 1/4 inch drilled hole
in it was removed which effectively increased the actuator vent size to 3/4 inches.
Further investigation revealed that the 1/4 inch vent plug was installed for debris control
during factory testing following actuator refurbishment in the 1980's and was not
intended to remain installed.
The inspectors questioned engineering personnel regarding past performance of the
MSIVs. System engineering personnel indicated that the valve stem packing method
and material was changed during the 1998 refueling outage in an effort to reduce valve
stem packing leaks. The new method .consolidated the packing during installation in
that each packing ring was torqued individually vice applying the torque only once. to the
entire packing gland after all of the packing was installed. Specifically, the new method
applied 40 foot pounds of torque to each of the inner packing rings after they were
installed and then 58 foot pounds of torque was applied after the outer packing ring was
installed. The new packing method was successful in reducing the valve stem leakage;
however, the increased friction on the packing apparently contributed to the valves
failure to close.
On May 20, 1998, following repacking using the new method and material, the MSIVs
were stroked satisfactorily and, therefore, met the requirements of TSs. However, due
to leakage, the torque on one of the packing glands for MSIV CV-0501 was increased
to 100 foot pounds on June 10, 1998, with the. plant in hot shutdown following the 1998
refueling outage. Valve CV-0501 was subsequently stroked satisfactorily, based on
control room indication, in accordance with special test T-377, "Main Steam Isolation
Valve Hot Shutdown Packing Adjustment Stroke Time Test." However, local valve
position verification was neither required nor performed. Consequently, it could not be
definitively concluded that CV-0510 went full closed.
Both MSIVs failed to fully close during this outage but only CV-0501 had packing
adjustments performed following the 1998 refueling outage. Therefore, the packing
adjustment apparently was not the only cause of the subsequent failures. Also, system
engineering personnel discussions with the vendor revealed that changes in the packing
characteristics during the power run were unlikely; however, changes in MSIV
--:-- -- -- -------dimensiorra1-configuratiorfana/or-packin-(flcfaaingcouffnofoe rulec:fo-ut: -
-------
The inspectors considered the analysis that was performed by system engineering
personnel as rigorous. However, system engineering personnel did not .determine the
exact failure mechanism. They concluded that the most likely cause for the failure was
17
that the 58 foot pounds that was applied to the outer packing ring eventually equalized
the consolidation on all of the packing rings during the extended power run that
increased the packing friction on the valve stem. Consequently, the increased friction
stopped the MSIVs from going full closed after the valve disc lost momentum in the
closed direction because of the partial vacuum that was created in the actuator.
Technical Specification 3.5.1.f required that the MSIVs be capable of going closed within
5 seconds under no flow conditions. System engineering was not able to precisely
predicl when packing friction increased to the point that precluded full closure of the
MSIVs under no flow conditions. Therefore, the licensee assumed that the valves would
not have satisfied the requirements of TS 3.5.1.f from the last time it was demonstrated
that the MSIVs would go full closed under no flow conditions on May 29, 1998, until the
condition was corrected on December 19, 1998.
The licensee's corrective actions, as documented in the evaluation of Condition
Report C-PAL-98-1942, were considered thorough. The corrective actions that have
been completed included: 1) removal of the vent plugs that increased the size of the
actuator atmospheric side vent to preclude the partial vacuum in the actuator when
closing the MSIVs; and 2) reduced the packing torque on the MSIVs until consistent
travel to the full closed seat was demonstrated. System engineering personnel also
identified that inadequate test methods and test procedures contributed to the failure.
The planned corrective actions included appropriate revisions to the applicable testing
procedures and methods.
Failure of the MSIVs to be capable of being fully closed under no flow conditions while
- the plant was above 300°F is a violation of TS 3.5.1.f. This non-repetitive, licensee-
identified and corrected violation is being treated as a Non-Cited Violation,
(50-255/98022-04(DRP)) consistent with Section Vll.B.1 of the NRC Enforcement
Policy.
The MSIVs were subseq\\,Jently tested satisfactorily on December 19, 1998, and
therefore, were in compliance with TS requirements. Also, the licensee concluded that
the MSIVs were functional at all times in that they would have closed to perform their
containment isolation safety function under accident conditions because of the amount
of differential pressure that would be present across the valves. Therefore, the potential
adverse safety consequences were minimal.
In addition, the inspectors noted that system engineering personnel appropriately
evaluated the failure of the MSIVs in accordance with the maintenance rule and
determined that the failure was a maintenance preventable functional failure. The
evaluation was considered rigorous.
---- ------ ~
- - --- --- -- -- ---
18
E2.2
Pressurizer PORV Inoperable Position Indication Lights
a.
Inspection Scope (37551. 71707)
b.
The inspectors reviewed the circumstances related to .the problems identified with PORV
position indicating lights. The operational impact of the PORV indication problems are
discussed in Section 01.2 of this report.
The inspectors reviewed applicable control room logs, condition reports, TSs, and
surveillance procedures. Also, the inspectors reviewed the root cause analysis and the
Updated Final Safety Analysis Report.
Observations and Findings
On December 14, 1998, pressurizer PORV-10438 was stroked open by control room
operators in preparation for establishing low temperature overpressure protection during
the start of the forced outage. The open indication (red light) did not illuminate.
Condition Report 98-1937 was generated to document the deficiency. Subsequent
troubleshooting identified that a bracket was loose on the position indication limit
switches. The bracket was tightened and the valve was subsequently stroked
satisfactorily. Similar problems regarding PORV position indication occurred during the
outage on December 27 and December 28, 1998. The position indication was repaired
following each instance.
Subsequently, on January 5, 1999, the PORVs were stroked for post maintenance
testing. The inspectors considered the post maintenance testing thorough in that it
opened the valves in a "cold" condition (room temperature with no process steam flow in
the line between the block valve and the PORV) and also required the valves to be
opened "hot" (process steam in the line between the block valve and the PORV to allow
the PORV to heat up). The testing was designed to recreate the conditions that existed
when the valve position indication lights first failed on December 14, 1998.
When the PO RVs were opened "cold,* the position indication worked as designed for
both valves. Subsequently, the PORV block valves were opened, one at a time, to heat
up the line to the PORVs. When the PORVs were stroked following the heat-up,
PORV 10428 indicated intermediate (red and green light out) and PORV 10438
indicated closed (green light on, red light out) with no apparent change in valve position.
When both valves were stroked approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later, PORV 10428 indication
worked as designed and PORV 10438 again indicated closed with no apparent change
in valve position. However, quench tank pressure and level both increased when the
PORVs were stroked which confirmed that the valves actually opened. Condition
Report C-PAL-99-0020 was generated to document this deficiency and both PORVs
were declared inoperable on January 5, 1999, for troubleshooting.
---~--- *----- ----
---- ---- --- .. --- ------ -----
--~--
System engineering conducted extensive testing on the PORVs and also consulted with
the vendor. The testing revealed inconsistent position indication (red/green lights in
control room) results and therefore, the position indication switches were declared
inoperable for both PORVs pending further repairs. The inoperable position indication
19
- .
lights in the control room created an operator work around that had minimal impact on
the operators. Technical Specification 3.17.6 required that the failed position indication
be repaired prior to the next startup from cold shutdown.
Operability of the PORVs was also questioned because of the inconsistent position
indication results. System engineering analyzed the test data and recommended that
the PORVs be declared operable. The following reasons were included in the
operability determination:
Non-intrusive acoustic monitoring results indicated that the valves fully stroked
under both hot and cold conditions.
Free valve travel to the full open and closed positions was apparent with
differential pressure across the valve.
Wavebook diagnostic equipment that monitored the PORV audio monitor, open
and closed limit switches, and voltage and current to the solenoid .was utilized
during hot cycling. The information obtained showed indications of fluttering (full
closed to full open) which correlated well to the audio signatures and quench
tank pressure change, and therefore indicated flow through the valves.
There was some evidence that valve 10438 ended in an intermediate position
(not full open) when cycled hot with no differential pressure across the valve.
However, based on discussions with the vendor representative and all diagnostic
results, it was concluded that the valve would fully open with the system
pressurized.
The inspectors noted the PORV block valves are closed to isolate the PORVs during
normal operations at power because credit was not taken for operation of the PO RVs. in
the plant transient accident safety analysis. The PORVs were designed to protect the
primary coolant system from overpressure during abnormal transients associated with
low temperature (less than 430°F), water solid system operations. The PORVs would
also be required to function for a "feed and bleedn evolution as a contingency action to
cool the primary coolant system during an emergency shutdown. The inspectors
considered the operability recommendation that was developed by system engineering
personnel as thorough in that it addressed the various design functions of the PORVs:
The PORVs were.declared operable on January 6, 1999.
c.
Conclusions Regarding Engineering Support of Facilities and Equipment
The inspectors concluded that engineering personnel conducted thorough testing and
performed an in depth analysis regarding the failure of the MS IVs to close which was
determined to be a maintenance preventable functional failure. lnoperability of the
- ----- __ . __________ MSIVsJrom-May-29,-1998,--until the~condition-was-corrected-on-Becember-19;--1998~
was a Non-Cited Violation.
Engineering personnel conducted extensive testing on the pressurize PORVs and
provided a thorough operability recommendation to operations. However, an operator
20
\\*
E4
E4.1
a.
work around was created in that the PORV position indication lights remained
inoperable pending required repairs prior to plant start-up following the next time the
plant is in cold shutdown.
Engineering Staff Knowledge and Performance
Inadequate Primary Coolant Pump Oil Collection System
Inspection Scope (37551)
The inspectors reviewed various phases of Primary Coolant Pump P-50D oil leak
repairs, applicable condition reports, and Design Basis Document 2.04, "Primary
Coolant System."
b.
Observations and Findings
On December 17, 1998, system engineering personnel identified that the primary
coolant pump's oil collection system was inadequate. Appendix R, Section 111.0, of
10 CFR Part 50, required that each primary coolant pump be provided with a lube oil
collection system that was sized to contain the entire lube oil system inventory. The oil
collection tanks associated with the primary coolant pumps were sized based on a
nominal capacity of the upper reservoir of 62 gallons and the lower reservoir of
18 gallons. The collection tank capacity for P-50D, based on tank dimensions, was
91 gallons.
- However, a total of 84 gallons was added to the upper reservoir for Primary Coolant
Pump P-50D following oil leak repairs. Therefore, the 84 gallons in the upper reservoir,
when combined with the nominal 18 gallons in the lower reservoir, exceeded the
capacity of the oil collection tank. Consequently, the oil collection tank on P-50D was
outside the design basis and failed to meet the requirements of Appendix R. System
engineering personnel demonstrated a positive questioning attitude that contributed to
the identification of this issue. Condition Report C-PAL-99-1962 was written to document
this non-compliance.
- The inspectors noted that Design Basis Document 2.04, dated June 18, 1997,
Section 3.4.4.6, "Fire Protection," stated that primary coolant pump oil collection system
- was validated by Engineering Analysis, EA-D-PAL-92-220, *Revision 1, "Analysis of--*
Adequacy of Oil Collection System for Primary Coolant Pumps P50A, B, C, and D,"
June 7, 1993. That engineering analysis apparently was a missed opportunity to identify
that the oil collection system was inadequate which demonstrated a lack of rigor during
performance of the analysis.
Further analysis by system engineering personnel determined that the upper and lower
--oil-reservoir-systems on the primary*coolant pumps-were* independent*of*each-other:-- - ------ ------
Also, the oil collection system was sized to collect oil from the worst anticipated leak and
not two totally separate oil reservoir leaks. Therefore, engineering personnel declared
the oil collection system operable but degraded because it would collect all the oil for a
leak from either the upper or lower reservoirs but not a simultaneous leak from both.
21
- .
However, the oil collection system did not meet applicable 1 O CFR Part 50, Appendix R,
requirements. The adverse safety consequences were considered minimal because
both the upper and lower oil reservoirs would have to fail concurrently to exceed the oil
collection system's capacity. Also, if the upper and lower reservoirs both failed then the
amount of oil that spilled onto the containment floor would be minimal and would not
come into direct contact with any heated or ignition surfaces.
Licensee personnel reported this condition to the NRC in accordance with
10 CFR 50. 73. The corrective actions were documented in the evaluation of Condition
Report C-PAL-98-1962, and in Licensee Event Report 98-011. The licensee's planned
corrective actions included requesting from the NRC an exemption from the
10 CFR Part 50, Appendix R, requirements. If the exemption was not granted then the
oil collection tank capacity would be increased to be able to collect the entire inventory
of the lube oil system. The corrective actions were considered to be reasonable and
adequate.
The inadequate sizing of the primary coolant pumps' oil collection system is a violation
of 10 CFR Part 50, Appendix R, Section 111.0. This non-repetitive, licensee-identified
and corrected violation is being treated as a Non-Cited Violation, consistent with
Section Vll.B.1 of the NRC Enforcement Policy (50-255/98022-05(DRP)).
E4.2
Primary Coolant Pump P-50A Pump Casing Leak (37551) *
The inspectors reviewed the applicable condition reports and the leak investigation
analysis. On December 14, 1998,_ with the plant in hot shutdown, system engineering .
conducted a walkdown of Primary Coolant Pump P-50A and identified a build-up of boric
acid near the component cooling water inlet line to the pump. Condition
Report C-PAL-98-1939 was generated to document the issue. System engineering
conducted the walkdown to specifically check P-50A because boric acid buildup was
identified, and subsequently cleaned, on the component cooling water inlet flange to
P-50A and the surrounding area during the 1998 refueling outage. However, at that
time, the boric acid buildup was incorrectly contributed to pump seal leakage.
System engineering personnel inspected all of the primary coolant pump casing studs
on the other three primary coolant pumps in response to the identified degraded studs
on P-50A. No other stud degradation or active leaks were identified. The inspectors
concluded that the walkdown that was performed during this outage demonstrated a
positive questioning attitude and a pro-active initiative by system engineering personnel
that contributed to the identification of the leak on primary coolant pump P-50A.
c.
- Conclusions Regarding Engineering Staff Knowledge .and Performance
The inspectors concluded that system engineering personnel demonstrated a positive
--**-* _____ questioning.attitude.during primary-coolant-pumpoil leak-repairs-this-outage-which-*-*
contributed to identifying the inadequate primary coolant pumps' oil collection system.
However, engineering personnel missed an earlier opportunity to identify the deficiency
during an engineering analysis that was conducted in the early 1990's. The inadequate
primary coolant pumps' oil collection system was a Non-Cited Violation.
22
Also, the inspectors concluded that the walkdown that was performed during this outage
demonstrated a positive questioning attitude and a pro-active initiative by system
engineering personnel that contributed to the identification of the leak on Primary
Coolant Pump P-50A.
IV. Plant Support
R1
Radiological Protection and Chemistry (RP&C) Controls
R 1.1
Radiological Protection (71750)
The inspectors conducted frequent plant tours and reviewed radiological protection dose
management that was conducted during the forced outage. No deficiencies were noted
during routine tours. The radiation do.se received (9.20 person-REM) during the forced
outage was less than the projected dose (10.45 person-REM) which demonstrated
effective dose management. Also, a first time evolution was completed that flushed the
shutdown cooling heat exchangers after shutdown cooling was secured by recirculating
the water to the safety injection refueling water storage tank. The evolution effectively
reduced post-outage dose rates in the area of the shutdown cooling heat exchangers
(safeguards rooms) to pre-outage levels and reduced dose rates in the safeguards
rooms which were routinely toured by plant personnel. The inspectors concluded that
effective dose management was demonstrated during the outage. Also, flush of the
shutdown cooling heat exchangers, a first time evolution, demonstrated a positive pro-
active initiative to reduce radiation dose rates in plant areas that were routinely toured
by plant personnel.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at
the conclusion of the inspection on January 12, 1999. The licensee acknowledged the
findings presented and senior plant management indicated that an evaluation regarding
the operator performance deficiencies that were identified during this outage would be
_ cqnducted. The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary information was
identified.
- - -------
--- -- --- --
-- ---------
-- --- --------------- ------ -- ----
~ -------
23
PARTIAL LIST OF PERSONS CONTACTED
Licensee
T. J. Palmisano, Site Vice President*
G. R. Boss, Operations Manager
P. D. Fitton, Manager, System Engineering
N. L. Haskell, Director, Licensing
D. G. Malone, Licensing
D. J. Malone, Acting Manager, Chemical and Radiological Services
R. L. Massa, Shift Operations Supervisor
D. W. Rogers, General Manager, Plant Operations
G. B. Szczotka, Manager, Nuclear Performance Assessment Department
R. G. Schaaf, Project Manager, NRR
-- -- -- --
~---------
--- -- --- --- *-
24
------- ------------- ~- -----------
..
I~
INSPECTION PROCEDURES USED
IP 71707:
IP 62707:
IP 61726:
IP 37551:
Plant Operations
Maintenance Observations
Surveillance Observations
Onsite Engineering
IP 71750:
IP 92901:
IP 92903:
IP 92700:
Plant Support Activities
Followup - Operations
Followup - Engineering
Licensee Event Reports
Opened*
50-255/98022-01
50-255/98022-02
50-255/98022-03
50-255/98022-04
50-255/98022-05
Closed
50:-255/98-007
50-255/98022-01
50-255/98022-04
50-255/98022-05
Discussed
"**
ITEMS OPENED, CLOSED, AND DISCUSSED
.NCV
CCW system placed In a configuration that was contrary to
procedural requirements
EEi
Apparent failure to follow surveillance procedure
Failure to submit engineering analysis for NRC review
Failure of the MSIVs to be capable of closing fully under
no flow conditions
Inadequately sized primary coolant pumps' oil colle.ction
system
LER
High pressure safety injection system inoperability ...
CCW system placed in a configuration that was contrary to
procedural requirements .
Failure of the MSIVs to be capable of closing fully under
no flow conditions
Inadequately sized primary coolant pumps' oil collection
system
---*------ ___ None ___________________ ------*------------------*----- .. ------*
25