ML15118A270
| ML15118A270 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A267 | List: |
| References | |
| 50-269-97-14, 50-270-97-14, 50-287-97-14, NUDOCS 9711250360 | |
| Download: ML15118A270 (58) | |
See also: IR 05000269/1997014
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:
50-269/97-14, 50-270/97-14. 50-287/97-14
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
September 7 - October 18, 1997
Inspectors:
M. Scott, Senior Resident Inspector
S. Freeman, Resident Inspector
E. Christnot, Resident Inspector
D. Billings, Resident Inspector
N. Economos, Regional Inspector (Sections M1.10, M1.11.
M1.12, M8.3, and M8.4)
D. Forbes, Regional Inspector (Sections R1.1, R1.2, and
R7.1)
P. Fredrickson, Branch Chief (Sections 08.4, 08.5. M8.1,
M8.2, and E8.4)
Approved by:
C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9711250360 971117
PDR ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2, and 3
NRC Inspection Report 50-269/97-14,
50-270/97-14,
and 50-287/97-14
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six-week
period of resident inspection, as well as the results of announced inspections
by three regional based inspectors.
Operations
In general, the conduct of operations was professional and safety
conscious.
(Section 01.1)
The inspectors concluded that both the shutdown and startup of
Unit 3 were performed appropriately. (Section 01.3)
The licensee did not perform a required Technical Specification
surveillance on Units 1 and 3 during the last refueling.
The
affected units were shutdown at the time of discovery and
performance of the surveillance indicated that the involved
instruments were within tolerance.
The licensee issued a Licensee
Event Report after the end of the inspection period. Further
follow up of this issue will be tracked under the Licensee Event
Report.
(Section 01.4)
During a forced shutdown to replace the 3B reactor building
cooling unit fan motor, the licensee successfully completed an
extensive and complex surveillance of.the replacement 3B high
pressure injection pump. The pump had been replaced in parallel
with the reactor building cooling unit fan motor to preclude a
possible future shutdown due to an observed gradual pump
degradation. (Section 01.5)
An Unresolved Item was identified dealing with the failure to
follow the low temperature over pressure procedure guidance.
(Section 03.1)
Poor administrative controls of isolation of Technical
Specification required low pressure service water loads resulted
in a negative finding on the control of out-of-service equipment.
(Section 03.2)
The licensee accurately determined the cause of adverse trends in
configuration control and developed corrective actions to reverse
the trends. However, by the end of the inspection period, the
licensee had not implemented all these actions. Consequently,
configuration control trends remain unchanged. (Section 08.1)
The licensee has completed annual operational assessments in the
areas of communications and procedures. The contents of the
Enclosure 2
2
assessments were relevant to improving plant activities and safety
performance. (Section 08.2)
The inspectors identified a violation for a failure to follow Lee
Steam Station Operating Procedure, Emergency Power Or Back-up
Power To Oconee, which caused the loss of CT-5 and the consequent
loss of Oconee main feeder busses on June 20, 1997.. (Section
08.4)
The inspectors identified a violation for a failure to provide
appropriate instructions for resetting Switchgear 1X lockout in
Keowee Alarm Response Guide SA1/E-04, 600V SWGR IX Lockout Relay.
(Section 08.5)
Maintenance
The inspectors concluded that general maintenance activities were
completed thoroughly and professionally. (Section M1.1)
Overall, maintenance troubleshooting and quarantine of parts in
response to the observed breaker closing coil failure on Keowee
Hydro Unit 2 was good. The replacement of the Y relay timers on
the Keowee safety-related Westinghouse DB-25 and 50 breakers was a
conservative corrective action. (Section M1.2)
Keowee preventive maintenance and testing activities were
general ly completed thoroughly with procedures and work orders at
the job site. The inspectors concluded that with the 1A sump pump
check valve leaking, the 1B sump pump was able to pump at 35 gpm.
This is sufficient to pump down the wheel well sump due to the 2
gpm limit on leakage. Although pump discharge check valve leakage
had been a previous work-around, new valves are scheduled for
installation in the near future. (Section M1.3)
During performance of major modifications to the Units 1 and 2 low
pressure service water piping, the majority of the observed work
was professionally and properly carried out. One of the plugs
installed in a 42-inch pipe was stranded in the pipe when removal
was attempted. Corrective action will occur outside the
inspection period with the licensee forming a Failure
Investigation Process team to investigate the cause and recommend
a possible resolution.
(Section M1.4)
The inspectors concluded that the Unit 3 main turbine generator
voltage regulator automatic card was adjusted in accordance with
procedures and with engineering and supervisory oversight. The
adjustments were consistent with the latest vendor information.
(Section M1.5)
Although problems did occur during emergency start testing of the
Enclosure 2
3
Keowee Hydro Units, overall, the tests were carried out properly
with good pre-job briefs, good test performance, and proper
equipment control.
During testing, a field flash breaker coil
failed (smoldered). Licensee actions in response were
appropriate. (Section M1.6)
Increased leakage from the 2LP-1 valve's body to bonnet joint
resulted in a Unit 2 shutdown to allow for a satisfactory seal
injection repair. The licensee applied appropriate operational
experience review and met current NRC guidance during the repair
effort. Operational controls during the period were good. Final
repair will occur at the next refueling or fuel off load.
(Section M1.7)
Upper surge tank work was well-engineered with good technical work
control. Overall, initial tank condition was good. Use of
uncovered wood in the tanks with minimal foreign material control
was an example of foreign material process weakness that the
licensee addressed prior to work performance. (Section M1.8)
The licensee provided excellent work control in the
lifting/removal of the 1A1 reactor coolant pump with health
physics personnel providing positive support. The pump's impeller
.was missing part of one vane and exhibited what appeared to be
cavitation damage on other vanes. A licensee evaluation was in
progress. (Section M1.9)
A nuclear station modification to replace certain valves and
associated piping in the high pressure injection system was being
performed following applicable code requirements. Prefabricated
subassemblies exhibited good workmanship attributes and material
records were retrievable and in order. Nondestructive
examinations met applicable code requirements: they were performed
and the results interpreted in a conservative manner. (Section
M1.10)
Low pressure service water system modifications to replace certain
valves and LPSW pump minimum flow lines were well planned. Valve
and pipe replacements were being installed consistent with
applicable code requirements and quality criteria.
(Section
M1.11)
Volumetric inservice inspection of designated welds was performed
satisfactorily by qualified and well trained personnel following
approved nondestructive examination procedures.
(Section M1.12)
To reduce the likelihood of peeling polar crane paint and
extensive hanger paint intrusion into refueling activities, the
licensee installed a protective foreign material tent over the
Unit 1 refueling cavity. This was installed prior to opening the
Enclosure 2
0II
4
reactor coolant system and commencing fuel off-load. (Section
M2.1)
The inspectors identified a weakness in the foreign material
exclusion program based on multiple examples of poor foreign
material exclusion practices. (Section M3.1)
The inspectors identified a violation for a failure to translate
.
information from a Westinghouse technical manual to the licensee's
maintenance procedure for the DB-25 circuit breakers.
(Section
M8.1)
The inspectors identified a non-cited violation for a failure to
provide detailed guidance in the preventive maintenance procedure
for measuring the timer settings for the Y coil in DB-50 breakers.
(Section M8.2)
Engineerino
The inspectors identified one violation in which improper
assessment of emergency feedwater valve operation resulted in a
recurrence of a previous component failure in the emergency
feedwater system. (Section E1.1)
The failure to ensure complete removal of unqualified thermal
insulation from the reactor buildings caused an inaccurate
calculation of operability and resulted in a violation based on
inadequate corrective action. (Section E1.2)
The inspectors concluded that the engineering real-time support
for a Keowee Hydro Unit emergency start test was effective.
The
performance of the failure investigation group in identifying the
failure mechanism for the Y relay timer was excellent. A review
of the present timer logic network for possible modification is
considered an example of good safety attitudes. (Section E2.1)
The test of reactor building cooling unit breakers was performed
in accordance with an approved procedure, by knowledgeable
personnel. and with engineering oversight. The inspectors
considered the breaker testing activities by the engineering,
maintenance, and procurement quality assurance personnel to be
good. (Section E2.2)
Failure to evaluate heavy load lifts over safety-related
components while Unit 1 was above cold shutdown conditions
resulted in a violation. (Section E3.1)
The inspectors identified a violation for a failure to implement a
modification inside the licensee's approved modification process.
Enclosure 2
5
resulting in the modification not receiving a post-modification
test. (Section E8.4)
Plant Support
Based on observations and procedural reviews, the inspectors
determined the licensee was effectively maintaining controls for
personnel monitoring, control of radioactive material,
radiological postings, and radiation area and high radiation area
controls as required by 10 CFR Part 20. (Section R1.1)
The inspectors determined the licensee's programs for controlling
exposures as low as reasonably achievable were effective and
management demonstrated strong support for the program. (Section
R1.2)
A violation was identified, with two examples, for inadequate
radiation protection practices and controls which allowed entry
into a posted radiation area without proper dosimetry. (Section
R1.3)
The inspectors determined that the licensee was performing Quality
Assurance audits and effectively assessing the radiation
protection program as required by 10 CFR Part 20.1101. The
inspectors also determined the licensee was completing corrective
actions in a timely manner. (Section R7.1)
Enclosure 2
Report Details
Summary of Plant Status
Unit 1 operated at 73 percent power, limited by three Reactor Coolant Pumps
(RCPs). until its shutdown September 18, 1997. for a normal refueling outage.
Unit 2 was shutdown from 100 percent power on September 4. 1997. for seal
injection. repairs to a non-isolable valve (2LP-1), off the Reactor Coolant
System (RCS). Following completion of the repairs, Unit 2 resumed power
operations on September 11, 1997. and remained at power through the remainder
of the inspection period.
Unit 3 was shutdown from 100 percent power on September 27. 1997, to replace
the 3B reactor building cooling unit (RBCU)
fan motor, as well as the
degrading 3B High Pressure Injection (HPI)
pump.
The unit was returned to
power on October 11, 1997.
Review of Updated Final Safety Analysis Report (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 parameters.
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 Keowee Hydro Unit (KHU) Emergency Start Test
General Comments (71707)
The inspectors observed the performance of the Keowee emergency start
test conducted on September 16. 1997. This test occurred over several
days, with delays due to instrumentation problems and an equipment
failure. This is discussed in Section M1.6 and E2.1 of this report.
During this period, operations personnel were positive in their control
of Technical Specification (TS) electrical equipment.
Enclosure 2
7
01.3 Unit 3 Shutdown and Startup Observations (71707)
a. Inspection Scope (71707)
The inspectors observed Unit 3 shutdown activities on September 27 and
startup activities on October 10 and 11. Unit 3 was shutdown due to a
testing failure of the 3B RBCU fan motor.
The motor had failed during
survei lance PT/O/A/0160/06 (Problem Investigation Process (PIP) 3-97
3068).
Specifically, the running fan was shutdown from fast speed and
it failed to restart in slow speed, requiring unit shutdown and motor
replacement. (See Section E2.2.)
b. Observations and Findinqs
The motor failure placed the unit in a Limiting Condition for Operation
(LCO) that could not be satisfied without a unit shutdown. The licensee
shutdown the unit prior to the end of the LCO time limit.
Both shutdown and startup were characterized by clear operator
communications, effective control by shift supervision, and management
oversight.
Shift management was present in the control room.
The plant
manager was also present for the startup in a management overview
capacity. During unit heat up prior to startup, the licensee identified
leakage of 2 drops per minute and 12 drops per minute from two different
RCS temperature instruments.
The licensee evaluated these leaks as
acceptable. It was observed that RCS leakage had not increased since
the unit restart.
c. Conclusion
The inspectors concluded that both the shutdown and startup of Unit 3
were performed appropriately.
01.4 Missed TS Surveillance
a. Inspection Scope (61726)
On October 10, 1997. the licensee discovered that the maintenance
performed surveillances (IP/0/A/0203/001C) for the low pressure
injection ([PI) flow and reactor building (RB)
spray flow instruments
(TS Table 4.1-1, Item 29) were not performed at their last required due
date (i.e., at the respective refueling outage for Units 1 and 3).
The
inspectors followed the licensee activities.
b. Observations and Findings
On October 10, the licensee called the inspectors to inform them that TS
surveillance performance mistakes had occurred on Units 1 and 3. This
was just prior to the Unit 3 startup following replacement of a RBCU fan
Enclosure 2
8
inspectors verified that Unit 2 surveillances had been performed.
The licensee performed the overdue surveillances on Unit 3 and then on
Unit 1. The results indicated that the flow instruments were within
tolerance. The licensee was investigating this issue at the end of the
inspection period.
c. Conclusions
The licensee did not perform a required TS surveillance on Units 1 and 3
during the last refue ing. The affected units were shutdown at the time
of discovery and performance of the surveillance indicated that the
involved instruments were within tolerance. The licensee issued a
Licensee Event Report after the end of the inspection period.
Further
follow up of this issue will be tracked under the Licensee Event Report.
01.5 Abnormal HPI Pump Configuration for Full Flow Test
a. Inspection Scope (71707, 61726)
As a part of the forced shutdown for the 3B RBCU repairs, the licensee
decided to replace the 3B HPI pump to preclude a subsequent possible
forced outage. The inspector followed the replacement, especially the
off-normal testing of the pump.
b. Observations and Findings
Normally, an HPI pump is full flow tested at the end of an outage with
the RCS at atmospheric pressure, ambient plant conditions, and the steam
generator RCS handholds open to containment pressure. Following the
replacement of the 3B HPI pump, the licensee decided to perform the
inservice full flow test with the RCS at about 340 degrees F and 370
psig and a pressurizer level of approximately 120 inches.
This testing
condition was markedly different from that normally used for outage full
flow testing and required special testing.
Preparations for the test and inspector observations were as follows:
-
The inspector found the simulator training for the evolution
excellent with attentive procedure writers, a senior reactor
operator, a general office engineer, and training personnel on
hand to debug the test procedure and address any concerns that the
operations shift crews had. An operations manager observed the
training.
-
The licensee contacted other Babcock and Wilcox (B&W)
plants and
questioned their staff about full flow testing.
They had obtained
a test that had been successfully utilized at another facility
that was very simila.r to the mode of testing that they had planned
Enclosure 2
9
a test that had been successfully utilized at another facility
that was very similar to the mode of testing that they had planned
to utilize and incorporated its salient points into their test.
-
The licensee had debugged the test using the system and component
engineers.
-
The test had been thoroughly reviewed by the plant review
committee.
The test was completed as predicted with the pump performing in an
acceptable manner. The pump slightly exceeded the manufacturer's pump
head curve. Data collected during the test was compared with previous
tests and used to enhance simulator response.
c. Conclusions
During a forced shutdown to replace the 3B RBCU fan motor, the licensee
successfully completed an extensive and complex surveillance of the
replacement 3B HPI pump. The pump had been replaced in parallel with
the RBCU fan motor to preclude a possible future shutdown due to a
observed gradual pump degradation.
02
Operational Status of Facilities and Equipment
02.1 Unit 1 Outage Schedule
Due to a multitude of problems, Unit 1 ended the period 10 days behind
schedule. Because of the potential for thermal heat stress, due to
auxiliar fan coolers not being initially available, the licensee could
not sa ey perform many reactor building entries to complete early
outage work. Additionally, the polar and jib cranes in the RB required
additional work and repairs. The refueling machinery broke down several
times during its setup and early operation requiring additional repair
time. The licensee indicated that the refueling machinery is to be
replaced next outage.
03
Operations Procedures and Documentation
03.1 Failure to Follow Low Temperature Over Pressure (LTOP)
Procedure
a. Inspection Scope (71707)
The inspectors reviewed procedures, problem investigation forms, and
interviewed personnel following the identification of a LTOP procedure
problem.
Enclosure 2
10
b.
Observations and Findings
TS 3.1.2.9 requires two trains of LTOP be operable when the RCS is less
than or equal to 325 degrees F and an RCS vent path capable of
mitigating the most limiting LTOP event is not open. Two trains of LTOP
consist of: (1) one train being the power operated relief valve set at
less than or equal to 480 psig; and (2) controls to assure 10 minutes
are available for operator action to mitigate an LTOP event.
Procedure OP/1/A/1104/49, Low Temperature Overpressure Protection,
requires verification that pressurizer levels 1, 2. and 3 are not in
Inserted Value, Scan Lockout, or No Alarm Check on the Operational Aid
Computer (OAC)
to meet TS 3.1.2.9.
The Shift Turnover Checklist and
PT/1/A/600/01, Periodic Instrument Surveillance, requires checks to be
made to ensure the requirements remain in effect during LTOP conditions.
If these conditions cannot be met, a dedicated LTOP operator must be
established.
On September 19, 1997, with the RCS less than 325 degrees and LTOP
required, two of the three required pressurizer alarms were placed in
OAC "no alarm status" for low pressurizer level without stationing a
dedicated LTOP operator. This resulted in the second train of LTOP
being in a -degraded state for 62 minutes before operators recognized and
replaced the alarm points back in service. However, this was within the
4-hour LCO time constraint.
The licensee is continuing to evaluate the cause and corrective actions
for this occurrence under PIP report 1-097-3047.
This item will be
identified as Unresolved Item (URI) 50-269/97-14-01, Failure to Follow
LTOP Procedure, pending completion of the evaluation.
c. Conclusions
An URI was identified dealing with the failure to follow the LTOP
procedure guidance.
03.2 Premature Exit of TS LCO
a. Inspection Scope (71707)
The inspector reviewed the circumstances surrounding the Unit 2 exit of
an LCO prior to completing all required actions.
b. Observations and Findings
For Units 1 and 2 there is a shared low pressure service water (LPSW)
system. TS 3.3.7 requires 3 LPSW pumps to be operable. The TS bases
states that 2 LPSW pumps are required provided that one unit is defueled
and the following LPSW loads are isolated on the defueled unit (in this
Enclosure 2
0II
11
case Unit 1): reactor building cooling units, component cooling cooler,
main turbine oil tank coolers, reactor coolant pumps, and low pressure
injection coolers.
On October 10. 1997, at 4:20 a.m.. Units 1 and 2 entered a 72-hour LCO
per TS 3.3.7 following removal of the C LPSW pump from service for
outage related work. The LCO expiration date was October 13, 1997, at
4:20 a.m. Unit 2 exited the LCO at 8:43 a.m. on October 12, 1997, with
the completion of Unit 1 core off-load and Unit 1 LPSW load isolations
performed by the day shift Operations crew. In its defueled state. Unit
1 had no LCO.
On October 12, 1997, with the first LCO supposedly exited, preparations
were in progress to remove electrical bus 1TC from service for outage
work. This would remove the A LPSW pump from service and place Unit 2
in a second 72-hour LCO until the A LPSW pump could be powered from 2TC
(approximately one hour).
Prior to the second LCO entry, the night
shift operators questioned the administrative controls for the Unit 1
LPSW loads previously isolated for compliance with the first LCO.
Subsequently, all loads which should have been isolated were found to be
isolated except for the LPSW to the Unit 1 component cooling cooler.
The cooler isolation valves were found open with flow through the
cooler. At this point, operations isolated the Unit 1 component cooling
cooler, revised the log to show exiting the LCO (October 12, 1997, at
4:30 a.m.), initiated PIP 2-097-3488, and informed operations
management. They verified and tagged the other LPSW loads with white
control tags. Importantly, due to the night shift's attention to
detail, the second LCO was not entered until the first LCO conditions
were met for a proper exit and the first LCO was properly exited prior
to the end of its 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limit.
Discussions with operations personnel verified that, in this case. there
were no tags hung for the initial entry into the first LCO. Local
instructions did not specifically require tags to be hung.
Historically, no positive means had been required to control equipment
isolated during an outage for TS reasons. The licensee will evaluate
and correct the causes following completion of the PIP evaluation.
c. Conclusions
Poor administrative control of the isolation of TS required loads
resulted in a negative finding on the control of out-of-service
equipment.
Enclosure 2
12
08
Miscellaneous Operations Issues (92901)
08.1 Assessment of Mispositioning Events
a. Inspection Scope
Licensee management observed that configuration problems had an adverse
trend. After the 3LP-40. 3HP-5, and 2HP-96 misposition events that
occurred in the last 12 months, the licensee formed a Continuous
Improvement Team (CIT) to review misposition problems at the Oconee
site. The residents validated the database used by the team and
reviewed the assessment output.
b. Observations and Findings
Beginning February 27, 1997, the licensee identified an adverse trend in
configuration control over the previous several months.
The licensee
documented this trend in PIP 0-097-0737 and organized a CIT to
investigate the trend and provide solutions.
The CIT attributed the
cause of the trend to several factors, including work practices and work
processes. It was determined that a large majority (76 percent) of the
mispositioning events from January 1996 to July 1997 were caused by
either inattention to detail or misjudgement.
The CIT recommended seven
main corrective actions and several sub-actions to address these
concerns. As of this inspection period, the licensee had implemented
one of these recommendations and partially implemented two others.
One partially implemented CIT recommendation called for verification of
worker skills regarding human performance. The corrective action
documented in PIP 0-097-0737 for this recommendation indicated that a
practical factors skills test would be developed and implemented for the
maintenance and work control groups before June 1998. Additionally, the
inspectors observed the practice of having managers present during
critical plant evolutions specifically checking on human performance.
The inspectors determined that this activity did indeed verify these
skills.
The inspectors agreed that the licensee accurately determined the cause
of adverse configuration control trends. The inspectors further agreed
that some of the developed corrective actions were adequate to reverse
the trends. However, the trend of overall configuration control
problems has remained constant. Mispositionings have not worsened, but
neither has any improvement been noted. Significant problems did occur
during the first part of 1997. Since the shift in management emphasis
has occurred, the significance of the mispositionings has not been as
great. Implementation of additional corrective action may reduce the
number of mispositionings.
Enclosure 2
c. Conclusions
The licensee accurately determined the cause of adverse trends in
configuration control and developed corrective actions to reverse the
trends. However, by the end of the inspection period, the licensee had
not implemented all these actions. Configuration control trends remain
unchanged.
08.2 Licensee Operational Internal Assessments
a. Inspection Scope
After several operational problems during this Systematic Assessment of
Licensee Performance (SALP) period, the licensee refocused, adding
emphasis to their normal annual assessment. These assessments are
performed in accordance with the licensee's Nuclear Policy Manual. NSD
607, Appendix A, Group Assessments. The assessments were in the
following areas:
-
Operations Communications SA-97-29 (ON)(OPS) of August 8, 1997,
through September 11, 1997
-
Operations Procedures 97-38 (ON)(OPS) of October 1. 1996, through
October 1, 1997
The inspectors validated the issues and reviewed the assessment output.
b. Observations and Findings
As a product of their annual assessment process, the operations group
completed two assessments that were meaningful, producing good overall
recommendations and findings. The assessments were sensitive to issues
addressed in recent augmented inspections and NRC operations licensing
comments on annunciator response guidance and three-way communication
discussed in Inspection Report (I
R) 50-269.270.287/97-05. The
communication assessment produced changes to existing procedural
guidance with 28 clear recommendations. The procedure groups had
increased the procedure change rate from 140 changes per year in 1996 to
396 in 1997 through (September 1997). This increase in procedure
production was indicative of a higher awareness of procedure problems
and less of a tendency to work around them. Accompanying the higher
production rate was an increase in demand rate with production lagging
behind a new demand of 330 change requests yet to be processed for 1997.
Highlights of the communications assessment recommendations were:
preplanning of re-qualification cycle with management involvement;
operations crew round sheet review at shift briefing shall be
Enclosure 2
14
consistent between shifts:
operations shift meeting improvements to provide improved shift to
shift turnover and focus at the meeting;
standardization of communication techniques;
systematic review of alarm response guides for the removal of
instructional steps and the placing of those steps in appropriate
procedures;
creation of a video for standard simulator communications;
develop procedural usage guidance and training on operations
radios (dead spaces in plant);
purchase cellular phones for non-licensed operator (NLO)
and
operator usage;
0
improve external communication through training and management
oversight; and
improve NRC, plant staff, and management notification process.
The notification improvements have begun. starting with an informational
badge containing a call-out list that was distributed to the on-shift
managers.
Highlights of the procedure assessment that have been implemented were
as follows:
-
procedure owners had been designated:
-
shift personnel were involved.in the procedure review process:
-
lower tolerance for procedure deficiencies had been clearly
communicated with the staff;
-
procedures found missing any critical parts are removed from use;
and
-
a qualified reviewer and reactivity management review checklist
has been incorporated into the procedure review checklist.
The inspectors have observed many of the above improvements during the
last several months inclusive of the reactivity review check sheet with
procedure changes and many additional corrective action items dealing
with procedure related problems. Although special evolutions drove
their creation, recently issued and used procedures for the Unit 3 full
Enclosure 2
15
flow test and the Unit 1 startup on three RCPs were professionally
competent instructions.
c. Conclusions
The licensee has completed annual operational assessments in the areas
of communications and procedures. The contents of the assessments were
relevant to improving plant activities and safety performance.
08.3 (Closed) URI 50-269,270,287/97-01-05: LPSW Piping to the RB Cooling
Inoperability
This issue was captured under URI 50-269,270.287/97-01-05 and LER 50
269,270,287/97-002. Due to the complexity of this Generic Letter 96-06
issue, it will not be closed until approximately mid 1998.
PIPs 97
0240, 0310, and 0311 are the internal licensee corrective action
documents. Paft operability will be examined during the LER closure
review. According y, this URI is closed.
08.4 Conduct of Lee Steam Station Operations
a. Inspection Scope (92901)
The inspectors eviewed the results of the Augmented Inspection Team
(AIT) NRC Inspection Report 50-269,270.287/97-11. Section 01.1. for
ossible NRC enlforcement action related to the circumstances involving
ee Steam Station for the Oconee event of June 20, 1997.
b. Observations and Findings
As documented in the AIT report, on June 20. 1997. Oconee was in the
p
rocess of perfbrming Surveillance Procedure PT/1/A/0610/06. 100 Kilo
Volt (KV) Power Supply From Lee Steam Station. This surveillance was
required by TS 4 6.7 to be performed at least every 18 months, usually,
concurrent withian Oconee Unit 1 refueling outage. In addition to
Procedure PT/1/A/0610/06, Procedure OP/0/A/1107/03A. Oconee Nuclear
Station and LeelSteam Station and Lee Procedure Emergency Power Or Back
up Power To Ocoee were also used to accomplish the surveillance.
Procedure OP/O/A/1107/03A primarily involved verification of certain
breaker alignments prior to starting the Lee gas turbines.
On June 20, 1997. at the request of Oconee. Lee operators had paralleled
the 6C gas turbine to the grid per Enclosure 6.1 of Lee operating
procedure Emergency Power or Backup Power to Oconee.
The Lee control
operator (LOA)
and Lee assistant control operator (LOB)
were performing
steps for the 60 Lee gas turbine in the Lee control room and were also
monitoring the control boards for the three operating fossil units.
The
LOA and LOB werd notified by Oconee operators that breaker alignments at
Oconee were complete, and Lee Operators could initiate steps to dedicate
Enclosure 2
16
Lee.
The alignment that dedicated Lee were steps 6.1.5 through steps
6.1.9 of Enclosure 6.1 of Lee steam station operating procedure. Step
6.1.5, first required switcher 89-3 to be closed and then step 6.1.6
required switcher 89-2 to be open.
The Lee operator performed steps
6.1.5 and steps 6.1.6 in reverse. First, opening switcher 89-2 caused
the operating 6C Lee gas turbine generator to be separated from the
grid, causing it to slightly overspeed.
When 89-3 was closed, the 6C
Lee gas turbine was now slightly tied out-of-phase with respect to the
grid. This caised a voltage surge which resulted in OCB-13 and breakers
SLi and SL2 tripping. Consequently, CT-5 was deenergized, resulting in
the loss of voltage on the Oconee main feeder busses (MFBs),
and causing
Keowee Units 1 and 2 to emergency start. The 6C Lee turbine generator
continued to operate, following the separation from the system.
The
gas turbine continued running until it was stopped by Lee operators 20
minutes after the event. Failure to follow the Lee Station Procedure as
dictated by thd Oconee periodic test procedure is a violation of TS 6.4.1 and is identified as Violation (VIO) 50-269,270,287/97-14-02:
Failure to Adequately Implement Lee Station Procedure.
c. Conclusions
The inspectors identified a violation for a failure to follow Lee Steam
Station Operating Procedure Emergency Power Or Back-Up Power To Oconee
which caused the loss of CT-5 and the consequent loss of Oconee MFBs on
June 20. 1997.
08.5 Adequacy of Keo ee Alarm Response Guide (ARG)
a. Inspection Scope (92901)
The inspectors reviewed the results of the NRC AIT Inspection Report 50
269,270,287/97-11, Section 01.2. for possible NRC enforcement action
related to the adequacy of Keowee ARG SA1/E-04, 600V SWGR 1X Lockout
Relay, Revision 7.
b. Observations and Findings
As documented in the AIT report, on June 23. 1997. after a Switchgear 1X
lockout, the Ke6wee operator referenced ARG SA1/E-04. Subsequently, the
operator, after noticing that no protective relay action had occurred,
checking the position of the breaker impact springs in Air Circuit
Breaker (ACB) 5 and ACB 7, and contacting the on-call technical support
specialist, reset the impact spring in ACB 7 and reset the lockout relay
for Switchgear 11X.
This action resulted in ACB 5 and ACB 7 attempting
to close and then tripping open.
The inspectors noted that the licensee had characterized the cause of
the blown fuses as an unanticipated circuit operation following the
operator's actioh to reset the lockout condition.
As immediate
Enclosure 2
17
corrective action, the licensee revised ARG SA1/E-04 (and also ARG
SA2/E-04),
to gequire the transfer scheme for Switchgear 1X and
Switchgear 2X to be placed in manual (in lieu of automatic), prior to
the resetting of a lockout condition in order to preclude both breakers
(ACB 5 and ACB 7 or ACB 6 and ACB 8) that supply power to the associated
switchgear from receiving close signals at the same time. The
inspectors condluded that ARG SA1/E-04 was inadequate because it allowed
the operator td reset the lockout with the transfer scheme in automatic,
which caused the unanticipated circuit response and blown fuses.
The
inspectors alsd concluded that this inadequacy was self-revealing.
Failure to provide ARG SA1/E-04 with appropriate instructions is a
violation of TSi 6.4.1 and is identified as VIO 50-269,270,287/97-14-03:
Failure to Provide Appropriate Lockout Reset Instructions in ARG SA1/E
04.
c. Conclusions
The inspectors Identified a self-revealing violation for a failure to
provide appropriate instructions for resetting. a Switchgear 1X lockout
in Keowee ARG S 1/E-04. 600V SWGR 1X Lockout Relay.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707. 61726)
The inspectors observed all or portions of the following maintenance
activities:
DC Grounds
WOs 97083263
Replace Y Relay Timers on KHU Field
thrd
and Field Supply Breakers
97083267
Check/Calibrate Unit 3 Generator Auto
Voltage Regulator
Remove and Test Unit 3 RBCU B Breaker
Repair and Test KHU 2 Field Breaker
Repair Stuck Float KHU-1 AC Sump Pump
- 0
3B RBCU Failed to Start
Enclosure 2
18
Perform Char Analysis on Unit 3A RBCU
Motor
RBCU 3B motor removal
Leak Repair Bonnet Leak on 2LP-1
TSM-1376
Minor Modification for Leak Repair on 2LP
1
IP/0/A/3000/018A
Ground Hog DC System Ground Location
MP/0/A/1800/016
System Leakage Repairs Using Vendor
I
Injection Methods
PT/1/A/2200/019
KHU-1 Turbine Sump Pump 1ST Surveillance
PT/0/A/0620/016
Keowee Hydro Emergency Start Test
TN/2/A/1376/TSM/00M
Leak Repair Bonnet Leak on 2LP-1
ONQE 10447
Perform 14-inch and 36-inch Wet Taps On
the LPSW A Line
- ON 1301
Units 1 and 2 LPSW Pumps Minimum Flow
Lines (Outage Portion)
IP/0/B/0200/023B
RCP Motor Temperature, Speed, and
Vibration Instrumentation Calibration and
Logic Test
Corrective WO for Unit 2 Voltage Regulator
B Chattering and Has Smokey Odor
IP/S/A/0100/001
Controlling Procedure for Troubleshooting
and Corrective Maintenance
PT/i
and 3/A/0251/027
HPI Pump Developed Head Test [at power]
OP/K/A/110e3/11
Drain and Nitrogen Purge of the RCS to
Less Than 50 Inches
MP/O0/A/1800/022
Directions for Using a Video Camera to
Look at Potentially Damaged Marbo Plug
IP/0/A/3011/014
1FDW-19 Infrared Thermography Scanning for
Electri cal Components
Enclosure 2
19
0 PT/0/A/0750/13
Miscellaneous Visual Inspection of Fuel
Assemblies
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 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.
The visual inspection of the fuel assemblies during the Unit 1 core off
load identified 4 fuel assemblies with slipped spacer grids and 22
assemblies with minor grid damage. These occurrences are captured by
PIP 1-97-3381. Based on their evaluation, the licensee will make core
reload changes as necessary.
c. Conclusion
The inspectors concluded that the maintenance activities listed above
were completed thoroughly and professionally.
M1.2 Keowee Breaker Repairs and Timer Change Out
a. Inspection Scope (62707)
The inspectors observed and reviewed maintenance activities involved
with the failed closing coil on the KHU 2 generator field breaker.
The
coil failed during KHU performance testing. Sections M1.6 and E2.1 of
this report discuss the failure.
b. Observations and Findings
The inspectors reviewed procedure IP/O/A/2001/003B, Inspection and
Maintenance of DB-50, DB-25. and DBF-16 Circuit Breakers and Work Order
(WO) 97080988. The inspectors observed portions of the maintenance
activities. The activities consisted of the following:
removal and quarantine of the breaker with the failed coil:
checking the replacement breaker from the warehouse:
setting up the test equipment for the performance of the
inspection procedure on the replacement breaker;
performance of the inspection procedure: and
Enclosure 2
20
0 installation of the replacement breaker.
Following completion of the above maintenance activities, KHU 2 was
tested and returned to operable status.
This event was discussed in PIP K-97-2983. Based on the failed relay
coil root cause, the licensee made the conservative decision to change
out the Y relay timers in all safety-related breakers of this type. The
timers were located in the direct current (DC)
generator field breakers
and the alternating current (AC) field supply breakers for both Keowee
units, as well as the spare breakers. The inspectors observed the work
activities (similar to those discussed above), reviewed the procedure,
and discussed the results with licensee personnel.
c. Conclusions
Overall, maintenance troubleshooting and quarantine of parts in response
to the observed breaker closing coil failure on Keowee Hydro Unit 2 was
good. The replacement of the Y relay timers on the Keowee safety-related
Westinghouse DB-25 and 50 breakers was a conservative corrective action.
M1.3 KHU 1 Inservice Testing and Preventive Maintenance
a. Inspection Scope (62707)
The inspectors reviewed and observed inservice testing (IST) and
preventive maintenance (PM) activities at the KHU. The PMs involved
circuit breakers and the IST involved the turbine wheel well sump pumps.
b. Observations and Findings
The quarterly PMs were performed on the generator field AC supply
breaker, the DC field breaker, and the air circuit breakers (ACB). A
previous failure of an ACB was caused by an air leak. The PM required
that a check for air leaks be performed. No air leaks were observed.
The inspectors observed the use of procedure PT/1/A/2200/019, KHU-1
Turbine Sump Pump.IST Surveillance, Revision 4. The sump pumps are
associated with TS 3.7, but are not addressed in the TS or the Selected
Licensee Commitments as attendant equipment. One pump will keep the
sump pumped and water off the important equipment in the area protected
by the sump. The KHU wheel wells have a continuous leak-off of less
than 2 gpm required by procedure. The procedure verified that the leak
off was less than 2 gpm. The test included pump performance and
vibration data collection.
The sump system is equipped with a DC driven pump (iB)
and an AC driven
pump (lA).
The pumps were each expected to remove 400 gallons from the
wheel well sump in seven to eight minutes. The 1 pump took between 11
Enclosure 2
0
21
and 12 minutes during the initial test. The inspectors observed that
the check valve on the 1A pump was leaking and diverting water back to
the sump. Accordingly, the normally open discharge valve on the 1A pump
was closed by procedure and the test was re-performed. Adequate results
were then obtained for the 1B pump. The inspectors observed that the
check valve on the 1B pump did not leak back to the sump during the 1A
test.
The time for the 1A pump was between seven and eight minutes.
The poor performance of the 1A discharge check valve was a potential
work-around that has been recently re-recognized and addressed by the
licensee. PIP K-95-1343 had been open since October 1995 on this check
valve issue. Minor modifications, one for each KHU (OEs-10468 and
10470), have been initiated to replace the check valves on all four
pumps (two per KHU) under work packages. Replacement valve availability
ad caused some of the corrective action delay. New stainless steel
valves, in lieu of bronze material, were scheduled to be installed in
the January 1998, time frame.
c. Conclusions
Maintenance and testing activities were generally completed thoroughly
with procedures and work orders at the job site. The inspectors
concluded that with the 1A sump pump check valve leaking the 1B sump
pump was able to pump at 35 gpm.
This is sufficient to pump down the
wheel well sump due to the 2 gpm limit on leakage. Although pump
discharge check valve leakage had been a previous work-around, new
valves are scheduled for installation in the near future.
M1.4 LPSW Modification ON0E 10447
a. Inspection Scope (62707,37551)
The inspector reviewed the procedures, interviewed personnel, and
observed activities associated with the modifications on the common LPSW
system for Units 1 and 2. (For further details on the modifications,
see Section M1.11)
b. Observations and Findings
The inspector observed the pipe preparation and welding of several wet
taps for Marbo plug installation, including the 36-inch wet tap
connection for the 42-inch LPSW pipe. Procedures were on hand with
adequate supervisory and quality control personnel monitoring the
activities. During the placement of the 36-inch isolation valve, it was
identified that the valve, when opened, would impact .a
support.
A
second issue was identified in that the valve and equipment to be used
to cut the pipe were not QA-1 qualified. These items were properly
identified and resolved satisfactorily.
Enclosure 2
22
An additional problem was identified during the attempted removal of the
36-inch Marbo plug when the plug failed to be withdrawn and lodged in
the isolation valve. The plant was in a stable condition and the work
performers were prompt in making checks of the system and its condition,
notifying Operations immediately.
The licensee initiated a Failure
Investigation Process (FIP) team and PIP 1-97-3621 to resolve the
problems.
c. Conclusions
During performance of major modifications to the Units 1 and 2 LPSW
piping the majority of the observed work was rofessionally and
properiy carried out. One of the plugs installed in a 42-inch pipe was
stranded in the pipe when removal was attempted. Corrective action will
occur outside the inspection period with the licensee forming a FIP team
to investigate the cause and recommend a possible resolution.
M1.5 Adiustment of the Unit 3 Generator Voltage Requlator
a. Inspection Scope (62707. 92902)
The inspectors reviewed and observed the calibration check and
adjustment of the Unit 3 main generator voltage regulator automatic
card. The calibration check and adjustment were performed as a result
of a Unit 2 trip on July 6. 1997. The licensee committed to perform a
check of the Unit 3 regulator during the next unit outage.
b. Observations and. Findings
The inspectors documented in IR 50-269.270.287/97-10 the calibration
check and adjustment of the voltage regulator on the Unit 2 main
generator. Licensee personnel used the same procedures and methods for
the check and adjustment of the Unit 3 main generator voltage regulator
as were used on Unit 2. The same technical personnel also performed the
activities.
The section of the voltage control circuit that was checked was the
auto-regulator circuit board which contained a first stage amplifier and
a second stage amplifier. The as-found condition indicated that the
gain for the first stage amplifier was approximately 3.55 to 1 and the
second stage 5.6 to 1. This resulted in an overall gain of
approximately 20 to 1. The requirement per procedure was a gain of 2 to
1 for the first stage and 8 to 1 for the second stage. This would
result in an overall required gain of 16 to 1.
Obtaining the best possible adjustment, the technical personnel adjusted
the first stage gain to 2.06 to 1 and the second stage to 7.8 to 1 with
an overall gain of approximately 16 to 1. The technicians were thorough
and methodical in their actions. The inspectors did not consider the
Enclosure 2
23
as-found overall gain of approximately 20 to 1 as excessive compared to
the required 16 to 1. This unit had responded well during a recent grid
fault that is one of the possible occurrences to which this circuit
responds.
c. Conclusions
The inspectors concluded that the Unit 3 main turbine generator voltage
regulator automatic card was adjusted in accordance with procedures and
with engineering and supervisory oversight. The adjustments were
consistent with the latest vendor information.
M1.6 KHU Emergency Start Test
a. Inspection Scope (61726)
On September 13. the inspectors reviewed, observed, and discussed the
KHU emergency start performance test. The test was a complex
surveillance and required management oversight. The inspectors were
informed that portions of this test were being performed for the first
time on an integrated basis following a modification to the system.
b. Observations and Findings
The complex surveillance was controlled by performance test procedure
PT/0/A/0620/19. Keowee Hydro Unit Emergency Start Test. Revision 22.
The purpose of the test was as follows:
to demonstrate operability of the KHUs' emergency start channel
from each control room and each cable room (Channels A and B);
to demonstrate each KHU will reach rated speed and voltage in less
than or equal to 23 seconds:
to verify KHUs' ACB closes automatically to the underground path;
to verify actuation and times for time delay relays for ACBs 1. 2.
3. and 4 close permissives; and
to demonstrate that each KHU can supply equal to or greater than
25 megawatts (MW) to the system grid.
The inspectors reviewed the test procedure and the management oversight
briefing paper. The inspectors attended the pre-job briefing and
discussed the procedure with licensee personnel.
The inspectors
observed the installation of digital relay timers at the KHUs. The
inspectors also observed operator activities in the Oconee Unit 3
control room and at the KHUs.
Enclosure 2
24
During the performance of the test, the inspectors observed testing
activities up to Section 12.5. To Test Keowee Emergency Start from Unit
3 Control Room (CR),
Subsection 12.5.5, Record Times From Digital
Timers.
The timers associated with ACBs 1, 2 and 3 did not pick up and
the relay times were not recorded.
The timers were installed on
terminal links in selected KHU cabinets and were to time the actuation
of ACBs 1. 2, and 3.
An operability issue was raised concerning the relays for the ACBs.
With the timers not picking up, the issue was whether or not the relays
actuated as required. The test was re-performed up to the relay
actuation with stopwatches being used to time the ACB relays. The
timers again failed to respond, but the visual timing of the relays
indicated acceptable operation.
The test was terminated and the KHUs
were returned to a normal lineup. The licensee found that the timers
were setup for a low trigger signal and they had actuated
prematurely/spuriously on existing circuitry noise.
The licensee made changes to the procedure for the timers to measure
relay contact position, and Revision 23 was issued. On September 16,
1997, the inspectors reviewed,. observed, and discussed the revised
procedure with licensee personnel. The inspectors attended the pre-job
briefing, observed the installation of the digital timers across the ACB
control relays, and observed operator activities.
The inspectors observed portions of the test up to Section 12.6. To Test
Keowee Emergency Start From Unit 3 Cable Room, Subsection 12.6.6. Test
of Channel B. During the performance of this subsection the inspectors
observed a large amount of smoke coming from the KHU-2 generator field
breaker cubicle. KHU-2 was tripped off the line and the breaker was
racked out from the cubicle. Although a large amount of smoke was
present from the field breaker closing coil, no visible flames were
observed. The test was terminated and KHU-2 was declared inoperable.
PIP K-97-2983 and a FIP team were initiated.
The field breaker was exchanged with a breaker obtained from the
warehouse and bench tested satisfactorily. KHU-2 was subsequently
returned to operable status. Additional comments and details on this
item are in Sections M1.2 and E2.1 of this report.
c. Conclusions
For the completed parts of the tests, the inspectors concluded that:
they were performed in accordance with both revisions of the procedure
the pre-job briefings were thorough and well conducted: the participants
demonstrated a questioning attitude concerning operability tests of the
underground path and the ACB timers; the operator actions taken when
smoke was observed were appropriate; operations maintenance of KHU
operability status was appropriate; and management and engineering
Enclosure 2
25
oversight were present. Theactions taken to verify the function of the
ACB re ays were good.
M1.7 Leak Repair of Valve 2LP-1
a. Inspection Scope (62707.37551)
On August 29, 1997, operators detected increased RB unidentified
leakage. As indicated in IR 50-269.270,287/97-12, a RB entry identified
leakage from valve 2LP-1, the LPI suction line isolation valve. The
inspectors observed activities associated with repair of valve 2LP-1.
b. Observations and Findings
The inspectors documented in IR 50-269.270.287/97-12, engineering
activities involved with temporary site modification TSM-1376 and PIP 2
97-2736. The modification was initiated to stop a pressure seal leak on
valve 2LP-1. The inspectors continued to observe, review, and discuss
the modification with licensee personnel. The inspectors also attended
meetings at which TSM-1376 was discussed.
The valve and plant were maintained above cold shutdown for seal
injection repair of the valve. Additionally, the valve had to be
maintained operable throughout the repair; it was opened and maintained
open until post repair stroke tests. The inspectors were informed and
observed that the leakage from valve 2LP-1 had reduced significantly
when the Unit 2 temperature and pressure were lowered from hot shutdown.
The licensee had wanted to initially maintain valve temperature above
250 degrees F for injection sealant reaction purposes. However, the
leakage from the valve resulted in the temperature of the valve falling
below 200 degrees F.
The originally selected sealing compound, referred to as Deacon 800T-N.
had a temperature range of 200 to 900 degrees F with a reaction
temperature of 250 degrees F. The inspectors attended a management
meeting held on September 7, 1997, at which the use of a different
sealing compound.was approved.
The new sealant. referred to as Deacon
400R-N, has a range of 50 to 400 degrees F and reacted with water.
The change in the sealant affected documents previously approved.
Accordingly, the inspectors reviewed the following documents:
Procedure TN/2/A/1376/TSM/00M, Installation of Temporary
Modification TSM-1376;
10 CFR 50.59 evaluation screening for change to TSM-1376 procedure
TN/2/A/1376/TSM/OOM:
Procedure MP/0/A/1800/016, System Leakage Repairs Using Vendor
Enclosure 2
SII
26
Injection Method; and
Work Order 97076613, Leak Repair Bonnet Leak 2LP-1.
The inspectors made the following observations:
the initial measurements at the valve to identify the location of
the four holes to be drilled;
the accounting for such items as drill bits, punches, pneumatic
drills, taps, parts, hand tools, etc., taken into the work area;
coverage of the overall activities by the health physics
personnel;
drilling by hand, tapping, and the installation of the
shutoff/vent valves;
the oversight by maintenance supervision and engineering: and
the final drilling into the valve cavity.
The inspectors noted that those measurements taken by the vendor
personnel for the hole location, the depth of the drilling, and the
shutoff valve thread engagements were accomplished using adequate depth
gauges and calipers. The inspectors also noted that the vendor
personnel consistently used second party verifications for all
measurements.
The inspectors also observed that when the final drilling was in
progress, and the valve cavity was breached, water would come out around
the drill bit. The vendor personnel would immediately remove the drill
bit and close the shutoff/vent valve. This action kept the amount of
additional leakage to a minimum.
A total of 11 cubic inches of the sealing compound, was injected into
the valve, to stop the leak. During the unit startup. the valve was
visually checked for leakage at 500 psig intervals increasing pressure.
No leakage was identified. The temperature of the valve body was
monitored at rated RCS temperature and pressure and indicated 98 degrees
F.
The inspectors discussed the cure-time required for the type Deacon
400R-N sealing compound. The licensee personnel were not aware of the
required cure time for the material. The vendor personnel were able to
identify the cure time as four hours.
The sealant sat for greater than
six hours with no valve operation and the plant at a constant
temperature and pressure. The valve was satisfactorily stroke tested
after the six-hour period.
Enclosure 2
27
The inspectors concluded that the temporary modification was installed
using approved procedures with maintenance supervisory and engineering
oversig t. The inspectors considered the activities performed by the
vendor personnel performing the drilling and injection activities as
excellent.
The inspectors also concluded that the following two items
were not fully addressed by the licensee prior to the modification
activities:
At the management meetings the possibility of the valve cooling
down to a temperature less than 250 degrees F was only briefly
discussed. Had this item been addressed further, plans for an
alternate sealing compound could have been pre-approved.
The cure-time for the type Deacon 400 R-N compound was not
captured in the revised modification package.
These two items did not affect the final installation of the minor
modification.
The inspectors considered the items as minor weaknesses
in the modification activities associated with the 2LP-1 valve leak
repair. The licensee had indicated that cure times would be captured in
associated repair documentation (PIP 97-2736).
c. Conclusions
Increased leakage from the 2LP-1 valve's body to bonnet joint resulted
in a plant shutdown to allow for a satisfactory seal injection repair.
The licensee applied appropriate operational experience review and met
current NRC guidance during the repair effort.
Operational controls
during the period were good. Final repair will occur at the next
refueling or fuel off load.
M1.8 Upper Surge Tank (UST) Inspections
a. Inspection Scope (62707)
IR 50-269.270,287/97-05. Section E1.1, discussed inspections of the Unit
3 USTs 3A and 3B. A NRC violation was issued for inadequate weld
inspection. This period, the licensee continued with the Unit 1 UST
outage inspections (Minor Modification OE-9270, VN 9270B) with the
inspector accompanying quality control (QC)
and engineering personnel
for observations at the job site.
b. Observations and Findings
The work instruction (TN/1/A/9270/MM/01C)
provided clear guidance on the
overall job scope. During the initial job walk down with QC, the QC
inspector pointed out that the stiffener welds made by the original N
stamp vendor were not clearly T by T welds and asked for clarification
on acceptance criteria on those welds. Engineering provided a package
Enclosure 2
28
change prior to inspection and repair commencement.
The tanks looked to
be in reasonably good shape. without major stress or deterioration
indications.
Prior to work commencement, the inspectors observed that wood had been
used inside of the USTs for a scaffold and drain port cover. It was
treated for fire protection, but did not have plastic sheathing for the
prevention of wood debris spread. Procedure NSD 104 indicated that wood
used in such applications "should" be covered with plastic for foreign
material exclusion (FME) purposes. Section M3.1 of this report
addresses FME weaknesses such as this example. Prior to commencement of
the work, the licensee covered the wood with plastic.
c. Conclusions
The UST work was well-engineered with good technical work control.
Overall, initial tank condition was good. Use of uncovered wood in the
tanks with minimal foreign material control was an example of foreign
material process weakness that the licensee addressed prior to work
performance.
M1.9 lA1 Reactor Coolant Pump Removal
a. Inspection Scope (62707)
As discussed previously, the 1A1 RCP had mechanical problems that
required it to be taken out of service and ultimately replaced.
During
its removal from the RCS, the inspectors observed pump body to casing
fastener destructive removal, the actual lifting of the pump out of its
casing, and the placement of the pump into its handling stand for
inspection and root cause failure determination.
b. Observations and Findings
The observed work was performed in a careful and methodical manner.
Particularly, the preparation for and the actual lift of the pump from
the volute were performed in a professional manner. Prior to the lift,
the crew careful y vacuumed the crack area between the pump casing and
top of the pump package to positively prevent material from entering the
soon-to-be-opened RCS. Health physics worked closely with the crew in
limiting dose and maintaining conditions safe for work.
One vane of the pump's impeller was missing approximately six inches of
the outside edge that was roughly triangular in shape.
The apparent
height of the missing piece was about three inches. The piece appeared
to have been mostly eroded away, but there were possible indications of
abrupt breakage on some of the uneven edges. Five of the seven vanes
showed through wall wear, possibly due to cavitation. The licensee was
to provide an evaluation of the failure outside of the inspection
Enclosure 2
0II
29
period. with an independent evaluation provided by the pump vendor.
Additionally, the licensee had planned future inspections of the second
pump (1A2) in that same loop and the other two pumps in the B loop. The
1icensee was scheduling additional inspections of the RCS and vessel for
vane debris.
c. Conclusion
The licensee provided excellent work control in the lifting and removal
of the 1A1 reactor coolant pump with health physics personnel providing
positive support. The pump's impeller was missing part of one vane and
exhibited what appeared to be cavitation damage on other vanes. A
licensee evaluation was in progress.
M1.10 Modification to Replace Valves and Associated Piping in the Unit 1 HPI
System
a. Inspection Scope (73753)
The inspector determined the adequacy of work activities in regards to
the replacement of certain stop and check valves along with small bore
piping in the HPI system:
b. Observations and Findings
Background
Nuclear Station Modification ON-12975 was issued to control the work for
replacing the existing HPI valves 1HP-126, 1HP-127. 1HP-152 and 1HP-153
with new angle check valves. 2 V,-inch diameter. In addition, the
licensee wi l add two 2 V2-inch diameter globe valves to each line for
isolation purposes. The replacement check valves include two one-inch
drain valves on the downstream side of the seating surface to allow for
leak testing. This modification was initiated to replace the subject
valves which performed poorly due to corrosion related problems and for
improvement of performance. Following installation and testing, the new
valves will be closed and used as the isolation valves to prevent RCS
backflow into the HPI system.
Procedure TN/1/A/12975/0/AMI was issued to provide instructions and
documentation for the work activities performed. The modification was
being performed under the American Society of Mechanical Engineers
(ASME) Code Section XI. 1989 Edition. Repair and Replacement IWA-4000.
Weld fabrication inspection and testing were controlled by American
National Standards Institute (ANSI) B31.7, 1968 Edition. Piping was
being replaced up to the safe ends, however, the safe ends and their
function were not affected by the subject modification. The safe ends
were scheduled for visual examination from the pipe internal diameter to
determine their condition. The valves, piping, fittings and
Enclosure 2
30
support/restraints were classified, QA-1 condition. Post-modification
pressure testing of replacement components was scheduled to be done
under Procedure MP/O/A/1720/016.
At the time of this inspection (September 29 - October 2, 1997) the
licensee had completed the welding and nondestructive examinations of
the subassemblies which included the replacement valves and associated
piping. Installation had been delayed until the primary system could be
drained down to the required level.
Observation
As such, the inspector inspected completed subassembly welds to verify
compliance with the above-mentioned code, quality of workmanship and
appearance. In addition, the inspector reviewed quality records for
replacement components, filler metal used and welder performance
qualification. As required by the controlling codes, completed welds
were radiographed to satisfy construction code and preservice inspection
requirements. The applicable radiographic procedures for this
evaluation were NDE-10A, Revision 19 and 12A. Revision 9. The welds
were shot once, in accordance with Procedure NDE-10A, Rev. 19. however,
they were reviewed to the acceptance standards of both procedures to
satisfy construction code and ASME Code Section XI preservice inspection
requirements. Radiographs for the following welds were reviewed to
verify compliance with applicable requirements.
- eld
Size (inches)
Component
Results
1-RC-201-92
2.5 x 0.375
Valve to Pipe
No
rejectable
indications
(NRI)
1-HP-282-90
4.0 x 0.531
Valve to Pipe
NRI
1-RC-201-91
2.5 x 0.375
Valve to Pipe
NRI
1-RC-200-166
2.5 x 0.375
Valve to Pipe
NRI
1-RC-200-160
2.5 x 0.375
Valve to Pipe
NRI
1-RC-199-150
2.5 x 0.375
Valve to Pipe
NRI
1-RC-199-149
2.5 x 0.375
Valve to Pipe
NRI
By this review, the inspector ascertained that film and radiographic
qualities met the applicable code requirements. The licensee's reviews,
interpretation and documentation of film artifacts and weld indications
Enclosure 2
31
were accurate and.fully documented.
c. Conclusion
A nuclear station modification (NSM)
to replace certain valves and
associated piping in the HPI system was being performed following
applicable code requirements. Prefabricated subassemblies exhibited
good workmanship attributes and material records were retrievable and in
order. Nondestructive examinations met applicable code requirements;
they were performed and the results interpreted in a conservative
manner.
M1.11 Modification to Replace LPSW Valves and Associated Piping (Unit 1)
a. Inspection Scope (62700.55050)
The inspector determined by observation, document review and discussions
with technical personnel, the adequacy of work activities relative to
this modification.
b. Observation and Findings
Backoround
Modifications to the LPSW system to improve system operability and
reliability were in progress at the time of this inspection, September
29 - October 2, 1997.
The modifications were identified as NSM ON
12977, 13001 Part AM2 and 13022. The inspector reviewed the subject
modification packages and held discussions with the cognizant engineers
to gain a better understanding of corrective actions taken and
improvements in plant operabi ity to be achieved by this work effort.
Following is a synopsis of objectives to be achieved by each of the
above modifications.
NSM-12977 Part AMI:
The purpose of this modification was to replace the LPI cooler shell
outlet valves (1LPSW-4 and 5), the RCP inlet isolation valve (1LPSW-6)
and RCP outlet isolation valve (1LPSW-15).
These valves were made from
carbon steel (CS) material which has exhibited rapid degradation in the
service water environment. Valves 1LPSW-4 and 5 will be replaced with
stainless steel (SS) ball valves which are designed to throttle flow
during accident conditions. Two vent valves (1LPSW-947 and 948) were
planned to be added upstream of 1LPSW-4 and 5 to facilitate routine
system testing.
Valves 1LPSW-6 and 15 have internal parts made of
carbon steel material and the licensee planned to rep ace them with full
port SS ball valves with containment isolation valve shutoff
characteristics.
The licensee also intends to replace check valves
1LPSW-75 and 76, located down stream of 1LPSW-4 and 5 respectively,
Enclosure 2
0II
32
because they do not serve a design basis or operational purpose and
their removal will improve system reliability.
NSM-13001. Part AM2:
This modification addresses the installation of minimum flow piping,
valves around each LPSW pump and associated components to assure minimum
flow after engineered safeguards (ES) signals had been removed from
valves 1LPSW-4 and 5. In addition, this modification along with other
LPSW system changes should ensure adequate net positive suction head is
available at the LPSW pumps during all design basis conditions.
The
licensee had determined that this portion of the LPSW system was
required for the mitigation of a design basis accident and therefore, it
had been designated safety-related. As such. all piping and components
were designated QA-1 condition. Instrumentation that maintained LPSW
system pressure boundary were also designated QA-1 condition. The
replacement pipe and associated components come under Duke Class F
category and therefore will be inspected in accordance with ASME Code
Section XI Subsection IWD requirements.
NSM-13022, Rev. 0 Part AM1:
This modification was developed to reduce flow induced cavitation and
vibration in the LPSW system at the LPI cooler flow control valves
(1LPSW-251 and 252).
The modification relocates and replaces the
subject valves to correct the problem.
In addition. manual isolation butterfly valves (1LPSW-254 and 256).
directly downstream from the subject flow control valves. have
experienced significant degradation and are planned to be replaced with
alike valves made from SS material. A failure associated with the iLPI
cooler train, ultimately caused the LPSW system to be designated as a
Maintenance Rule Al system.
All subject valves in this NSM were identified as Duke Class F category
and therefore were QA-1 condition. The Unit 1 LPSW system isolation for
this NSM were bounded by the installation of wet taps/Marbo Plugs
downstream of isolation valves lLPSW-254 and 256. The bulk of the work
involved in this NSM was located in the auxiliary and turbine buildings.
Installation of the wet taps was performed under Minor Modification
ONOE-10447. This modification called for the installation of a 14-inch
diameter wet tap on the LPSW non-essential header and a 36-inch diameter
wet tap on to the LPSW A header. This work was performed under
procedure TN/1/A/10447/MM/AM1. The controlling code of this activity
was ANSI B31.1, 1968 Edition.
Enclosure 2
0I
33
Observation
The inspector performed a walk through inspection to observe completed
work and work in progress. Line installation, weld appearance and
workmanship were satisfactory. Quality records for replacement
components were reviewed and determined to be satisfactory.
c. Conclusion
LPSW system modifications to replace certain valves and LPSW pump
minimum flow lines were well planned. Valve and pipe replacements were
being installed consistent with applicable code requirements and quality
criteria
M1.12 Inservice Inspection of Safety-Related Welds (Unit 1)
a. Inspection Scope (73753)
Through work observation, procedure and records review, the inspector
determined the adequacy of inservice inspection activities during the
present refueling outage.
b. Observations and Findings
The inspector observed surface and volumetric examination on two welds
of the core flood system.
The subject welds were identified as
follows:
Item
Weld No.
Description
Results
B09.011.089
1-53A-02-68L
Pipe to Valve
Root condition..
verified by RT
B09.011.091
1-53A-02-50L
Ell to Pipe
Root condition.
verified by RT
The ultrasonic examination was performed with Procedure NDE-600 which
complied with the requirements of ASME Code Section XI. 1989 Edition and
had been reviewed and approved by the Authorized Nuclear Inspector (ANI)
and the licensee's Level III examiner. The examination was performed by
well trained personnel in a conservative manner such as reviewing
previously shot radiographs and using supplementary transducers to
further investigate apparent indications. The surface examination
(i.e., liquid penetrant on the subject welds) was performed with
procedure NDE-35 which complied with applicable code requirements. The
examination was performed in a satisfactory manner by well trained
personnel.
Results of this examination showed both welds to be free of
rejectable indications. A review of inspection records and
Enclosure 2
34
certifications for materials used, equipment and personnel were
satisfactory.
c. Conclusion
Volumetric inservice inspection of designated welds was performed
satisfactorily by qualified and well trained personnel following
approved nondestructive examination procedures.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Reactor Building Coatings
a. Inspection Scope (71707)
As indicated in Inspection Report 50-269.270.287/96-20, Reactor Building
(RB)
coatings were not in optimal condition requiring an evaluation for
each of the three RBs.
Just prior to the September 18. 1997, Unit 1
outage start, the inspectors pointed out that the peeling paint in the
overhead of the Unit 1 RB may pose problems during the refueling phase
of the outage.
b. Observations and Findings
During the inspection documented in JR 50-269,270.287/96-20. the
residents encountered a number of conditions that required technical
evaluation by the licensee. Tape. loose paint, and insulation without
supporting documentation were found in significant quantities in various
locations in all the units' RBs.
Following the recent Unit 1 shutdown, the license installed a tent over
the refueling cavity and reactor vessel area. The need to protect from
foreign material entry was recognized in PIP 97-1971, as implemented by
WO 97-084586 and TM 1380. During routine inspector RB tours, the tent
was effective in keeping falling paint from entering the RCS and
attendant support systems.
As emergent work, the licensee planned to attempt inspection and re
coating of the peeling paint on the polar crane and the building spray
framework and supports this outage. Late in the inspection period, a
vendor estimating the job discovered asbestos in the zinc undercoat that
may postpone the job. Remaining loose coating material will be
evaluated prior to closeout of the Unit 1 RB.
The licensee planned to implement new procedure MP/0/B/3005/012.
Containment Inspections/Close Out Procedure, at the end of outage.
This
is a result of a previous NRC Violation (IR 50-269,270,287/96-20).
If
properly implemented. the procedure should provide adequate assurance
that the RB will be in good condition prior to power operations.
Enclosure 2
35
c. Conclusions
To reduce the likelihood of peeling polar crane and extensive hanger
paint intrusion into refueling activities, the licensee installed a
protective foreign material tent over the refueling cavity.
This was
installed prior to opening the RCS and commencing fuel off-load.
M3
Maintenance Procedures and Documentation
M3.1
Weakness in the Procedure for Foreign Material Exclusion (FME)
a. Inspection Scope (62707)
During the inspection period, the inspectors identified a weakness in
the procedural controls for FME with several examples.
b. Observations and Findings
On October 7. 1997. the inspector entered the RB to observe refueling
activities. Prior to entry into the refueling canal area, the inspector
observed the canal FME monitor in a location that precluded direct
observation of the canal/FME zone. While in the canal FME area. the
inspector observed a flashlight without a lanyard being used by licensee
personnel over the canal FME zone. Upon exiting the canal FME zone the
inspector observed another individual. a different canal FME monitor.
reading a magazine. Site management was informed. While touring the
RB. the inspector identified that piping work above the emergency sump
had resulted in a large amount of grinding debris in and around the
emergency sump area. The RB coordinator was informed. The RB
coordinator had already taken note of the area and notified maintenance
for cleanup. In each of the above cases, no specific licensee procedure
was violated.
During the Unit 1 outage, the emergency feedwater (EFW)
recirculation
valve and the turbine driven emergency feedwater (TDEFW)
pump were
disassembled. During inspector tours of the areas, the recirculation
valve and the TDEFW pump were observed to have minimal FME coverage, in
that plastic bags were draped over the openings and parts were laid out
without covers or organization. As discussed in Section M1.8 of this
report, the upper surge tank was entered for observation of welds and
the inspector noted that the wood cover for the opening to the
condensate system was not covered with plastic. After questioning the
responsible engineer, the wood and the area were covered in plastic to
prevent foreign material intrusion into the system.
On October 16, 1997. during work in the spent fuel pool, a vendor.
dropped a 3/16 inch allen wrench into the spent fuel pool.
An
Enclosure 2
36
underwater camera was used to locate the wrench on the bottom of the
spent fuel pool underneath the fuel racks. This has been evaluated to
pose no future problem with fuel movement. The wrench did have a
lanyard attached, but the lanyard was not sufficient to prevent the tool
from falling into the spent fuel pool.
The inspector discussed these observations with radiation protection and
maintenance management. Personnel involved in the issues addressed
above were re-instructed in management's expectations for the canal FME
duties. Additionally, areas were covered and tools and parts were
removed or covered as appropriate. As discussed in Section E1.1. the
EFW recirculation valves have had three failures due to foreign material
entry. The EFW system takes suction on the condenser hot well, which is
difficult to maintain clean. These failures cannot be directly
attributed to recent FME program observations. No events have been
identified that are attributable to recent FME problems.
c. Conclusions
The inspectors identified a weakness in the FME program based on
multiple examples of poor FME practices.
M8
Miscellaneous Maintenance Issues
M8.1 Evaluation of Maintenance Procedure for DB-25 Circuit Breakers
a. Inspection Scope (92902)
The inspectors reviewed the results of the AIT NRC Inspection Report 50
269.270.287/97-11. Section M1.2. for possible NRC enforcement action
related to adequacy of the licensee's maintenance procedure for the DB
25 circuit breaker to the recommendations in the manufacturer's
instruction manual. The licensee's maintenance procedure was contained
in Procedure IP/O/A/2001/003B. Inspection and Maintenance of DB-50. DB
25 and DBF-16 Air Circuit Breakers, dated July 23. 1996. The
manufacturer's recommendations were contained in Westinghouse Electric
Corporation Publication I.B. 33-850-1 and 2E. Instructions for De-ion
Air Circuit Breakers Types DB-15, DB-25, DB-F and DBL-25. 600 Volts AC,
250 Volts DC, which became effective May 1965.
b. Observations and Findings
As documented in the AIT report, as of June 20, 1997, Procedure
IP/O/A/2001/003B did not contain a recommendation from Westinghouse
Publication I.B. 33-850-1 and 2E to "Check for over-adjustment [of
contacts] by manually pulling the moving contact away from the
stationary contact, with the breaker in the closed position. It
should
be possible to obtain at least 1/64-inch gap between the contacts."
Enclosure 2
37
This step was not in the Oconee
rocedure for DB-25 circuit breakers.
The inspectors determined that this over adjustment could result in an
inadvertent "trip free" condition for the breaker. This missing step
resulted in a June 20. 1997. KHU DB-25 field flash breaker failure
mechanism not being initially evaluated. Subsequent performance of this
step on July 17. 1997, resulted in the verification of adequate
adjustment. Failure to maintain the station in accordance with approved
maintenance procedures with appropriate instructions is a violation of
TS 6.4.1 and is identified as VIO 50-269.270.287/97-14-04: Failure to
Implement Vendor Recommendation for DB-25 Circuit Breakers.
c. Conclusions
The inspectors identified a violation for a failure to translate
information from a Westinghouse technical manual to the licensee's
maintenance procedure for the DB-25 circuit breakers.
M8.2 ACB Timer Calibration
a. Inspection Scope (92902)
The inspectors reviewed the results of the NRC AIT Inspection Report 50
269.270.287/97-11. Section M1.1, for possible NRC enforcement action
related to calibration of the timers for the Y coil in each closing
control circuit for ACBs 5, 6. 7. and 8. The procedure used for these
calibrations was Procedure IP/0/A/2001/003B. Inspection and Maintenance
for DB-50. DB-25. and DBF-16. Air Circuit Breakers, Revision 4.
b. Observations and Findings
As documented in the AIT report on June 26. 1997, the licensee
determined that in the past. the technicians performing the timer
calibrations were hooking up their test equipment in such a manner that
the measured time delay included normal breaker travel time along with
the Y timer delay as opposed to just the Y timer delay. This was
because the calibration procedures lacked detailed guidance.
The
licensee issued work orders to check the timer settings and breaker low
voltage operation to ensure that the Y coil timers in all DB-50 breakers
were adjusted properly and that the breakers were currently operable.
Also, the AIT report stated that since all timers checked following the
June 23. 1997, event were found with settings well below the required
set point, past operability of the Keowee DB-50 breakers was
questionable. Licensee low voltage testing revealed that all were
operable, except ACB-6. The breaker was subsequently determined to have
been operable. For procedure corrective action, the.licensee updated
the timer preventive maintenance procedure to include specific details
to ensure that the timer set points were calibrated properly.
Failure
to rovide IP/O/A/2001/003B with appropriate instructions is a violation
of TS 6.4.1. This non-repetitive, licensee-identified, and corrected
Enclosure 2
38
violation is being treated as a Non-Cited Violation (NCV).
consistent
with Section VII.B.1 of the NRC Enforcement Policy.
This is identified
as NCV 50-269,270,287/97-14-05: Failure to Provide Appropriate
Instructions for Calibrating Y Coil Timers in DB-50 Breakers.
c. Conclusion
The inspectors identified a non-cited violation for a failure to provide
detailed guidance in the preventive maintenance procedure for measuring
the timer settings for the Y coil in DB-50 breakers.
- M8.3
(Closed) VIO 50-269,270.287/96-10-03: Weld Procedure Qualifications
Welded, Tested. Certified and Approved by Same Individual
The licensee's corrective actions on this violation were reviewed and
documented in NRC Inspection Report 269.279.287/97-12. That report
documented that although the licensee had taken appropriate actions to
address the concerns delineated in the violations, the inspector noted
that the revised controlling procedure (L-100) did not reference Duke's
QA topical Report, QA-1 which addressed 10 CFR 50. Appendix B and the
requirement for an independent QA review of welding procedure
qualification records. During the current inspection, the inspector
determined by review that the 1icensee had included by reference the QA
Topical in Revision 22 of the subject procedure. This item is closed.
M8.4 (Closed) VIO 50-269.270.287/96-17-09:
LPSW Modification Did Not Meet
ASME Code Section XI Nondestructive Examination Requirements
The licensee's corrective actions in response to this violation were
documented in NRC Inspection Report 269.270.287/97-12. paragraph M8.5.
The licensee's action plan for resolving identified problems, grouped
the activities into short and long term objectives. Work on the short
term objectives was to be implemented by the start of Unit 1 refueling
outage EOC 17. As such, during the current inspection the inspector
reviewed the status of the short term corrective actions and held .
discussions with cognizant personnel to obtain an update on this matter.
Through this work effort the inspector determined that essentially all
short term objectives had been achieved. The long term objectives
involved development of post-maintenance testing guidelines, procedures
and controls to prevent recurrence of similar type problems in this
area. Also, through this work effort the inspector concluded that the
licensee had taken sufficient actions to address the short term
objectives and was actively pursuing the long term objectives.
Because
of the actions taken and of those planned to address ownership and
controls in this area, this item is closed.
Enclosure 2
0II
39
III. Engineering
El
Conduct of Engineering
E1.1 EFW Automatic Recirculation Valve
a. Inspection Scope (61726)
Motor driven (EFW)
pump 3B failed its performance test because the
automatic recirculation valve failed to open. The inspectors reviewed
the circumstances surrounding this event.
b. Observations and Findings
On October 2. during Performance Test PT/3/A/0600/013.
Motor Driven
Emergency Feedwater Pump Test, automatic recirculation (ARC)
valve 3FDW
380 failed to pass recirculation flow as required. This resulted in
pump discharge pressure increasing to 1480 psig. Subsequent
investigation by the licensee revealed that a small portion of a rivet
lodged between the main disc and seat prevented the main disc from
closing: thereby, keeping the recirculation valve from opening.
Valve 3FDW-380, a Yarway 7100 Series ARC valve, has been designed to
operate as a combination check valve, flow sensor. and recirculation
control valve.
It has been designed for the main disc to open and close
in response to system flow and to control the recirculation portion of
the valve in order to maintain
ump discharge pressure below the pipe
design pressure of 1420 psig. The vendor has stated that debris as
smal
as 1/16 inch could prevent the main disc from closing and the
recirculation portion of this composite valve from opening.
Yarway 7100
Series ARC valves have been installed on the discharge of the motor
driven emergency feedwater pumps for all Oconee units. The turbine
driven EFW pumps have orifice plates.
The licensee determined from the site PIP database that foreign material
had also prevented a 7100 Series ARC recirculation valve from opening on
two previous occasions. On February 2. 1997. valve 1FDW-380 failed
during performance testing due to a piece of wood on the main seat.
Discharge pressure reached 1448 psig. On February 24. 1997, Valve 3FDW
380 also failed during performance testing. The licensee attributed the
failure to foreign material even though they were unable to find any.in
the seat (possibly moved during post event manipulation).
The licensee
documented three events in PIP Reports 1-097-0505, 3-097-0696, and 3
097-3285.
After the first failure, as documented in PIP Report 1-097-0505. system
engineering proposed to install a strainer in the main flow path for the
Enclosure 2
40
ARC valves. System engineering later rejected this proposal on the
grounds that it could introduce new failure modes for the system.
System engineering further stated that failure of the recirculation
valve to open did not affect the ability of the emergency feedwater
system to deliver the required flow to the steam generators, and that,
because the recirculation valve failures had only occurred during
testing at cold shutdown conditions/alignments, no failures were
expected during actual emergency conditions. After the first failure
the licensee indicated that foreign material intrusion would likely
occur again, but the risk was acceptable because the failures would
occur at cold shutdown while the system was not needed. System
engineering finally decided that strainers would be installed in the
recirculation pilot assembly of the ARC valves. These strainers have
not yet been installed.
After the third ARC failure, the residents held several discussions with
the licensee. After an emergency system start, the flow control valves
may throttle or cycle providing low or no flow from the EFW system to
maintain steam generator level.
During these instances, the
recirculation valve could fail throttled (recirculation portion not
open) and emergency feedwater pump discharge pressure could exceed 1420
psig (shutoff head) with the subsequent opening of the flow control
valve. The likelihood of failure while in emergency operation was
possible and not evaluated by the licensee for low decay heat conditions
or changes in suction source from the UST to the hot well (possible
primary debris containing volume). It was pointed out that operators
had no instrument indication of pump recirculation flow and had not been
procedurally directed to check or maintain EFW pressure less than 1420
psig. The licensee stated that exceeding 1420 psig for a small amount
of time would be acceptable under ANSI B31.1 for the piping. However.
the inspectors understood this was not acceptable as a permanent
solution for the piping. Pumps running at shutoff head fail within a.
short period and are not avai able again for emergency use. The
inspectors also understood that strainers in the recirculation pilot
assembly of the ARC valves would not correct the problem of foreign
material on the main seat preventing the recirculation portion of the
valve from opening.
The inspectors determined that, because of repeat failures, the lack of
corrective action constituted a violation of 10 CFR Part 50 Appendix B.
Criterion XVI. Accordingly, this is identified as VIO 50-269,287/97-14
06: Failure to Take EFW Recirculation Valve Corrective Action. This
appeared to be caused by the improper assessment that failure of the
recirculation valve to open would not affect the ability of the
emergency feedwater system to deliver the required flow during potential
debris induced failure. The inspectors understood that the valves had
been installed in 1994 and had no operational problems until the three
occurrences this current calendar year.
Enclosure 2
41
3590 on October 16. changed procedures, and took compensatory
actions/measures to lessen the possible challenges to the ARC valves and
the motor driven portion of the EFW system.
The PIP was modified
October 21 to indicate interim corrective actions.
c. Conclusions
The inspectors identified one violation in which improper assessment of
emergency feedwater valve operation resulted in a recurrence of a
previous component failure in the emergency feedwater system.
E1.2 Unqualified Thermal Insulation Found in the Reactor Buildings
a. Inspection Scope
The inspectors have been following the activities of the licensee
regarding URI 50-269.270.287/96-20-05, Past Operability of RB
Recirculation Flow Path.
In June, the licensee found additional
insulation in all three RBs (Inspection Report 50-269.270.287/97-10..
Section E1.1).
Recently, the licensee found additional, similar
insulation in nearly inaccessible regions of the Unit 1 RB.
Also, the
licensee had received testing results on the undesirable insulation from
a vendor.
The resident reviewed the information and viewed pictures of
the newly found insulation.
b. Observations and Findings
After the June discovery of additional insulation, the licensee had left
an open corrective action to look at all areas that could not be
reasonably inspected while at low power or with the plant thermally hot.
A recent licensee tour of Unit 1 revealed approximately 50 square feet
of additional unqualified or previously undesirable insulation.
These
insulation bats which were firmly attached to RCS piping were found
behind cages that cover the RCS piping where it enters the vessel shield
wall. The licensee did a limited inspection of Unit 3, which was also
shutdown and did not find any undesirable insulation at the same
locations as Unit 1.. Unit 2 was still at power with the open commitment
to be re-inspected.
In the recent past, the licensee had contracted with a vendor to test
the same undesirable insulation type to determine if it would cause
recirculation flow path problems. The NRC had deferred closure of the
URI until the evaluation was complete. The vendor determined that the
insulation would not float and therefore could not be transported to
In October 1997, the licensee had completed an operability calculation
on the insulation following testing of the insulation.
Testing which
had found.the undesirable insulation to sink readily was documented in
Enclosure 2
42
PIPs 1-097-1924, 2-097-1957. and 3-097-1950. The RB emergency sump was
found to be past and presently operable.
Failure to verify complete removal of all unqualified insulation for the
period of January 1997 until October 1997 from the RBs is a violation of
10 CFR 50, Appendix B, Criterion XVI and is identified as VIO 50
269,270.287/97-14-07: Inadequate Corrective Actions for Calculation of
Emergency Sump Operability. This was documented in PIP 0-097-1971 as an
operability evaluation performed with inaccurate input.
c. Conclusions
The failure to ensure complete removal of unqualified thermal insulation
from the reactor buildings was identified as a violation based on
inadequate corrective action.
E2
Engineering Support of Facilities and Equipment
E2.1 Keowee Emergency Start Test and Circuit Breaker Coil Failure
a. Inspection Scope (37551. 92903)
The inspectors observed and reviewed the engineering support activities
involved with the KHU emergency start test and a circuit breaker coil
overheating. Comments on the performance of the test and the
maintenance activities on the failed coil are in Sections M1.2 and M1.6
of this report.
b. Observations and Findings
On September 13 and 16, 1997. the inspectors observed the performance of
a test of the KHU emergency start logic system. Based on the previously
discussed test and equipment problems, the licensee initiated PIP K-097
2939 for the timers and FIP K-097-2983 for the overheating of the
breaker closing coil. The problem investigation indicated that the
relays involved with the timers functioned properly. This was based on
a visual observation and manual timing of the relays during a retest.
The failure investigation indicated that the overheating of the closing
coil for the field breaker involved the X relay. Y relay timer, and the
Y relay logic network. The test procedure required that the KHU
emergency start logic be tested for both Channels A and B from the
Oconee remote stations. These included the control rooms and the cable
rooms. The test also required that start signals be initiated while the
KHU were operating. Each start signal would activate the X relay, Y
relay timer, and Y relay logic. During a start signal initiation the Y
timer failed to time out. This resulted in closing current being
applied to the closing coil, through the X relay, continuously for
approximately 20 minutes: thereby causing the coil to overheat.
The Y
Enclosure 2
0II
43
relay timer and Y relay de-energized the X relay after 0.3 seconds of a
close signal.
The FIP group was able to identify and to duplicate the failure
mechanism of the Y timer. The group also interfaced with the vendor on
the failure. Based on the results of the groups' activities, the timers
on the generator field supply breakers and the field breakers were
changed out. The inspectors were informed that engineering would
examine the present breaker timer logic network for possible
modification.
c. Conclusions
The inspectors concluded that the engineering real-time support for the
KHU test was effective. The performance of the failure investigation
group in identifying the failure mechanism for the Y relay timer was
excellent. A review of the present timer logic network for possible
modification is considered an example of good safety attitudes.
E2.2 Testing of the Unit 3B RBCU Motor and Breaker
a.
Inspection Scope (37551)
The inspectors observed, reviewed, and discussed with licensee personnel
tests performed on the RBCU motors and breakers. The tests included a
Time Domain Reflectometry (TDR) test and a trip test of the 3B RBCU
motor supply breaker.
b. Observations and Findinos
The tests on the breakers were performed at the Quality Assurance
breaker testing facility. The criteria required that each of the three
phases of the breaker trip at 2400 amps to 3150 amps. Prior to the trip
test, breaker resistance readings in milli-ohms were taken from each
phase. The results indicated that the B phase had a higher resistance
compared to the other phases by a factor of three. The engineer
overseeing the activities indicated that there would be some reluctance
in reinstalling the breaker and using it. The trip test on phases A and
C indicated a trip of the removed breaker at approximately 2600 amps.
The test on phase B was terminated when the breaker still had not
tripped at 5230 amps. The engineer declared the removed breaker
defective. A new breaker was obtained, tested, and installed.
TDR tests were performed on various motors, such as Unit 1 RBCU motor IA
and all the Unit 3 RBCU motors. The tests included both the high and
low speed windings and were from phase to phase, as well as from phase
to ground. All of the tests were satisfactory.
Enclosure 2
44
c. Conclusions
Testing on the breakers was performed in accordance with an approved
procedure, by knowledgeable personnel, and with engineering oversight.
he inspectors considered the breaker testing activities by the
engineering, maintenance, and procurement quality assurance personnel to
be good.
E3
Engineering Procedures and Documentation
E3.1 Inadequate Engineering Analysis of Heavy Load Lifts Over the Borated
Water Storage Tank (BWST)
a. Inspection Scope (37551. 71707)
The inspector interviewed operations and engineering personnel on
operation of a large crane near the Unit 1 RB.
The inspector also
reviewed procedures and documentation associated with the crane testing.
b. Observations and Findings
On September 12. 1997, a 4100-series Manitowoc crane rated at 230 tons.
entered the protected area and was parked near the Unit 1 BWST. The BWST
is adjacent to an existing RB steam line and abuts the RB with a short
intervening section of LPI suction piping between them.
The inspectors
observed the crane in operation lifting materials to the top of the Unit
1 RB on September 15. 1997.
The lifts were being made over the BWST to
prevent lifting material over the steam lines. Due to plant layout.
choice of crane location was very limited. Unit 1 was not shutdown
until September 18, 1997. Therefore, lifts of heavy materials that
could have possibly impacted the BWST and affected the function of
safety-related equipment was made while the unit was still at power.
The inspectors questioned licensee personnel regarding an evaluation 'of
this evolution. The licensee provided the inspectors information
relating to crane qualifications and maintenance. A letter to file
describing this evolution for Unit 2 in 1990 was also included.
The
inspectors questioned whether this evolution had been re-evaluated for
the lifts while Unit 1 was still operating. The licensee initiated PIP
0-097-3044 to evaluate lifting over the BWST.
The licensee also
identified that there was a possibility of damage to an LPI line and
valve LP-28, which if damaged during certain system alignments, could
cause draining of the Spent Fuel Pool and lead to offsite dose
consequences.
MP/O/B/1710/015, Reactor Building Power Scaffold - Load and Functional
Test was used to load test the Reactor Building Power Scaffold (RBPS).
There was no procedure used to lift the composite pieces of the RBPS to
the top of the RB. These lifts were made over the BWST and the LPI line.
Enclosure 2
45
The BWST and 1LP-28 are safety-related components. NUREG 0612 requires
licensees to evaluate risk associated with heavy lifts over safety
related components. This item will be identified as VIO 50-269/97-14
08: Inadequate Engineering Evaluation for Lifts over Safety-Related
Components.
c. Conclusions
Failure t@ evaluate heavy load lifts over safety-related components
while Unit 1 was above cold shutdown conditions resulted in a violation.
E8
Miscellaneous Engineering Issues (92903, 90712)
E8.1 (Closed) URI 50-269.270.287/96-20-05: Past Operability of RB
Recirculation Flow Path
Based on the discussion in Section E1.2 this item is closed.
E8.2 (Closed) LER 50-269/93-01 (Revisions 1 and 2): Design Deficiency Results
in the Technical Inoperability of the Oconee Emergency Power Source Due
to a Postulated Failure of Keowee Hydro Units
The event date for this item was January 11. 1993.
The initial LER
(dated February 10, 1993) was closed in IR 50-269.270.287/93-20. based
on the actions taken by the licensee in 1993.
The initial issue of
concern was the lack of conservatism in the then existing Keowee
engineering calculations. Subsequent revisions (Revision 1 - dated
August 1, 1994 and Revision 2 - dted July 13. 1995) to the LER
addressed engineering issues that resulted from NRC inspections.
The
initial [ER and the revisions covered a time period of approximately two
and one-half years.
The initial and subsequent problems discussed in the LERs dealt with the
Keowee units potentially under different conditions, causing a loss of
generated power. As the primary issue developed, additional details
regarding engineering refinements were identified. Out of those issues
two violations of NRC requirements were identified.
The licensee
captured their engineering efforts in a series of PIPs indicated below.
During the review of this LER. the inspectors evaluated the following
related documents:
OP/O/A/2000/041, Keowee Modes of Operation, Revisions 8 through 16
Inspection Report 50-269.270.287/93-20
PIP 0-93-0041, Loss of Excitation When Keowee Load Rejects as a
Result of ES [Engineering Safeguards Actuation], dated January 11,
1993
Enclosure 2
46
PIP 0-94-0649, Keowee Units Supplying Above Normal Frequency
Following Load Rejection, dated May 16. 1994
PIP 5-95-0113, Keowee Power Limits Based on Non-Conservative
Calculation [Calculation OSC-6003], dated January 26, 1995
PIP 0-95-0330, Keowee Change OSC-6003 for Added Conservatism,
dated March 15, 1995
NRC Inspection Report 50-269,270,287/95-03 (violation 02.
Calculation Errors Associated with Keowee Output Limit)
NRC Inspection Report 50-269,270,287/95-06 (violation 01,
Inadequate Corrective Action for Control of Keowee Operating
Limits)
NRC Inspection Report 50-269,270,287/95-27 (violation closure)
0
NRC Inspection Report 50-269,270,287/96-12 (violation closure)
0
Selected Licensee Commitment 16.8. Subsection 16.8.4. Keowee
Operational Restrictions
Engineering Directives Manual Section 101.4.2.4, Assumptions
Engineering Directives Manual Section 101.4.3. Verification and
Certification
Engineering Directives Manual Section 101.4. Regulatory
Requirements
The culmination of the above resulted in documentation and procedures to
control Keowee generation during normal and emergency operation. Based
on the inspectors' reviews, the close out of the viol ations, and the
actions taken by the licensee, Revisions 1 and 2 of this LER are closed.
E8.3 (Closed) URI 50-269,270,287/97-02-07:
Non-Conservative Setting of the
LTOP Controls
This item was identified on February 25, 1997, when the licensee was
performing a review of the LTOP portion of the Improved Technical
Specification Conversion Project. The item concerned the setting of the
travel stops on the HP-120 valves. These valves are the normal make-up
valves to the RCS for all three units. The potential non-conservative
setting involved the HPI flow if operation of more than one HPI pump was
to occur during LTOP conditions. The item also concerned the
operability of LTOP flow paths. The licensee made a 10 CFR 50.72.
notification on April 17, 1997. After further analysis the notification
Enclosure 2
0II
47
was rescinded on June 16, 1997.
The inspectors reviewed the licensee's evaluation documented in PIPs 0
097-0710 and 5-097-1204. The PIPs stated, in part, the following:
the travel stops were adjusted for a flow of 70 to 80 gpm to limit
the amount of RCS coolant make up:
the setting is based on the operators having 10 minutes to correct
failed open HP-120 valves when LTOP controls are required:
an analysis, using the most restrictive data, indicated that the
maximum flow from two pumps operating, with a failed open valve,
would be less than the analyzed maximum allowable flow: and
the procedures used for adjusting the travel stops would be
changed to require both pumps to be in operation when the stops
are adjusted.
The inspectors reviewed Procedures OP/1. 2. and 3/A/1104/49. Low
Temperature Overpressure Protection, (Revision 6 for Unit 1 and Revision
7 for Units 2 and 3).
The inspectors observed that Enclosure 4.9. HP
120 Travel Stop Setup, of the procedures required that both HPI pumps be
in operation when adjusting the travel stops.
The inspectors also
observed that the 70 gpm adjustment was for a unit shutdown and the 80
gpm was for startup.
The inspectors concluded that the LTOP flow limitations would not have
been exceeded and the flow paths would have been operable. Based on
this review, this item is closed.
E8.4 Evaluation of Overvoltaoe Relay Set Point Chance
a. Inspection Scope (92903)
The inspectors reviewed the results of the NRC AIT Inspection Report 50
269.270,287/97-11, Section E1.2. for possible NRC enforcement action
related to a set point change made to an overvoltage relay in the
voltage regulator circuitry for the Keowee Hydro Units.
b. Observations and Findinas
As documented in the AIT report, a 53-31T relay set point was changed
outside the licensee's plant modification process. The change was made
via a calculation and calibration. The inspectors determined that the
set point change was basically a safety-related plant modification:
however, no post-modification test was specified or performed. This
post-modification testing omission resulted in an unanticipated relay
cycling phenomena created by the design change remaining Undetected
Enclosure 2
48
until June 1997. The reason that the relay was not working as intended
was that the KC-2023 calculation did not include all the relevant design
inputs. The design inputs not considered were that the 53-31T relay
would see low frequencies and the set point of the SV style relay varies
directly with frequency.
Failure to develop and implement the set point
change inside the Oconee design change process and without verifying the
design change adequacy is a violation of 10 CFR 50. Appendix B.
Criterion III and is identified as VIO 50-269.270.287/97-14-09:
Failure to Conduct Post-Mod Testing on Keowee Overvoltage Relay.
c. Conclusions
The inspectors identified a violation for a failure to implement a
modification inside the licensee's approved modification process,
resulting in the modification not receiving a post-modification test.
IV.
Plant Support Areas
R1
Radiological Protection and Chemistry Controls
R1.1 Tour of Radiological Protected Areas
a. Inspection Scope (83750)
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program as -required by 10 CFR Parts
20.1201. 1501. 1502. 1601. 1703, 1802. 1902. and 1904. The review
included observation of radiological rotection activities including
personnel monitoring controls, contro of radioactive material.
radiological surveys/postings, and radiation area/high radiation area
controls.
b. Observations and Findinqs
During tours of the auxiliary building and radioactive waste
storage/handling facilities, the inspectors reviewed survey data and
performed selected independent radiation and contamination surveys to
verify area postings. Observations and survey results determined the
licensee was effectively controlling and storing radioactive material.
During plant tours, the inspectors observed that Extra High Radiation
Areas (Locked High Radiation Areas) were locked as required by licensee
procedures and all other high radiation areas observed were
appropriately controlled as required by licensee procedures. Dosimetry
controls for these areas observed were also established in Radiation
Work Permits (RWPs) as required by licensee procedures.
A review of the licensee's records determined the licensee was
maintaining approximately 126,081 square feet (ft
2) of floor space as a
Radiologically Controlled Area (RCA).
Records reviewed also determined
Enclosure 2
0
49
the licensee maintained approximately 800 ft2 or less than 1 percent of
the RCA as contaminated area during non-outage periods.
During the
current outage period the licensee was maintaining approximately
6,000 ft2 as contaminated area.
The inspectors reviewed Personnel Contamination Event (PCE)
reports
prepared by the licensee to track, trend, determine root cause, and any
necessary follow up action forepersonnel contaminations.
The licensee
had continued efforts in 1997 to reduce personnel contaminations.
Approximately 154 PCEs had occurred in 1997. which was a significant
reduction from the previous two years. In 1997 the licensee was
averaging approximately 16 PCEs/month as compared to 35 PCEs/month in
1996 and 49 PCEs/month in 1995.
The inspectors reviewed and discussed
licensee efforts to reduce the percentage of personnel contaminations
occurring outside of posted contaminated areas.
The licensee had
executed some actions to reduce contamination from getting into clean
areas.
Based on several recently identified examples of personnel failing to
follow RWP requirements, the inspectors reviewed RWPs established for
working in or entering various plant areas. The RWPs were reviewed for
adequacy of the radiation protection requirements based on work scope,
location, and conditions.
For the RWPs reviewed, the inspector noted
that appropriate protective clothing and dosimetry were required.
During tours of the plant, the inspectors observed the adherence of
plant workers to the RWP requirements.
c. Conclusions
Based on observations and procedural reviews, the inspectors determined
the licensee was effectivey maintaining controls for personnel
monitoring, control of radioactive material. radiological postings, and
radiation area and high radiation area controls as required by
R1.2 Occupational Radiation Exposure Control Proaram
a. Inspection Scope (83750)
The inspectors reviewed the licensee's implementation of 10 CFR
20.1101(b) which requires that the licensee shall use, to the extent
practicable. procedures and engineering controls based upon sound
radiation protection principles to achieve occupational doses and doses
to members of the public that are as low as reasonably achievable
(ALARA).
Enclosure 2
50
b. Observations and Findings
The inspectors interviewed licensee personnel and reviewed records of
ALARA program results and activities.
The licensee demonstrated strong management support in the area of ALARA
as indicated by source term reduction efforts in the 3 units and by
establishing challenging exposure goals.
The licensee was effectively
tracking and trending dose rate reduction efforts in 1997 for outage and
non-outage tasks.
An effective Unit 1 chemical shutdown peroxide
crudburst had resulted in reactor building dose rate reductions of
approximately 3 millirem/hour.
This crudburst also resulted in reducing
steam generator tube sheet dose rate averages at the high contact survey
points by approximately 1.3 rem/hour. Exposure history s for all 3
units had continued to trend downward based on ALARA initiatives. The
licensee had established an annual exposure projection for 1997 of
approximately 204 person-rem or 68 person-rem/unit.
At the time of the
inspection, the licensee was tracking approximately 130.6 person-rem
year-to-date, which was below year-to-date estimates of 192.5 person
rem.
However, the licensee was approximately four days behind in the
Unit 1 End of Cycle (EOC)-17 refueling outage schedule and was
anticipating total person-rem to increase closer to estimates as the
outage progressed.
During tours of the facility, the inspectors attended pre-job briefings.
observed RP technicians controlling access to work areas. In addition
the inspectors observed RP technicians briefing workers in the work
areas as radiological conditions changed. Good use of shielding,
teledosimetry, remote cameras and wireless communications systems for
controlling personnel exposures during maintenance evolutions was
observed.
c. Conclusions
The inspectors determined licensee management demonstrated strong
support for ALARA and the licensee's programs for controlling exposures
ALARA were effective.
R1.3 Inadequate Radiation Protection Controls
a. Scope (71750)
The inspector used Inspection Procedure 71750 while touring to observe
RP practices ensuring compliance with regulations and licensee
procedures.
Enclosure 2
51
b.
Observations and Findinqs
On September 26, 1997. while touring the turbine floor area, the
inspector observed a contractor exiting a roped off radiation area (RA)
without electronic dosimetry. The area is above the control valves for
the Unit 1 turbine.
The Unit 1 turbine is considered a radioactive
materials area due to contamination.
The inspector notified the on
shift RP supervisor and met with the contractor and the RP supervisor to
determine the details.
The contractor stated that he had entered the RA from the ground floor
from a ladder to run an extension cord.
He then proceeded through the
RA to another ladder and exited on the turbine floor, crossing the RA
rope with the posting.
The RP supervisor stated that the lower ladder
should have been posted or removed.
He then left to notif RP
personnel/scaffolding personnel to either post or remove the lower
.
adder.
On October 1, 1997, the inspector observed another individual inside a
posted area also without electronic dosimetry directing crane movement.
The individual exited the area upon observing the inspector realizing he
did not have the proper dosimetry.
Appropriate RP personnel were
notified. RP stated the previous incident had been discussed with all
workers and they were aware of the need to wear proper dosimetry.
These two examples were identified as VIO 50-269,270.2871/97-14-10:
Inadequate Radiation Protection Posting and Controls.
c. Conclusions
A violation was identified, with two examples, for inadequate radiation
protection practices and controls which a lowed entry into a posted
radiation area without proper dosimetry.
R7
Quality Assurance in Radiological Protection and Chemistry Activities
R7.1 Quality Assurance in Radiation Protection and Chemistry
a. Inspection Scope (83750)
10 CFR 20.1101 requires that the licensee periodically review the RP
program content and implementation at least annually. Licensee periodic
reviews of the RP program were reviewed to determine the adequacy of
identification and corrective actions.
b. Observations and Findinas '
Reviews by the inspectors determined that Quality Assurance audits and
self-assessment efforts in the area of RP were accomplished by reviewing
Enclosure 2
52
RP procedures, observing work, reviewing industry documentation, and
performing plant walkdowns to include surveillance of work areas by
supervisors and technicians during normal work coverage. Documentation
of problems by licensee representatives was included in Quality
Assurance audits and self-assessment reports.
During the inspection, the inspectors reviewed the licensee's self
assessment processes for evaluating several licensee identified problems
in the area of radiation protection activities and determined that
corrective actions were included in PIPs and were being completed in a
timely manner.
c. Conclusions
The inspectors determined that the licensee was performing Quality
Assurance audits and effectively assessing the radiation protection
program as required by 10 CFR Part 20.1101.
The inspectors also
determined the licensee was completing corrective actions in a timely
manner.
Si
Conduct of Security and Safeguards Activities
S1.1 Observation of Security Staff
a. Inspection Scope (71750)
The inspector toured the Central Access Station (CAS), Secondary Access
Station (SAS).
Access Control Station (ACS).
and various patrol stations
to observe security personnel and operations.
b. Observations and Findings
The stations observed were well maintained. CAS and SAS alarm panels
and monitoring devices were maintained with clear view and few alarms.
Security personnel were attentive at all stations observed and were
prompt in acknowledging all alarms. The inspector completed a tour of
the Protected Area on night shift to verify ]ighting.
The PA lighting
was verified adequate. no problems or discrepancies noted.
Security
personnel were attentive to their stations. Lighting and equipment was
verified adequate and free of alarms.
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 October 22, 1997. The
licensee acknowledged the findings presented. No proprietary
information was identified to the inspectors.
Enclosure 2
0II
53
Partial List of Persons Contacted
Licensee
E. Burchfield, Regulatory Compliance Manager
T. Coutu. Scheduling Manager
D. Coyle, Mechanica] Systems Engineering Manager
T. Curtis, Operations Superintendent
B. Dobson, Mechanical/Civil Engineering Manager
W. Foster. Safety Assurance Manager
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Engineering Manager
W. McCollum, Vice President, Oconee Site
M. Nazar, Manager of Engineering
B. Peele, Station Manager
J. Smith, Regulatory Compliance
J. Twiggs, Manager,' Radiation Protection
Other licensee employees contacted during the inspection included technicians.
maintenance personne], and administrative personnel.
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Engineering
Onsite Engineering
Installation and Testing of Modifications
Effectiveness of Licensee Controls in Identifying and Preventing
Problems
Preparation for Refueling
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
Physical Security Program For Power Reactors
Protection of Safeguards Information
Occupational Exposure
LER Review
Onsite Follow up of Written Event Reports
Follow up - Plant Operations
Follow up - Maintenance
Follow up - Engineering
Follow up - Plant Support
Prompt Onsite Response to Events
Enclosure 2
54
Items Opened, Closed, and Discussed
Ooened
50-269/97-14-01
Failure to Follow LTOP Procedure (Section
03.1)
50-269,270.287/97-14-02
Failure to Adequately Implement Lee
Station Procedure (Section 08.4)
50-269.270,287/97-14-03
Failure to Provide Appropriate Lockout
Reset Instructions in ARG SA1/E-04
(Section 08.5)
50-269.270,287/97-14-04
Failure to Implement Vendor Recommendation
for DB-25 Circuit Breakers (Section M8.1)
50-269.270,287/97-14-05
Failure to Provide Appropriate
Instructions for Calibrating Y Coil Timers
in DB-50 Breakers (Section M8.2)
50-269.287/97-14-06
Failure to take EFW Recirculation Valve
Corrective Action (Section E1.1)
50-269,270.287/97-14-07
Inadequate Corrective Actions for
Calculation of Emergency Sump Operability
(Section E1.2)
50-269/97-14-08
Failure to Follow Procedure for Lifts Over
Safety Related Components (Section E3.1)
50-269.270,287/97-14-09
Failure to Conduct Post-Mod Testing on
Keowee Overvoltage Relay (Section E8.4)
50-269.270.287/97-14-10
Inadequate Radiation Protection Posting
and Controls (Section R1.3)
Closed
50-269,270,287/97-01-05
LPSW to RB Cooling Inoperability (Section
08.3)
50-269.270,287/96-17-09
LPSW Modification Did Not Meet ASME Code
Requirements (Section M8.4)
50-269,270,287/96-10-03
Weld Procedure Qualifications. Welded.
Tested. Certified and Approved by Same
Individual
(Section M8.3)
Enclosure 2
55
50-269,270,287/97-02-07
Non-conservative Setting of the LTOP
Controls (Section E8.3)
50-269/93-01, Revision 1 & 2 LER
Design Deficiency Results in the Technical
Inoperability of the Oconee Emergency
Power Source Due to a Postulated Failure
of Keowee Hydro Units (Section E8.2)
50-269.270.287/96-20-05
Past Operability of RB Recirculation Flow
Path (Section E8.1)
List of Acronyms
ACB
Air Circuit Breakers
ACS
Access Control Stations
Augmented Inspection Team
As Low As Reasonably Achievable
ANSI
American National Standard
American Society of Mechanical Engineers
Authorized Nuclear Inspector
Automatic Recirculation
Babcock and Wilcox
BWST
Borated Water Storage Tank
CALC
Calculation
Central Access Station
CIT
Continuous Improvement Team
CFR
Code of Federal Regulations
CR
Control Room
Carbon Steel
Direct Current
Electronic Dosimetry
Engineering Directive Manual
Emergency Feedwater
End of Cycle
Engineered Safeguards
F
Fahrenheit
Failure Investigation Process
Foreign Materia] Exclusion
Final Safety AnalysisReport
ft2
square feet
GPM
Gallons Per Minute
High Pressure Injection
Integrated Control System
IR
Inspection Report
Inservice Testing
KHU
Keowee Hydro Unit
KV
Kilo Volt
LER
Licensee Event Report
Enclosure 2
56
LCO
Limiting Condition for Operation
LOA
Lee Control Operator
LOB
Lee Assistant Control Operator
Low Pressure Injection
Low Pressure Service Water
Low Temperature Over Pressure
Milli-ohm
Resistance Measurement
MFB
Main Feeder Buses
Megawatts
Non-Cited Violation
Non-Licensed Operator
NRC
Nuclear Regulatory Commission
0AC
Operations Aid Computer
Personnel Contamination Events
Public Document Room
Problem Investigation Process
Preventive Maintenance
Plant Operating Review Committee
PRVS
Penetration Room Ventilation System
Pounds Per Square Inch Gauge
Physical Security Plan
Performance lest
Quality Assurance
Quality Control
Radiation Area
Reactor Building
- RBCU
Reactor Building Cooling Unit
Reactor Building Power caffold
Radiation Control Area
Reactor Coolant Pump
RCZ
Radiation Control Zone
REV
Revision
Radiation Protection
Radiation Work Permit
Systematic Assessment of Licensee Performance
Secondary Access Station
Safeguards Information
Selected Licensee Commitments
Self-Reading Pocket Dosimeter
Stainless Steel
SSF
Safe Shutdown Facility
Turbine Driven Emergency Feedwater
Time Domain Reflectometry
Thermoluminescent Dosimetry
TM
Training and Qualification Program
Enclosure 2
0anFee ue
57
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
UST
Upper Surge Tank
Violation
Work Order
Enclosure 2