ML15118A159
| ML15118A159 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/04/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A156 | List: |
| References | |
| 50-269-96-16, 50-270-96-16, 50-287-96-16, NUDOCS 9612170442 | |
| Download: ML15118A159 (37) | |
See also: IR 05000269/1996016
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:
50-269/96-16. 50-270/96-16. 50-287/96-16
Licensee:
Duke Power Company
Facility:
Oconee Nuclear Station, Units 1, 2 & 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
October 6, 1996 - November 16, 1996
Inspectors:
M. Scott, Senior Resident Inspector
G. Humphrey, Resident Inspector
N. Salgado, Resident Inspector
N. Economos. Reactor Inspector
R. Freudenberger, Senior Resident Inspector
D. Forbes. Reactor Inspector
R. Carroll, Project Engineer
R. Baldwin, Reactor Inspector
P. Kellogg, Reactor Inspector
Approved by:
L. D. Wert, Acting Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9612170442 961204
ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2 & 3
NRC Inspection Report 50-269/96-16,
50-270/96-16, 50-287/96-16
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six-week
period of resident inspection: in addition, it includes the results of
announced inspections by two regional safety inspectors, one visiting senior
resident, and one project engineer.
Operations
The Unit 1 shutdown and associated rod drop test was performed in
a professional and controlled manner. (Section 01.2)
Unit 2 midloop operation was well controlled and coordinated.
(Section 01.3)
The overall cold weather protection program was determined to be
adequate. (Section 01.4)
A Non-Licensed Operator was aggressive in the identification of a
discrepant condition on safety-related equipment. (Section 04.1)
0
Initial review of operator training associated with Integrated
Control System modifications indicated that the training was
adequate. An inspector followup item was identified to address
licensed operator qualification issues associated with the
modification.
Maintenance
Specific observed maintenance activities were generally performed
thoroughly and professionally. (Sections M1.1 and M1.2)
The licensee's welding instruction and field inspection programs
were appropriate. The licensee's efforts to identify and document
field conditions following the Unit 2 water hammer event were
commensurate with applicable code requirements and quality
standards, and reflected a conservative attitude. (Section M1.3)
Inservice Inspection examinations scheduled for this outage were
being performed as required by well trained personnel following
procedures written in compliance with applicable code
requirements. Personnel performing the inspections were well
qualified to execute their assigned tasks. Eddy current
examinations were consistent with Technical Specifications (TS)
4.17 requirements. Three tubes were identified in Steam Generator
"B"
with primary water stress corrosion cracking indications in
the roll transition region of the upper tubesheet. A decision had
not been reached on their disposition and/or repair at the end of
the inspection period. (Section M1.4)
2
Maintenance personnel, based on identified drawing discrepancies
with as-built configuration, installed blanks on the Unit 1 and
Unit 2 auxiliary building ventilation system vents supplying the
control battery rooms. Subsequently, it was determined that the
blanks adversely affected the Unit 1 and Unit 2 penetration room
ventilation system (PRVS) tests, and should not have been
installed. A violation was identified to address the failure of
Maintenance personnel to initiate a Problem Investigation Process
Report for problem evaluation when drawing discrepancies were
identified. (Section M4.1)
Maintenance personnel failed to implement the procedural
requirements for restoration of the Main Steam Safety Valves
(MSSV) by not ensuring spindle nut cotter pins were installed on
two Unit 3 MSSVs and improperly installing the cotter pins on four
Unit 2 MSSVs. These examples of poor Maintenance performance
could have led to entry into Emergency Operating Procedures and/or
loss of the steam generators as decay heat removal paths. An
apparent violation with two examples was identified. (Section
M4.2)
Engineering
The licensee's interim corrective actions with respect to a recent
main feedwater pump failure were adequate. (Section E1.1)
A violation was identified concerning an inadequate Letdown
Storage Tank (LDST) Level Calibration Procedure. (Section E8.1)
A non-cited violation was identified to address the inadvertent
removal of redundant power on the Unit 1 and Unit 3 LDST
instrumentation. (Section E1.2)
Plant Support
The licensee effectively implemented a program for shipping
radioactive materials and for classifying waste destined for
burial. (Section R1.1)
The licensee's water chemistry control program for monitoring
primary and secondary water quality had been implemented in
accordance with the TS requirements and the EPRI guidelines for
Pressurized Water Reactor water chemistry. (Section R1.2)
The licensee was maintaining a high level of operability for
radiation monitors in 1996. (Section R2.1)
The transportation training focused on good radiological control
work practices and compliance with transportation regulations.
(Section R5.1)
Enclosure 2
3.
The licensee had complied with the TS required program for
conducting audits of station activities. (Section R7.1)
A non-cited violation was identified for an inadequate procedure
in the Technical Support Center for terminating an Unusual Event.
(Section P3.1)
Enclosure 2
Summary of Plant Status
Report Details
On October 4, 1996, Unit 1 reduced power to fifteen percent and the main
turbine generator was taken offline. The unit remained at fifteen percent
power to provide steam for the shutdown of Unit 3. On October 9, 1996, the
unit was shutdown, and remained in that condition throughout the rest of the
reporting period (Section 01.2).
Unit 2 remained in cold shutdown for the entire reporting period. On October
17, 1996, the licensee entered midloop operation to replace a leaking cold leg
resistance temperature detector (RTD) (Section 01.3).
Unit 3 remained in a refueling mode throughout the entire reporting period.
Review of UFSAR Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and/or parameters.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general the conduct of
operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below.
01.2 Unit 1 Shutdown and Rod Drop Test
a. Inspection Scope
On October 9, 1996, the licensee reduced power on Unit 1 from
approximately 15 percent and subsequently tripped the unit. The
licensee manually tripped the unit to perform a rod drop test. The
licensee has a program to check the drop times and evaluate/replace
Control Rod Drive Mechanisms (CRDM) if times exceed a 1.40 second
administrative limit (TS limit is <1.66 seconds). The inspectors
observed the power reduction and the rod drop test.
b. Observations and Findings
The licensee held an effective pre-job briefing on the power reduction
and the rod drop test. Reactor engineers were present to support
performance of the test. Once the evolutions were understood, the
Operations staff cleared the Control Room (CR) of extraneous people and
readied the CR for the test.
2
During the power reduction, all control and parametric indications were
nominal. As power approached the trip test point as described in
procedure PT/1/A/600/15. Control Rod Movement, power reduction was
slowed and control board indications were carefully observed. After the
trip, Operations performed appropriate checks to ensure that all rods
were in the core and the reactor was shutdown.
Reactor engineers determined that the test was valid and that the rod
insertion times, while longer than previous testing times, were well
within the allowed TS limits. Nine of the rods did not drop into the
core in less than the allowed administrative limit. The administrative
limit is used by the licensee to ensure the TS limit is not exceeded.
Management determined that the nine CRDMs would require replacement. In
addition, based on its approach to the 1.40 second administrative drop
time limit, one additional CRDM would also be replaced. The replacement
actions were completed during this period.
c. Conclusions
The Unit 1 power reduction and rod drop test were effectively performed
in a professional and controlled manner.
01.3 Unit 2 Midloop Operation
a. Inspection Scope
The inspector reviewed the Unit 2 midloop operations as controlled by
procedure OP/2/A/1103/11, Draining And Nitrogen Purging Of Reactor
Coolant System.
b. Observations and Findings
During the Unit 2 forced outage, the licensee reduced Reactor Coolant
System (RCS) inventory and reached the midloop operations level on
October 17, 1996. Unit 2 was in midloop status for approximately
eighteen hours. Midloop conditions were required for the replacement of
the 2B1 cold leg RTD which was leaking. The inspectors reviewed the
licensee's controls prior to the reduction of RCS inventory and verified
that the requirements were met while operating at the reduced inventory
levels as specified in procedure OP/2/A/1103/11, Enclosure 3.6.
Requirements for Reducing Reactor Vessel Level to < 50" on LT-5. This
procedure stipulated the sequence and steps required for reduction of
RCS inventory and mid-loop operation. It further specified the
precautions and limitations to be adhered to while in midloop
operations.
The inspector verified that the requirement for two independent trains
of RCS level monitoring was met while at reduced inventory. This was
accomplished through the use of two permanently installed instruments
(LT-5A and LT-5B) and two temporary ultrasonic instruments. During the
Enclosure 2
3
approach to midloop, level reduction was properly delayed because of the
development of ultrasonic instrument problems. The licensee addressed
the problems appropriately. Level indications were displayed in the CR
on the LT-5A and LT-5B indicators, the Inadequate Core Cooling Monitor,
and on the Operator Aid Computer.
The inspector verified that two trains of core exit thermocouples were
available and utilized while at reduced inventory, as well as that the
two sources of inventory makeup and cooling were available for
operation. Multiple sources of offsite power were also available.
c. Conclusion
The licensee implemented and maintained the requirements specified by
procedure while accomplishing reduced inventory operations without
incident. The inspector concluded that the Unit 2 midloop operations
were well controlled and coordinated.
01.4 Cold Weather Preparations
a. Inspection Scope (71714)
The inspector reviewed the licensee's program to protect equipment and
systems against extreme cold weather conditions.
b.
Observations and Findings
The licensee's cold weather protection program was based on an
evaluation of plant equipment where conditions were such that freeze
protection was necessary. The evaluation included plant areas/equipment
that have experienced problems in the past. The more significant areas
included: (1)
the Borated Water Storage Tank (BWST) level indication,
(2)
the Elevated Water Storage Tank (EWST) level indication, and (3)
the
cooling water to the Condenser Circulating Water (CCW) pumps.
On November 15. 1996, the inspectors reviewed the status of heat trace
alarm panels on all three units. Two annunciators were found to be in
the alarm state. However, the affected heaters were not related to
freeze protection and both had been identified by the licensee for
corrective actions. Control room annunciation was periodically reviewed
by the inspectors during routine control room tours. Loss of cooling
water flow to the CCW pumps will actuate a CR alarm.
The inspector verified that freeze protection program actions were
initiated as required when Control Room Alarm, 1SA9B3, RBV Purge Inlet
Temp Low, annunciated indicating outside temperature had reached a low
of 40 degrees F. The program response required that various heaters be
reviewed for malfunctions and steam supplies be readied for use per
OP/0/A/1106/22. Auxiliary Steam System. A second control room alarm
annunciates when the outside temperature drops to 35 degrees F. The
Enclosure 2
4
requirements for that alarm are outlined in Enclosure 5.12, Cold Weather
Checklist, of OP/1/A/1102/20. Shift Turnover. This procedure checklist
specified various preventive measures to be implemented such as building
doors being closed, dampers being closed, heaters being turned on and
verified to be operating properly, proper cooling water flows to outside
equipment, trench covers in place, heat tracing operating properly, and
building heating systems in service. The inspectors toured areas of the
plant, observing damper and door status.
The inspectors reviewed and/or discussed with the licensee the
following:
-
The most recent Work Orders (WO) that were performed on heat
tracing for the BWST level indications [Unit 1, W091037141 (last
performed 2/12/96), Unit 2, W091037410 (last performed 6/5/95),
and Unit 3, W091037645 (last performed 6/12/96)]. These circuits
do not have alarms and a failed heat trace circuit would not be
detected by the operator during heat trace panel checks. However,
redundant level instrumentation is provided and is heat traced.
-
Site discrepancy reports (PIPs 2-96-0252, 0-96-2185, 0-96-2372,
and 0-96-0639) had been generated in reference to problems
experienced at Oconee Nuclear Station (ONS) and other industry
sites. A corporate audit was performed by Duke Power Company (DPC)
to formalize a freeze protection program for all three nuclear
sites. As a result of that audit, Problem Investigation Process
(PIP) report 0-096-0639 was generated to indicate areas that are
not consistent between the Duke facilities.
-
Liquid radiological waste building freeze.protection issues. The
liquid waste building has no steam heat and temporary space
heaters must be maintained to assure proper protection.
-
Procedure upgrades that are planned or being evaluated by site
management for implementation.
Based on the above, the inspectors noted that the licensee had initiated
enhancements in several programmatic areas. Specific changes are still
being pursued by the licensee under the corrective action program. The
inspectors verified that the BWST heat trace instrumentation was
calibrated on its last normal 18 month frequency. Procedures require
that the liquid radiological waste building is manually maintained above
freezing by appointed freeze protection personnel. Additional
programmatic improvements are scheduled in the licensee's corrective
action program.
Enclosure 2
c. Conclusions
The status of plant freeze protection equipment and program was
determined to be adequate. However, the program will be enhanced with
the implementation of actions that have been initiated by the licensee.
02
Operational Status of Facilities and Equipment
02.1 Engineered Safety Feature System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walkdown accessible
portions of the following safety-related systems:
Keowee Hydro Station
High Pressure Injection System
Main Steam System
Equipment operability, material condition, and overall housekeeping were
acceptable in all cases. Several minor discrepant conditions were noted
by the inspectors in the Units 1 and 2 Emergency Core Cooling System
(ECCS) pump areas. These were present after an extensive paintout
period in these areas. Examples of the found conditions were bent
instrument lines, taped covers on mechanical joints, and trash in open,
uncovered floor drains. The discrepancies were reported to the licensee.
04
Operator Knowledge and Performance
04.1 Unit 3 Reactor Building Purge System (71707)
On November 12, 1996, alarm 3SA-9, RBV Purge Inlet Temp Low, annunciated
on the Unit 3 Control Room panel. A Non-Licensed Operator (NLO) was
dispatched to the 3B Reactor Building Inlet Purge equipment area to
determine the cause for the alarm. The NLO completed the alarm response
requirements and found no problems. However, the operator noticed that
a damper indicator lever was not in the position that he had remembered
it during previous inspections of that equipment. He opened a duct
panel door and inspected the inside of the duct. As a result, the
operator identified that the inlet dampers had been damaged.
Subsequently, the purge system was shut down for repairs.
The inspectors noted that the NLO aggressively pursued the cause of the
alarm. The Auxiliary Steam system was experiencing problems at that
time and low steam pressure was the most likely suspect for the
annunciated condition since the heating steam was supplied from that
source. The NLO demonstrated excellent operational skills by
understanding the equipment and continuing to investigate the cause of
the problem.
Enclosure 2
6
05
Operator Training and Qualification
05.1 Operator Requalification Program (71001)
a. Inspection Scooe (71001)
During the period of November 12-15, 1996, the inspector used guidance
from Inspection Procedure 71001 to review and evaluate the licensee's
operator requalification program in the area of the Unit 3 Digital
Integrated Control System (ICS) modification training, start-up
training, lesson plan (system description) evaluation, examination
review, operator license disposition and procedural validation.
b. Observations and Findings:
The inspector observed two sessions of a start-up training lab on the
Unit 1 simulator with the Unit 3 digital ICS model installed. The
simulator training crews consisted of four operators. The inspector
observed two of the four operators performing start-up training using
the new digital ICS. The two additional operators were questioned by
the instructor while the start-up lab was being conducted. When the
first group was done with the start-up lab the two groups exchanged
positions. During the start-up training lab the inspector conducted
interviews concerning their training with six operators, two Reactor
Operators and four Senior Reactor Operators. Start-up training is
scheduled to be completed January 2, 1997.
The inspector found that each operator considered the first round of
classroom training adequate in providing technical knowledge concerning
the digital ICS modification. The inspector questioned the operators
concerning the ability to operate both digital and analog ICS models.
The operators stated that they felt it would not be a problem going
between the different ICS models provided some type of "just-in-time"
training was provided prior to assuming the shift on either unit. The
operators interviewed also stated that their opinion on the ability to
operate both the new and old ICSs may change once they became exposed to
the malfunction training scheduled in December. 1996.
The inspector reviewed lesson plan OP-OC-STG-ICS. Integrated Control
System (STG-ICS). The training department provided sixteen hours of
classroom training to plant operators. This training was completed for
all licensed personnel on October 8, 1996. Following this training,
additional ICS review was provided and an examination was prepared for
all licensed personnel.
All licensed operators received the
examination. However, eighteen personnel have to be retested due to
receiving a failing grade. The inspector reviewed one comprehensive ICS
modification examination. The examination contained twenty detailed
multiple choice questions concerning the modification and was found to
adequately test that knowledge.
Enclosure 2
7
The inspector discussed with the Training Department's staff their
recommendation to the Operations Department concerning the dispensation
of current license holders. At the time of the inspection, the Training
Department had not decided on what their recommendation would be
pertaining to licensed operators. The inspector determined that the
Training Department would not make a recommendation until malfunction
training was started, allowing them time to evaluate problem areas not
previously identified. Malfunction training was scheduled for the first
crew during the week of December 2. 1996. Since the results of
malfunction training will be an decision point, this item will be
tracked under Inspector Followup Item (IFI) 50-287/96-16-06, ICS
Malfunction Training Results.
The inspector observed two separate sessions of the validation of
testing procedures. The procedures being evaluated were marked
"Preliminary." The group was comprised of plant engineers, operations
personnel and training instructors. The procedures evaluated were
TN/3/B/2989/00/ALI-26. ICS/NNI Transient Testing at Power, and
TN/3/B/2989/0/A-03. Loss of ICS/NNI Power Testing at 15% Reactor Power.
The inspector observed a good working relationship within this group.
c. Conclusions
The inspector concluded that the first round of start-up training
conducted on the new digital ICS model was satisfactory. The inspector
also concluded that operators felt confident with going from the analog
to the digital ICS, however, the inspector was unable to determine the
actual impact without viewing the malfunction training scheduled in
December. The inspector determined that the sixteen hours of operator
requalification class room training contributed to the confidence
exhibited by the operators during interviews.
By reviewing the system description, the inspector determined that the
new ICS model uses inputs differently than the analog version. The
system description was well written in clear and concise language. This
document was formatted in a logical sequence, which enabled a
comprehensive understanding of a very complex system.
The inspector concluded from the review of one examination that a
comprehensive examination was administered to the operators. The
examination contained pertinent test items. The examination encompassed
a range of aspects concerning the integrated control system.
The inspector concluded the validation process for the testing
procedures was conducted in a professional manner. The validation team
discussed various aspects of the testing scheme while providing insights
concerning certain aspects of plant systems and contingency actions not
addressed in the procedures.
Enclosure 2
8
08
Miscellaneous Operations Issues (92901. 92700)
08.1 (Closed) URI 50-270/96-12-04 Pressurizer Safety Valve 2RC-67
Operability
This item addressed the technical issues associated with pressurizer
safety valve (PSV) 2RC-67 not lifting within the required setpoint. As
documented in PIP 2-096-0945. the early actuation of the 2RC-67 would
delay a reactor trip for transients that trip on high pressure, or the
reactor may trip on a different trip function.
The licensee performed
an analysis on the past operability of 2RC-67, as documented in
calculation OSC-6687. PSV Past Operability Evaluation (PIP #2-096-0945).
The conclusion of OSC-6687 determined that PSVs would have performed
their intended safety function during Cycle 15 based on the licensee's
analysis results. The inspector reviewed OSC-6687 and identified no
problems. This item is closed.
08.2 (Closed) URI 50-270/96-12-03 Delay In Licensee Event Report (LER)
Submittal
This item was opened pending the licensee's results of the past
operability review for PSV 2RC-67. The licensee determined that 2RC-67
was past operable as documented in a letter dated October 10, 1996, from
Duke Power Company to the U.S. Nuclear Regulatory Commission.
Therefore, the licensee determined that the event was not reportable per
10 CFR 50.73. As described above, the inspector reviewed the evaluation
and found no problems. This item is closed.
08.3 (Closed) LER 270/96-03 Pressurizer Relief Valve Technically Inoperable
The licensee determined that this event was not reportable, and that the
LER was not required. During the initial report, the licensee indicated
that PSV 2RC-67 failed to meet its as found set pressure band. After
further analysis, it was concluded that 2RC-67 would have performed its
intended safety function. This item is closed.
Enclosure 2
III
9
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62703, 61726)
The inspectors observed all or portions of the following maintenance
activities:
TN/3/A/0E9360/00 Procedure For The Implementation and
Verification of Minor Modification OEC-9360
(Wet Tap on CCW-42)
Keowee Unit #1 Turbine Sump Pump's Quarterly
Test
PT/3/A/203/04
Low Pressure Injection System Leakage
MP/0/A/1500/009
Defueling/Refueling Procedure (Unit 3)
PM Relays In Switchgear 3TD14
NSM-32976, Replacement of 3HP-5
Wide Range Instrument Channel Check
2HD-50 Valve Replacement
OEC-7451. Replace 1SD-40
Replace Valve Seat on 3C-20
NSM 2491, Steam Drain Modifications
NSM 32979. Replace 2MS-126, 130, and AS-1
Investigate and Repair 2LPSW-6
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and thorough. All work observed was performed with the
work package present and in active use. Technicians were experienced
and knowledgeable of their assigned tasks. The inspectors frequently
observed supervisors and system engineers monitoring job progress.
Enclosure 2
10
Quality control personnel were present when required by procedure. When
applicable, appropriate radiation control measures were in place.
c. Conclusion
The inspectors concluded that the maintenance activities listed above
were completed thoroughly and professionally.
IM1.2 Implementation of Temporary Modification to Remove Valve 1LPSW-254
a. Inspection Scope (62707. 40500)
On October 15. engineering personnel performing a visual inspection of
valve 1LPSW-254 identified a crack in the valve stem at the keyway. The
A train of Low Pressure Injection (LPI) was removed from service, and a
temporary modification was initiated to remove the valve from the
system. To implement the modification, the licensee installed a
mechanical plug downstream of valve 1LPSW-254 to provide an isolation
boundary for the work. A temporary modification (TSM 1301) was
developed to remove the valve from the piping system and replace it with
a spacer. This maintenance evolution rendered the A train of LPI unable
to perform its decay heat removal function with the unit in cold
shutdown.
The inspector assessed the maintenance activity by performing the
following:
observation of interdepartmental planning and contingency
meetings: observation of management, operations, and maintenance prejob
briefings; observation of work in progress; review of Temporary
Modification TSM-1301. Temporary Removal of 1LPSW-254 from the Piping
System, including the 10 CFR 50.59 evaluation: review of procedure
TN/1/A/1301/TM/01M, Procedure to Install Temporary Modification TSM
1301: and attendance at Plant Operation Review Committee Meetings on the
subject.
b. Observations and Findings
During the planning of the maintenance evolution, operators identified
enhancements that would improve existing procedures to cope with a loss
of decay heat removal, particularly with the specific plant conditions
that existed at the time the A train was to be isolated. Commencement
of the maintenance was delayed until the enhancements could be
incorporated into the procedures and described in the operations prejob
briefing information.
Management, operations, and maintenance prejob briefings consistently
emphasized the actions that would be necessary in response to a loss of
Enclosure 2
11
The temporary modification, its associated 10 CFR 50.59 evaluation, and
implementing procedure were complete, of appropriate detail, and
developed in accordance with station procedures.
The maintenance, including the installation of the mechanical plug
(which was performed by a contractor), was performed in a controlled
manner with an appropriate level of management oversight.
c. Conclusion
Contingency planning for a potential loss of the decay heat removal
function while a single train of LPI was available during maintenance to
remove valve 1LPSW-254 was appropriate. The implementation of the
temporary modification was performed in a controlled manner with an
appropriate level of management oversight.
M1.3 Maintenance Welding (55050)
a. Inspection Scope
The inspector reviewed the control of welding processes and weld
production.
b. Observation and Findings
The inspector determined that the Generation Services Department at
Duke's Corporate Offices was responsible for generating and revising the
Corporate Welding Manual. This department was also responsible for
generating and issuing weld procedure qualifications, welder performance
qualifications, and the code required updates used in the field to
verify welder qualification and work assignments. Welding procedures
and welder performance qualifications were executed to the requirements
of the latest approved edition of ASME Code Sections IX and XI as
applicable.
Welding activities at the ONS are controlled by the
Maintenance Welding Manual (manual), and the applicable construction
code which controls certain fabrication, inspection and testing
requirements for given welds. Mechanical/Civil Equipment Engineering,
generates and revises the manual and administers the welding program at
ONS. The Superintendent of Mechanical Maintenance implements and
maintains control of the welding program. Responsibilities for weld
production and QC inspections are assigned to the Mechanical/Civil
Manager and to the Maintenance Support Manager, respectively.
As required by the welding manual, Class G, non-QA, piping is installed
per the appropriate guidelines with documentation of required
inspections. Production welds in this category are subject to a final
visual inspection that are performed by the welding supervisor or his
designee. Also, Section 9 of the welding manual provided a list of
craft responsibilities and the general requirements to be followed
during weld fabrication.
These included use of appropriate materials,
Enclosure 2
12
Field Weld Data Sheet, weld joint details, cleanliness, cold spring,
preheating and postweld heat treatment.
The inspector identified the following observations which were discussed
with the licensee's cognizant engineer who has been given the
responsibility for reviewing and revising the subject manual as part of
the overall corporate effort to improve the Duke welding program.
Visual inspections of completed welds fabricated to B31.1
requirements are presently performed by the welding supervisor or
his designee. To provide increased independence, this type of
inspection can be done by a welding inspector or QC inspector who
has been trained and qualified in accordance with applicable ANSI
Standards and Duke's written program.
Paragraph 9.6 of the welding manual requires the welder/fitter to
achieve weld fit-up without unacceptable cold spring. No details
or specifics are provided except for the applicable ONS
specification given as reference. The control of cold spring
appears to be a function best monitored by engineering.
Preheating is another responsibility for which welders are
accountable. Paragraph 9.8 states in part that preheating shall
be performed in accordance with the specified Field Weld Data
Sheet (FWDS). The inspector noted that the FWDS states the
requirement for preheat and the appropriate temperature, but does
not identify the procedure which provides the necessary
information for acceptable heat treating practices.
In addition to the above, the inspector reviewed applicable FWDS to be
used for pipe replacement and check valve installation for the first and
second stage reheater drain tanks A and B. FWDS reviewed included
L-350, Rev. 17; L-365, Rev. 4: L-231, Rev. 18; L-250. Rev. 17; and
L-264. Rev. 3. FWDS reviewed were to be used for welding the following
materials:
Mild carbon steel to like material
Mild carbon steel to stainless steel material
Stainless steel to like material
The welding processes to be used for joining these materials were
shielded metal arc and gas tungsten arc or a combination of the two.
The inspector's review revealed that these procedures were properly
qualified and documented in accordance applicable code requirements.
Pipe and Valve Installation - Reheater Drain Line Modification
The instructions and documentation for installation of pipe and valves
in the reheater drain system of Unit 2 are described in modification NSM
22941, Part AM1 and Temporary Modification Procedure TN/2/A/2941/0/AM1.
Enclosure 2
13
Enclosure 5.4 of the package will be used for instructions and
documentation of new pressure retaining welds. Also, the instructions
provide for QC/ANI inspections, and associated hold points and for
surfaces examinations of root and completed welds. Additionally,
cleanliness requirement for carbon and stainless steel piping as
recommended by ANSI Standard N45.2.1-73 were added as a quality measure.
Field Inspections
As documented previously in Inspection Report 50-269,270.287/96-15.
extensive field inspections were performed by the licensee and
contractors focusing on locating branch connections, taking data, and
performing calculations to determine whether as built conditions met
minimum code requirements. Branch connections that failed to meet code
requirements were scheduled for replacement. Additionally, pipe and
elbow welds whose location could have rendered them subject to cracking
in the weldment or associ.ated base metal were radiographed to determine
their integrity. Selected pipe and elbow welds were visually examined
for anomalies. Associated surfaces were examined using a magnetic
particle examination technique to look for evidence of crack
indications. Finally, a consultant was contracted to perform field
inspections and to provide stress analysis evaluations with respect to
the effects of water hammer on existing piping.
c. Conclusion
The licensee's welding instruction and field inspection appeared
appropriate. The licensee's efforts to identify and document field
conditions following the Unit 2 water hammer event were commensurate
with applicable code requirements and quality standards, and reflected a
conservative attitude.
M1.4 Inservice Inspection Unit 3 (73753)
a. Inspection Scope
Observe inservice activities to determine adequacy of nondestructive
examination and compliance with code requirements and FSAR commitments.
b. Observation and Findings
The scheduled Unit 3 refueling outage was changed to coincide with the
unscheduled shutdown in response to the water hammer events on Unit 2.
This outage was identified as End-Of-Cycle 16 (EOC-16) and was the
second refueling of the third interval since commercial plant operation.
The applicable code was identified as ASME Sections XI and V. 1989
Editions. The scope of the Inservice Inspections (ISI) during this
outage was limited to: augmented examinations in response to IE Bulletin
88-08; and followup ultrasonic examinations in response to previously
identified rejectable indications in welds No. 3SGA-WG8-1 and 3SGA-WG8-2
Enclosure 2
14
of Once Through Steam Generator (OTSG) "A"
of Unit 3. Thi-s item was
documented in PIP No. 3-092-0371 for tracking purposes. In addition,
inspections included examination of the pressurizer relief nozzle welds,
pressurizer spray nozzle weld and upper head and upper shell course
weld.
The inspector observed the examination of the aforementioned welds on
the pressurizer. This included system calibration and examination with
00, 450 and 600 transducers. Duke Non-Destructive Examination (NDE)
procedures used for these examinations included NDE-640, Rev. 1, for the
00 scan and NDE-620, Rev. 5, for the 450 and 600 scans.
These procedures have been reviewed on previous inspections and were
found to meet code requirements. Calibrations and examinations were
properly performed and documented. Indications were evaluated and
dispositioned. Limited examinations were calculated and percentage of
weld examination/coverage was documented. Personnel who performed the
examinations were adequately trained and knowledgeable of code and
procedural requirements. Rejectable indications were not identified.
Eddy Current Examination of Unit 3 OTSGs
The scope of examining OTSG tubes at ONS Unit 3 during the current
refueling outage (EOC-16) was as follows:
(1) Inspect 100% of inconel-600 plugs and 40% of inconel-690 plugs on
the hot leg, using motorized pancake coil (MRPC) probe.
(2) Inspect Lane/Wedge tubes in hot leg of both OTSGs with MRPC.
(3) Inspect selected inconel-600 and -690 sleeves in hot leg of both
OTSGs with Bobbin and Plus-Point coil probes.
(4) Inspect 100% of tubes available in both OTSGs with Bobbin coil
probe.
(5) Inspect roll transitions in hot leg of both OTSGs with MRPC coil
probe.
With respect to item (5)
above, a 20% randomly selected sample was
scheduled for examination with MRPC coil probe. The sample was
subsequently increased to 100% when the examination identified an
indication in the roll transition region. This indication was believed
to be associated with Primary Water Stress Corrosion Cracking (PWSCC)
mechanism.
The licensee plans to pull four tubes for a metallurgical examination to
determine conditions associated with tube degradation. Procedures used
to perform the examination and analyze results comply with ASME Code
Enclosure 2
15
Section XI. 1989 Edition with no Addenda. Also applicable by reference
is Regulatory Guide 1.83. July 1975. Applicable procedures include:
NDE-701. Rev. 3:
Multifrequency Eddy Current Examination of
Steam Generator tubing at McGuire, Catawba
and Oconee Nuclear Stations.
NDE-707. Rev. 3:
Multifrequency Eddy Current Examination on
Non-Ferrous Tubing, sleeves and plugs
using a motorized rotating coil probe.
In addition to these procedures, the licensee developed a set of
guidelines which are used to assist in data acquisition and analysis of
data at the Oconee Nuclear Station and to establish consistency and
compliance with applicable requirements. These guidelines were as
follows:
Eddy Current Acquisition Guidelines, October 6. 1996
Eddy Current Analysis Guidelines, October 9, 1996
Data acquisition was being performed by the licensee using Zetec's
Eddynet Acquisition system. Data analysis was being performed offsite
at the McGuire Nuclear Station, as well as Framatome in Lynchburg, VA
and Rockbridge, IL.
At the close of this inspection on October 18, 1996, bobbin coil
examination was in progress, but had not reached the point of
identifying tubes for plugging. In a similar manner, examination of the
roll transition at the upper tube sheet was making good progress, but no
evidence of PWSCC had been identified. On October 22, 1996, the
licensee's accountable engineer indicated that preliminary evaluation
identified three tubes in OTSG "B"
with axial indications. The suspect
tubes were identified in locations 136-47, 113-114. and 132-1. The
licensee expected to have the examination and the list of tubes to be
repaired during the week of October 27, 1996.
c. Conclusion
ISI examinations scheduled for this outage were being performed as
required by well trained personnel following procedures written in
compliance with applicable code requirements. Personnel performing the
inspections were well qualified to execute their assigned tasks. Eddy
current examinations were consistent with Technical Specifications 4.17
requirements. Three tubes were identified in S/G "B"
with PWSCC
indications in the roll transition region of the upper tubesheet. No
decisions had been reached on their disposition and/or repair at the
close of the inspection period.
Enclosure 2
16
M4
Maintenance Staff Knowledge and Performance (92902. 62707)
M4.1 Failure To Initiate a PIP
a. Inspection Scope
The inspector reviewed an issue involving the installation of blanks on
the auxiliary building ventilation system (ABVS) supply vents which feed
the Unit 1 and Unit 2 control battery rooms. The blanks adversely
affected the Unit 2 and Unit 1 Penetration Room Ventilation System
(PRVS) testing.
b. Observations and Findings
On October 2, 1996. during the performance of PT/2/A/0100/010.
Penetration Room Ventilation System Vacuum Test, the PRVS could not
maintain a vacuum against the Unit 2 control battery room as documented
in PIP 0-096-1960. The licensee determined that Maintenance personnel
had installed blanks on the ABVS supply vents feeding the Unit 2 control
battery room on September 25, 1996, which adversely affected the PRVS
test. On October 9, 1996, the licensee performed PT/1/A/0100/010,
Penetration Room Ventilation System Vacuum Test, and the system could
not maintain a vacuum against the Unit 1 control battery room. Blanks
had also been installed on the ABVS vents feeding the Unit 1 control
battery room on September 25. 1996. Isolating the supply air to the
battery rooms reduced the pressure in the rooms to the point where it
was no longer positive with respect to the penetration room when the
PRVS was in operation. The licensee determined that there were no
present operability concerns on Unit 1 and Unit 2 since they were
shutdown. The Unit 1 past operability evaluation documented in OSC
6679. Penetration Room Allowable Leakage, concluded that the Unit 1 PRVS
was past operable from September 25. 1996. through October 9, 1996. The
licensee determined that there was no past operability concern for Unit
2 because the blanks were installed while the unit was offline. The
inspector noted that there is an open deviation (DEV) on the operability
of the PRVS (DEV 50-269.270,287/94-24-04).
The licensee incorporated minor modification ONOE-9540 which removed the
installed blanks from Unit 1 and 2 ABVS supply vents in the control
battery rooms. The inspector independently verified that the blanks had
been removed from the supply vents. The modification will also revise
the drawings to reflect the correct as-built configuration (blanks
removed). The licensee successfully performed the Unit 1 and Unit 2
PRVS tests after the implementation of ONOE-9540.
In early September 1996. Maintenance personnel identified that station
drawings 0-504A and 0-2504B indicated that the subject vents should have
been blanked off. The NSM which originally installed the Control
Battery Room Air Conditioning Units was also intended to blank off the
ABVS supply vents in the rooms. Maintenance initiated work requests
Enclosure 2
17
(WR) 96038038 and 96037440 to install the blanks to assist cooling the
battery rooms during the summer since the air temperature coming out of
the duct was higher than the 80 degree limit for the room. Nuclear
Station Directive (NSD) 208. Problem Investigation Process. provides
criteria for initiating a PIP for drawing discrepancies. On September
9, 1996, Maintenance personnel identified that drawing 0-2504B did not
match as-built conditions, but failed to initiate a PIP as required by
NSD 208. The inspector concluded that Maintenance personnel should have
initiated a PIP once the drawing discrepancies were identified, then
Engineering could have evaluated the installation of the blanks. This is
being identified as example one of Violation 50-269,270/96-16-01,
Maintenance Failed To Initiate a PIP. On September 12, 1996,
Maintenance personnel identified that drawing 0-504A did not match as
built conditions, but again failed to initiate a PIP. This is being
identified as example two of Violation 50-269,270/96-16-01. Maintenance
Failed To Initiate a PIP.
c. Conclusion
A violation with two examples was identified to address the failure of
Maintenance personnel to initiate a PIP to address drawing discrepancies
on the missing blanks on the ABVS vents supplying the Unit 1 and Unit 2
control battery rooms. Maintenance initiated WRs that installed blanks
on ABVS supply vents which adversely affected the Unit 1 and Unit 2 PRVS
testing.
M4.2 Main Steam Safety Valve (MSSV) Cotter Pin Inspection (92902, 40500)
a. Inspection Scope
In May 1996, another B&W plant had a Dresser Main Steam Safety Valve
(MSSV) fail to reseat after lifting. This was due to its spindle nut
not being held in place by a cotter pin that should have engaged a slot
in the nut and a drilled hole in the valve's spindle. The nut vibrated
down the spindle and interfered with the valve's downward motion as the
lifted. That B&W plant had Main Steam Isolation Valves and a Feed-Only
Good-Generator system. As documented in Inspection Report 50
269,270,287/96-12, the licensee was aware of the problem and determined
that the specific problem was not an immediate concern at Oconee
because: the Oconee valve vendor was a different manufacturer (Crosby
Valve and Gage Company): the valve details. though similar in function,
were sufficiently different: the Oconee valve procedure specifics would
tend to prevent incorrect cotter pin/nut engagement; and discussions
with valve assembly technicians provided no negative findings. Based on
this and personnel safety concerns while at power, inspection of the 48
MSSVs (8 per steam line; 16 per unit) was scheduled for the next cold
shutdown periods. During recent plant shutdowns to cold conditions for
other reasons, the inspectors participated in the inspections and
reviewed applicable WOs and PIPs.
Enclosure 2
b. Observations and Findings
18
On October 15, 1996, per WO 96080355, the licensee conducted the Unit 1
inspection and did not identify any problems. On October 14, 1996, per
WO 96080322, the licensee conducted the Unit 2 inspection which
identified that spindle nut cotter pins were improperly installed on
four MSSVs. The four MSSVs were 2MS-0001. 2MS-0005, 2MS-0013, and 2MS
0014. Each valve has a nominal lift setpoint of 1100 psig except for
2MS-001, which has a setpoint of 1104 psig. The cotter pins were not
bent sufficiently, and could have vibrated out of the spindle nut. The
subject MSSVs were located on separate steamline headers; therefore, if
the valves failed to reseat under certain conditions both OTSGs could
have been lost as decay heat removal paths. On October 21, the licensee
performed a past operability evaluation for the four MSSVs. It was
concluded that the valves would have performed their protection function
by opening, but the valves could not be credited for closing to provide
a fission barrier and preventing a loss of inventory. The evaluation
also concluded that even if the four valves failed to reseat, the
radiological dose released would not have exceeded the 10 CFR Part 100
limits. This conclusion was drawn assuming a Chapter 15 Steam Generator
Tube Rupture.
The Unit 3 inspection conducted on October 24, 1996, by the inspectors
along with the licensee identified that cotter pins were not installed
on two MSSVs. The two valves were 3MS-0010 and 3MS-0001, each with a
nominal lift setpoint of 1065 psig and 1104 psig, respectively. The
valves were on separate steamline headers; therefore, if the valves
failed to reseat under certain conditions both OTSGs could have been
lost as decay heat removal paths. The licensee's system operability
evaluation concerning the two valves was not available prior to the end
of the inspection period.
On October 29, 1996, the licensee made a 10CFR 50.72 notification
concerning the two Unit 3 MSSVs missing their cotter pins. The licensee
determined that the possibility existed for flow induced vibration to
have caused the unsecured spindle nut to rotate down the spindle toward
the valve body. Therefore, 3MS-0001 and 3MS-0010 could have been
prevented from properly closing, resulting in an potential primary
system overcooling event. On October 30, 1996, the licensee made a
similar 10 CFR 50.72 notification addressing the four Unit 2 MSSVs
having improperly installed cotter pins. The 10 CFR 50.72 section cited
in the reports was "Any event or condition that alone could have
prevented the fulfillment of the safety function of structures or
systems that are needed to mitigate the consequences of an accident".
During each Unit's respective refueling outage the valves were partially
disassembled to perform setpoint tests. The manual lift linkage
assembly, which includes the spindle nut, was removed and re-installed
each time. The licensee considered the parts removed as not being
Enclosure 2
19
safety parts. As reported by the licensee, the Unit 2 valves identified
above did not lift (as expected) during the last reactor trip.
The cotter pins on the four Unit 2 MSSVs (2MS-0001. 2MS-0005, 2MS-0013,
and 2MS-0014) were improperly installed on May 4-5, 1996. Associated
Maintenance Procedure MP/0/A/1200/089, Valve - Main Steam Safety
Setpoint Test, Step 12.3 states that, "Spindle nut cotter pins are in
place and in good mechanical condition." The inspector noted that there
was no documented QC or second party verification to ensure correct
cotter pin installation. The failure of Maintenance personnel to
properly install the subject cotter pins per MP/0/A/1200/089 is
considered a violation of TS 6.4.1 and is identified as example one of
Apparent Violation (EEI) 50-270,287/96-16-05: Failure to Properly
Install MSSV Spindle Nut Cotter Pins.
The two Unit 3 MSSVs (3MS-0001 and 3MS-0010) which had missing cotter
pins should have had the pins installed during the performance of
MP/0/A/1200/089 on July 17-18, 1996. The failure of Maintenance
personnel to properly install the subject cotter pins per
MP/0/A/1200/089 is considered a violation of TS 6.4.1 and is identified
as example two of Apparent Violation (EEI) 50-270,287/96-16-05:
Failure
to Properly Install MSSV Spindle Nut Cotter Pins.
The licensee's proposed corrective action was to perform minor
modifications on all three units' MSSVs to remove the lift lever
assembly (i.e., lift lever, lever pin, lever cotter pin, forked lever,
forked lever pin, forked lever cotter pin, spindle nut, and spindle nut
The inspector verified that W096083643, W096083248, and WO 96083850 were being generated, and will be implemented during the
ongoing outages. The inspector also reviewed the safety evaluations
associated with the lift lever assemblies and did not identify any
additional issues of concern.
c. Conclusion
Maintenance personnel failed to appropriately implement the procedure
requirements for restoration of the MSSVs by ensuring that cotter pins
were properly installed on two Unit 3 MSSVs and four Unit 2 MSSVs.
These examples of poor Maintenance performance could have led to entry
into Emergency Operating Procedures and/or loss of OTSGs as decay heat
removal paths. Accordingly, an Apparent Violation with two examples was
identified.
M8
Miscellaneous Maintenance Issues (92903)
M8.1
(Closed) IFI 269,270.287/96-12-01 MSSV Cotter Pin Inspection
This item is closed based on the information provided in Section M4.2 of
this inspection report.
Enclosure 2
20
M8.2
(Open) Unresolved Item 269/96-04-04 Root Cause Assessment of Failures
to Valves 1MS-77 and 1LPSW-254
One of the two issues addressed by this item involved unreliability of
valve 1LPSW-254. The valve is in the Low Pressure Service Water (LPSW)
system and is the Unit 1 Train A Low Pressure Injection (LPI) Cooler
outlet isolation valve. Valve 1LPSW-251 is the LPI cooler outlet flow
control and is located directly upstream of 1LPSW-254. As documented in
NRC Inspection Report 50-269,270,287/96-04. piping vibration in the
vicinity of these valves has caused failures of valve 1LPSW-254 in the
past. A modification was implemented in 1992 in an attempt to improve
reliability: however, there have been subsequent failures. Each train
of LPI on all three units has a similar arrangement. The unresolved
item was opened pending the licensee's evaluation of the vibration
problem and determination of necessary corrective actions.
During this inspection period, the A train of LPI was placed in service
for decay heat removal following shutdown of Unit 1. In service
inspections of the valve were performed by engineering personnel. As
documented in PIP 1-096-2000. on October 11 slight motion of the 1LPSW
254 valve stem relative to the operator was identified. On October 12
corrective maintenance was performed to replace the key (which showed
signs of wear) and the operator was rotated 1800 to utilize the unused
keyway in the operator drive sleeve. The A train of LPI was returned to
service following testing later the same day. On October 15, a followup
inspection of the valve by engineering personnel identified a crack in
the valve stem at the key way. The A train of LPI was removed from
service and a temporary modification was initiated to remove the valve
from the system. The inspector observed the work to implement the
modification as documented in Section M1.2. of this report.
Since unreliability of valve 1LPSW-254 continued, the inspector reviewed
the status of Unresolved Item 269/96-04-04. The licensee had completed
the engineering evaluation of the system vibration in the vicinity of
the LPI cooler flow control valves, including an initial recommendation
for corrective action.
The results of the vibration evaluation were documented in an
engineering memo to file dated October 1, 1996. The evaluation
indicated that excessive vibration existed in the LPSW LPI cooler flow
control valves on all three units. The vibration is the result of flow
induced cavitation through the flow control valves. Valve 1LPSW-254 is
the shortest distance downstream from its associated flow control valve.
This has likely contributed to its higher rate of failure. The
engineering evaluation recommended replacement of the flow control
valves with larger valves that included a flow attenuator and the
replacement of the isolation valves with larger valves of the same
style.
Enclosure 2
21
Additional corrective actions for the 1 LPSW-264 failures are still
under review by station management. The failure of 1MS-77 was not
reviewed. The URI .remains open.
III. Engineering
El
Conduct of Engineering
E1.1 3B Main Feedwater Pump (MFP) Gear Failure
a. Inspection Scope
The inspector reviewed the licensee's root cause evaluation and PIPs
associated with the 3B MFP failure which occurred on August 24. 1996.
b. Observations and Findings
On August 24. 1996. Unit 3 experienced a runback to 65% power due to a
loss of the 3B MFP. The licensee determined that the runback was caused
by a failure of the 3B MFP turbine main shaft oil pump (MSOP) to
function because of the failure of the number three and number four gear
set. The actual root cause of the gear failures is still under
evaluation. As documented in PIP 3-096-1626. part of the assessment of
the failure addressed whether the failed gears were a matched pair, or
not. Previous failures dating back to 1994 had identified this as a
problem. The licensee's investigation revealed that the gears that were
replaced were a matched pair but that it was fortuitous and not because
of corrective actions from previous events. PIP 2-094-474 provided
guidance to purchase the gears in matched sets. Due to a lack of
communication, the gears that were already purchased were not returned,
and no matched pairs were ever ordered. Currently, there is an active
purchase identification number for matched gear sets.
Since the late 1980s the licensee had performed major Preventive
Maintenance (PM) on the MFPs every refueling outage (RFO). On October
4, 1994, the licensee changed the major PM to every third RFO and minor
PM to every RFO. On July 25, 1995, the licensee changed the major PM to
every fourth RFO to coincide with MFP rebuild. After this latest
failure, the licensee revised the PM frequency on the MFP front standard
hydraulic system to once per refueling outage until a cost benefit
analysis can be performed on the available MSOP reliability improvement
options.
The inspectors observed the 3B MFP being rebuilt with the new gears.
The licensee conducted the work with appropriate WOs and procedures.
c. Conclusion
The licensee's corrective actions were appropriate to address this
issue.
Enclosure 2
22
E1.2 Letdown Storage Tank Level Redundant Power SuDly
a. Inspection Scope (37551)
The inspector reviewed the circumstances leading to the identification
that the Letdown Storage Tank (LDST) level instrumentation was not
powered from a redundant power supply.
b. Observations and Findings
On October 28, 1996. the licensee identified that Unit 3 LDST level
transmitter ON3HPILTOO33P1 was not powered from the Integrated Control
System (ICS) Redundant Power Panel.
Further investigation revealed that
Unit 1 was also not powered from the Redundant Power Panel.
A modification,.NSM 1.2,3 2728 had been implemented in the 1989 and 1990
time period which changed the transmitters from Bailey to Rosemount
types. During the modification, the redundant power supply detailed on
drawings had not been reconnected on Units 1 and 3, but was properly
installed on the Unit 2 instruments. IP/O/A/0202/1F, HPI LDST Level
Instrument Calibration Procedure, was performed as a post modification
test. The test did not address the redundant power supply.
The inspectors reviewed applicable Bailey Meter Company instrument
drawing D80323245, Rev. DQ (drawing referenced the Rosemount
Instruments) and verified that the field installation was not in
accordance with the drawing.
The consequences of a power failure to
the LDST Level instrumentation was discussed with the system engineer.
A power failure to the instrument would result in the indication
dropping to mid-scale. This mid-scale instrument failure would be less
noticeable than a failure to the low-end of the scale. However, in
reviewing the control room indication, it was learned that there was a
light on the face of the gage which would go out if power failed. It
was further observed that the normal operating range was at
approximately 90 percent of full scale and a failure to the 50 percent
position should be detected by the operators. The inspector concluded
that should the single power source fail, Operations would have detected
the failure within a short period of time.
The licensee issued PIP 0-96-2165 to describe and resolve this problem.
Additionally, they aggressively initiated corrective action. The
licensee has reconnected the redundant power supply on Unit 1
instruments and has scheduled the work on Unit 3 to be performed prior
to its restart. The inspector reviewed the Unit 1 re-installation
functional test data and had no further concerns.
c. Conclusion
Although the LDST indication is not considered safety-related, the
indication is essential (importatant to safety) to ensure that the plant
Enclosure 2
23
is operated in a safe manner. Failure to maintain plant configuration
as detailed on the drawings is a violation. This licensee identified
and corrected violation is being treated as a Non-Cited Violation (NCV),
consistent with Section VII.B.1 of the NRC Enforcement Policy. This
issue will be identified as NCV 269,287/96-16-04, Failure to Maintain
Equipment in Accordance with Plant Drawings.
E8
Miscellaneous Engineering Issues (92903)
E8.1 (Closed) Unresolved Item (URI) 50-269.270,287/96-12-02 LDST Pressure
Level Curves
The licensee determined that LDST level calibration procedure
IP/0/B/0202/001F. Letdown Storage Tank Level vs. Pressure Curve Limits,
did not properly account for instrument uncertainties. The procedure
was in error because a specific gravity correction factor had been
misapplied in calculation OSC-4506, Letdown Storage Tank Level
Instrument Loop Accuracy Calculation For 1, 2. 3 HPILTOO33P1 and 33P2.
The inspector concluded that calibration procedure IP/0/B/0202/001F was
inadequate, in that it did not correctly account for instrument
uncertainties, and is being identified as Violation 50-296.270,287/96
16-02. LDST Calibration Procedure In Error.
As described in IR 50-269.270,287/96-12, there was no present
operability concern. The inspector reviewed calculation OSC-6646. Past
Operability Determination For PIPs 0-096-1539 and 0-096-1550, LDST Curve
Analysis. Calculation OSC-4616 determined the curves for operations use
in maintaining the correct level pressure relationship in the LDST to
ensure that gas would not be carried into the suction of the HPI pumps.
Non-conservatisms were noted in OSC-4616. Specifically, the partial
pressures of gas and water vapor had not been considered in the
calculation. OSC-6646 examined the results of OSC-4616 and previous
revisions of the curves that had been used at ONS. The results of this
calculation were that all points, except one at 92 inches (outside the
normal operating range), were bounded by the data sheets of the previous
calculations. The calculation concluded that there were some extremely
remote conditions (i.e., elevated BWST temperature) that may not have
been bounded. However these conditions were considered not to be
credible. Accordingly, URI 50-269.270,287/96-12-02 is closed.
IV.Plant Support Areas:
R1
Radiological Protection and Chemistry (RP&C) Controls (71750)
R1.1 Transportation of Radioactive Materials
a. Inspection Scope (86750. T12515/133)
The inspectors evaluated the licensee's transportation of radioactive
materials program for implementing the revised Department of
Enclosure 2
24
Transportation (DOT) and NRC transportation regulations for shipment of
radioactive materials as required by 10 Code of Federal Regulations
(CFR) Part 71 and 49 CFR Parts 100 through 177.
b. Observations and Findings
The inspectors reviewed procedures and determined that they adequately
addressed: assuring that the receiver has a license to receive the
material being shipped; assigning the form, quantity type, and proper
shipping name of the material to be shipped; classifying waste destined
for burial: selecting the type of package required: labeling and marking
the package; placarding the vehicle; assuring that the radiation and
contamination limits are met; and preparing shipping papers.
The inspectors reviewed the licensee's records for 15 shipments of
radioactive material and determined the shipping papers contained the
required information. The licensee was maintaining records of shipments
of licensed material for a period of three years after shipment as
required by 10 CFR 71.91(a). Certificates of Compliance (CoC) for the
shipping casks the licensee currently used were reviewed and the
inspectors determined that the CoCs were currently NRC approved for use.
A review of the licensee's computer software for classifying waste
shipments indicated that it had been updated to reflect the latest DOT
isotopic concentration changes in the Al and A2 shipping table values.
c. Conclusions
Based on the above reviews, it was concluded that the licensee had
effectively implemented a program for transporting radioactive materials
and for classifying waste destined for burial.
R1.2 Water Chemistry Controls
a. Inspection Scope (84750)
The inspectors reviewed implementation of selected elements of the
licensee's water chemistry control program for monitoring primary and
secondary water quality. The review included examination of program
guidance, as well as implementing procedures and analytical results for
selected chemistry parameters.
b. Observations and Findings
The inspectors reviewed Technical Specification (TS) 4.1.3. which
described the operational and surveillance requirements for reactor
coolant activity and chemistry. The inspector also reviewed Final
Safety Analysis Report (FSAR) Sections 5.2.1.7 and 9.3.1.2, which
indicated guidelines for maintaining reactor coolant and feedwater
quality that were derived from vendor recommendations and the current
Enclosure 2
25
revisions of the Electric Power Research Institute (EPRI)- Pressurized
Water Reactor (PWR) Primary and Secondary Water Chemistry Guidelines.
The FSAR also indicated that detailed operating specifications for the
chemistry of those systems were addressed in the Chemistry Section
Manual.
The inspector reviewed selected analytical results recorded for Units
1, 2, and 3 reactor coolant and secondary samples taken during June 1,
1996, and October 19, 1996. The selected parameters reviewed for
primary chemistry included pH, dissolved oxygen, chloride, fluoride, and
sulfate. The selected parameters reviewed for secondary chemistry
included pH, dissolved oxygen, fluoride, and chloride. Those primary
and secondary parameters reviewed were maintained well within the
relevant TS.limits and within the EPRI guidelines for power operations
and cold shutdown modes for PWR primary water chemistry.
c. Conclusions
Based on the above reviews, it was concluded that the licensee's water
chemistry control program for monitoring primary and secondary water
quality had been implemented in accordance with the TS requirements and
the EPRI guidelines for PWR water chemistry.
R2
Status of Radiation Protection Facilities and Equipment
R2.1 Process and Effluent Radiation Monitors
a. Inspection Scope (84750)
The inspectors reviewed selected licensee procedures and records for
required surveillances on process and effluent radiation monitors and
for radiation monitor availability.
b. Observations and Findinqs
The inspectors toured the facility and observed the physical operation
of radiation monitors in use. Radiation monitor local digital displays
were compared to control room monitor displays for ten radiation monitor
displays. The displays were determined to be tracking consistently with
each other. The inspectors also reviewed selected surveillance
procedures and records for performance of channel checks, source checks,
channel calibrations, and channel operational tests for the radiation
monitors listed below:
RIA-39
Control room ventilation monitor
RIA-41
Spent fuel building ventilation monitor
Spent fuel building ventilation monitor
CRIA-43
Unit 1 ventilation monitors
Unit 1 ventilation monitors
Unit 1 ventilation monitors
Enclosure 2
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Unit 1 ventilation monitors
Reactor building airborne monitoring system
Reactor building airborne monitoring system
Reactor building airborne monitoring system
Reactor building airborne monitoring system
Surveillance testing was required by the TSs and/or the Offsite Dose
Calculation Manual (ODCM) to demonstrate that the instrumentation was
operable. Records indicated that the surveillances were current and had
been performed in accordance with the applicable procedures. The most
recent system status report available, which covered the period January
through June 1996, indicated that the overall availability for the
Radiation Monitoring System remained above 99 percent. The inspectors
discussed operability trending methods for both safety-related and
nonsafety-related monitors with the radiation monitor system engineer in
addition to reviewing spare parts inventory data. Operability records
reviewed and discussed with cognizant licensee personnel indicated that
one containment high range monitor had previously been out of service
for a period of 25 days as a result of spare parts availability
problems.
c. Conclusions
Based on the above reviews, it was concluded that the licensee had
effectively implemented procedures to track the availability of
radiation monitors and to demonstrate operability of process and
effluent radiation monitors by performance of surveil ances at the
frequencies specified in the TSs and the ODCM. Discussions with
cognizant licensee personnel and a review of performance records
determined the licensee was maintaining an overall high level of
operability for radiation monitors in the first six months of 1996.
R5
Staff Training and Qualification in Radiation Protection and Chemistry
R5.1 Training for Transportation of Radioactive Material
a. Inspection Scope (86750, TI 2515/133)
The inspectors reviewed training for personnel and supervisors involved
in transportation of radioactive material.
b. Observations and Findings
The inspector reviewed licensee training records and verified that
personnel involved with radioactive material shipping were maintaining
current hazardous material (HAZMAT) training qualifications.
Enclosure 2
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c. Conclusions
The inspectors determined the licensee's training program associated
with transportation of radioactive material was adequate. The
inspectors concluded the transportation training focused on good
radiological control work practices and compliance with transportation
regulations.
R7
Quality Assurance in Radiation Protection and Chemistry Activities
R7.1 Review of RP&C Self-Assessment Activities
a. Inspection Scope (84750, 86750, TI 2515/133)
The inspectors reviewed a licensee self-assessment and discussed issues
identified with licensee management to determine if the licensee was
identifying issues of substance, proposing corrective actions, and
tracking items for completion in the areas inspected.
b. Observations and Findings
The assessment, Regulatory Audit SA-96-39(ON)(RA), dated August 27,
1996, was conducted during the period of July 22, 1996, through July 30,
1996. at the Oconee Nuclear Site. The scope of the assessment was in
the areas of chemistry, radiation protection, and transportation of
radioactive material program activities. A number of substantive issues
were identified by the audits and were characterized as either findings.
followup items, strengths, weaknesses, recommendations, or observations.
Pursuant to the licensee's auditing procedures, the identified issues,
including corrective actions for the findings, were tracked for
completion of warranted followup actions by initiating PIPs. The
inspector determined that the audits were of sufficient scope and depth
to identify existing problems and that corrective actions for the
identified findings were documented and resolved through the PIP. The
audit results were well documented and reported to facility management
in a timely manner.
c. Conclusions
Based on the above reviews, it was concluded that the licensee had
complied with the TS required program for conducting assessments of
station activities.
Enclosure 2
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P3
Emergency Preparedness Procedures and Documentation.
P3.1 Emeroency Preparedness Followup to Licensee Event (Unit 2)
a. Inspection Scope (71750)
The inspectors reviewed the declaration and termination actions taken by
the licensee for the licensee's Notice of an Unusual Event (NOUE)
associated with a Unit 2 secondary side steam line break to verify the
licensee complied with their Emergency Coordinator procedures for event
classification.
b. Observations and Findings
The inspectors verified the event was classified in accordance with
licensee procedure RP/O/B/1000/01, Emergency Classification, Change 3,
dated July 16, 1996. The licensee classified this event as an Unusual
Event based on emergency action levels (EALs) identified in the
procedure.
The Event Notification form reviewed by the inspectors, verified the
event was declared and terminated at 8:40 p.m. on September 24, 1996,
from the Technical Support Center (TSC). During the event debrief, the
licensee identified that the Emergency Coordinator procedure did not
contain adequate guidance for event declarations and termination.
Specifically, an event checklist used in the Control Room and Emergency
Operating Facility (EOF) for terminating an event was not available in
the TSC Emergency Coordinator procedure. The licensee initiated a
Problem Investigation Process (PIP) report to evaluate the problem and
completed a procedural revision for the Emergency Coordinator TSC
procedure to provide procedural guidance for terminating a NOUE
consistent with the guidance in the control room and EOF procedures.
The inspector had also identified that the procedure used in the TSC
during the event was not adequate for terminating an Unusual Event. The
inspector informed the licensee that this was a violation of TS 6.4.1
which required written procedures with appropriate instructions and
check-off list shall be provided. The inspector noted that the licensee
took immediate corrective actions to upgrade the TSC procedure. This
licensee-identified and corrected violation is being treated as a Non
Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement
Policy. This issue is identified as NCV 50-269,270.287/96-16-03,
Failure to Provide Adequate Procedural Guidance in the TSC for Exiting a
NOUE.
c. Conclusions
Based on an independent review of records, logs, and interviews with
personnel involved with the event, the inspectors verified the event was
classified in accordance with licensee procedures.
However, the
licensee terminated the event without adequate procedural guidance in
the TSC. Accordingly, an NCV was identified for this licensee
identified violation.
Enclosure 2
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X1.
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on November 20, 1996. The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
Partial List of Persons Contacted
Licensee
B. Peele, Station Manager
E. Burchfield. Regulatory Compliance Manager
D. Coyle. Systems Engineering Manager
T. Curtis, Operations Manager
J. Davis. Engineering Manager
T. Coutu. Operations Support Manager
W. Foster, Safety Assurance Manager
J. Hampton. Vice President, Oconee Site
G. Hamrick, Manager, Chemistry
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
J. Smith, Regulatory Compliance
J. Twiggs, Manager. Radiation Protection
NRC
D. LaBarge. Project Manager
Enclosure 2
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Inspection Procedures Used
IP 55050:
Nuclear Welding
IP 71750:
Plant Support Activities
IP 71707:
Plant Operations
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
IP 37551:
Onsite Engineering
IP 92901:
Followup - Plant Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92700:
Onsite LER Followup
IP 73753:
Inservice Inspection
IP 84750:
Radioactive Waste Treatment, Effluent Environmental Monitoring
IP 86750:
Solid Radioactive Waste Management Transportation of Radioactive
Materi als
IP 71001:
Licensed Operator Requalification Program Evaluation
IP 71714:
Cold Weather Preparations
IP 62703:
Maintenance Observations
IP 40500:
Effectiveness of Identification and Resolving Problems
TI 2515/133:Implementation of Revised 49 CFR Parts 100-177 AND 10 CFR Part 71
- EEnclosure
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31
Items Opened, Closed, and Discussed
Opened
50-269,270/96-16-01
Maintenance Failed To Initiate A PIP
(Section M4.1)
50-296,270,287/96-16-02
LDST Calibration Procedure In Error
(Section E8.1)
50-269,270,287/96-16-03
Failure to Provide Adequate Procedural
Guidance in the TSC Exiting a NOUE
(Section P3.1)
50-269,287/96-16-04
Failure to Maintain Equipment in
Accordance with Plant Drawings (Section
E1.2)
50-270.287/96-16-05
Failure to Properly Install MSSV Spindle
Nut Cotter Pins (Section M4.2)
50-287/96-16-06
IFI
ICS Malfunction Training Results (Section
05.1)
Closed
50-270/96-12-04
Pressurizer Safety Valve 2RC-67
Operability (Section 08.1)
50-270/96-12-03
Delay In LER Submittal (Section 08.2)
50-270/96-03
LER
Pressurizer Relief Valve Technically
Inoperable (Section 08.3)
50-269,270,287/96-12-02
Letdown Storage Tank Pressure-Level Curves
(Section E8.1)
50-269,270.287/96-12-01
MSSV Cotter Pin Inspection (Section M8.1)
Discussed
50-269/96-04-04
Root Cause Assessments of Failures to
Valves IMS-77 and 1LPSW-254 (Section M8.2)
Enclosure 2
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List of Acronyms
Auxilary Building Ventilation System
American Nuclear Insurance
ANSI
American Nuclear Society Institute
American Society of Mechanical Engineers
BWST
Borated Water Storage lank
CFR
Code of Federal Regulations
Component Cooling
Condenser Circulating Water
Certificates of Compliance
CR
Control Room
Control Rod Drive Mechanism
Department of Transportation
Duke Power Company
Emergency Action List
Apparent Violation
Emergency Feedwater
End Of Cycle
Emergency Operating Facility
Electric Power Research Institute
EWST
Emergency Water Storage Tank
FWDS
Field Weld Data Sheet
Final Safety Analysis Report
GPM
Gallons Per Minute
Hazardous Material
H/L
Hot Leg
Health Physics
High Pressure Injection
Integrated Control System
I&E
Instrument & Electrical
IR
Inspection Report
Inservice Inspection
KHU
Keowee Hydro Unit
LDST
Letdown Storage Tank
LER
Licensee Event Report
LCO
Limiting Condition for Operation
Loss of Coolant Accident
Low Pressure Injection
Low Pressure Service Water
Main Feedwater Pump
MRPC
Motorized Pancake Coil
MSOP
Main Shaft Oil Pump
Maintenance Procedure
MVA
Mega Volts-Amps
Megawatts
Non-Cited Violation
- NEnclosure
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33
0
Non-Licensed Operator
Notice Of Unusua] Event
NRC
Nuclear Regulatory Commission
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
Offsite Dose Calculation Manual
Oconee Nuclear Station
Once Through Steam Generator
PRVS
Penetration Room Ventilation System
Pounds Per Square Inch Gauge
PSV
Pressurizer Safety Valve
pH
Conductivity
Problem Investigation Process
Preventive Maintenance
PRVS
Penetration Room Ventilation System
Pressurized Water Reactor
Primary Water Stress Corrosion Cracking
Quality Assurance
Quality Control
Refueling Outage
RIA
Radiation Instrument Area
RP&C
Radiological Protection & Chemistry
Resistance Temperature Detector
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Work Order
Work Request
- yEnclosure
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