ML15118A221
| ML15118A221 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/02/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A219 | List: |
| References | |
| 50-269-97-02, 50-269-97-2, 50-270-97-02, 50-270-97-2, 50-287-97-02, 50-287-97-2, NUDOCS 9706120187 | |
| Download: ML15118A221 (45) | |
See also: IR 05000269/1997002
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04
License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503
Report No:
50-269/97-02, 50-270/97-02, 50-287/97-02
Licensee:
Duke Power Company
Facility:
Oconee Nuclear Station, Units 1, 2 & 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
March 23, 1997 - May 3. 1997
Inspectors:
M. Scott, Senior Resident Inspector
G. Humphrey, Resident Inspector
N. Salgado, Resident Inspector
D. Billings, Resident Inspector
R. Moore, Reactor Inspector (Sections E2.1, E8.2, E8.4,
E8.5)
R. Chou, Reactor Inspector (Sections E1.3, E1.4, E1.5)
N. Economos. Reactor Inspector (Section M1.3)
B. Carroll, Project Engineer (Sections M8.5, M8.6)
Approved by:
C. Casto, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9706120187 970602
ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2 & 3
NRC Inspection Report 50-269/97-02,
50-270/97-02. 50-287/97-02
This integrated inspection included aspects of licensee operations.
engineering, maintenance, and plant support. The report covers a six week
period of resident inspection; in addition, it includes the results of
announced inspections by four regional reactor inspectors.
Operations
Unit 1 was shutdown for a scheduled Reactor Coolant Pump (RCP)
outage. This was professionally and methodically accomplished
with good operator command and control.
Rod drop time testing
during the shutdown was acceptable. (Section 01.2)
The return of Unit 1 to power operation was appropriately managed
and executed. Aside from the higher than expected RCP vibration
values, the plant operated ina normal and expected manner.
(Section. 01.4)
On April 21, licensee investigation discovered unidentified
Reactor Coolant System (RCS) leakage. On April 22, the licensee
declared a Notice of Unusual Event based on unidentified Unit 2
leakage greater than 10 gpm. The 2A1 High Pressure Injection
(HPI) line had a crack in the pipe to safe end weld. During the
discovery and investigative phases of the 2A1 event, the
Operations staff performed professionally. The licensee
appropriately communicated with the NRC and other agencies. A
special NRC inspection team was formed to followup on this event.
(Section 01.5)
During the two Unit 2 drain downs to < 50 inches RCS level (mid
loop), the inspectors concluded that the licensee implemented and
.
maintained the requirements specified by procedure while
accomplishing reduced inventory operations. The inspectors
concluded that the reduced inventory evolutions were well
coordinated and controlled. (Section 01.6)
Based on initial Unit 2 HPI pipe crack event findings of the
licensee's Failure Investigation Process (FIP) team, the licensee
re-evaluated previous non-destructive examinations made on Unit 3
and voluntarily shut it down.
(Sections 01.7 and E1.6)
On May 3 at 9:20 a.m., Unit 3, which had been shutdown the
previous evening and was being prepared for further cooldown, lost
the flow from two HPI pumps. The residents were promptly notified
by the licensee and responded to the site. Aside from the failure
of the pumps, the licensee activities in response to the Unit 3
event were adequate. Post event operational management of the
Enclosure 2
2
problem was adequate. In view of the initial non-level emergency
plan action determination, the licensee's decision tQ man the
Technical Support Center (TSC) and Operations Support Center (OSC)
was conservative and practical. A NRC Augmented Inspection Team
was formed to evaluate the circumstances surrounding the unusual
event. (Section 01.8)
The licensee identified a lack of procedural controls to maintain
Low Pressure Injection (decay heat removal) cooler outlet
temperature above the minimum temperature (70 degrees F) shown on
the Technical Specification (TS) heatup and cooldown curves,
section 3.1.2. Procedural guidance permitted operation at
temperatures lower than the operating region as defined by TS
curves. A licensee engineer identified this problem during a Unit
3 outage review and a Non-Cited Violation (NCV) was identified.
(Section 03.1)
A Technical Specification required lock on a Control Rod Drive
System patch panel was found unlocked in 1995. This was reported
in a Licensee Event Report and a NCV was identified. (Section
08.1)
Maintenance
The inspector concluded that the licensee's actions were
appropriate to identify and repair a Unit 3 HPI pump oil leak
within the required Limiting Condition for Operation (LCO)
timeframe. The licensee's evaluation of the Component Cooling
(CC) system flashing during the post modification HPI performance
test was adequate. Placing the operations procedure for the CC
system on administrative hold was appropriate while the licensee
continued to review the process .of setting up flow to the letdown
coolers. (Section M1.2)
Corrective maintenance on the 1A1 Reactor Coolant Pump was being
performed in accordance with approved procedures. Craft and
supervisors were knowledgeable and carried out their tasks
satisfactorily (Section M1.3).
Operations failure to complete the procedure prerequisites prior
to performing other sections in the main body of an elevated water
storage tank (for fire protection) civil inspection procedure was
identified as a violation of procedure adherence. (Section M1.4)
Engineering
The inspectors concluded that the two remaining sections of Unit 3
Integrated Control System (ICS) testing were satisfactorily
accomplished in accordance with the licensee's procedures.
Control of all test activities was good. Positive observations
Enclosure 2
3
were made relating to test briefings. Control Room (CR) briefings,
and communication and coordination of test evolutions. (Section
E1.1)
The licensee reported an unresolved safety question to the NRC on
missile protection of the Low Pressure Service Water (LPSW) system
piping. (Section E1.2)
The inspectors concluded that the licensee performed adequate pre
operational tasks for the transporting, inserting, and retrieving
of the Dry Storage Cask from the Fuel Receiving Area to the
Horizontal Storage Module. (Section E1.3)
The inspectors considered that the licensee performed an adequate
installation of concrete base mat and Horizontal Storage Modules
for Phase III of the Independent Spent Fuel Storage Installation,
except as identified in the violation on under sized welds (first
example). (Section E1.4)
The inspectors concluded that the licensee performed an adequate
review on the vendor Calculation Evaluation for the Upper Surge
Tank Supports. The modification on the supports was acceptable,
except as identified in the violation on Upper Surge Tank
uninspected welds (second example of one above).
(Section E1.5)
The cognizant engineer controlled and directed the maintenance
activity associated with the 1A1 Reactor Coolant Pump in a well
planned and conservative manner. Additional resources contracted
to assist in vibration analysis made a positive contribution in
assessing the problem. (Section M1.3)
The licensee was proactive in rapidly forming a Failure
Investigation Process (FIP) team shortly after the Unit 2
injection line crack condition was known. The licensee called in
available industry talent to support and supplement the team. The
licensee was communicative with the NRC and provided information
as required and requested by the NRC. (Section E1.6)
Procurement Engineering performance related to upgrade and
qualification of safety-related replacement parts was good.
Engineering evaluations were technically sound and well
documented. (Section E2.1)
Deficiencies were identified in the licensee's measures to assure
the quality of equipment and services received from a 10 CFR 50.
Appendix B, vendor. A violation of regulatory requirements was
identified. (Section E2.1)
Unrelated to procurement engineering, a violation was identified
for inadequate corrective actions and design control on Reactor
Enclosure 2
4
Building Cooling Unit (RBCU) fuse failures identified in 1995.
Additionally, Engineering failed to identify the opepability
impact of the fuse failures on the RBCUs. (Section E8.4)
Plant Support
During the Unit 2 HPI pipe crack and Unit 3 HPI pump degradation
events that occurred this inspection period, inspectors were
present to observe Emergency Plan activities performed by the
licensee. Overall, the licensee performed in a conservative
manner on both events and followed their Emergency Plan
Procedures. (Sections 01.5, 01.8, and E1.6)
Enclosure 2
Report Details
Summary of Plant Status
Unit 1 operated at full power until a scheduled shutdown on March 28, 1997.
to investigate the cause of high vibration on the 1A1 Reactor Coolant Pump
(RCP). (Section 01.2) The Unit was back online on April 8. 1997 (Section
01.3). and remained at full power for the remainder of the reporting period.
Unit 2 operated at full power until April 21, 1997, when the Unit began
experiencing increased unidentified leakage. During the process of shutting
down the unit, unidentified leakage increased to approximately 12 gpm at which
time the licensee initiated a Notice of Unusual Event (NOUE). (Section 01.5)
In order to examine and repair a failed weld in the 2A1 High Pressure
Injection (HPI) line (Section E1.6). the licensee reduced Reactor Coolant
System (RCS) inventory to 16 (+\\- 2) inches on two occasions (Section 01.6).
At the end of the inspection period, the unit remained drained down to 16 (+\\
2) inches.
Unit 3 operated at full power for most of the reporting period until May 2.
1997, when the unit began shutting down in order to examine a HPI nozzle based
on re-evaluation of previous Non-Destructive Examination (NDE). During the
process of going from hot to cold shutdown, two of three HPI pumps were
potentially damaged. A NOUE was declared by the licensee on May 3. 1997.
(Section 01.8)
Review of UFSAR Commitments
While performing-inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and/or parameters. A licensee identified UFSAR
issue is addressed in Section E1.2.
I. Operations
01 - Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious. Specific events and
noteworthy observations are detailed in the sections below.
01.2 Unit 1 Scheduled Shutdown (71707)
a. Inspection Scope
On March 28, Unit 1 shutdown to perform repairs on the 1A1 RCP that had
exhibited higher than normal vibration since the last inspection
period/startup from a forced outage (Inspection Report 50-269,
Enclosure 2
2
270,287/97-01, Section 01.2). The inspectors observed the'shutdown
activities and reviewed emergent problems.
b. Observations and Findings
The shutdown was normal, with all equipment operating as expected except
as indicated below. An inspector observed the satisfactory performance
of PT/0/A/0300/01, Control Rod Drive (CRD) Rod Timing Test. All rods
were within the administrative and less restrictive Technical
Specification (TS) time limits.
During the shutdown, the 1A2 RCP experienced high vibration and was
secured earlier than anticipated. An alternate RCP was used to cool the
plant to conditions permitting entry into Decay Heat Removal (DHR). The
1A2 RCP had reached approximately 30 mils displacement intermittently at
the pump's coupling spool piece which is higher than its normal at power
operation shutdown alarm setpoint of 20 mils. No damage occurred to the
pump or other plant components. Section M1.3 discusses work performed
on the 1A1 and 1A2 pumps. Section 01.4 discusses the return to power
operations of the unit.
c. Conclusions
The Unit shutdown was professionally and methodically accomplished with
good operator command and control.
Rod drop time testing performed
during the shutdown was acceptable.
01.3 Unit 1 Venting of the RCS (71707)
a. Inspection Scope
As discussed in Inspection Report 50-269.270.287/96-17. a violation was
identified regarding incomplete venting of the RCS due to valve
mispositioning. On April 5, the inspector observed the venting of the
Unit 1 RCS.
b. Observations and Findings
After repairs were performed on the 1A1 and 1A2 RCPs, the RCS loops were
refilled. The senior resident inspector observed the satisfactory
venting of the loops in accordance with OP/1/A/1103/02. Operations
performed the activities with appropriate diligence. As an independent
verification of a proper vent, when the RCPs were started no pressurizer
level changes were observed. Gaining additional information during this
venting, Operations has planned further enhancements to the procedure
prior to its next use. The RCP work is discussed in Section M1.3.
Enclosure 2
3
01.4 Unit 1 Restart (71707)
a. Inspection Scope
After RCP repairs had been performed, Unit 1 was prepared for restart.
Restart activities took place from April 7 - 11.
During the
preparation, which included various combinations of RCP pump operation,
the inspectors observed pump vibration levels and operator activities.
b. Observations and Findings
Aside from some higher than expected RCP vibration levels, the startup
preparation activities were normal and appropriately carried out by the
licensee. The unit went critical at 6:36 a.m., on April 11, 1997. The
Main turbine generator was latched to the electrical grid at 4:12 p.m.
that same day. Two minor problems occurred during startup. One
involved pressure swings in the auxiliary steam header pressure when the
operators were balancing steam load between Unit 1 and Unit 3. The
licensee had been continually looking at this problem throughout the
inspection period. The second minor problem occurred during the
approach to criticality. The startup was delayed due to Group 5. Rod 7
not moving when other rods in the group indicated movement. A corroded
connector pin was identified as the cause. Following cleaning of the
pin and testing, the Unit was started up without further problems.
Observation of the approach to criticality was found to be adequate.
During the restart activities, the 1A1 and 1A2 RCPs had higher than
expected vibrations. During low RCS pressure and temperature 1A2 RCP
runs, the pump ran with 30.3 and 25.8 mils vibration (at the pump
coupling spool piece, X and Y orientation on 4-7-97) but settled into
more expected levels of 5.5 and 4.3 mils (4-10-97) at higher pressure
and temperature with all RCPs in operation. During low RCS pressure and
temperature 1A1 RCP runs, the pump ran 46.0 and 39.0 mils (at same
locations as above on 4-7-97) and it settled into slightly higher than
expected levels of 19.6 and 20.5 mils (on 4-10-97). The recommended
emergency shutdown vibration levels provided by the pump vendor was 20.0
mils at the spool piece location. The licensee had been in
communication with the pump vendor as previously discussed in Inspection
Report 97-01, resolving that the higher than expected vibration was
mainly an economic'consideration. The RCP seal package was not
challenged by the pump vibration levels. The pump vendor was expected
on site in May 1997, to review collected data from the "A"
loop RCPs.
As of this report, the licensee planned to run the RCP with appropriate
planned contingencies, 50.59 evaluation, and engineering overview until
the next refueling outage (late August). The licensee did not yet have
a course of action for the 1A1 RCP repair/reduction in vibration level.
Enclosure 2
4
c.
Conclusions
The return of Unit 1 to power operation was appropriately managed and
executed. Aside from the higher than expected RCP vibration values, the
plant operated in a normal and expected manner.
01.5 Unit 2 2A1 Injection Line Break
a. Inspection Scope (71707. 93702)
On April 21, Unit 2 personnel detected an increase in RCS unidentified
leakage and responded to the event. The licensee called the Senior
Resident Inspector (SRI), who came to the plant to followup on the
occurrence. The leakage was not readily identified. While the licensee
performed an orderly shutdown, the leakage increased to the point that a
Notice of Unusual Event was declared.
b. Observations and Findings
On April 21. at 10:45 p.m., Operations personnel observed indications
that Unit 2 had increased unidentified RCS leakage. The licensee began
investigating in accordance with Technical Specification (TS) 3.1.6.
The normally constant level Letdown Storage Tank (LDST) was slowly
losing level and the normal Reactor Building (RB) sump required
increased pumping. As the above was observed, the RB general radiation
monitors came into alarm. A subsequent RCS leakage calculation
indicated a 2.36 gpm leak rate, which was up from the normal rate of a
few tenths of a gpm. The licensee called the SRI at 12:50 a.m., who
responded to the plant. On April 22, 1997, at approximately 1:30 a.m.,
an Operations RB entry revealed a spraying fog in the "A"
cavity near
the 2A1 RCP that could not be safely approached. The licensee began an
orderly shutdown of the unit at 3:52 a.m. and notified the NRC duty
officer at 4:26.a.m. At that time the leakage rate was 3.4 gpm. The
inspectors went into an around the clock coverage for plant monitoring
with supplemental personnel from the regional office staff.
That same day, reactor power was reduced to 20 percent (reached at 09:08
a.m.), an held for another RB entry but the licensee was still unable to
identify the leak due to spray. The leakage was seen at or near the
2HP-127 isolation valve, which is on the 2A1 normal makeup injection
line near the RCS cold leg. Leakage continued to gradually increase
until about 4:00 p.m. when it exceeded 10 gpm and the licensee declared
a Notice of Unusual Event. At 4:46 p.m., the licensee verified that RCS
boron was within the limits of the shutdown boron calculation and plant
cooldown was commenced. Later on April 22, 1997, the licensee exited
the unusual event condition at 8:32 p.m. when RCS leakage went below 10
gpm (two consecutive calculations). Maximum achieved leakage was nearly
12 gpm.
Enclosure 2
5
On April 23, 1997,
at 4:45 a.m., a third containment entry-was made. At
the time, the plant was approximately 250 degrees F and 278 psig. with
RCS leakage at 1.8 gpm. The SRI entered the building with two
operations personnel, discovering a still spraying unisolable crack in
the weld joining the 2A1 injection line pipe and the injection nozzle
safe end. The 2.5 inch diameter pipe weld was cracked between the 10:00
to 2:00 o'clock position. All hangers on the piping appeared to be
intact, as did the 2A2 injection line.
Once on shutdown cooling, Operations proceeded to drain down for
inspection and removal of the crack area for root cause determination.
Section E1.6 discusses preliminary investigation of the problem.
Section 01.6 below discusses the two draindowns to reduced inventory.
A special NRC team inspection was officially formed (Inspection Report
97-07) April 5, 1997, to follow this event to its completion. Prior to
team formation, the team leader had been on site since the day of the
event following licensee activities.
c. Conclusions
During the discovery and investigative phases of the problem, the
Operations staff performed professionally. The licensee appropriately
communicated the emergency class notification and updates to the NRC and
other agencies.
01.6 Draindown of the Unit 2 RCS to Midloop
a. Inspection Scope (71707. 93702, 40500)
As a controlled repair activity followup to the above event, the
licensee drained the Unit 2 RCS twice to levels below the RCP seal
package. Prior to, and during the draindowns, the residents attended
the prejob briefs, pre-planning meetings, Plant Operations Review
Committee (PORC) meetings, as well as observed the draindown evolutions
to achievement of stable conditions.
The inspectors reviewed the Unit 2 midloop operations as controlled by
procedure OP/2/A/1103/11. Draining And Nitrogen Purging Of Reactor
Coolant System.
b. Observations and Findings
In order to repair a failed weld downstream of 2HP-127 on the outlet
side of the tee where the warming line connects to the injection line
(Section 01.5), the licensee reduced RCS inventory to 16 (+\\- 2) inches.
The licensee achieved the required levels on April 27 and 30. The
inspectors reviewed the licensee's program prior to the reduction of RCS
inventory and verified that the requirements were met while operating at
the reduced inventory levels as specified in procedure OP/2/A/1103/11,
Enclosure 2
6
Enclosure 3.6, Requirements for Reducing Reactor Vessel Level to < 50"
on LT-5. This procedure stipulated the sequence and stepsrequired for
reduction of RCS inventory and midloop operation. It further specified
the precautions and limitations to be adhered to while in midloop.
The inspectors verified that the requirement for two independent trains
of RCS level monitoring was met while at reduced inventory. This was
accomplished through the use of two permanently installed instruments
(2LT-5A and 2LT-5B) and two temporary ultrasonic instruments.
Level
indications were displayed in the control room (CR) on the 2LT-5A and
2LT-5B indicators, the Inadequate Core Cooling Monitor, and on the
Operator Aid Computer.
The inspector verified that two trains of core exit thermocouples were
available and utilized while at reduced inventory, as well as that the
two sources of inventory makeup and cooling were available for
operation. Multiple sources of offsite power were also available. The
inspector reviewed the licensee's contingency plans to repower vital
busses from available alternate electrical power supplies in the event
of the loss of the primary source.
Once the section of pipe was cutout, and capped, the licensee commenced
makeup to raise RCS level to 80 inches on April 29, 1997. Although, the
level was increased, the licensee was maintaining < 50" requirements
until repairs were completed.
A second draindown to 16 (+/-2) inches was necessary to perform repairs
on the damaged thermal sleeve and to replace the HPI piping that had the
weld crack. The draindown commenced on April 30, 1997. The inspectors
were in.the CR to observe operations during this draindown evolution.
All the parameters described in the previous paragraphs were applicable
for this draindown. No problems were identified. The Unit remained in
the draindown condition through the end of this reporting period.
c.. Conclusion
The inspectors concluded that the licensee implemented and maintained
the requirements specified by procedure while accomplishing reduced
inventory operations without incident on two occasions. The inspector
concluded that these reduced inventory evolutions were well coordinated
and controlled.
01.7 Unit 3 Shutdown Due to Injection Line Concerns
a. Inspection Scope (71707, 93702. 40500)
Based on initial Unit 2 event findings of the Failure Investigation
Process (FIP) team, the licensee re-evaluated previous non-destructive
examinations made on Unit 3. The licensee voluntarily shutdown Unit 3
when the 3A1 injection line condition had been brought into question
Enclosure 2
7
(see Section E1.6). The inspectors monitored the activities before and
during the shutdown.
b. Observations and Findings
The unit completed a normal shutdown from 100 percent power on May 1 and
2. Aside from some minor Integrated Control System (ICS) problems at
about 12 percent power, the shutdown was routine. All parameters and
plant equipment except ICS operated normally. As power was decreasing
from the 12 percent range, the ICS transfer from constant Tave to
decreasing Tave programs was not a bumpless transfer in that power
abruptly dropped from 12 to 7 percent power (as indicated on NIs).
The
operators stopped power reduction and reset the reduction rate from 0.2
% per minute to 0.1 % per minute and a slow, predictable power reduction
resumed. Instrument & Electrical (I&E) engineers were reviewing the
occurrence at the end of the period.
01.8 Unit 3 Loss of Normal RCS Makeup
a. Inspection Scope (93702)
On May 3, at 9:20 a.m., during preparations for further Unit 3 cooldown,
the 3A and 3B HPI pumps experienced fluctuating pressure, flow, and
motor amperes. The licensee declared the pumps inoperable/out-of
service. The residents were promptly notified by the licensee and
responded to the site.
b. Observations and Findings
As indicated above, Unit 3 was preparing to cooldown with one Low
Pressure Injection (LPI) pump in RCS recirculation and the 3B1 RCP
running to cool RCS components. With the Letdown Storage Tank (LDST)
indicating approximately 55.9 inches level, a statalarm annunciated
indicating low HPI header pressure. Operators observed the running 3B
HPI pump motor amperes oscillate. The 3A HPI pump auto-started with the
low pressure and it also indicated swinging motor amperes. Both pumps
were secured. The entire episode with the pumps lasted approximately 19
minutes when the last HPI pump, the 3A, was secured. At the end of this
time, the plant was still at a stable temperature and pressure with the
heat from the running RCP maintaining pressure. All other evolutions
were stopped while the licensee evaluated the condition. Once notified,
the residents responded to the plant. Licensee evaluation of the
emergency plan indicated that no notifications were required at that
time. The licensee manned the Operation Support Center (OSC) and the
Technical Support Center (TSC) to support evaluation of the condition
and to be available should conditions worsen. The residents went into
an around the clock coverage.
During the pump problems, a non-licensed operator (NLO) was dispatched
to the HPI pump room for observation. He noted smoke and/or a vapor in
Enclosure 2
8
the air around the 3A pump and the pump was warm. He reported this to
the CR. When the SRI arrived at the site at approximately9:40 a.m.
(well after the HPI pumps had been secured), he immediately inspected
the pump areas noting no smoke or unusual heat. There was a slight
electrical odor in the air. Suction pressure was 45 to 50 psig on the
pumps. The 3A pump had a local discharge gage pressure of zero and the
3B pump had a pressure of 2030 psig (CR pressure read zero for this
value). The pump seals were observed not to be leaking fluid at that
time. Reportedly, the licensee flooded the suction line with borated
water storage tank (BWST) head pressure and the 3A pump seal leaked
water. Separately, a resident inspector also responding to the site had
entered the Unit 3 CR to followup on recovery activities.
The licensee took actions to get out of the condition of being unable to
cool down the RCS further. They took time to understand what of the HPI
system was functioning and available for use. Due to the chance that
the 3A and 3B pump were damaged, they did not want to pump/flow
associated pieces into the-rest of the HPI piping. Other than to the
LDST, the 3C HPI pump, which is normally only used during refueling
outages, can also be aligned to the BWST for makeup to the plant. A
procedure was developed to makeup to the RCS with this pump. Further, a
contingency procedure was also written to perform actions should the 3C
pump and flow path not work.
In parallel, the licensee attempted to.determine what had happened to
the two HPI pumps that had been secured. Checks on the level of the
LDST indicated that the level instruments were not reading correctly.
The reference leg of the instruments was found to be approximately 50
percent full after the tank had been re-filled. With tank level being
operated previously at around an indicated 55.9 percent, there was some
likelihood that the out-of-service HPI pumps had become air bound.
Due to the length of time it took to prepare the procedures for use of
the 3C HPI pump and the contingency plan, at the discretion of plant
management, the licensee entered into an Unusual Event Classification
from their emergency plan (May 3).
The 3C HPI pump use procedure became
available in the evening of May 3. The contingency plan procedure was
not available until the next day which was outside of the current
inspection period.
Through the night of May 3, the licensee made preparations for the next
day's operational recovery to resume plant cooldown. The licensee
flushed and vented the piping surrounding the 3C pump and made
instrument checks of components. The plant was heating up about one
degree per hour, but otherwise was in a very stable condition.
The NRC formally chartered an Augmented Inspection Team (AIT) on May 5,
1997, to evaluate the licensee's activities regarding the above event.
The manager for the AIT was sent to the site on May 3, 1997, to support
Enclosure 2
9
the resident's around the clock coverage. The AIT's findings will be
documented in IR 50-269.270,287/97-06.
c. Conclusions
Operational management of the problem was adequate. In light of the
non-level emergency plan action determination, the licensee's manning of
the TSC and OSC was conservative and practical.
01.9 10 CFR 50.72 Reports Submitted During this Inspection Period
During the inspection period, five 10 CFR 50.72 notifications were
called in by licensee. The inspectors were appropriately notified of
the reports by the licensee. The residents tracked any Limiting
Condition for Operation (LCO) conditions and followed up on any
corrective actions.
The following reports were made by the licensee:
-
On April 2. 1997, for Unit 3. it was determined that the Reactor
Building Cooling Unit (RBCU) primary side control fuses were
potentially under rated and may not have permitted the RBCUs to
start during a Loss of Coolant Accident (LOCA)/Loss of Offsite
Power (LOOP) upon receipt of an Engineered Safeguards (ES) signal.
The fuses had been replaced with fuses of a higher rating on June
21. 1995. Therefore, the potential RBCU inoperability existed on
Unit 3 prior to June 21, 1995. Section E8.4 of this report
addresses this issue..
-
On April 17, 1997, it was determined by the licensee's engineering
analysis that the travel stops on valve HP-120 may not have been
set to adequately restrict makeup flow through this valve. As a
result, during past periods in which Units 1, 2. and 3 were in a
condition where RCS temperature was less than 325 degrees F, the
second train of Low Temperature Overpressure Protection (LTOP)
may
not have been capable of mitigating certain LTOP events since less
than a ten minute delay period would have been available. This is
discussed in Section E2.2 of this report.
-
On April 26, 1997, it was determined that portions of Oconee's Low
Pressure Service Water system piping did not meet the Oconee UFSAR
design requirements for high trajectory turbine missiles. This is
discussed in Section E1.2 of this report.
-
On May 2, 1997, it was determined that Oconee Unit 2 primary
unidentified leak rate was found to exceed TS 3.1.6.1 limits of 1
gpm. Maximum leak rate was approximately 12 gpm.
Based on this
information, the licensee entered into an Emergency Plan Unusual
Event action level.
This is discussed in Section 01.5 of this
report.
Enclosure 2
10
-
On May 3, 1997, it was determined by engineering evaluation that
with an inaccurate LDST level indication the Unit 3 HPI system
would not have been able to perform its intended safety function
during power operations. At approximately 9:20 a.m. on the same
day, two of the HPI pumps had been potentially damaged by possible
air binding due to voiding of the LDST. Section 01.8 discussed
this event.
02
Operational Status of Facilities and Equipment
02.1 Engineered Safety Feature System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walkdown accessible
portions of the following safety-related systems:
Keowee Hydro Station
Unit 2 HPI injection lines
Unit 2 HPI pumps
Unit 3 HPI pumps
Unit 3 penetration rooms
Unit 1, 2. & 3 600 Volt electrical breakers and supply
transformers
Unit 2 and 3 TDEFW pumps
Unit 2 and 3 RBs
Equipment operability, material condition, and housekeeping were
acceptable in all cases. Several minor discrepancies were brought to
the licensee's attention and were corrected. The inspectors identified
no substantive concerns as a result of these walkdowns.
03
Operations Procedures and Documentation
03.1
Inadequate Procedure for Control of LPI Temperature
a..
Inspection Scope.(71707)
The inspector reviewed Licensee Event Report (LER) 269/97-01 and
interviewed personnel associated with the issue of inadequate procedural
control of LPI temperature.
b. Observations and Findings
On December 15, 1997, Units 1 and 2 were in cold shutdown and Unit 3 was
in a refueling outage. All three units were being cooled by LPI flow
which is the B&W version of decay heat removal. A system engineer
identified a lack of procedural controls to maintain LPI (decay heat
removal) cooler outlet temperature above the minimum temperature (70
degrees F) shown on the TS heatup and cooldown curves, section 3.1.2.
Procedural guidance permitted operation at temperatures lower than the
operating region as defined by TS curves.
Enclosure 2
11
A 10 CFR 50.72 notification was made on February 13. 1997,-following the
completion of a past operability evaluation (PIP 5-96-2653.).
The
evaluation concluded that limiting values for temperature had been met
in the past.
The licensee's review of Operations procedures indicated that 70
degrees F was the minimum temperature that can be injected into the
reactor vessel. However, when compared to the TS limit, the procedure
limit was not compensated for instrument inaccuracy or operational
margin. Other Operations procedures required that the LPI pump suction
temperature be maintained between 60 and 125 degrees F.
Technical inaccuracies in the operating procedures did not include
adequate consideration and emphasis on the applicability of TS
temperature limits when heatup and cooldown activities were not in
progress. Therefore, the applicability of monitoring LPI cooler outlet
temperature as a controlling parameter was omitted. This could have
allowed LPI to enter the vessel at a temperature lower than that allowed
by TS.
Immediate corrective actions were to increase LPI cooler outlet
temperature to 81 degrees F until instrument inaccuracies could be
determined. Followup corrective actions included revising Operating
Procedures with correct instrument accuracies to specify operation at
greater than 75 degrees F at the LPI cooler outlet temperature to assure
current minimum TS limits were met.
This licensee-identified and corrected violation is being treated as a
Non-Cited Violation (NCV). which was consistent with section VII.B.1 of
the NRC Enforcement Policy. This is identified as NCV 50-269.270,
287/97-02-01, Inadequate Procedure For Control of LPI Temperature.
LER 269/96-01 has other planned corrective actions that have yet to be
implemented. Figures in TS 3.1.2 may be changed under the corrective
action scheme.
On a separate but related topic, the site's Design Basis Document (DBD.
00S-0254.00-00-1028, dated 11-27095, section 31.3.17) discusses BWST
electric heater capabilities. The heaters are supposed to maintain BWST
temperatures between 60 to 65 degrees F. The rational behind this
statement was recognizing the need to maintain the borated water supply
above 50 degrees F to lessen the potential for thermal shock of the
reactor vessel during high pressure system operation. TS 3.3.4 basis
stated the same information as the DBD. The DBD section did not discuss
HPI or LPI inadvertent injections or ES flow testing at lower BWST
temperatures. The inspectors will review other documents as it relates
to pressurized thermal shock of the RCS under Inspector Followup Item
(IFI) 50-269,270,287/97-02-09, BWST Temperature Requirements.
Enclosure 2
12
c. Conclusions
The licensee identified a lack of procedural controls to maintain LPI
(decay heat removal) cooler outlet temperature above the minimum
temperature (70 degrees F) shown on the TS heatup and cooldown curves,
section 3.1.2. Procedural guidance permitted operation at temperatures
lower than the operating region as defined by TS curves. A licensee
engineer identified this problem during a Unit 3 outage review. An NCV.
was issued.
08
Miscellaneous Operations Issues (92901, 90712)
08.1 (Closed) LER 50-269/95-05-00: Breach of Technical Specification Due To
Unlocked Control Rod Patch Panel
On July 8, 1995, at 10:15 a.m., operators discovered a Unit 1 CRD System
Patch Panel was unlocked as described in Inspection Report 50-269,270,
287/95-18. This panel was required by TS 3.5.2.7 tobe locked at all
times after confirmation of proper rod operation and sequence. The
licensee entered LCO 3.0 that required plant shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
unless the condition is rectified and the LCO exited. The licensee
determined the panel lock to be broken, and placed a security guard at
the panel at 1:00 P.M. At that time, the LCO was exited. The lock was
repaired at 4:10 p.m. The licensee also verified that all three Units
CRD patch panels were locked. This licensee-identified and corrected
violation is being treated as a Non-cited Violation, consistent with
Section VII.B.1 of the NRC Enforcement Policy. This item is identified
as NCV 50-269/97-02-02. Unlocked CRD System Patch Panel.
08.2 (Closed) LER 50-269/95-05-01: Breach of Technical Specification Due To
Unlocked Control Rod Patch Panel
This LER supplement was sent by the licensee to correct a typographical
error documented in LER 50-269/95-05-00. This item is closed based on
the closure of LER 50-269/95-05-00 documented in section 08.1 of this
inspection report.
08.3 (Closed) VIO 50-270/96-10-01: Failure To Change Flux/Flow Imbalance
Setpoint
As described in Inspection Report 50-269,270.287/96-10 on July 6, 1996.
control rod 3 of group 7 dropped from approximately 95% withdrawn to
approximately 84% withdrawn. During the recovery attempt the rod
dropped to fully inserted. TS required a power reduction to less than
60% and a reset of the high flux and flux/flow imbalance trip setpoints.
The licensee did not reduce the Nuclear Overpower Trip Setpoints for the
flux/flow imbalance after reducing power to less than 60%. As part of
the corrective actions, the abnormal procedures for addressing a dropped
control rod, AP/1,2.3/A/1700/15, Dropped Control Rods, was to be changed
to include independent steps for resetting the high flux and
Enclosure 2
13'
flux/flow/imbalance trip setpoints. A note was to be added to the
procedure to state the necessity to perform steps in a timely manner.
Also, the alarm response guide for the quadrant power tilt statalarm was
to be updated and approved to include a separate step for changing the
high flux and flux/flow/imbalance setpoints. The inspector reviewed all
procedures and verified that the revisions were implemented
appropriately. Therefore, this item is closed.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707)
The inspectors observed all or portions of the following maintenance
activities:
PT/0/A/600/18
Emergency Feedwater Operability Test
PT/0/A/0230/01
Rad Monitor Checklist
MP/0/B/1800/121
Elevated Water Storage Tank (EWST) Civil
Inspection
TT/1/A/0150/046
Enclosure 131, 1LP-18 Functional
Verification
PT/3/A/0202/11
High Pressure Injection Pump Test
PT/0/A/0300/01
Control Rod Drive Trip Time Test
Cut-out of Failed 2A1 Injection Pipe
IP 3/A/0305/014-1
CRD Trip Breakers
WO 97028206/01
IP/0/B/0326/019, Jumper Setup and Program
Installation
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and thorough. All work observed was performed with the
work package present and in active use. Technicians were experienced
and knowledgeable of their assigned tasks. The inspectors frequently
observed supervisors and system engineers monitoring job progress.
Quality control personnel were present when required by procedure. When
applicable, appropriate radiation control measures were in place.
Enclosure 2
14
The EWST civil inspection is covered in M1.4. The HPI test is discussed
in Section M1.2..
c. Conclusion
The inspectors concluded that.the Maintenance activities listed above
were completed thoroughly and professionally.
M1.2 Unit 3 High Pressure InJection Pump Oil Leak (62707)
a. Inspection Scope
The inspector reviewed Problem Investigation Process (PIP) report 3-097
1250, which addressed an oil leak in the lower bearing of 3B HPI pump
motor. The inspector also observed the performance of portions of
procedure PT/3/A/0202/11,. High Pressure Injection Pump Test.
b. Observations and Findings
On April 8, 1997, the 3B HPI pump motor lower bearing oil pot was
experiencing approximately one quart oil loss after operating times that
varied between 31 and 68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br />. The licensee initiated PIP 3-097-1250
to resolve this problem. The 3B HPI pump motor was declared inoperable
due to the inability to maintain the proper oil levels in the lower
bearing oil pot as designed during a postulated accident condition. The
failed 3B HPI pump motor was removed and replaced with a spare HPI pump
motor per Work Order (WO) 97032280.
The inspector observed portions of the post modification performance
test, PT/3/A/0202/11. The test was performed to return the pump to
operable status and to exit the-LCO. While performing the prerequisites
concerning increasing letdown flow to setup the necessary flow rate,
flashing occurred in the Component Cooling (CC) system. This caused
reduced heat transfer across the letdown coolers which resulted in an
increasing letdown temperature. Letdown flow was reduced and the
standby CC pump was started. The reactor operator bypassed and isolated
the inservice purification demineralizer at 130 degrees F. A team was
dispatched to place the standby CC cooler in service and an NLO was sent
to makeup to the CC surge tank. After these actions were taken, the CC
system temperatures began to decrease. Following system stabilization
and return to normal alignment, the 3B HPI pump performance test was
completed.
During this event the 3B letdown cooler CC outlet temperature was
observed to be 355 degrees F, which exceeded the design temperature
limit of 225 degrees F as specified by OFD 144A-3.2. The highest
observed CC outlet temperature for the 3A letdown cooler was 263 degrees
F, which also exceeded the design temperature limit. The licensee's
evaluation as documented in PIP 3-097-1315 determined that the CC system
Enclosure 2
15
was operable. The inspector reviewed the evaluation and did not
identify any problems.
During the licensee's review of this event, it was identified that there
existed insufficient CC flow to the letdown coolers. A review of
OP/1,2,3/A/1104/08, Component Cooling System, revealed a possible
procedural weakness for setting up proper CC flow to the letdown
coolers. The licensee placed the particular enclosure for setting up
this flow on administrative hold pending further review of the process.
c. Conclusion
The inspector concluded that the licensee's actions were appropriate to
identify and repair the HPI pump within the required LCO timeframe. The
licensee's evaluation of the CC system flashing during the post
modification HPI performance test was adequate. Placing the operations
procedurefor the CC system on administrative hold was appropriate while
the licensee continued to review the process of setting up flow to the
letdown coolers.
M1.3 Corrective Maintenance on 1A1 Reactor Coolant Pump (62700)
a. Inspection Scope
This inspection was performed for the purpose of observing the
corrective maintenance activity on the Unit 1, 1A1 Reactor Coolant Pump
(RCP) which exhibited high vibration during plant operation. The plant
was placed in a outage condition to identify and correct the problem.
b. Observations and Findings
Through discussions with the cognizant engineer and by review of reports
and/or related documents the inspectors ascertained the following
information.
Unit 1 entered the outage on March 28, 1997, in order to investigate the
cause for the high vibration in 1A1 RCP and to take appropriate
corrective action. Once the plant reached hot shutdown condition, the
licensee inspected the subject pump and found no signs of reactor
coolant seal leakage. The licensee observed minimal RCP motor external
oil leakage. Audible and physical evidence of vibrations observed
.during plant operation were reviewed. Instrument readings indicated
normal and stable seal flow, as well as pump and motor temperatures. A
no-load test run revealed evidence of damage and/or wear to the RCP
lower motor guide bearings.
A summary of the licensee's inspection and test results were as follows:
No major changes in pump vibration were observed from 100% power
to hot shutdown condition.
Enclosure 2
16
No evidence of misalignment due to motor movement from slippage
and/or binding occurring during shutdown or during the as-found no
load run.
Uncoupled run vibration data revealed that overall shaft vibration
in the area of the motor coupling was approximately 2.75 mils vs.
the 1.4 mils encountered in the May 1994 outage.
As-found alignment with the rotor in the mechanical center was out
approximately 19 mils and 48 mils with the rotor in the electrical
center.
Bearing Inspection and Results
The licensee's visual inspection of the lower bearing revealed no
significant bearing babbitt wear. Some measurable wear was evident on
the bearing support plates:
the worst being approximately 8 mils on the
number 6 bearing support plate. Significant wear was observed on 4 of
the 6 jack screws: the jack screw in number 4 bearing was worn more
severely than the others. A similar inspection showed the upper
bearings were in good condition; support plates and jack screws were
suitable for continued service. The licensee determined that the
probable source of the vibration was motor misalignment and associated
bearing wear. Consequently, it was decided that no further disassembly
or inspections would be necessary.
The subject pump was reassembled and aligned using Revision 1. to the
existing troubleshooting procedure, MP/0/A/1800/22. This revision
provided for motor alignment by centering the motor rotor in the stator
as opposed to aligning the motor shaft to the motor base cutout. On
April 2, 1997, the inspectors ascertained that alignment of 1A1 had been
accomplished to the acceptance criteria of the aforementioned procedure.
A review of related records verified that the alignment was
satisfactory.
RCP 1A2 Vibration Profile
The licensee's records revealed that RCP 1A2 experienced increased pump
shaft vibration during power reductions. For example, while reducing
power for the present outage, shaft vibration increased from 11 to 12
mils when the reactor was at about 15% power, then increased to between
20 - 22 mils when RCP 1B2 was shut down. Also, high vibration was noted
while decreasing power with both 1A2 and 1B1 pumps in operation. The
RCP 1A2 shaft vibration gradually increased to about 30 mils. Because
of vibration similarities during operational transients in RCPs 1A1 and
1A2, the licensee decided to perform a similar inspection and
maintenance on RCP 1A2. Results of this inspection showed the lower
motor bearing components exhibited no abnormal wear patterns with the
exception of two bearing shoes which had significant wear in the support
groove area. No significant wear or damage was observed on the upper
Enclosure 2
17
bearing components. At the close of this one week inspectton,
maintenance activities were still in progress on both RCPs.
Inspection Assessment
Based on a review of inspection results, analyses and assessments, the
inspectors ascertained the following information.
Both 1A1 and 1A2 RCPs demonstrated extreme vibration responses to
changing plant conditions. For example, major transients or step
changes occurred on the 1A1 and 1A2 RCPs when either of the two were
started or stopped. The 1A1 RCP transient occurred when the 1B1 RCP was
started to commence two pump operation. The 1A2 transient occurred when
the 1A1 RCP was stopped. Also, it appears that the magnetic and
mechanical misalignment and the lower motor bearing jack screw wear
observed in the 1A1 pump, were contributing factors to the high
vibration phenomenon. The inspectors reviewed the following
information/documents for technical content and adequacy:
MP/0/A/1800/22, Troubleshooting and/or Corrective Maintenance
MP/0/A/3009/009, Motor Reactor Coolant Pump Major Preventive
Maintenance
AP/1/A/1700/16. Abnormal Reactor Coolant Pump Operation, Revision
8, and the 10 CFR 50.59 Evaluation Screening for AP/1/A/1700/16
PIP 1-097-1043, Pre-outage Shutdown Risk Assessment For 1A1 RCP
c. Conclusion
The licensee's response to this abnormal condition was satisfactory.
In-house and contractor personnel appeared to be very knowledgeable and
attacked the problem in a well planned manner with satisfactory results.
Craft and field supervisors worked in a conscientious manner to identify
and correct the problem. Procedures and field records appeared to be
complete and accurate.
M1.4 Elevated Water Storage Tank (EWST) Civil Inspection
a. Inspection Scope (61726)
The inspector reviewed procedures and observed activities for draining
the EWST. This activity was necessary to perform an internal civil
inspection of the tank. The inspectors interviewed CR personnel,
operations staff, and system engineers.
Enclosure 2
18
b. Observations and Findings
As part of the high pressure service water system, the EWST provides
sealing water for the low pressure service water/condenser circulating
water system siphon (upon a loss of power) when lake levels are low.
On April 8, 1997, work was scheduled to drain the EWST for the civil
inspection of the tank via MP/O/B/1800/121, Elevated Water Storage Tank
Civil Inspection. Unit 2 Operations personnel were in charge of the
procedure and the evolution. During the night shift from April 8 - 9,
1997, Operations completed steps 11.3 through 11.5.4 of MP/O/B/1800/121.
On April 9, 1997, during a review of the procedure in the Unit 2 CR, the
inspector identified that section 6.0, Prerequisites, had not been
completed. Included in these prerequisites was the requirement to
maintain lake levels to prevent an impact on low pressure service
water/condenser circulating water siphon flow on a loss of power.
Nuclear Policy Manual NSD 703 Administrative Instructions for Station
Procedures. Conduct of Mechanical Maintenance Procedures Section C.16
states: "Each procedure shall list those items which are to be completed
and those conditions which are to exist prior to performing the
specified maintenance. Appropriate provisions shall be made to document
compliance with the prerequisites listed."
Operations placed the evolution on hold, conducted a meeting with
involved personnel, and initiated PIP 0-97-1215 to document the error.
This NRC identified violation is being identified as Violation (VIO)
50-269.270.287/97-02-03, Failure to Perform Procedure Prerequisites.
c. Conclusions
The inspector concluded that the failure of operations to complete the
EWST Civil Inspection procedure prerequisites prior to performing other
sections in the main body of the procedure is a violation of procedure
adherence.
M8
Miscellaneous Maintenance Issues (92902, 90712)
M8.1
(Closed) LER 50-270/96-005-00: Main Steam Relief Valves Technically
Inoperable Due To Improper Assembly Of Component
This issue was addressed in Inspection Report 50-269.270,287/96-20 as
VIO EA 96-478-01014, Failure To Follow Procedure and Properly Install
MSSV Spindle Nut Cotter Pins. Accordingly, this LER is considered
closed as this issue will be evaluated during the followup on VIO EA 96
478-01014.
Enclosure 2
19
M8.2 (Closed) Unresolved Item (URI) 50-270/96-13-06:
Lug Connections for
High Voltage Terminations
Problem Investigation Process report 2-96-1777 documented a 2B HPI pump
motor failure which occurred on September 18, 1996. The motor failure
was indicated to be due to a random failure of the winding insulation.
The subject motor was the first HPI motor to be replaced by the licensee
under a new HPI motor overhaul program in April 1996. LER 270/96-03
addressed the operational impact of the motor winding failure.
Additionally, the PIP discussed two loose motor lead lugs that did not
cause or contribute to the winding failure, but were indicated to be
improperly installed. Review indicated the reasons for the improper
lugs was mixed, but basically, the vendor had provided the wrong size
lugs (loose/unattached) with the refurbished motor. The lugs were
provided separately such that the motor phase leads could pass through
the terminal box porting and then be lugged.
The licensee installed the lugs with appropriate crimping tools for that
size lug. The lugs were tight on the subject phase leads to
appropriately pass current and did megger correctly after the motor
installation. However, at some period after installation of these
stranded wire leads, pull-out force required to separate the conductor
from the lug was/became minimal. It was observed that the electrical
phase that failed had the tightest "as-found" crimp connection. The
programmatic weakness to this "skill of the job task" was that there was
no guidance for determining proper lug size, even though the lugs
utilized were vendor provided.
The PIP intermediate response contained corrective action that scheduled
and directed issuance of procedures and training to cover the
programmatic lead termination issue. The change that provided guidance
for 600 Volt and less motor lugs, MP/0/A/3009/020B, was issued February
24, 1997. It now gives specific guidance for the lugging of the HPI
motors. This less than 600 Volt procedure had no associated remedial
training, had adequate instructions, and did provide sizing criteria for
lugging. A procedure for greater than 600 Volt motors termination.
IP/0/A/3009/018, was issued on April 28, 1997. A training task was
issued on April 29, 1997, to require training of personnel prior to new
procedure use or require previously qualified personnel task performance
under supervision during procedure utilization: thus completing the
actions of the PIP. No HPI or other safety-related motors had been re
lugged prior to issuance of the above instructions.
The absence of programmatic aspects for electric motor terminations was
a violation of Appendix B, Criterion V. Based on the facts that the
event was licensee-identified, the lug problem could not have been
prevented by corrective actions of a previous violation, the problem was
corrected in a reasonable time period, it was not a willful violation,
and the licensee prevented recurrence prior to corrective action
implementation, the requirements of Section VII.B.1 of the Enforcement
Enclosure 2
20
Policy were satisfied to consider this issue NCV 50-269,270,287/97-02
04, Failure To Have A Sizing Criteria For Electrical Lugs.*
M8.3 (Closed) IFI 50-270/96-13-05: HPI Motor Failure
The PIP identified above addressed the root cause of the HPI motor
failure as being a ground in the slot-to-slot section of the first coil
in an electrical phase of the 2B HPI pump motor. The conclusion was
supported by the motor vendor repair/refurbishment report (P.O. ON
11670, dated 4-16-97). This item is considered closed.
M8.4 (Closed) LER 50-270/96-03: Technical Specification Required Shutdown
Due to Inadequate Work Planning
The closure of IFI 50-270/96-13-05 also closed the above LER. The
licensee had completed the corrective actions stated in the LER.
M8.5 (Closed) Licensee Event Report (LER) 270/95-01: Technical Specification
(TS) Exceeded Due to Equipment Failure
This LER concerned the failure of valve 2LP-19 (Low Pressure Injection
Emergency Sump Suction) to open while performing quarterly valve stroke
testing, and its spurious opening during subsequent troubleshooting.
The problem was attributed to the periodic sticking of the B finger on
the CLOSED contactor, which when stuck open would not allow the OPEN
circuit to energize. As this type of erratic failure would most likely
occur only after the valve.was placed in the closed position, the
licensee considered 2LP-19 inoperable since its previous quarterly
stroke test.
After affected components in the motor control center (MCC) and the
control switch were replaced, 2LP-19 was successfully stroke tested and
the associated TS LCO was exited. Because the affected components were
replaced with those removed from a spare MCC compartment in the field as
opposed to a clean warehouse, the stroke test frequency for valve 2LP-19
was increased to monthly (for the next three months) and an infrared
scan was required to be conducted. Through a review of completed work
requests, the inspector verified that these additional activities were
performed satisfactorily. Associated with General Electric breaker
model No. TED 134015, the failure mode of 2LP-19 was such that the valve
could have been opened at the breaker by manually closing in the
contacts to start the motor. The redundant train valve (2LP-20) was not
affected by the failure of 2LP-19 and was available for control switch
actuation. Accordingly, having confirmed that the licensee had approved
and scheduled a Nuclear Station Modification (NSM ON-3027) for the
replacement of obsolete safety-related MCC starter compartments with new
components over the next five years, the inspector had no further
questions. This LER is considered closed.
Enclosure 2
21
M8.6 (Closed) LER 269/95-03: Low Pressure Injection (LPI) System Technically
Inoperable Due To A Design Analysis
This LER concerned two issues. The first issue, which was previously
addressed in Inspection Reports 94-38 and 95-01, involved a postulated
loss of coolant accident in which a single failure disables one of the
two reactor building emergency sump lines. Under these circumstances,
Abnormal Procedure AP/1/A/1700/07, Loss of Low Pressure Injection
System, directed the operators to secure both reactor building spray
pumps. The licensee determined that this condition was beyond the
design basis assumptions contained in the maximum hypothetical accident
safety evaluation report and 'made a procedure change to require that one
.train of reactor building spray be maintained operable. Subsequently,
the licensee performed an analysis and determined that 10 CFR Part 100
dose limits would not have been exceeded. Consequently, the associated
10 CFR 50.72 notification to NRC was determined not to be required, and
was subsequently retracted. The inspector verified that APs/1.2,3/
A/1700/07 still require one train of reactor building spray be
maintained during a postulated single failure of a reactor building
emergency sump line.
As previously addressed in Inspection Report 95-01, the second issue
reported in this LER concerned a condition outside of design basis due
to a procedural requirement to split LPI header flows in the event of a
postulated single failure of a LPI pump during emergency core cooling
system operation. Specifically, if LPI flow instrument inaccuracies and
fouling of reactor building and LPI coolers were considered coincident
with a postulated single failure of a LPI pump during emergency core
cooling system operation, then the reactor building pressure/temperature
profile required in the Equipment Qualifications (EQ) analysis could
have been exceeded. In order to resolve this issue, the licensee
revised APs/1.2.3/A/1700/07 on December 27, 1994. to require that LPI
flow not be split between headers during a loss of coolant accident.
Since that time, LPI cooler fouling has been resolved and LPI pump
capacity and maximum instrument inaccuracies have been found acceptable
to allow flow split of one LPI pump (if
no others are available) to both
LPI headers. Accordingly, the inspector verified that the APs have
since been changed to reflect this desirable alignment.
III. Engineering
El
Conduct of Engineering
E1.1 Unit 3 Integrated Control System (ICS) Testing
a. Inspection Scope (61726, 62707)
The inspectors continued to observe the complex post modification
testing of the new Unit 3 ICS.
Enclosure 2
22
b. Observations and Findings
During this inspection period the licensee completed TT/3/B/0326/ 001,
ICS/NNI Transient Testing At Power:
ICS/NNI System Upgrade, NSM ON
32989/ALl. The sections which remained to be tested were a Feedwater
(FDW) Pump Trip Transient From 70% Reactor Power and a section involving
tripping a RCP From 50% Reactor Power.
Prior to each test section the licensee conducted pre-test briefings for
all personnel involved in the testing. The inspector considered the
pre-briefs to be thorough and with the appropriate focus on nuclear
safety.
After completion of each test, a post-test brief was conducted by the
test coordinator with all personnel involved in the test. The briefs
focused on data acquisition results, test acceptance criteria, and
lessons learned. The inspectors considered the test post-briefs to be
thorough, and noted that there were no issues that required resolution
prior to continuation of testing.
The inspectors monitored testing activities from the Unit 3 CR. The
test coordinator and management designee was located in the Unit 3 CR
for all testing. Command and control in the CR during all testing was
good. The test coordinator maintained good control of all test
evolutions. The inspector concluded that testing activities conducted
in the Unit 3 CR were good and operators maintained appropriate focus on
nuclear safety at all times.
Test Results
On March. 23, 1997, the inspectors observed the performance of procedure
TT/3/B/0326/001 in the CR. Unit 3 was at approximately 70% power for
the FDW Pump Trip Transient and was at 50% reactor power for the RCP
Trip. All acceptance criteria were met for both test sections. No
discrepancies were identified.
c. Conclusions
The inspectors concluded that the two remaining sections of
TT/3/B/0326/001 were satisfactorily accomplished in accordance with the
licensee's test procedures. Control of all test activities was good.
Positive observations were made relating to test briefings, CR
briefings, and communication and coordination of test evolutions.
E1.2 Low Pressure Service Water (LPSW) Outside Design Basis
(92901)
During this inspection period, the licensee made a 10 CFR 50.72
notification when the licensee determined that some portions of the Unit
1 and Unit 2 LPSW system did not meet UFSAR Section 3.1.40 design
requirements for high trajectory turbine generated missiles.
Enclosure 2
23
Specifically, there are two portions of the LPSW system piping which are
not sufficiently separated to protect against loss of redundant LPSW
system trains if a high trajectory turbine missile were to occur. The
LPSW system serves as a safety-related heat sink during certain design
basis accidents and is considered an engineered safeguards system. The
licensee has identified this issue as an unreviewed safety question and
submitted a license amendment to the NRC on April 29, 1997, to clarify
the turbine missile design criteria in Oconee's UFSAR.
E1.3 Spent Fuel Cask Dry Run Operation
a. Inspection Scope (60854)
The inspectors observed portions of the spent fuel cask dry run (from
the spent fuel building to the storage facility) to verify that the
activities were performed in accordance with the applicable procedure.
b. Observations and Findings
The procedure used in the dry run for the transporting of the spent fuel
cask to a Phase III Horizontal Storage Module (HSM) of the Independent
Spent Fuel Storage Installation (ISFSI) was Procedure TT/O/A/1500/001.
ISFSI Phase III DSC Test Loading Storage. Rev. 0.
The licensee had already lifted the cask onto the transporter before the
inspectors arrived and was waiting for good weather to complete the
transport. The inspectors observed the licensee perform the preparation
and radiation level survey, transporting of the cask from the Fuel
Receiving Area (FRA) to the storage facility, and insertion to and
withdrawal from the HSM set in the storage facility.
The licensee followed the written procedure and the transporting,
insertion, and retrieval (or withdrawal) of the Dry Storage Canister
(DSC) proceeded without incident. However, the inspectors made the
following comments to the licensee after the DSC dry run activities:
-
The transporter speed from the FRA to the storage facility seemed
to be about 5 miles per hour (MPH). The procedure allows a
maximum of 3 MPH.
-
The four bolts remaining in the cask head after the rest of the
bolts were removed were not 90 degrees apart as required by the
procedure. They were about 70 and 110 degrees apart.
During the subsequent damage inspection, the metal debris peeled
off from the DSC was found in both of the shipping rails inside of
the cask and HSM.
With respect to the first two comments, the licensee indicated that they
would take measures to assure better control during the loading
Enclosure 2
24
operation currently scheduled for May 1997. Regarding the third
comment, the licensee plans to evaluate and take appropriate actions to
prevent DSC damage before the loading operation.
c. Conclusions
The inspectors concluded that the licensee performed adequate operations
for the transporting, inserting, and retrieving of the DSC -from the FRA
to the HSM.
E1.4 Phase III of Independent Spent Fuel Storage Installation
a. Inspection Scope (60851. 60853)
The Inspectors reviewed Phase III of the ISFSI in order to verify that
the facility was installed in accordance with the applicable procedures
and drawings.
b. Observations and Findings
The Oconee Phase I and II of the ISFSI with 40 HSMs were installed under
the specific License No. SNM-2503 and Docket Number 72-4 based on 10 CFR
72 for the storage of nuclear spent fuel material on site. The addition
(Phase III) of 20 new HSMs will be completed under a general license to
store the spent fuel on site by using the existing reactor license and
docket numbers under 10. CFR 50 for all its activities per Sections 72.6.
72.210. and 72.212 of 10 CFR 72. The licensee filed a notice of
intention with the NRC on November 7, 1996, to install Phase III of the
ISFSI by using a NUHOMS storage system manufactured by Vectra
Technologies, Inc. The inspectors reviewed the notice and determined
that it met the requirements for the general license.
The inspectors reviewed the test records and the batch data for the
concrete poured into the base slab for the slump test, air content,
temperature on air and concrete, unit weight, and compressive strength.
All the results of the tests were within the limits set in the procedure
and specification.
The licensee assembled eight HSMs on site. The inspectors, using the
manufacturing drawings, inspected HSM E21 which will be used to store a
DSC during May-June 1997 time frame. The inspectors found several welds
undersized by about 1/16" for the connections between the right beam (or
rail) web and the stiffener plates at both webs. The measured fillet
weld sizes were 1/8".
Drawing 9-354-6105, Oconee Phase III NUHOMS ISFSI
Horizontal Storage Module DSC Support Structure, Rev. 0, requires the
fillet weld be 3/16".
The High Tech Company that manufactured the steel portion of the HSM for
Vectra performed a detailed inspection the following week on all eight
HSMs installed and found more undersized welds. Vectra and High Tech
Enclosure 2
25
are currently performing analysis and evaluation of the undersized welds
and will do repairs, if required. The identified discrepancies on
installed module HSM E21 (the undersized welds) when compared with the
requirements in the drawing 9-354-6105 collectively constitute a
violation of 10 CFR 50 Appendix B, Criterion V, and, the licensee's
accepted Quality Assurance (QA) Program, Updated Final Safety Analysis
Report, Chapter 17, Quality Assurance and Topical Report DUKE 1-A,
Instructions, Procedures, and Drawings which state, in part that
activities affecting quality shall be accomplished in accordance with
documented drawings. This was identified to the licensee as Example 1
of Violation 50-269,270,287/97-02-05, Weld Undersized Or Not Inspecting
By QA.
The NRC headquarters performed several inspections of the Standardized
NUHOMS and found many deficiencies regarding the QA program. The NRC
issued a Demand for Information (DFI) on January 13. 1997, to Vectra and
requested that Vectra provide information and resolutions to the
deficiencies found in the QA program implementation for the design,
changes, and fabrication of the NUHOMS system. Duke has eight HSMs and
one DSC on site which were manufactured before the DFI was issued. Duke
is required to perform an independent review on the deficiencies based
on its own QA program if Vectra can not resolve the issue with the NRC
before Oconee loads its cask in May or June 1997. Duke plans to perform
the following activities to resolve the deficiencies found by the NRC
before its cask loading:
-
Verify fabrication drawings, specifications, and purchase orders
against the licensee requirements.
-
Verify that Noncomformance Reports, Engineering Change Notices,
and Correct Action Reports written by the manufacturers are
adequately dispositioned for the Oconee equipment.
The inspectors plan to inspect these issues before the cask is loaded to
- see if Duke adequately addressed and resolved the issues.
c. Conclusions
The inspectors considered that the licensee performed an adequate
installation of concrete base mat and HSMs for Phase III of the ISFSI.
A violation was issued for undersized welds.
E1.5 Seismic Qualification for Upper Surge Tank Support
a. Inspection Scope (37700)
The inspectors reviewed the calculation and modification package used to
qualify and modify the Upper Surge Tank Support (USTS) for the
earthquake condition in order to verify that the supports were qualified
and installed in accordance with the applicable procedures and drawings.
Enclosure 2
26
b. Observations and Findings
The licensee's Seismic Qualification Utility Group (SQUG) engineers
reviewed the USTSs and identified: a lower and out-of-date seismic
acceleration coefficient value used by Earthquake Qualification
Engineering (EQE) International: and cover plates for columns (or legs)
of the supports were not installed in the field as required by the
drawings. Problem Investigation Process report (PIP) 0-095-1307 was
issued to resolve the problem. Based on the correct seismic
acceleration coefficient value and the existing support configurations
in the field, the licensee concluded that the applied stresses of the
support members would exceed the allowable stresses: thereby, requiring
the tank supports be modified. After the identification of the
calculational mistakes made by EQE, the licensee engineers very
carefully reviewed the assumptions and methodologies in the
calculations performed by EQE and did not find other major problems.
The inspectors reviewed other PIPs related to SQUG and did not identify
any major problems.
The inspectors inspected the modification by using the as-built
drawings. The inspectors identified several welds that did not meet the
5/16" minimum weld sizes required by the drawings. After searching for
the inspection records, the licensee stated that these welds were not
inspected by QA inspectors because the Step 4.12.4 of Procedure
TN/3/A/8979/MM/01C. Minor Modification OE-8979. for verifying the weld
sizes was marked "N/A" by the acting craft supervisor due to a
communication misunderstanding with the design engineer.
In addition, the design engineer and the QA personnel in the final
review for the closure of the package also failed to notice the problems
of not verifying the weld sizes. The licensee issued PIP 3-097-1005 for
the root cause investigation and resolution. The problem for not
verifying the 5/16" minimum weld sizes for the connections between the
tank support columns and base plates required by the Step 4.12.4 and the
attached drawing sheet 11 of 18 of Procedure TN/3/A/8979/MM/01C, Minor
Modification OE-8979, was identified to the licensee as Example 2 of
Violation 50-269,270,287/97-02-05, Welds Undersized or Not Inspecting by
QA: The Example 2 applies to Unit 3 only.
c. Conclusions
The inspectors concluded that the licensee performed an adequate review
of the EQE Calculation Evaluation for the Upper Surge Tank Supports.
The modification on the supports was acceptable except as for a failure
of QA to inspect and verify existing fillet weld sizes. A violation was
issued.
Enclosure 2
27
E1.6 Engineering Action on Unit 2 2A1 InJection Line Crack (93702, 40500)
a. Inspection Scope
As a result of the cracked injection line, on April 23. the licensee
formed a Failure Investigation Process (FIP) team to evaluate and
resolve the event described in Section 01.5 of this report.
The
resident inspectors, who were joined by a Region II DRS NRC inspector,
followed and evaluated the problem and the licensee's actions that ran
beyond this inspection period.
b. Observations and Findings
Based on the discovery of the crack, the licensee initiated PIP 2-97
1324 and formed the FIP team in accordance with Nuclear Site Directive
212, Cause Analysis. The team took a very broad based look at the
failure of the weld in the injection line. The licensee brought in
several vendors to support their investigation of the problem. The
vendors had backgrounds in metallurgy, thermal fatigue, pipe vibration,
and root cause investigation analysis. The following were areas that
the team was to evaluate:
Vibration - equipment induced, flow induced
original design - workmanship, weld material, weld configuration,
weld process, and pipe alignment
existing analysis - as built configuration, analysis review,
analysis error
miscellaneous loads - stratification, thermal interferences,
transients, modification loads, overpressure
material degradation - embrittlement, stress corrosion cracking,
chemical attack, erosion
- .
history - thermal sleeve work, temporary work load (rigging).
shock, operational history
snubber failure
The team formation was appropriate for the complexity of the problem.
The licensee provided information in an open manner to the NRC. The
licensee, with various team members, held nearly daily phone
conversations with the NRC at the regional and headquarters offices.
The B&W owners group participated with the evaluation process.
The licensee provided a Justification for Continued Operation (JCO) on
April 28, 1997, for Units 1 and 3. which were still operating at the
Enclosure 2
28
time of the Unit 2 forced shutdown. Based on the results of the team's
investigation, Unit 3 was shutdown on May 1. 1997. due to concerns about
the 3A1 injection line thermal sleeve condition. A second JCO was
issued on May 2 for Unit 1.
Inspection Report 97-07 will address the findings of the FIP team and
subsequent corrective actions.
c. Conclusions
The licensee was proactive in rapidly forming a FIP team shortly after
the Unit 2 injection line crack condition was known. The licensee
called in available industry talent to support and supplement the team.
The licensee was communicative with the NRC and provided information as
required and requested by the NRC.
E2
EngineeringSupport of Facilities and Equipment
E2.1 Engineering Support of Facilities and Eauipment - Procurement
Engineering (37550)
a. Inspection Scope
The inspector reviewed Procurement Engineering activity related to the
purchase and receipt of safety-related replacement parts and services.
The areas reviewed included commercial grade dedication (CGD).
acceptable substitutes, verification of receipt inspection acceptance
criteria, resolution of receipt inspection deficiencies, material QA
quality level changes, and salvage/repair of equipment. The inspection
included a sample review of licensee performance in these areas to
determine if activities were consistent with applicable regulatory
requirements and licensee procedures. Applicable regulatory
requirements included 10 CFR 50 Appendix B, UFSAR, and the following:
ANSI N45.2.13-1976, QA Requirements for Control of Items and
Services for Nuclear Power Plants
RG 1.123, QA Requirements for Control of Procurement of Items and
Services for Nuclear Power Plant
Generic Letter (GL) 91-05. Licensee Commercial Grade Procurement
and Dedications Programs
b. Observations and Findings
Technical evaluations for CGD and acceptable substitutes appropriately
identified and addressed replacement parts' critical characteristics.
Acceptance criteria for critical characteristics were adequately
addressed and verified at receipt inspection. Receipt inspectors
demonstrated a strict adherence to the established acceptance criteria
Enclosure 2
29
and deficiencies were appropriately documented and resolved. Required
post installation testing identified in acceptance criteri-a was
appropriately designated on the item and tracked. Replacement parts' QA
classification changes were adequately justified. Procurement
Engineering evaluations were technically sound and well documented.
An example was identified in which equipment or services from an
approved Appendix B vendor was not consistent with procurement
documentation requirements. This involved an 8-inch safety-related
valve (LP-40) which was procured and installed in the Unit 3 Low
Pressure Injection (LPI) system. The valve did not meet the Purchase
Order (PO) requirements related to Duke valve specification CNS 1205.28
00-0001, ASME Section III Carbon and Stainless Steel Ball Valves, dated
March 3. 1982. Two valves were procured on PO 8575, dated March 26.
1996. to be installed on minor modifications ON0E 8859 and 8860 which
were to provide double valve isolation between the LPI system and the
Borated Water Storage Tank (BWST). Section 8.6.2.2 of the valve
specification stated that all valves were to close in the clock-wise
direction. The valves were received, inspected, and accepted in
November 1996. The vendor had inadvertently deviated from the PO
referenced design specification of one valve by reversing its operation
(i.e., counter-clockwise to close). The vendor, Anchor Darling Company,
had been audited and approved by the Duke Procurement Engineering
organization and was an approved 10 CFR 50, Appendix B, vendor. The
vendor documentation received with the valves certified that all PO
requirements and specifications were met. The licensee's and the
vendor's quality control programs failed to identify the procured valve
did not meet the PO requirements. This item is identified as Violation
50-287/97-02-06, Inadequate Control of Purchased Material, Equipment,
and Services. This procurement deficiency was self-identifying in that
the associated valve design error contributed to a Unit 3, loss of
Reactor Coolant System (RCS) inventory event on February 1, 1997 (NRC
Report Nos. 50-269,270,287/96-20). Performance weaknesses by
Engineering, Maintenance, and Operations which contributed to this event
are discussed in paragraph E8.3 of this report.
c. Conclusions
Procurement Engineering performance in establishing and verifying
quality requirements for upgraded replacement parts, acceptable
substitutes, and resolution of deficiencies was good. An example was
identified in which an approved 10 CFR 50, Appendix B, vendor provided
defective materials or services which demonstrated a deficiency in the
licensee's vendor qualification or oversight process. A violation was
identified on this issue.
Enclosure 2
30
E2.2 Non-conservative Setup of Controls for Low Temperature Overpressure
Protection (LTOP)
The licensee identified methods used to set the travel stops for HP-120
(make-up control valve) were potentially non-conservative during Low
Temperature Overpressure Protection (LTOP) operation. The inspectors
reviewed the operability issues concerning operation during LTOP.
On February 25, 1997, the licensee identified the procedure used to set
the HP-120 controls to limit Reactor Coolant System (RCS) make-up flow
were non-conservative. HP-120 is the normal make-up to the RCS control
valve. The controls were set for a maximum of 70 - 80 gpm with one HPI
pump in operation using OP/1.2,3/A/1104/49, Low Temperature Overpressure
Protection (LTOP). The licensee identified that more than one HPI pump
could be operating after the travel stop on HP-120 was set. The standby
pump could start on low seal injection flow. 'This would allow more than
the maximum flow through HP-120. The maximum flow through HP-120 is
based on allowing an operator ten minutes to correct HP-120 failing
open.
The licensee is evaluating the LTOP concerns through PIP 0-097-0710 and
PIP 5-097-1204. A 10 CFR 50.72 notification was made on April 17, 1997.
The inspectors also interviewed operations personnel on the duties of
the dedicated LTOP operator, a compensatory action.
At the close of the inspection period, NRC review of the issue was not
complete. This issue will be followed as URI 50-269,270.287/97-02-07,
Non-conservative Setting of LTOP Controls.
E7
Quality Assurance in Engineering Activities
E7.1 Quality Assurance in Engineering Activities - Procurement Engineering
a. Inspection Scope (37551)
The inspector reviewed the licensee's self-assessment activities
associated with procurement engineering processes. Applicable
regulatory guidance was.provided by 10 CFR 50. Appendix B. These
included two station self-assessments and one corporate consolidated
performance audit in 1995 which included Procurement Engineering
activities.
b. Observations. Findings, and Conclusion
The scope of the self-assessments was adequate to evaluate performance
of the procurement activity under review. Findings were appropriately
documented and tracked for resolution.
Enclosure 2
31
E8
Miscellaneous Engineering Issues (92903)
E8.1 (Closed) VIO 269,270,287/96-09-01:
Inoperable Hydrogen Recombiner
Condensate Pumps
This violation involved the Containment Hydrogen Recombiner System
(CHRS) not being able to satisfy TS 3.16.3 for an indeterminate
timeframe. The licensee investigation indicated that the drain pumps on
all three units failed to operate due to corrosion between the pump
casing and the impeller. Completed corrective actions included
increasing the test frequency on the pumps and machining and coating the
inside of the pump casing with epoxy. The pumps were part of a
temporary modification, a permanent modification will be implemented to
remove the accumulation of moisture in the section and discharge piping
such that the temporary modification including the pumps will no longer
be needed. The permanent modification is complete on Unit 2 and Unit 3.
The other permanent modifications are scheduled to be complete by the
end of the Unit 1 upcoming Refueling Outage (RFO). Based on the
licensee's completed/planned corrective actions, this item is closed.
E8.2 (Closed) URI 50-269.270,287/96-03-03:
Adequacy of Information Provided
for Spent Fuel Pool (SFP) Design
The Oconee SFP inspection (NRC Inspection Report 96-03. paragraph 4.4.2)
identified a design concern related to the interface between the Spent
Fuel Pools (SFP) and the Standby Shutdown System (SSS). The SSS
modification to the SFP installed in 1980 deviated from the design
described in the Standard Review Plan (SRP). Section 9.1.3 of the SRP
stated that the SFP should be designed such that the failure of inlets,
outlets, piping or drains will not result in inadvertent drainage below
a point approximately ten feet above the top of the active fuel in the
SFP. The Oconee design, which provides a three-inch diameter
seismically qualified piping connection for the SSS, would permit
draining the SFP to six feet below the top of the active fuel assembly.
Barriers to prevent this drain down included administrative controls to
monitor level during a SSS event, a low level alarm annunciated at two
foot below the normal 23.5 foot level, and the seismic qualification of
the connecting three inch diameter piping.
This issue is being addressed by NRC Task Action Plan No. M88094,
"Resolution of SFP Action Plan Issues", and will be resolved in
conjunction with this plan.
E8.3 (Closed) URI 50-269,270,287/96-20-03:
Loss of RCS Inventory
This item was related to the inadvertent Unit 3 RCS inventory reduction
event which occurred on February 1, 1997. The unit was in mode 5 with
decay heat removal provided by the LPI system. The cause of the event
was a configuration control error that occurred during a static pressure
test alignment. The test was performed to verify the acceptability of
Enclosure 2
32
welds on LP-40 and LP-42, which were installed by minor modifications.
The issue was unresolved pending further review of event precursors and
root causes.
The root cause was determined to be an inadvertent vendor deviation from
the PO requirements of LP-40. This is discussed in paragraph E2.1 of
this report as a procurement process deficiency and a violation of
regulatory requirements was identified (VIO 50-287/97-02-06).
The precursors to the event demonstrated performance weaknesses by
Engineering. Maintenance, and Operations which degraded barriers and
contributed to the installation of defective equipment in a safety
related system. Engineering post modification functional testing did
not identify the valve design defect. Additionally, Engineering did not
identify the potential shutdown risk associated with the test and did
not establish adequate precautions or configuration verification
parameters. Maintenance demonstrated a-weakness regarding a questioning
attitude for abnormal equipment conditions. A maintenance technician
had previously noted the valve was a reverse acting valve but did not
question this abnormal condition or communicate it to management or
Engineering. Operations demonstrated a weakness in configuration
control verification in that no secondary means were used to verify the
valve position. Due to routine faulty position indication, operators
did not check the position indication on the valve itself. In this
case, a clockwise turn of the valve verified the valve was full open
rather than full closed. Additionally, Operations reviewed and approved
the static test configuration and did not identify or establish
precautions for the shutdown risk associated with system misalignment.
The above weaknesses were also discussed in the licensee's Event
Investigation Team report of the loss of RCS inventory event.
Positive performance related to this event included the operators'
prompt actions to terminate the RCS inventory loss upon discovery, five
minutes after the test was initiated. Additionally, an event
investigation team was established promptly and provided a comprehensive
review of the event cause and precursors.
E8.4 (Closed) URI 50-269,270.287/96-17-03: Reactor Building Cooling Unit
(RBCU) Operability Concerns Due to Wrong Fuse in Control Circuit
This item addressed the licensee's actions to resolve a fuse deficiency
in the RBCU control circuit which was identified on February 27, 1995.
by the licensee's equipment failure trending process and documented on
PIP 0-95-0267. During an NRC inspection of open PIPs in November 1996,
it was noted that the issue was not resolved and that RBCU operability
had not been addressed. The item was unresolved pending further NRC
review of licensee corrective actions and the impact of deficient fuses
on RBCU operability.
Enclosure 2
33
The RBCU failure trend was identified for the Unit 3 RBCUs'which failed
four times between 1990 and 1995 from blown fuses after the. RBCU was
energized following maintenance. The licensee's cause determination
concluded that the wrong fuse type was installed (i.e.. instantaneous
rather than time delay fuses). The Unit 3 KTK-8 instantaneous fuses
were changed in June 1996, to KTK-15 instantaneous fuses. The PIP
corrective actions replaced the fuses on all RBCU control circuits in
Units 1, 2, and 3 with time delay CCMR-6 fuses. The CCMR-6 fuses were
installed in Units 1 and 2 in 1996. replacing the original KTK-8 fuses.
The PIP was closed on December 2, 1996. On December 23. 1996, CCMR-6
fuses were installed on Unit 3 RBCUs and two of the three RBCUs failed
during post maintenance testing. This demonstrated that the corrective
actions for the PIP were inadequate.
The original cause evaluation failed to identify the design control
deficiency that the fuses were not suitable for application in the RBCU
fan motor circuit. The fuses were rated below circuit conditions.
Following the December 1996 Unit 3 RBCU failures the licensee evaluated
the control circuit conditions and determined that the fuses were under
rated for circuit conditions. On January 16. 1997, the licensee
received information from the RBCU control transformer vendor that the
transformer in-rush current could reach 171 amps. Unit 1 and 2 possible
in-rush current was approximately 168 amps. The original KTK-8 fuses
and the replacement CCMR-6 fuses were rated at 80 and 90 amps,
respectively for in-rush current. The KTK-15 fuses which had been
temporarily installed in Unit 3 were rated at 200 amps and were adequate
for this application. This demonstrated that the licensee's cause
determination, which did not evaluate circuit conditions, was
inadequate.
The licensee categorized PIP 0-95-0267 as a less significant event issue
and no operability evaluation was documented. The under rated fuses
impacted the operability of all RBCUs in which they were installed. The
in-rush current varied due to the cycle discrepancy between the power
supply and the primary control circuit transformer when the RBCU was
energized, therefore it was not predictable which start up would exceed
the KTK-8 or CCMR-6 current capacity. During a Loss of Coolant Accident
(LOCA) the RBCU fans change from fast to slow speed and the fuse
limiting condition would not occur. The RBCUs would only need to be re
energized following a Loss Of Offsite Power Event (LOOP). Therefore,
following a LOOP the operability of the RBCUs could not be assured.
Technical Specification 3.3.5 requires three trains of RBCUs to be
operable when the reactor is critical, and two trains when the RCS
conditions are above 250 degrees F and 350 psig. The performance
history of Unit 1 and 2 RBCUs included no blown fuse failures as in the
Unit 3 RBCUs. However, the design conditions of the under rated fuses
indicated that all RBCUs were inoperable. This was demonstrated for
Unit 3 based on design and performance history. This demonstrated that
the licensee's corrective actions were inadequate in that they did not
Enclosure 2
34
adequately identify and address the significance of this condition
adverse to quality.
Following the licensee's identification in January 1997, that the fuses
were under rated in all RBCUs, adequately rated fuses (KTK-15) were
installed in all RBCUs before the Units were restarted from the extended
outage. However, at this time the licensee did not initiate a new PIP
or re-open the original PIP to evaluate the past operability of the
RBCUs or the extent of condition for this issue. Following discussion
with the inspector, the licensee initiated PIP 0-097-1109 on April 1,
1997, to investigate the inappropriate categorization of PIP 0-95-0267,
and initiated a 10 CFR 50.72 report on April 2, 1997. This item is
identified as Violation 50-269,270,287/97-02-08, Inadequate Corrective
Action and Design Control for RBCU Fuse Failures.
E8.5 (Closed) VIO 50-269.270,287/96-04-03: Failure to Follow Procedure for
Drawing Control
This item was related to the identification of controlled drawings that
had not been updated to reflect changes from a modification completed 18
months prior to the drawing control inspection. Ten Vital to Operations
(VTO) drawings in the Units 1, 2, and 3 CRs had not been updated. The
corrective actions in the licensee's June 20, 1996, response to the
violation included improvement of VTO marking designations on drawings
and a 100 percent audit of station controlled drawings to verify correct
revisions were at all drawing file locations. The inspector verified
the corrective actions were completed and concluded that the licensee's
corrective actions were comprehensive.
IV. Plant Support Areas
P1
Conduct of EP Activities (71750)
During the two major events that occurred this inspection period.
inspectors were present to observe Emergency Plan activities performed by
the licensee. These activities are discussed in Sections 01.5, 01.8, and
E1.6 of this report.
Overall, the licensee performed in a conservative
manner on both events and followed their Emergency Action Levels.
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 May 7, 1997. The licensee acknowledged
the findings presented. No proprietary information was identified.
Enclosure 2
35
Partial List of Persons Contacted
Licensee
T. Barron, Procurement and Engineering Manager
S. Benesole. Independent Spent Fuel Storage Installation Readiness Manager
E. Burchfield, Regulatory Compliance Manager
T. Coutu, Operations Support Manager
D. Coyle, Systems Engineering Manager
T. Curtis, Operations Superintendent
J. Davis, Engineering Manager
B. Dobson, Systems Engineering Manager
W. Foster, Safety Assurance Manager
J. Hampton, Vice President. Oconee Site
G. Hawkins, Maintenance Manager
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
J. McLean. Senior Engineer-Modification
B. Peele, Station Manager
J. Smith. Regulatory Compliance
A. Wells. Civil Engineer
NRC
D. LaBarge, Project Manager
Enclosure 2
36
Inspection Procedures Used
IP 71750:
Plant Support Activities
IP 71707:
Plant Operations
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
IP 40500:
Self-Assessment
IP 37551:
Onsite Engineering
IP 92901:
Followup - Operations
IP 93702:
Responding to Events
IP 90712:
LER Review
IP 62700:
Maintenance Implementation
IP 92902:
Followup - Maintenance
IP 60854:
ISFSI - Dry Run
IP 60853:
ISFSI - Fabrication
IP 60851:
ISFSI - Design
IP 37700:
Design, Design Changes and Modifications
IP 37550:
Engineering
IP 92903:
Followup - Engineering
Enclosure 2
37
Items Opened, Closed, and Discussed
Opened
50-269,270,287/97-02-01
Inadequate Procedure for Control of LPI
Temperature (Section 03.1)
50-269/97-02-02
Unlocked CRD System Patch Panel (Section
08. 1)
50-269,270,287/97-02-03
Failure to Perform Procedure Prerequisites
(Section M1.4)
50-269.270.287/97-02-04
Failure to Have a Sizing Criteria for
Electrical Lugs (Section M8.2)
50-269,270,287/97-02-05
Welds Undersized or Not Inspecting By QA
(Section E1.4 and E1.5)
50-287/97-02-06
VIG
Inadequate Control of Purchased Material.
Equipment, and Services (Section E2.1)
50-269,270,287/97-02-07
Non-conservative Setting of LTOP Controls
(Section E2.2)
50-269.270,287/97-02-08
VIG
Inadequate Corrective Action and Design
Control for RBCU Fuse Failures (Section
E8.4)
50-269,270.287/97-02-09
IFI
BWST Temperature Requirements (Section
03. 1)
Closed
50-269/95-05-00
LER
Breach of Technical Specification Due to
Unlocked Control Rod Patch Panel (Section
08.1)
50-269/95-05-01
LER
Breach of Technical Specification Due to
Unlocked Control Rod Patch Panel (Section
08.2)
50-270/96-10-01
Failure to Change Flux/Flow/Imbalance
Setpoint (Section 08.3)
50-270/96-005-00
LER
Main Steam Relief Valves Technically
Inoperable Due to Improper Assembly of
Component (Section M8.1)
- CEnclosure
2
38
50-270/96-13-06
Lug Connections for High Voltage
Terminations (Section M8.2)
50-270/96-13-05
IFI
HPI Motor Failure (Section M8.3)
50-270/96-03-00
LER
Technical Specification Required Shutdown
Due to Inadequate Work Planning (Section
M8.4)
50-269.270,287/96-09-01
Inoperable Hydrogen Recombiner Condensate
Pumps (Section E8.1)
50-269.270.287/96-03-03
Adequacy of Information Provided for Spent
Fuel Pool (SFP) Design (Section E8.2)
50-269,270,287/96-20-03
Loss of RCS Inventory (Section E8.3)
50-269,270,287/96-17-03
RBCU Operability Concerns Due to Wrong
Fuse *in
Control Circuit (Section E8.4)
50-269,270,287/96-04-03
VIG
Failure to Follow Procedure for Drawing
Control
(Section E8.5)
50-270/95-01-00
LER
Technical Specification Exceeded Due to
Equipment Failure (Section M8.5)
50-269/95-03-00
LER
Low Pressure Injection System Technically
Inoperable Due to.a Design Analysis
(Section M8.6)
Enclosure 2
39
List of Acronyms
Augmented Inspection Team
ANSI
American Nuclear Society Institute
American Society of Mechanical Engineers
Babcock and Wilcox
BWST
Borated Water Storage Tank
Corrective Action Report
CFR
Code of Federal Regulations
Component Cooling
CFR
Code of Federal Regulations
CHRS
Containment Hydrogen Recombiner System
CR
Control Room
Control Rod Drive
Design Basis Document
Demand For Information
Division of Reactor Safety
Dry Storage Canister
Emergency Action Level
Engineering Change Notice
Engineered Safeguards
EWST
Elevated Water Storage Tank
F
Degrees Fahrenheit
FDW
Failure Investigation Process
FRA
Fuel Receiving Area
GPM
Gallons Per Minute
GL
Generic Letter
High Pressure Injection
HQ
Headquarters
HSM
Honizonal Storage Module
In Accordance With
Integrated Control System
I&E
Instrument & Electrical
IR
Inspection Report
Independent Spent Fuel Storage Installation
JCO
Justification for Continued Operation
KHU
Keowee Hydro Unit
LDST
Letdown Storage Tank
LER
Licensee Event Report
LCO
Limiting.Condition for Operation
Loss of Coolant Accident
Low Pressure Injection
Low Pressure Service Water
LT
Level Transmitter
Low Temperature Over Pressure
Maintenance Procedure
Enclosure 2
40
MPH
Miles Per Hour
MVA
Mega Volts-Amps
Nonconformance Report
Non-Cited Violation
NI
Nuclear Instrument
Non-Licensed Operator
Notice of Unusual Event
NRC
Nuclear Regulatory Commission
Nuclear Reactor Regulation
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
Nutek Horizonal Modular Storage
Operations Support Center
Problem Investigation Process
Plant Operating Review Committee
PO
Purchase Order
Pounds Per Square Inch Gage
Quality Assurance
Reactor Building
RBCU
Reactor Building Cooling Unit
Reactor Coolant Pump
Refueling Outage
0RG
Regulatory Guide
Spent Fuel Pool
Seismic Qualification Utility Group
Senior Resident Inspector
Standard Review Plan
Standby Shutdown System
Tave
Temperature Average
Transfer Cask
Turbine Driven Emergency Feedwater
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
USTS
Upper Surge Tank Support
Work Order
Violation
VTO
Vital To Operations (drawing)
- rEnclosure
2