ML15118A120
| ML15118A120 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/20/1996 |
| From: | Crlenjak R, Harmon P NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML15118A117 | List: |
| References | |
| 50-269-96-04, 50-269-96-4, 50-270-96-04, 50-270-96-4, 50-287-96-04, 50-287-96-4, NUDOCS 9606120069 | |
| Download: ML15118A120 (43) | |
See also: IR 05000269/1996004
Text
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UNITED STATES
0
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/96-04, 50-270/96-04 and 50-287/96-04
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.: 50-269, 50-270 and 50-287
License Nos.:
Facility Name: Oconee Units 1, 2 and 3
Inspection Conducted: March 10, 1996 - April 20, 1996
Inspectors:
N<KOf
Inspectors
'e"o
ispecC6r
ieS~e
P. E. Harmon, Senior Reside
igned
J. L Coley, Reactor Inspec r
N. Economos, Reactor Inspector
D. B Forbes, Reactor Inspector
P. G. Humphrey, Resident Inspector
D. W. Jones, Reactor Inspector
L. P. King, Reactor Inspector
R. L..Moore, Reactor Inspector
N. L. Sa
o, Resident Inspector
J. W.
r
/, cto
tor
Approved by:
R. .
rlenja , Branch C ef
Dite
igned
Division of Reactor Proj cts
SUMMARY
Scope:
Inspections were conducted by the resident and/or regional inspectors in the
areas of plant operations, maintenance and surveillance testing, engineering,
and plant support.
Results:
Plant Operations
During a rod exercise test, a control rod did not fully insert when
dropped from 10% withdrawn, paragraph 2.3. Two valves left partially
open allowed RCS water from the decay heat mode lineup to be diverted to
the Borated Water Storage Tank, paragraph 2.4.
ENCLOSURE 2
9606120069 960520
ADOCK 05000269
GPDR
2
Maintenance
Fuel handling personnel damaged a new fuel assembly during equipment
checkout. Weaknesses in the licensee's procedure were identified,
paragraph 3.1.6. A 4160 volt breaker failed during testing due to
hardened grease in the breaker closing mechanism, paragraph 3.1.7.
Required testing of charcoal filters had not been performed as required
by TS, paragraph 3.2.4. An Unresolved Item was identified regarding the
licensee's resolution of recurring failures to a Main Steam valve and a
Low Pressure Service Water cooler outlet valve, paragraphs 3.3.2 and
3.3.3. A Non-Cited Violation was documented for deficiencies in the
procedure for adjusting chevron type valve packing, paragraph 3.3.5.
Engineering
One Violation was identified for failure to follow procedure for drawing
control, paragraph 4.3. One Unresolved Item was identified concerning
the operability of the SSF, Paragraph 4.1. The engineering self
assessment was effective in identifying strengths and problems in the
engineering area. Both the PORC and the NSRB oversight committees
functioned effectively in evaluating engineering activities. A sample
review of Nuclear Safety Modifications at Oconee identified no
programmatic problems. The safety evaluation program(10 CFR 50.59) was
being performed in an adequate manner, paragraph 4.2. The accuracy of
Keowee low voltage electrical drawings had improved following licensee
actions to correct errors identified in 1995, paragraph 4.3.
Although an example was identified in which a Vital-to-Operations
designated drawing was not updated, drawing distribution control was
generally good. Operability evaluations were adequately supported and
management review of operability evaluations was appropriately
challenging, paragraph 4.4.
Plant Support
Radiation Protection personnel performing a routine survey found a
slightly contaminated thermocouple in the scrap metal dumpster being
used for outage trash disposal, paragraph 3.1.4. The licensee's
Radiation Protection program was effectively implemented. The licensee
continued to improve upon ALARA initiatives, particularly in the
reduction of outage doses. The program to control liquid and gaseous
radioactive effluents was effective. The projected offsite doses from
those effluents were well within limits. The annual total body dose
estimate to the maximum exposed member of the public, calculated from
the 1995 environmental sampling results, was less than one quarter of a
mrem, paragraph 5.0.
6
ENCLOSURE 2
REPORT DETAILS
Acronyms used in this report are defined in paragraph 9.0.
1.
Persons Contacted
Licensee Employees
D. Berkshire, Senior Scientist, Radiation Protection
R. Bond, Director, Work Process
S. Bryant, Internal Assessment, Radiation Protection
- M. Bailey, Regulatory Compliance
S. Capps, Project Management
T. Coleman, Technical Specialist, Inservice Inspection
T. Coutu, Operations Support Manager
D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
R. Dobson, Modifications Manager
- W. Foster, Safety Ass urance Manager
J. Hampton, Vice President, Oconee Nuclear Station
- G. Hamrick, Manager, Chemistry
D. Hubbard, Maintenance Superintendent
B. Jones, Manager, Training
C. Little, Electrical Systems/Equipment Manager
B. Millsaps, Mechanical/Civil Equipment Engineering Manager
- D. Nix, Engineer, Regulatory Compliance
B. Norris, -Supervisor, Chemistry
B. Peele, Station Manager
G. Rothenberger, Operations Superintendent
J; Twiggs, Manager, Radiation Protection
B
J. Smith, Regulatory Compliance
P. Street, Supervisor Mechanical Engineering
R. Sweigart, Work Control Superintendent
" Attended exit interview.
Other licensee employees contacted included office, operations,
engineering,'maintenance, chemistry/radiation, technicians, craftsmen,
and corporate personnel.
2.0
PLANT OPERATIONS (71707 and 92901)
The inspectors reviewed plantoperations throughout the reporting period
to verify conformance with regulatory requirements, Technical
Specifications (TS), and administrative controls. Control room logs,
shift turnover records, temporary modification log, and equipment
removal and restoration records were reviewed routinely. Discussions
were conducted with plant operations, maintenance, chemistry, health
physics, instrument & electrical (I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost daily
basis.
Inspections were conducted on day and night shifts, during
weekdays and on weekends.
Inspectors attended some shift changes to
evaluate shift turnover performance. Actions observed were conducted as
required by the licensee's Administrative Procedures.
The complement of
2
licensed personnel on each shift inspected met or exceeded the
requirements of TS.
Operators were responsive to plant annunciator
alarms and were cognizant of plant conditions.
Plant tours were taken throughout the reporting period on a routine
basis.
During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed.
2.1
Plant Status
Unit 1 operated at or near full power throughout the reporting period.
Unit 2 operated at full power until March 28, 1996, when the unit began
shutting down for a scheduled 33-day End-Of-Cycle 15 Refueling Outage.
The outage schedule was extended until May 10, 1996, to incorporate
additional steam generator (SG) tube plugging.
Unit 3 operated at full power until March 16, 1996, when the unit
tripped during the performance of PT/O/A/0610/22, Degraded Grid
Switchyard Isolation, and Keowee Overfrequency Protection Functional
Test as documented in NRC Inspection Report 269,270,287/96-05. The unit
was returned to full power operation on March 26, 1996, and remained at
full power throughout the rest of the inspection period.
2.2
Mid-loop/Reduced Inventory Activities
During the Unit 2 End-Of-Cycle 15 Refueling Outage, the licensee reduced
RCS Inventory and reached the mid-loop operations level on April 1,
1996. This was done for the purpose of installing nozzle dams in the
steam generators. The inspectors reviewed the licensee's program prior
to the reduction of RCS inventory and verified that the requirements
were met while operating at the reduced inventory levels as specified in
procedure OP/1/A/1103/11, Draining and Nitrogen Purging of RCS,
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 mid-loop.
The inspector verified that the requirement for two independent trains
of RCS level monitoring was met while at reduced inventory. This was
accomplished by use of two permanently installed instruments (LT-5A and
LT-5B) and two temporary ultrasonic instruments. 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 two
sources of inventory makeup and cooling were available for operation.
Multiple sources of offsite power were also available. The inspector
ENCLOSURE 2
3
reviewed the licensee's contingency plans to repower vital busses from
available alternate electrical power supplies in the event of the loss
of the primary source.
Unit 2 was in reduced inventory status for approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />.
During that time, the licensee implemented and maintained the
requirements specified by procedure while accomplishing reduced
inventory operations without incident. The inspector concluded that
this reduced inventory evolution was well coordinated and controlled.
2.3
Reactor Manual Trip Test, PT/0/A/305/01, and Control Rod Drive Trip Time
Testing, PT/0/A/0300/01.
The inspector reviewed documentation from the Unit 3 reactor manual trip
test that was performed on March 24, 1996, to verify CRDM operability
prior to unit restart. Control rod drive groups, 1 through 7, were
individually withdrawn to 10 percent and tripped. Control rod drive
breakers were verified to open upon pressing the reactor manual trip
pushbutton. Although the test was to verify that the control rod drive
breakers opened, a problem was experienced in that control rod #9 in
group 5 indicated that it remained at 7 percent withdrawn and all other
rods within the group indicated fully inserted at 0 percent withdrawn.
Operators took immediate actions to verify that an adequate shutdown
margin existed and to get plant management involved to resolve the
problem. The exact cause of the rod indication problem was not
determined. However, it was the general consensus that the rod drop
inertia was very low because of dropping the rod from only 10 percent
out of the core and being in the hydraulic damper region of the rod drop
area. This hydraulic area is designed to slow drop speed to prevent rod
damage.
A PORC meeting reviewed the problem and made the decision to perform
PT/0/A/0300/01, Control Rod Trip Time Testing, which involved pulling
the rods, one group at a time, to the full-out position, trip the group,
and record the time required for the rods to drop into the core. Each
group, 1 thru 7, were tested and all rods fell into the core within
acceptable time limits.
Problem Investigation Process, 3-096-0594, was generated to document and
track the issue for further evaluation and long-term corrective actions.
This issue is addressed further in paragraph 3.2.2, Reactor Manual Trip
Test.
2.4
LPI Valve Leakage
During the Unit 3 trip and cooldown on March 16 and 17, the LDST level
began decreasing when the LPI system was valved in to place the unit in
the decay heat removal mode. The licensee investigated and determined
that two manual valves, LP 40 and LP 41 were partially open and leaking
ENCLOSURE 2
4
by their seats. The valves are in the LPI recirculation back to the
BWST and are normally shut. One valve was open 3/4 turn and the
otherwas open 1 turn. The leakage through the valves back to the BWST
was approximately 10 gpm. The valves are located in a difficult
position for manual operation, and the licensee concluded they were
inadvertently left partially open the last time they were operated.
The licensee has imposed a limit of 5 gpm total leakage from the sump
recirculation flow path back to the BWST. This limit ensures that the
10 CFR 100 release limits would not be exceeded. This is considered a
secondary release path from the BWST following a core damage accident.
A limit of 2 gph for direct leakage from the recirculation flow path is
stipulated in T.S. 4.5.5, Low Pressure Injection System Leakage.
The licensee performed a past operability evaluation and determined that
although the self-imposed secondary leakage path limit was exceeded, the
particular case event would not have exceeded 10 CFR part 100 limits.
The LPI System was therefore operable.
Within the areas reviewed, there were no Violations or Deviations identified.
2.5
Operations Area Followup Issues
2.5.1 (Closed) URI 270/95-03-03, Valve Configuration
The inspector reviewed Unresolved Item 270/95-03-03, Valve
Configuration, and determined that a similar issue of configuration
control had been subsequently addressed in Violation 269,270,287/95-18
01, Inadequate Configuration Control.
Based on the open violation, URI
270/95-03-03 is closed.
2.5.2 (Closed) LER 269/94-02, Inappropriate Action Results In False High
Steam Generator Level, Causing Loss of Main Feedwater And Reactor
Trip
On February 26, 1994, at approximately 6:57 a.m. Unit 1 experienced an
anticipatory reactor trip on loss of both main feedwater pumps. The
loss of both feedwater pumps was caused by an indicated high steam
generator water level signal in the integrated control system (ICS).
The indicated high water level resulted when the neutral wire was lifted
from an internal ICS power supply to the feedwater valve D/P circuitry
that had failed and was smoking. The lifted neutral wire also resulted
in the loss of power to the 1B1 and 1B2 SG signal monitors which
simulated high SG level in the lB SG. As documented in NRC IR
269,270,287/94-07 the post trip response was normal and emergency
feedwater initiated as required to maintain SG levels and maintain the
unit in hot shutdown. The ICS power supply was replaced and the unit
was returned to service at 1:37 a.m., on February 27, 1994.
ENCLOSURE 2
5
The licensee determined that the root cause of the this event was
inappropriate action. A contributing cause was equipment failure due to
the failure of the output loading resistor in the ICS power system. As
previously mentioned the ICS power supply was replaced and the circuit
was tested. The licensee removed the daisy chain neutral wiring
configuration which placed an unnecessary burden on I&E personnel from
the Main Feedwater Valve D/P ICS power supplied on Unit 1 and Unit 2.
Unit 3 did not have the daisy chain neutral wiring configuration. The
inspector reviewed all completed WOs. The licensee discussed this event
with the I&E personnel as part of their corrective action. The
inspector concluded that all corrective actions associated with this LER
were complete. This item is closed.
2.5.3
(Closed) IFI 50-269,270,287/94-37-02, Monitor General Fundamentals
Examination (GFE) Results For Improved Performance.
During the December 1994 inspection, NRC reviewed the recent performance
of operator training classes in the General Fundamentals Examination
area. The overall performance was considered poor, and the licensee
proposed several corrective actions to improve the program. The
inspectors concluded that the root causes identified and the corrective
actions proposed appeared to be comprehensive and adequate, but
determined that the program performance should be monitored to ensure
the adequacy of the corrective actions.
During the inspection period, the inspectors reviewed the recent results
of the GFE class performance. The results indicate that the corrective
actions applied to address the previous weaknesses had been effective.
All students passed the examination, with the lowest grade at 92% and
the class average at 95%. This item is closed.
3.0
Maintenance and Surveillance Testing (62703, 61726, 62700, and 92902)
3.1
Maintenance Activities
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work that
was not within the skill of the craft. Activities, procedures and work
orders were examined to verify that proper authorization and clearance
to begin work was given, cleanliness was maintained, exposure was
controlled, equipment was properly returned to service, and limiting
conditions for operation were met. The following are maintenance
activities which were observed or reviewed in whole or in part.
3.1.1 NSM-22873, AKI Modify MFDW Control On MSLB, WO 950773
On March 13, 1996, the inspector observed activities in progress during
the installation of the brackets and tubing for the mounting of pressure
transmitters associated with the main steam line isolation modification.
ENCLOSURE 2
6
The modification was to isolate feedwater in the event of a main
steamline break inside containment to prevent over-pressurization and
possible containment rupture. Portions of this Unit 2 modification were
being performed prior to the refueling outage (Unit 2 EOC 15) scheduled
for March 28, 1996, to ensure ample time for the process tie-ins and
testing during the outage.
The work effort was in accordance with the design documents and work was
performed to acceptable standards.
3.1.2 Install STAR Equipment For PIF In RPS Ch. A,B,C,&D, WO 95056617
On April 1, 1996, the inspector reviewed activities in progress to
replace the existing Unit 2 Bailey 880 analog-based RPS
Flux/Imbalance/Flow trip strings in RPS Channels A,B,C,&D with B&W
Nuclear Technologies digital-based STAR module trip string. Each STAR
module trip string consists of a Serial Bus Isolation Module, a STAR
Processor module and an Analog Voltage Isolation Module.
The inspector determined that a thorough safety evaluation had been
performed for the modification and the work activity was in accordance
with the procedure guidance. All work had been properly documented and
the documentation was current.
3.1.3 ICS Unit Load Demand Load Limits Calibration, WO 96006915
The inspector reviewed calibration of the ICS unit load control module.
The effort was performed on April 1, 1996, and was in accordance with
the applicable procedure, IP/O/B/0321/002, ICS/Unit Load Demand Load
Limits.
The work observed was performed to acceptable standards.
3.1.4 Hot Thermocouple Found In Dumpster, WO 94023013
On April 8, 1996, while performing a routine survey of scrap metal
dumpster contents the licensee identified a thermocouple, 2TE0106, in
the dumpster reading 400 corrected counts per minute using an RM-14
frisker. The licensee performed a computer search to identify a WO
associated with the thermocouple. The licensee identified that the
thermocouple was associated with WO 94023013-03, TDEFW Install
Hangers/Tray. The maintenance crew involved with the disposal of the
thermocouple thought that because RP had performed swipes of the area
and the thermocouple was removed from a dry socket the equipment was
clean. On April 11, 1996, the licensee performed some additional
training for maintenance personnel to discuss lessons learned from this
incident. One of the main issues covered was that, as a good practice,
all equipment removed from the turbine building would be frisked prior
to disposal.
The inspector concluded that the licensee's routine survey
acted as a successful barrier to improper disposal of the thermocouple.
ENCLOSURE 2
7
S
3.1.5 Change Voltage Taps On Keowee's Main Step Up Transformer,
ON0E-9047
On April 17, 1996, the inspector observed portions of the licensee's
implementation of minor modification, ONOE-9047, Change Voltage Taps On
Keowee's Main Step Up (MSU) Transformer. As described in the associated
10 CFR 50.59 evaluation, the change of the transformer's taps did not
alter the function of the transformer. The tap change only increased
the transformer voltage from 218,500 volts to 224,250 volts. The
increase in system voltage initiated the need to change the taps on the
Keowee's MSU transformer. Keowee generating voltage remained the same
(13.8 kV) after the tap change. The inspector concluded that the work
observed was performed to acceptable standards.
3.1.6 New Fuel Assembly Damage
On April 8, 1996, fuel assembly (FA) NJO88U was damaged when refueling
operators attempted to place it in the Unit 1/2 Spent Fuel Storage
Building East upender and traverse carriage.
The FA was a new, unburned
assembly. The operation being performed was a check-out of the upenders
after counterweights had been adjusted. The licensee was using an
actual FA rather than the dummy FA because the dummy weight and weight
distribution are not equivalent to an actual assembly. The FA was first
placed in the West upender carriage, traversed into the Reactor
Building, and removed without incident. When the same process was
attempted for the East upender, the operators experienced several
problems, which eventually resulted in damage to a single grid strap in
the new assembly.
After the successful check-out of the West upender, the refueling bridge
was moved to the indexing mark for the East upender, and the FA was
lowered from the mast into the upender. At approximately 3 feet into
the upender carriage, the hoist underload limit stopped the hoist. The
underload limit indicates the FA has encountered resistance sufficient
to take some of the FA weight off the load cell for the hoist. The
operators raised the FA back into the mast, and repositioned the bridge
according to directions from the fuel handling "spotter."
The spotter,
using binoculars, saw that the FA was misaligned over the upender
carriage and directed the bridge operator to move in the north direction
via manual indexing. After repositioning approximately 1/4 inch, the FA
was again lowered into the upender. The FA again experienced contact
and an underload limit. The operators attempted several minor bridge
position changes, and eventually moved the bridge as much as 3 inches
from the original indexing mark.
At least one of the position changes occurred while the fuel assembly
was partially inserted. A-later root cause evaluation determined that
the fuel assembly was damaged during the repositioning while the bottom
of the FA was partially stuck in the upender. The upender itself was
found to be out of position from true vertical.
The root cause of the
ENCLOSURE 2
8
upender aligned from true vertical is still under investigation by the
licensee. When operators drove the bridge to reposition over what the
spotters saw as the true upender position, the FA was distorted. The
distortion forced the FA out of the alignment guides inside the mast.
When the operators attempted to raise the assembly back into the mast,
the grid strap was damaged slightly at two corners. When operators
realized the FA was stuck and couldn't be raised or lowered, they
indexed back toward the index mark. The assembly was then successfully
raised back into the mast. The FA was returned to the vendor (B&W) and
repaired.
The licensee performed a root cause and Human Performance Evaluation.
The evaluation determined that the damage was due to manual indexing of
the bridge while the fuel assembly was inserted and lodged in the
upender carriage. The operators moved the bridge as much as 3 inches
off the indexing mark in an attempt at aligning the mast over the
upender. Since a fuel assembly has almost no lateral strength or
support, the assembly was sprung out of alignment and sustained damage
during the subsequent withdrawal into the mast.
During and prior to this event, there was no effective restriction on
manual repositioning or indexing while a fuel assembly is out of the
mast. This is identified as a weakness in the licensee's fuel handling
procedure. Prior to resuming fuel handling, the licensee implemented
procedure changes to restrict indexing whenever the fuel assemblies are
not fully retracted into the mast. The inspector reviewed the
licensee's assessment, root cause evaluation, and corrective actions.
The licensee's actions were thorough and accurate. The corrective
actions were appropriate for the event.
3.1.7 4160 Volt Breaker Failure
On March 9, 1996, during testing of the Emergency Power Switching Logic,
4160 volt breaker 2S2 failed to close when the breaker close circuit was
actuated. The breaker is the tie for Standby Bus 2 to Main Feeder Bus
2. The breaker is a type ABB Series HK 4kV volt, 3000 amp. The breaker
was examined and found to have binding of the closing mechanism's spring
guide sleeves. The two closing springs are double springs with an inner
and outer spring and sliding sleeves between the springs. The sleeves
have close clearances and require lubrication (grease) to eliminate
sliding friction when the springs expand to close the breaker. The
licensee determined that the grease on the sleeves had hardened and
caused binding of the mechanism. The spring/sleeve assembly had not
been periodically cleaned and lubricated since initial installation,
approximately 17 years ago.
The licensee's root cause evaluation determined that the manufacturer's
technical manual did not specifically refer to a requirement to grease
the spring/sleeve assembly. The only reference is to "periodically
grease the operating mechanism."
The licensee had interpreted the
ENCLOSURE 2
9
operating mechanism as the linkages and pivot points in the breaker
mechanism, and had not considered the spring/sleeve assembly to be part
of the operating mechanism. NRC Information Notice (IN) 93-26, "Grease
Solidification Causes Molded-Case Circuit Breaker Failure To Close"
described a grease hardening failure mechanism. The IN did not
specifically refer to the spring/sleeve mechanism as requiring
lubrication. The IN referred to recommendations for switchgear
maintenance including Westinghouse Owners Group guidelines on DB and DS
breaker maintenance, industry guidance such as National Electrical
Manufacturers Association (NEMA) publications, and American National
Standards Institute/Institute of Electrical and Electronic Engineers
(ANSI/IEEE) standards. The licensee had received and reviewed the
information in the IN, but had not identified the spring/sleeve assembly
as a lubrication point.
The licensee replaced the spring/sleeve assembly for the 2S2 breaker,
and disassembled all other breakers of the same type. Several other
breakers were found with hardened grease, but were not binding in
operation. All the breakers were cleaned, lubricated, and placed back
in service. A change to the maintenance procedure (SI/O/A/2400/013)
Refurbishing 5HK, 7.5HK, and 15 HK Air Circuit Breakers, was implemented
which stipulates periodic cleaning and lubrication of the breakers.
The inspectors witnessed the disassembly, inspection, and reassembly of
several of the breakers. Corrective actions were comprehensive and
thorough.
3.2- Surveillance Activities
The inspectors observed surveillance activities to ensure they were
conducted with approved procedures and in accordance with site
directives. The inspectors reviewed surveillance performance, as well
as system alignments and restorations. The inspectors assessed the
licensee's disposition of any discrepancies which were identified during
the surveillance. The following are surveillance activities which were
observed or reviewed in whole or in part.
3.2.1 Steam Generator Secondary Hot Soak, Fill, Drain and Layup,
OP/3/A/1106/08
On March 24, 1996, the inspector observed portions of operations
procedure OP/3/A/1106/08, Steam Generator Secondary Hot Soak, Fill,
Drain and Layup. The licensee had to generate a new enclosure for
OP/3/A/1106/08 to perform a steam generator blowdown. The new Enclosure
3.24, Steam Generator Blowdown, was performed to maintain chemistry
control at RCS temperature <250 F. The inspector concluded that the
licensee adhered to the guidance of the associated procedure. No
problems were identified.
0
ENCLOSURE 2
10
3.2.2 Reactor Manual Trip Test, PT/0/A/305/01
On March 24, 1996, while the licensee was performing PT/O/A/305/01,
Reactor Manual Trip Test, rod #9 of group 5 failed to indicate that its
position was zero percent. The rod indicated it was seven percent
withdrawn with all other rods in the group indicating zero percent
withdrawn. The licensee generated PIP 3-096-0594 to address this
problem.
The licensee performed a 10CFR part 50.59 evaluation for a restricted
change to PT/0/A/305/01 for performing rod exercising while the unit was
shutdown. To withdraw the rod for retesting, the procedure as written
required driving the rods in and aligning rod position indicators (PI).
The licensee determined if the rod was actually binding within the fuel
assembly, driving in could possibly damage the control rod. Therefore,
a restricted change as documented as Enclosure 13.4 allowed pulling the
individual rod back out for retesting without PI alignment to determine
whether the indication was accurate and the rod was actually not fully
inserted. The inspector observed the performance of Enclosure 13.4 of
PT/0/A/305/01 in the control room. The Enclosure was repeated three
times successfully with good indication. No further problems were
identified.
.
3.2.3 3RC-164 and 3RC-165 Inoperable, PT/3/A/0150/22A
On April 7, 1996, while performing PT/3/A/0150/22A, Operational Valve
Stroke Test, 3RC-164 could not be closed via its reach rod and 3RC-165
could not be opened or closed via its reach rod. The licensee initiated
PIP 3-095-0703 and PIP 3-096-0704 to address these issues.
These RC sampling valves provide two functions. One is to be capable of
being opened via its reach rod to obtain a post-accident RCS sample at
the Post Accident Liquid Sampling System (PALS) panel.
The second
function is to be capable of being closed via its reach rod to isolate
containment after the samples are obtained.
The licensee determined that both valves were presently inoperable and
past inoperable since December 10, 1995, which was the date of the last
successful stroke test.
With the valves being inoperable the licensee
did not have a method to obtain a post accident sample of the RCS via
the PALS panel.
The licensee repaired the valves on April 20, 1996, as
documented in WO-95047472 and WO-95047471. The'licensee plans on
replacing the valves during upcoming outage. With the valves repaired,
the licensee was within its 90% operability limit for the panel as
described in the licensee's PALS-NUREG 07373 Position. The inspector
concluded that the licensee's actions were appropriate to address the
problem.
ENCLOSURE 2
11
3.2.4 Charcoal Filter Testing Requirements
On April 2, 1996, the licensee determined that the surveillance testing
performed per TS 4.5.4, Penetration Room Ventilation System, was not the
testing specified in the TS.
The TS requires that the filter system be
declare inoperable if testing is not performed per ANSI N510-1975.
Since 1992 the testing actually performed by the licensee is per ASTM
D3803-1989. Although the licensee considers the testing performed is
more current, conservative, and in general use throughout the industry,
the TS is specific regarding the testing to be performed. Therefore,
the licensee decided to conservatively declare the Penetration Room
Ventilation System inoperable and enter the LCO for TS 3.15.1. Since
the LCO for TS 3.15.1 requires the shutdown of all three Oconee units
within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if the system is found to be inoperable, the licensee
requested an emergency TS change to surveillance requirement 4.5.4. NRC
reviewed the emergency TS change request and issued the change at
approximately 7:00 p.m., on April 2, 1996. The change to the
surveillance requirements stipulates that the testing performed on the
charcoal filters is conducted per ASTM D3803-1989.
Although the evaluation performed by the licensee's Engineering
department concluded that the testing actually performed was adequate to
ensure functional operability of the filters and the system, the
licensee decided to declare the system inoperable, enter the LCO, and
process an -emergency TS change. The inspector considers the actions
taken by the licensee to have been conservative, and ensured full
compliance with the requirements.
3.3
Maintenance Implementation
The inspectors observed/reviewed portions of selected maintenance
activities as detailed below to determine if these activities were
conducted in accordance with TS requirements, approved procedures and
appropriate industry codes and standards. In addition to verification
that procedures were followed and TS requirements were met, the
inspectors verified that personnel were knowledgeable and qualified,
that post maintenance testing (PMT), was performed and was appropriate
and, that calibrated measuring and testing devices were used.
3.3.1 Condensate System Valve ON1C-VA0061
A review of work history (WH) reports from 2/4/93 to the
present,disclosed the following information:
WO-93009557-01 (2/4/93) This WO was written to correct an alignment
problem between the limit switch and the valve shaft. Work was
completed on 2/11/93 and the valve functioned properly; however, the
root cause of the problem was not determined.
ENCLOSURE 2
12
WO-95055195-01,-07 (7/16/95) This WO was written to investigate and
correct a pinging noise coming from the subject valve or associated
piping, to rebuild the actuator and perform a leak check. By record
review and through discussions with cognizant licensee personnel the
inspectors learned that the pinging ceased when the bypass around the
subject valve was throttled open and it returned when the bypass was
closed. The subject valve was identified as a Fisher butterfly flange
valve, 7600 Series. The valve was removed from the line and inspected
without finding evidence of a foreign object. The valve was repacked
and reinstalled in the line. The licensee stated that a visual
inspection inside the line failed to detect a foreign object. The
licensee could only speculate on the nature or origin of the suspected
foreign object. However, they concluded that if a foreign object did
exist, it likely came to rest in the bottom of the cooler just
downstream from the subject valve where it would not pose a significant
threat to the system. The licensee plans to look for this object when
access to the cooler becomes available during the next refueling outage.
WO-96017607 (2/28/96) This WO was written to investigate a problem with
the 1C-61 Moore Controller which did not perform its intended function
during the Unit 1 trip on 2/28/96. By record review and through
discussions with cognizant licensee personnel, it was learned that the
valve failed to open on demand from the controller. The licensee's
investigation determined that the problem was related to a
malfunctioning valve positioner which was subsequently replaced. During
subsequent testing it was noted that the valve was sluggish to respond
to a signal from a close to an open position. To correct the problem,
the licensee replaced the relay assemblies used to control both valve
positions. Through this review the inspector concluded that the
licensee's corrective actions were appropriate as the controller was
returned to normal operation.
3.3.2 Main Steam Valve 1MS-77
A review of WH records from (10/1/92) to the present disclosed the
following information.
WO-92074505-01 (10/1/92) This WO was written when the subject valve
failed to close in auto mode during power reduction. An inspection by
maintenance disclosed that one of the phases at the MCC had opened on
overload. Following reset of the overload, Operations cycled the valve
which operated satisfactorily. A functional test verified the valve's
operability.
WO-94027312-01 (5/1/94) This WO was written in response to a breaker
trip on power decrease. Upon investigation, maintenance discovered a 25
ohm phase to ground, on phase Z with the breaker open.
No failures were
identified and the trip settings were increased from 2 to 2.5. The
valve could not be cycled fully until the next scheduled Unit outage.
ENCLOSURE 2
13
WR-95019982 (4/27/95) Although no work order was written for this
problem, maintenance inspected the subject valve when it failed to close
on demand from the control room. The problem was attributed to one of
the three phase overloads having-tripped and not resetting. This
problem was corrected by changing the overload block. Following this
corrective action, Operations cycled this valve and determined that it
worked normally.
WO-96017559-01 (2/29/96) This WO was written when the limitorque
operator on this valve failed to close in response to a turbine trip
signal.
An inspection by maintenance found the valve disc was wedged
against the back seat of the valve. Subsequently, the valve's open
limit was adjusted to specification. However, when it was cycled to
test operability the breaker tripped when energized. Additional testing
revealed that the operator motor had degraded and required replacement.
A functional test following motor replacement showed the valve was
functioning satisfactorily. On 2/28/96 the licensee issued PIP 1-096
0417 to evaluate the problem. The evaluation determined that
circumstances suggested that Maintenance had set the operator's open
limit too close to the back seat of the valve causing it to travel
against the back seat whenever it was fully opened. This required an
excessive amount of torque to free the valve disc from its open
position. The heat generated was sufficient to trip the breaker on
thermal overload and it eventually caused the motor to fail.
Through this review the inspectors determined that this valve had a
history of maintenance related problems in that critical settings which
are vital to good performance were not closely controlled. Each time the
valve failed, the symptom was fixed without addressing the root cause of
the problem. Although PIP 1-096-0417 evaluated the reasons for the
valve's failure, the root cause and the steps taken to prevent its
recurrence were not addressed. Until the licensee completes an
evaluation for root cause this is identified as Unresolved Item (URI)
269/96-04-04, Root Cause Assessment of Failures to Valves 1MS-77 and
3.3.3 Low Pressure Service Water Valve 1LPSW-254
A review of WH reports from 6/15/94 to the present disclosed the
following corrective maintenance activity.
WO-94045550-01 (6/15/94) This WO was written to investigate and repair
adverse conditions which resulted in restricted flow through valve
WO-95085230-01 (11/7/95) was written to inspect the subject valve's
operator for a sheared key and to determine the reason for the low flow
to 1A LPI cooler. Upon investigation maintenance discovered that the
low flow problem was due to the failure of the subject valve. Through
discussions with cognizant licensee personnel and by review of WH
ENCLOSURE 2
14
reports and PIP 1-095-136, dated 11/6/95, the inspectors ascertained the
following information. The subject valve is a manually operated, Fisher
10 inch butterfly valve 150# Class model No A31A.
Within these areas the licensee's investigation of the failure revealed
that the key connecting the operator to the stem had vibrated out of the
keyway thus allowing the disc to partially close and restrict flow to
the 1A LPI cooler. The vibration was due to cavitation induced by
control valve 1LPSW-251. As stated in the PIP, the degree of cavitation
and the resultant vibration are influenced by the flow velocity through
valve 1LPSW-251 which decreases and levels off as the flow rate
increases.
Also, by records review the inspectors determined that in 1988 the
licensee issued a station Problem Report to address a similar failure on
this valve which was attributed also to cavitation and vibration. These
findings led to a Design Study - completed on June 20, 1991.
From this
study, the licensee replaced, during the 1992 outage (1EOC-14), valves
1LPSW-251 and -254, under modification NSM ON-12888. However, it
appears that this valve replacement did not address or correct the root
cause of the problem as evidenced by the recurrence of this valve's
failure on 11/6/95, for the same reason. On this date, the problem was
identified when the LPI system was being aligned to perform the 1A LPI
cooler test portion of Procedure PT/0/A/251/18 "LPI Cooler test."
Basically, the test calls for a flow rate of 5000-5200 gpm of LPSW
through the lA LPI cooler. However, when Operations opened 1LPSW-251 to
raise the LPSW flow from 2500 gpm to 5000+ gpm the meter indicators
showed no change in flow rate in the 1A LPI cooler. Since identifying
the failed key problem on 11/6/95, the licensee made several attempts to
use a key that would withstand the rigors of operating conditions. This
was finally achieved by using a longer key, equal to the length of the
keyway, and capturing the key in place by bolting a washer plate to the
end of the shaft. The evaluation of system operability document in
Section 9 of PIP 1-095-1396 addressed operability from 1EOC-14 (12/3/92)
to 1EOC-16 (11/2/95), design basis requirements, and root cause
analysis. It concluded that during the above time frame it could not be
determined whether full LPSW flow could have been maintained to the 1A
LPI cooler for the duration of accident mitigation. Also, because under
existing valve conditions sufficient justification could not be obtained
to guarantee that during that time frame 1LPSW-254 would have remained
in the fully open position upon initial ES activation, the 1A LPI train
was considered inoperable. The Licensee issued a Licensee Event Report
LER 269/95-07 (Rev. 1) pursuant to 10 CFR 50.73 requirements. In
addition, the licensee issued PIP 0-095-1491 to address and track the
proposed resolution and corrective actions to be taken on this problem.
The licensee's System Engineering Group was leading an effort to
evaluate the 1LPSW system vibration problem to determine necessary
correction actions.
Pending completion of the evaluation this item is
unresolved (URI 269/96-04-04) as identified above in paragraph 3.3.2.
ENCLOSURE 2
15
The issues associated with LER 269/95-07, Rev. 1,
discussed above, will
be tracked in this unresolved item. LER 269/95-07, Rev. 1 is considered
closed.
3.3.4 SSF Diesel, Periodic Test
WO 96018726-01 I/R the Governor Control on SSF Diesel Generator
While performing PT/0/A/600/21, SSF Diesel Generator Operation, on March
4, 1996, diesel governor and generator control problems were
experienced. The diesel was shutdown and subsequently restarted per
OP/0/A1600/10 and speed increased to 900 RPM. At this point the
governor was cycling with noticeable change in engine speed indicated on
the engine tachometer. The diesel was again shutdown, but later
restarted and paralleled to Unit 2. At this time problems were
encountered with control on speed, VARs, voltage, and watts. The diesel
was shutdown, placed in a 7-day LCO and Work Request 96009782 was
written.
WO 96018726-01 was also issued to investigate and repair the governor
control on the SSF diesel generator. A diesel vendor representative
arrived at the site to assist in the troubleshooting and repair
activities. The vendor representative determined by questioning
licensee personnel, that the problem was electrical and that symptoms
indicated an intermittent control signal to the governor. The vendor
representative then developed and recommended additional instructions
for troubleshooting the SSF diesel generator which included visual
verifications, governor response and electrical input/output checks.
On March 5, 1996, the inspectors reviewed the work order, the additional
troubleshooting instructions provided by the vendor representative, and
procedure IP/0/A/0100/001 which was the controlling procedure for
troubleshooting and corrective maintenance. Troubleshooting activities
were also observed with the diesel in auto-idle-start and at normal
rated speed with the diesel removed from the grid, tied to the
generator, and loaded with the auxiliary service water pump. All
governor inputs and outputs were checked and found to be correct. The
diesel ran smoothly during the entire run.
Further investigation then
focused on the motor operated potentiometer (MOP) as the most probable
cause of the previously reported diesel instability. A test was
performed to verify the satisfactory operability of the MOP. No erratic
operation occurred during the troubleshooting analysis. The license
concluded that the initial problem had been caused by the MOP having a
wiper-to-winding interference and this interference had been "cleaned
off" during the unloading of the diesel generator. For further
verification that the diesel would run satisfactorily, operations
performed a 60 minute run with the diesel tied to the grid for full
load. All systems operated as designed.
S
ENCLOSURE 2
16
As a result of troubleshooting the governor operation, Problem
Investigation Process (PIP) form 1-096-0461 was issued on March 5, 1996,
and the licensee determined that the following preventive measures
should be taken: (1) keep a spare governor module in stock, (2) have a
"matched pair" of actuators set up and installed as a long-term solution
to load sharing between the two tandem engines, (3) consider upgrading
- from the MOP reference system to a later more stable digital reference
unit, and (4) personnel responsible for the operability and maintenance
of the SSF diesel generator attend further training on the SSF
installation specific governor system. In addition, operations elected
to perform PT/0/A/0400/11 (which is a quarterly SSF diesel generator
test) four additional times on a weekly basis to see if the problem
recurred. No problems occurred during these four tests, and the diesel
generator was returned to the normal test schedule.
3.3.5 WO-96018085-01 I/R Valve 1HP-120
This work order was issued on March 3, 1996, to determine why valve 1HP
120 was sticking and conduct an appropriate repair. Valve 1HP-120 is
used to maintain the proper level of water in the pressurizer. The
licensee suspected the valve was sticking because the packing was too
tight and issued MP/0/A/1200/001, a generic procedure entitled:
"Adjusting and Packing," to loosen the packing nuts several flats. The
inspectors selected this corrective maintenance to observe and on March
5, 1996, met with the maintenance lead technician to coordinate the
inspection. The inspectors discovered, however, the procedure had been
rejected by the lead technician and needed to be revised because it did
not give instructions for loosening the packing. The next day the
inspectors again met with the maintenance supervisor to observe the
corrective maintenance on this valve. This time the inspectors
discovered that the procedure had been rejected by the maintenance
supervisor because the cover page of the procedure specifically
prohibited its use on chevron packing. However, the inspectors had
reviewed the maintenance history of this valve going back two outages in
time. This history had indicated that this valve had the same reported
problem on December 26, 1995, and the packing nuts were subsequently
loosened two flats at that time. Discussions with the maintenance
supervisor concerning the previous maintenance revealed that this
procedure had inadvertently been used to loosen the nuts at that time.
The inspectors also examined previous records where the valve had been
repacked and found that another procedure for refurbishing the valve had
been used to repack the valve each time. However, the licensee did not
have a procedure for loosening chevron packing. Failure to have and use
an applicable procedure which covers the corrective maintenance to be
performed on a high temperature/high pressure safety-related valve is a
violation of NRC requirements. 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: Non-Cited Violation 50
269/96-0401, Inadeguate Procedure Used to loosen lackingi Nuts on
Chevron Packing. The licensee subsequently decided not to work on valve
ENCLOSURE 2
17
9
1HP-120 at that time, because operations reported the valve was
functioning correctly. A review of the maintenance history, however,
indicated that this valve had a history of sluggish and rough movement,
but had not been disassembled for inspection in over seven years.
Discussions with the licensee revealed that PIP NO. 1-096-0461 had been
issued and plans were being made to disassemble the valve next outage to
evaluate the root cause of the valve sticking. A review of the
equipment failure history, conducted by the licensee, revealed that this
problem existed on the same valve in Units 2 and 3.
3.4
Maintenance Area Followup Issues
3.4.1 (Closed) IFI 95-05-01 Limited Access Weld Examinations
The inspector met with cognizant licensee personnel to discuss and
review the status of limited access weld examinations documented in
Inspection Report 95-05. All welds in this category have been
identified and classified according to the action required to achieve
code compliance. Examinations have been performed when practicable and
for others, requests for code relief have been submitted to NRR.
Accordingly, the inspector closed this item and will continue to monitor
the status of this matter as a routine inspection item.
.
Within this area, one Non-Cited Violation was identified in paragraph 3.3.5.
4.0
ENGINEERING (37551, 37550, 40500, and 92903)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
4.1
Operability Of High Pressure Injection Valves
On March 19, 1996, the licensee notified the NRC per 10 CFR 50.72 that
as a result of evaluating Generic Letter 89-10 data, an engineering
analysis determined that inboard containment isolation valves 2HP-3 and
3HP-3 (Letdown Cooler A outlet) may not be able to close against full
differential pressure under certain accident scenarios. A single
failure of their associated outboard containment isolation valves (2HP-5
and 3HP-5) for the subject containment penetration could potentially
result in the failure to isolate the containment following an accident.
As a result, the licensee closed 2HP-3 and 3HP-3. PIP 0-096-0544 was
generated on March 18, 1996, to document, evaluate, and track the issue
to completion. The licensee subsequently retracted the associated 50.72
report on April 10, 1996, when further engineering analysis revealed
that 2HP-3 and 3HP-3 were both past and presently operable. This
analysis was reported to have evaluated the valves during each
millisecond of the design basis accident and concluded that the valves
could have stroked against the expected differential pressures during
ENCLOSURE 2
18
the design basis accident. Based on the licensee's evaluations, valves
HP-3 & 4 (Letdown Cooler B outlet) for Units 1, 2, & 3 are operable for
a design basis accident scenario.
On March 20, 1996, the licensee reported to the NRC per 10 CFR 50.72
that reactor coolant system letdown valves HP-3 and HP-4 on Units 1,2,&
3 were not capable of closing during an event which requires the SSF to
be placed in operation. Engineering analysis determined these valves
may not be able to close against full differential pressure under
certain accident scenarios.
These valves are required to close to
prevent loss of reactor coolant system inventory during an SSF event.
For an SSF event where pressures could reach 2790 psid, valves HP-3 & 4
for each of the 3 units were determined to be past and presently
inoperable. Consequently, the licensee changed their abnormal operating
procedures to require the operators to close valve HP-5 for the affected
unit prior to leaving the control room to activate the SSF. Valve HP-5
is down stream of the HP-3 and 4 valves and will reduce the higher
differential pressures across these valves once they begin to close. As
a result, valves HP-3 & 4 for Units 1, 2, & 3 are operable.
The past inoperability of Units 1, 2, & 3 valves HP-3 & 4 causes the SSF
Reactor Coolant Makeup System to be inoperable in excess of TS 3.18.4,
which in turn causes the SSF to be inoperable. The TS requires the SSF
_RC Makeup System and the SSF to be operable when the RCS is above 250
degrees F, or restored to operable status within 7 days. As a result of
the discerned inability of the valves to close against design pressure,
the RC makeup System and the SSF may have been inoperable from initial
installation until March 20, 1996, when the procedure change was
effected. The licensee was still evaluating this item at the close of
the inspection period. This item will be identified as an Unresolved
Item pending completion of the licensee's evaluation of the closure
capability of the isolation valves: Unresolved Item 269,270,287/96-04
02, Potential Inoperability Of SSF Due To Inoperable Isolation Valves.
4.2
Engineering
The inspectors reviewed documentation and observed activities related to
the following areas: engineering self-assessment, oversight groups,
modifications, 50.59 safety evaluations, drawing control, operability
evaluations, and follow up on previously identified NRC findings.
4.2.1 Engineering Self-Assessment
The inspectors reviewed an engineering self-assessment that had been
performed during a two week period in October 1995. Discussions were
held with the engineering supervisor that had been in charge of the
assessment and some of the findings were discussed in detail.
The
assessment was conducted using INPO and NRC performance objectives and
ENCLOSURE 2
19
guidelines. The results of the areas identified indicated that the
assessment was self critical.
Some of the findings indicated that there were problems with scheduling
and prioritizing of engineering work; communications needed improving
both internally and with groups outside of engineering; problems meeting
established modification schedules were identified; etc. The assessment
was well received by engineering management and a commitment was made to
followup on the recommendations provided by the team. This assessment
was issued in January 1996 and quarterly review meetings are to be held
to followup on the current status of all the recommendations.
4.2.2 Oversight Groups
The inspectors reviewed the activities of the Plant Operations Review
Committee (PORC) and the Nuclear Safety Review Board (NSRB). A review
was made of the PORC requirements in Section 16.13-3 of the site Conduct
of Operations document. On two occasions during the inspection period
regional inspectors attended a meeting of the PORC. One meeting was
held to review an operable but degraded condition for a power range
nuclear instrument (3NI-8). There was a free exchange of ideas,
questions, and discussions. The second PORC meeting involved a report
of the changes In the Shutdown Risk Assessment for the scheduled Unit 2
refueling outage due to schedule changes. Another issue involved
operability concerns for valves HP-3 and HP-4. The two valves are
considered operable in the emergency mode with a one percent margin.
The recommended solution on two units was to cut the valves out and turn
them around which would cause the valves to function against
differential pressure without the aid of the electric motor (therefore
no one percent margin would be present). Another unit would be left as
is with the one percent margin. During the exchange of information and
ideas between the various engineering groups, it was evident to the PORC
members that there was a difference of opinions on the one percent
margin. Based on this PORC did not agree with the recommendations and
asked engineering to come back with a revised plan for PORC review. In
addition to these meetings, the inspectors reviewed a sample of 18 PORC
meeting minutes dating back to 1994. In this sample of minutes there
were other examples where PORC rejected ideas or asked for a revised
plan.
The inspectors reviewed the TS requirements for the NSRB board including
functions, organization, and the areas that the board will review. A
review was performed of the minutes for the 1994, 1995, and 1996 board
meetings. It was noted that the findings and remarks were detailed.
Several remarks or observations were made in the Oconee engineering area
by the board. One concern from the September 1995 meeting addressed a
suggestion for continued management attention to ensure proper staffing
level and utilization of engineering resources. Another continuing
concern in the same minutes regarded the adequacy for planning,
scheduling, and independent reviews for refueling outages. In the
ENCLOSURE 2
20
latest meeting (February 1996) a remark for Oconee engineering stated
that the system engineering group appears diverted to design base
document reviews versus plant support. Some of the remarks of the NSRB
appear similar to those -identified during the engineering self
assessment. In conclusion both of the groups were functioning
effectively in evaluating engineering and other activities.
4.2.3 Modifications and Safety Evaluations
The inspectors reviewed the following modifications to determine if they
complied with the existing directive at time of implementation. The
initial and final scoping document and the 10 CFR 50.59 for each
modification was reviewed along with the necessary post modification
testing requirements.
NSM-12873 Modify main feedwater control on Main Steam Line
Break(Unit 1)
NSM-12923 Upgrade Safety Related Instrumentation for LPSW flow
through decay heat coolers 1A & 18,
add switches for 1LPSW-251 and
252
NSM-32879 Replace the Letdown Storage Tank Makeup
Controller/Totalizer and provide bypass capabilities (Unit 3)
NSM-22963 Unit 2 Reactor Building Cooling Unit replacement
NSM-32905 Redundant Level Monitoring for the Reactor Vessel when
shutdown (Unit 3)
The inspectors reviewed all correspondence associated with NSM-12873
because a review of the modification indicated that it was not in
compliance with IE Bulletin 80-04. The licensee stated in the 10 CFR
50.59 that the modification was an enhancement to their previous
submittal and took credit for operator action to close the main
feedwater block valve within 120 seconds to avoid overpressurization of
the containment if the main feedwater control valve sticks open. The
licensee also requires the operators to respond within 20 seconds if the
control valve is in manual position to avoid overpressurization of the
containment. IE Bulletin 80-04 requires safety-related instrumentation
and requires that the design be single failure proof. A review of the
modification testing showed documentation that the Main Feed Water
(MFDW) control valves did not close off in the 20 seconds as stated in
correspondence. An analysis was done by the licensee to allow a 25
second closure. The inspectors reviewed documentation that stated that
the MFDW control valves and the MFDW startup control valves must close
within a total of 25 seconds of reaching the MFDW isolation circuitry
setpoint. This was documented by calculations OSC-5233 and OSC-5373.
The licensee agreed to provide the inspector with the calculations to
support a 25 second closing time. The inspector interviewed licensee
ENCLOSURE 2
21
training personnel, reviewed the EOPs, and ascertained that the EOPs
contained guidance for a.steam line break. The licensee personnel
stated that operators had received training on the simulator and were
able to respond within the allowable time frames.
Documentation reviewed by the inspector indicated that the NRC was aware
that the modification did not meet the requirements of IE Bulletin 80-04
and had accepted the licensee's design. Specifically, a licensee letter
titled "Supplemental Response to IE Bulletin 80-04 Delay of NRC
Commitment Item," dated June 14, 1995, stated, "The MFDW equipment being
controlled by the new MSLB circuitry is non-safety related and was never
intended to be safety-related. Therefore, this equipment is not single
failure proof. However, the associated pressure transmitters, logic,
and control circuitry installed by this modification for mitigation of a
MSLB will be safety-related (QA-1). Therefore, these components will be
redundant and single failure proof."
The NRC responded in a letter
dated June 30, 1995, and although the letter did not specifically
address the acceptance of the non-safety and non-single failure proof
portions the modification was accepted.
The inspectors reviewed LER 269/93-06, Design Deficiency Results in a
Condition Outside the Design Basis of Containment For A Main Steam Line
Break. Based on the licensee's response and the statement in the LER
that "The equipment required to mitigate the consequences of the MSLB is
environmentally qualified and would perform its safety function" refers
to the equipment being qualified to 60 psig, the LER is closed.
A review of PLAN, the management tool used to determine the progress of
the modifications, revealed that it was a useful tool for tracking
progress.
The inspectors concluded that there were no programmatic problems with
the modification program as a result of the review of the above
modifications. The inspectors also concluded that for these
modifications the 10 CFR 50.59 program was being followed according to
procedure. During this inspection, the inspectors did not evaluate the
minor modification program.
4.3
Drawing Control
The inspectors reviewed elements of drawing control which included
drawing accuracy and drawing distribution control.
Previous NRC
inspections had identified drawing deficiencies associated with drawing
accuracy (NRC Inspection Reports 50-269,270,287/95-20 and 95-27). In
particular, these deficiencies were associated with inconsistencies
between Keowee electrical drawings and the as-built condition in the low
voltage electrical (logic) cabinets. The inspectors reviewed the
licensee's actions to resolve Keowee drawing accuracy deficiencies and
actions planned to assess the accuracy of Oconee station electrical
drawings. Drawing distribution control was reviewed by evaluating the
ENCLOSURE 2
22
consistency of the revisions of Vital to Operations (VTO) drawings
between the master index and the satellite control drawing locations.
In conjunction with the Keowee Upgrade Project, an as-built verification
of Keowee electrical drawings was performed in 1993. Deficiencies or
errors were identified as editorial Station Problem Reports (SPRs).
Drawing errors were again identified in October 1995 during the
implementation of a modification of the Keowee logic configuration.
This resulted in an extensive walkdown of the low voltage cabinets which
identified further errors. The licensee initiated Problem Investigation
Program reports (PIPs) PIP 0-95-1461 and PIP 0-95-1577 to evaluate the,
errors and track resolution. The evaluation identified that the drawing
errors were non-functional (i.e., the errors did not impact the function
of circuits, logic, or components). Additionally, the majority of the
errors had been previously identified in the 1993 verification and had
not been corrected. The SPR process provided no time constraints on
resolution of editorial SPRs.
The major cause of drawing errors was
inadequate as-built verification during construction. The 1995 errors
were identified in the above PIPs and minor modifications were
implemented which corrected the errors. The inspectors verified the
corrective actions of the PIPs adequately addressed the drawing errors
and performed a sample as-built verification of Keowee electrical
cabinets 1LC1, 1LC2, and CB8. No drawing errors were identified. The
inspectors concluded that the licensee had improved the accuracy of
Keowee low voltage electrical drawings.
The inspectors reviewed the licensee's planned actions to assess the
accuracy of Keowee high voltage electrical cabinets and Oconee station
electrical drawings. Project PLAN ON-96-0039, Implement Emergency Power
Improvement Plan, provided an activity schedule for these actions. The
Keowee high voltage cabinets (i.e., 600 VAC motor control centers and
switchgear, were scheduled for as-built verification in November 1996).
The Oconee station-drawings have been maintained by a QA program since
construction. The Keowee drawings were not subject to similar controls
until 1993, which contributed to their deficient quality. Although the
Oconee station drawings were better controlled, potential drawing errors
could exist due to deficient as-built verification during construction.
The Oconee station safety-related Electrical cabinet drawings were
scheduled for as-built verification from June 1996 to April 1998. The
licensee had conducted a modification documentation completion and
drawing update program in 1995. This program had eliminated the drawing
backlog. The inspectors concluded the licensee had scheduled
appropriate actions to assess the accuracy of Keowee high voltage
electrical cabinets and Oconee station safety-related electrical
drawings.
The licensee recently conducted a self-assessment of engineering drawing
quality (Report No. SA-96-13-ON-SRG) at the request of the Modifications
organization. This organization was responsible for drawing accuracy
and control.. The assessment was conducted by the Safety Review Group
ENCLOSURE 2
23
(SRG) from February 1 - March 11, 1996, and primarily consisted of a
review of the 1995 PIP data base to assess potential adverse trends in
drawing quality. Of the 86 drawing related PIPs the root cause of the
above problems was determined to be deficient as-built verifications
during the station construction.- An additional cause was determined to
be deficient drawing update activity from modifications. The conclusion
was that an adverse drawing trend was not apparent at Oconee. The
licensee was in the process of establishing a standard for drawing
quality to facilitate future monitoring of performance in this area.
The inspectors concluded the SRG review of engineering drawing quality
provided an effective assessment which was independent of the staff
responsible for the drawing activities.
The inspectors reviewed drawing distribution control. There were
approximately ten satellite locations for controlled drawings, which
included the three control rooms, the work control center and
engineering locations. The staff was knowledgeable of the distribution
control process and conscientious in fulfilling their responsibilities.
Following the elimination of the drawing backlog discussed previously,
the licensee established additional time constraints for updating
drawings to prevent development of a backlog. These included two days
to update VTO drawings after modification installation and 60 days for
non-VTO drawings. The inspectors noted there were less than five
outstanding drawing changes exceeding 60 days which indicated the
process was.effective in assuring drawings were updated. A sample of
approximately 65 drawings were selected to compare the revision status
of the satellite locations and the master index. One example was
identified in which the field revision was inconsistent with the master
drawing index. This example is discussed in the following paragraph.
The exception not withstanding, the inspectors concluded that the
overall drawing distribution process was well controlled.
The inspectors identified a VTO drawing in the Unit 1 control room which
was not appropriately updated from a 1994 modification,.NSM 52875.
Elementary Electrical Diagram 0-803, AC Circuits 230 Kv Switchyard, PCBs
26 & 27, revision 10, was in the control room; revision 11 which
incorporated the NSM was in the master index. Further investigation
determined that the October 19, 1994, drawing transmittal which included
this and 33 other drawings had not been processed. As a result, a total
34 drawings associated with NSM 52875 had not been updated. This
included 10 VTO drawings in the Unit 1, 2, and 3 control rooms and two
other controlled drawing satellite locations. The NSM was related to
monitoring components and circuits for switchyard parameters; therefore,
there was no apparent impact on the capability of operators to perform
their activities. However, this is an example of non-compliance with QA
program requirements for drawing control. This item is identified as
Violation 50-269,270,287/96-04-03, Failure to Follow Procedure for
Drawing Controls.
ENCLOSURE 2
24
4.4
Operability Evaluations
The inspectors reviewed the licensee's process for accomplishing
operability evaluations, selected a sample of operability evaluations,
and observed the PORC review and approval of a completed evaluation.
Nuclear Station Directive (NSD) 203, Operability, revision 4, provided
guidance for the development of operability evaluations. Document NSD
208, Problem Investigation Process, provided additional guidance for
operability evaluations. The primary vehicle for operability
evaluations was the More Significant Event (MSE) PIPs. The inspectors
selected a sample of approximately fifteen MSE PIPs from the previous
two years and reviewed the associated operability evaluations to verify
that conclusions were adequately supported by design or performance
information. Also reviewed was the independent check and approval
process required by NSD 203. Additionally the inspectors observed the
PORC review of an operability evaluation related to a power range
nuclear instrument (3NI-8) being in an operable but degraded condition.
The inspectors concluded that the MSE PIP operability evaluations were
adequately supported by design and performance information and that the
conclusions were adequately communicated to Operations via the
memorandum process described by NSD 203. The PORC reviewers
appropriately challenged Engineering to support the assumptions and
conclusions of the operability evaluation related to safety-related
valves HP-3 and HP-4 being operable in an emergency mode with a one
percent margin.
4.5
Engineering Followup Issues
4.5.1 (Closed) Apparent Violation 50-269,270,287/94-21-01, Keowee Air Circuit
Breaker (ACB) Air System Not Controlled as QA Safety Related System.
(Violation EA 94-125-01014)
This item identified that the Keowee ACB air system was not
appropriately covered by the licensee's Quality Assurance (QA) program.
For example, the Quality Standards Manual-did not show the air system as
QA-1, QA program controls consistent with the system's importance to
safety were not applied for maintenance and modifications activities,
and there was no system control drawing. The lack of these controls
resulted in a system air leakage which contributed to an unanticipated
lockout of the overhead emergency power path in June 1994. The
licensee's corrective actions specified in the response to the violation
dated September 23, 1994, included a modification to enhance the air
system logic and incorporation of QA controls consistent with the
system's importance to safety.
The inspectors verified that the ACB air system was added to the Quality
Standards Manual, a controlled system drawing (KFD-107A1.1, Flow Diagram
of ACB Air System, revision C) had been developed, and QA level
procedures had been developed for inspection and maintenance of the ACBs
which included the air system. The Keowee electrical and mechanical
ENCLOSURE 2
25
support systems were evaluated in November 1994 to determine if other
support systems required upgraded quality controls. Several mechanical
components were added to NSD 307, Quality Standards Manual, revision 7,
as a result of the evaluations. Work orders dated July 1994
demonstrated that the check valve problems which caused the system
leakage were corrected. The logic modifications were implemented with
NSM 52966 which remains open pending completion of post modification
testing. This modification incorporated appropriate QA controls for
safety-related equipment. The inspectors concluded the licensee's
completed and scheduled corrective actions adequately resolve this item.
4.5.2 (Closed) IFI 50-269,270,287/95-30-02, Propane Issue
This item concerned the NRC's questioning the design, placement, and
documentation requirements associated with propane tanks that supplied
heaters placed in the reactor building personnel hatch areas. The
inspectors reviewed PIP 0-096-0025 that documented the problem and
discussed the resolution with the system engineer. Unit 2 was the only
unit that was not in compliance with the fire code because of the
distance of the propane tanks to a safety-related building. However,
the licensee has removed these propane tanks from the site for all three
units and capped the lines. This resolves the issue and the item is
closed.
4.5.3 (Open) Deviation 50-269,270,287/94-24-05, Improper Code Classification
This item identified that the licensee did not classify the high
pressure injection minimum flow piping properly. Since this piping may
see recirculated reactor building sump water following a LOCA, the
piping should be ASME Class II (licensee Class"B"). The inspectors
discussed this item with the licensee and since more actions have to be
taken this item will remain open.
4.5.4 (Closed) IFI 269/94-16-04, HPI Pump Runout Flow Testing
A review was made of Calculation OSC-5909, Test Acceptance Criteria for
High Pressure Injection Pump Developed Head. The inspectors found that
the operable pump required for the duration of an accident had 25
percent conservatism. The HPI pump which is required to be available in
ten minutes had a conservatism of 12.6 percent. Seven percent of this
allowable by the ASME Code (Sec. XI) and 5.6 percent allowed for
instrument error. A review of the calculation and discussions with the
system engineer indicated that time was available to take operator
action before runout occurred. The inspector also reviewed whether the
HPI pump 2B was installed within the necessary guidelines during the
last outage. The inspector's review of the calculation showed it was
within the acceptable guidelines and the inspector discussed the results
of the baseline curve with the component engineer. The baseline was
lower than expected but still within the acceptable limits. A decision
was made to use that pump continuously during the last cycle. Unit 2
ENCLOSURE 2
26
started down for a refueling outage during this inspection and a
decision was made to replace the pump because it had degraded an
additional 60 psig. This could be due to normal wear. There was not
enough previous data under full flow testing to make this judgement.
The licensee intends to disassemble the pump to determine if there are
any noticeable problems. This item is closed.
4.5.5 (Closed) LER 269/95-06, LPI Past Inoperable Due to
Inadequate Vendor Information Causing Calculation Errors
The inspectors reviewed Calculation OSC-5121, LPI Pump Runout Analysis
and determined that the different Cv (flow coefficient) for the LPI
throttle valves would not have contributed to a runout condition. This
LER was closed.
4.'5.6 (Closed) LER 269/93-06 Design Deficiency In a Condition Outside the
Design Basis of Containment for a Main Steam Line Break.
The inspectors reviewed the response to the LER and had discussions with
the licensee. It appears logical that the equipment required to mitigate
the consequences of the MSLB is environmentally qualified and would
perform its safety function. This item was closed on the basis of the
licensee statement that EQ was done for a containment pressure of 60
psig.
4.5.7 (Closed) IFI 270/94-11-01, Slow Transfer Of The "E" Breakers
During a Unit 2 reactor trip on April 6, 1994, the "E" breakers did not
transfer the tripped unit to the startup transformer as rapidly as
designed. During an investigation into the event, the licensee
determined that a modification which included the addition of auxiliary
relays would be necessary to get the fast transfer. The problem was
determined to exist on the other two units also.
The licensee implemented design changes to modify the existing
circuitry; ONOE 7442 (Unit 1), ON0E 7477 (Unit 2), and 7478 (Unit 3).
The modifications have been completed for Units 1 and 2, and Unit 3 is
scheduled to be modified during the next refuelling outage. Based on
these actions, this item is closed.
Within this area, One Violation (paragraph 4.3) was identified for failure to
follow procedures for drawing control, and one Unresolved Item (paragraph
4.1) was identified for a potential inoperability of the SSF due to isolation
valve operability.
ENCLOSURE 2
27
5.0
PLANT SUPPORT (71750, 83750, 84750, AND 92904)
The inspectors 'assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the following areas were reviewed:
Radiological Controls, Physical security and Fire protection.
5.1
Administrative Controls for External Exposure
This area was reviewed to determine whether personnel dosimetry,
administrative controls, and records and reports of external radiation
exposure met regulatory requirements.
10 CFR 20.1201(a) requires in part, that each licensee control the
occupational dose to individual adults.
The inspector reviewed and discussed with licensee representatives TEDE
exposures for plant and contract personnel for the period of 1995.
Through review of selected dose records and discussions with licensee
representatives, the inspector confirmed that all TEDE exposures
assigned during the period were within 10 CFR Part 20 limits.
5.2
Personnel Dosimetry
10 CFR 20.1502(a) requires in part, each licensee monitor occupational
exposure to radiation and supply and require the use of individual
monitoring devices.
The licensee's dose tracking system tracked personnel exposures in order
to ensure adherence to procedural administrative allowances as well as
10 CFR Part 20 limits.
The inspector conducted random interviews with radiation workers in the
RCA and observed personnel logging into the ED system. From
observations, the inspector noted personnel were properly utilizing the
ED system and were knowledgeable of their personal dose, and proper
response to ED alarms.
Based on direct observation, discussion and review of records, the
inspector determined personnel dosimeters were being effectively
utilized.
5.3
Internal Exposure Control
10 CFR 20.1502(b) requires each licensee to monitor the occupational
intake of radioactive material by and assess the committed effective
dose equivalent (CEDE) to:
ENCLOSURE 2
28
(1) Adults likely to receive, in one year, an intake in excess of
10 percent of the applicable ALI in Table 1, Columns 1 and 2 of
Appendix B to 10 CFR 20.1001-20.2401; and
(2) Minors and declared pregnant women likely to receive, in one year,
a committed effective dose equivalent in excess of 0.05 rem.
This area was reviewed to determine the adequacy of licensee's use of
process and engineering controls to limit exposures to airborne
radioactivity, adequacy of respiratory protection program, licensee's
administrative controls for assessing the CEDE in radiation and airborne
radioactive materials areas, and assessments of individual intakes of
radioactive material and records of internal exposure measurements and
assessments.
The inspector discussed with the licensee, respirator reduction efforts
with respect to engineering controls to be used by the licensee to
enhance ALARA concepts. Discussions with licensee personnel identified
the licensee was using worksite ventilation and decontamination methods
as engineering controls to limit airborne radioactivity in work areas.
The licensee informed the inspector that their investigative limit for
internal exposures was 0.050 Rem per exposure and that when the sum of
the individual internal exposures reached 0.100 Rem per year, the sum of
the CEDE would be added to the individuals Total Effective Dose
Equivalent (TEDE), which was within regulatory requirements. Only 1
worker received internal exposure that met the licensee investigative
limit in 1995 and 2 workers had received internal exposures at
investigative limits in 1996 at the time of the inspection.
Based a review of records, and discussions with licensee personnel, the
inspector determined that the licensee was using engineering controls to
minimize internal exposure and that the licensee's program for
monitoring, assessing, and controlling internal exposures was conducted
in accordance with regulatory requirements with no exposures in excess
of 10 CFR Part 20 limits identified.
5.4
Operational and Administrative Controls
The inspector reviewed Operational and Administrative controls for
entering the RCA and performing work. These controls included the use of
RWPs to be reviewed and understood by workers prior to entering the RCA.
The inspector reviewed selected RWPs 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, respiratory protection, and dosimetry were required. During
tours of the plant, the inspector observed the adherence of plant
ENCLOSURE 2
29
workers to the RWP requirements. The inspector also performed
independent radiation surveys of selected areas in the Auxiliary
Building to confirm RWP exposure information and no discrepancies were
identified.
The inspector found the licensee's program for RWP implementation to
adequately address radiological protection concerns and to provide for
proper control measures.
5.5
Control of Radioactive Materials and Contamination, Surveys, and
Monitoring
10 CFR 20.1501(a) requires each licensee to make or cause to be made
such surveys as (1)
may be necessary for the licensee to comply with the
regulations and (2) are reasonable under the circumstances to evaluate
the extent of radioactive hazards that may be present.
10 CFR 20.1904(a) requires the licensee to ensure that each container of
licensed material bears a durable, clearly visible label bearing the
radiation symbol and the words "Caution, Radioactive Material," or
"Danger, Radioactive Material." The label must also provide sufficient
information (such as radionuclides present, and the estimate of the
quantity of radioactivity, the kinds of materials and mass enrichment)
to permit individuals handling or using the containers, to take
precautions.to avoid or minimize exposures.
The inspector reviewed selected records of routine and special radiation
and contamination surveys performed and discussed the survey results
with licensee representatives. The inspector discussed labeling
procedures, practices, and storage of radioactive material with licensee
personnel during the facility tours.
During tours of the plant, the inspector independently verified
radiation levels in portions of the Auxiliary Building were in
accordance with licensee survey results.
The inspector also identified
that survey instrumentation and continuous air monitors observed in use
within the RCA were operable and currently calibrated. The inspector
noted that all containers and materials inspected were labeled to denote
the radiological hazards present.
Discussions with licensee management identified continuing efforts to
minimize radioactive waste. The licensee generated approximately 3500
cubic feet of radioactive waste in 1995 which was below the licensee's
original 1995 goal of 6570 cubic feet.
During facility tours, the inspector noted that contamination control
and general radiological housekeeping practices were adequate. At the
time of the inspection, contaminated square footage was approximately
0.006 percent (813 square feet) of the total Radiological Controlled
ENCLOSURE 2
30
Area (RCA) of 126,311 square feet. The licensee averaged approximately
0.03 percent (4000 square feet) of the total RCA as contaminated area
during a normal refueling outage.
The inspector detected contamination in an area adjacent to a
contamination boundary in the Auxiliary Building. Water routed to a
drain line in the contaminated area had apparently migrated beyond the
posted contamination boundary. The licensee initiated immediate
corrective action to survey and appropriately control the area to
prevent further spread of the contamination. The inspector reviewed
personnel contamination records for 1995 and 1996. The licensee had
accumulated 592 PCEs for all three units in 1995. This included 2
refueling outages and 2 forced outages. Of the PCEs accumulated in 1995,
approximately 381 occurred during the Unit 3 outage which had high
activity levels in the Reactor Coolant System due to failed fuel.
The
failed fuel contributed to approximately 91 Iodine contaminations and
107 particle contaminations. At the time of the inspection, the
licensee had accumulated approximately 30 PCEs in 1996. Records
reviewed determined the licensee was tracking and trending personnel
contamination events.
Based on observations during tours of the facility, procedure reviews,
and discussions with licensee personnel, the inspector identified that
the licensee's posting and control policies for radiation areas, high
radiation areas, very high radiation areas, airborne radioactivity
areas, contamination areas, and radioactive material storage areas were
appropriate and that the licensee was conducting surveys to comply with
procedural requirements using appropriate instrumentation. The
inspector determined the licensee was meeting FSAR facilities and
equipment requirements for those areas inspected.
5.6
Program for Maintaining Exposures As Low As Reasonably Achievable
(ALARA)
10 CFR 20.1101(b) requires that each licensee 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 ALARA.
The inspector discussed ALARA goals and annual exposures with licensee
management and determined the organizational structure and
responsibilities for the ALARA staff were clearly defined in
organizational charts. The inspector determined that the licensee's
ALARA policy and objectives were adequately addressed in General
Employee Training (GET).
Areas reviewed included source term reduction, ALARA accomplishments,
and future ALARA plans. A discussion with licensee representatives and
a review of pertinent records determined the licensee had established an
annual site exposure goal for 1995 of approximately 420 person-rem. The
ENCLOSURE 2
31
licensee's 1995 annual site exposure goal was based on operational
exposure and dual Unit refueling outages. Site exposure actually
accrued in 1995 was approximately 303.9 person-rem for an average 1995
dose per reactor of approximately 101 person-rem. The site's actual
1995 exposures were based on operational exposure, two refueling
outages, and two forced outages. The site's 3 year average through 1995
was approximately 120 person-rem per Unit. The licensee's
crudburst/shutdown procedures used during the last 1995 Unit 1 refueling
outage removed 285 curies of Cobalt 58 and 1.7 curies of Cobalt 60 which
contributed to lower source term activity and lower outage exposures.
Total outage dose was 73 person-rem compared to the previous refueling
outage dose of 125 person-rem. The lower outage dose was largely
attributed to the reduced number of RWP hours used to perform tasks.
The licensee informed the inspector the reduced number of RWP hours was
achieved through worker efficiency and minimizing the number of workers
performing a task. Future ALARA plans to reduce dose and enhance
radiological controls included increased use of video equipment in
conjunction with audio communications and wireless teledosimetry.
Based on discussions with licensee management and records reviewed the
inspector determined the licensee had continued to improve upon ALARA
initiatives and meeting ALARA goals, particularly relating to outage
dose reductions. The licensee was continuing to meet FSAR ALARA program
commitments.
5.7
Radiological Effluent Controls
Technical Specification (TS) 6.6.1.4 and Section 16.11-9 of the Final
Safety Analysis Report (FSAR) described the reporting schedule and
content requirements for the Annual Radioactive Effluent Release
Reports. The reports were required to be submitted before May 1 of each
year covering the operation of the facility during the previous calendar
year.
(Prior to 1994, radioactive effluent release reports were
required to be submitted on a semi-annual basis.)
Summaries of the
quantities of radioactive material in liquid and gaseous effluents
released from the facility and an assessment of the radiation doses due
to those releases were required to be included in the reports.
The effluent data presented in Table 1 below were compiled from the
licensee's effluent release reports for the years 1989 through 1995.
The inspector reviewed the preliminary report for the year 1995 and
discussed it's content and the data presented in Table 1 with the
licensee.
ENCLOSURE 2
32
Table 1
Effluent Release Summary for Oconee Units 1, 2, and 3
Activity Released (curies)
Liquid Effluents
Gaseous Effluents
Fission and
Dissolved
Activation
Noble
Noble
Year
Products
Gases
Gases Halogens Particulates Tritium
1989
3.88
1023
6.36
8970
3.11E-2
1.76E-2
118
1990
3.11
992
1.17
8830
1.69E-2
1.59E-2
101
1991
1.40
1130
2.86
3450
4.06E-2
8.50E-2
109
1992
2.58
998
3.12
3280
2.13E-2
8.35E-1
64
1993
0.47
1100
0.53
658
2.20E-2
1.06E-1
44
1994
0.37
909
0.92
3500
4.71E-2
.08E-1
43
1995'
0.39
835
0.18
1290
2.25E-2
9.38E-1
43
Preliminary values - Report due May 1, 1996
Annual Doses
Liquid Effluents
Maximum
Total Body Dose Percent of.
Organ Dose
Percent of
Year
(Limit: 9 mrem)
Limit
(Limit: 30 mrem)
Limit
1989
0.62
6.91
2.61
8.70
1990
0.99
11.00
1.47
4.90
1991
0.36
3.97
0.47
1.57
1992
0.29
3.22
0.58
1.93
1993
0.13
1.44
0.17
0.57
1994
0.43
4.78
0.62
2.07
1995'
0.24
2.67
0.40
1.33
Preliminary values -
Report due May 1, 1996
ENCLOSURE 2
33
Gaseous Effluents
Maximum Organ Dose
Air Dose
(Limits: Gamma 30 mrad, Percent of
and Particulates]
Percent of
Year
Beta 60 mrad)
Limit
(Limit: 45 mrem)
Limit
1989
Gamma 0.047
0.16
0.31
0.70
Beta 0.145
0.24
1990
Gamma 0.067
0.22
0.11
0.24
Beta 0.19
0.32
1991
Gamma 0.026
0.09
0.24
0.54
Beta 0.059
0.10
1992
Gamma 0.034
0.11
0.12
0.27
Beta 0.057
0.09
1993
Gamma 0.005
0.02
0.02
0.04
Beta 0.018
0.03
1994
Gamma 0.088
0.29
0.42
0.93
Beta 0.244
0.41
1995
Gamma 0.051
0.17
0.11
0.24
Beta 0.098
0.16
Preliminary values - Report due May 1, 1996
The licensee provided the following information regarding the amounts of
activity released during 1995 and the resulting doses from those
releases. Less than one half of a curie of activity was released as
fission and activation products in liquid effluents during each of the
last three years (1993, 1994, and 1995).
This was partially achieved by
processing laundry water and miscellaneous waste water through powdered
resin before release. This additional step in liquid radwaste
processing was begun during 1992 and continued through 1995. The resin
used for this treatment had initially been used in the condensate
polishers. Radwaste personnel found that mixing the waste water with the
partially spent resin for several hours in a storage tank provided
sufficient contact between the water and the resin to significantly
reduce the activity concentration in the water. During the mixing
operation additional activity was deposited on the resin. The resin was
then disposed of by shipment to a licensed waste processor for
incineration. The decrease in the activity released as dissolved noble
gases in liquid effluents was a result of the continuous agitation of
the liquid radwaste as it was being accumulated in the radwaste
collection tanks for treatment. The initial purpose for agitating the
waste water was to keep particulates in suspension in order to capture
them during waste treatment rather that allow them accumulate as sludge
in the collection tanks. The agitation also liberated dissolved gases
ENCLOSURE 2
34
from the waste water. The licensee indicated that the majority of the
activity released in gaseous effluents was generated during
depressurization of the reactor coolant systems in the initial stages
outages, either forced outages or refueling outages. The decrease in
the activity released as noble gas in gaseous effluents during 1995 was
a result of fewer Unit 3 outages during that year as compared to 1994.
The activity in the Unit 3 reactor coolant system had been higher than
the activity in the coolant systems of the other two units for several
years due to leaking fuel. No leaking fuel was returned to the Unit 3
core during the 1995 refueling outage and the licensee expects the
gaseous activity released from Unit 3 to decrease during the current
fuel cycle.
As indicated in Table 1, the annual total body and organ doses from
liquid effluents were less than 3 percent of their limits. The air and
organ doses from gaseous effluents were less than 1 percent of their
limits.
The effluent release report indicated that during 1995 there were no
unplanned releases and no effluent monitors inoperable for more than 30
days.
Based on the above reviews, it was concluded that the licensee had
implemented and maintained an effective program to control liquid and
gaseous radioactive effluents. The projected offsite doses resulting
from those effluents were well within the limits specified in the TSs
and 40 CFR 190.
5.8
Radiological Environmental Monitoring Program
Technical Specification (TS) 6.4.4.f required the licensee to establish,
implement, and maintain a program to monitor the radiation and
radionuclides in the environs of the plant as described in Chapter 16 of
the Final Safety Analysis Report (FSAR). The sampling locations, types
of samples or measurements, sampling frequency, types and frequency of
sample analysis, reporting levels, and analytical lower limits of
detection (LLDs) were specified in FSAR section 16.11-6. TS 6.6.1.5 and
FSAR section 16.11-10 delineated the requirements for submitting, the
submittal dates, and the content of the Annual Radiological
Environmental Operating Reports. The reports were required to be
submitted prior to May 1 of each year and to provide an assessment of
the observed impact on the environment resulting from plant operations
during the previous calendar year.
The inspector reviewed the licensee's preliminary 1995 Annual
Radiological Environmental Operating Report and discussed its content
with the licensee. The report included the following: a description of
the program, a summary and discussion of the results for each exposure
pathway, analysis of trends and comparisons with previous years and
preoperational studies, and an assessment of the impact on the
ENCLOSURE 2
35
environment resulting from plant operations. The report also included
the results of the Land Use Census and the results of the
Interlaboratory Comparison Program required by TS 6.4.4.f and FSAR
section 16.11-6. The following observations for the various exposure
pathways were made by the licensee through their evaluation of the 1995
environmental monitoring program data, and documented in the report, or
were noted by the inspector during the review of the report.
Airborne - No man-made radionuclides were detected on any of the
312 particulate filter samples collected during 1995.
1-131 was
not detected in any of the 312 charcoal cartridges collected
during 1995 but Cs-137 was detected in 6 of those cartridges. The
observed Cs-137 concentrations were below the required lower limit
of detection (LLD).
Since Cs-137 was not detected on the
corresponding particulate filters, it was concluded that, as was
found during previous investigations of this phenomenon, the Cs
137 was an-active constituent of the charcoal.
Drinking Water - Gross beta activity was detected in 19 of the 26
samples collected from the two indicator locations and in 9 of the
13 samples collected from the one control location. The highest
concentration observed was 10 pCi/1 which was above the required
LLD of 4 pCi/l.
H-3 was detected in 5 of the 10 composite samples
collected from the two indicator locations but the highest
concentration observed was less than on fourth of the required
LLD.
Surface Water - Other than K-40, which occurs naturally in the
environment, H-3 was the only radionuclide detected in the 10
surface water samples collected during 1995. The highest H-3
concentration observed was 11,400 pCi/1, which was well below the
reporting level of 20,000 pCi/1.
Milk - Cs-137 was the only radionuclide, other than naturally
occurring K-40, detected in the milk samples. A total of 78 milk
samples were collected from 3 dairies. Cs-137 was detected in one
sample collected from one indicator location and in one sample
collected from the control location. The observed concentrations
were less than the required LLD.
Broadleaf Vegetation - Cs-137 was detected in 2 of the 48 samples
collected from the indicator locations and in 11 of the 12 samples
collected from the control location. The highest concentration
observed was less than 16 percent of the required reporting level.
Shoreline Sediment - Mn-54, Co-58, Co-60, Cs-134, and Cs-137 were
detected in low concentrations (<250 pCi/kg) in some of the
samples collected from the two indicator locations and Cs-137 was
detected in one of the samples collected from the control
location. The highest concentrations observed for Cs-134, and Cs
ENCLOSURE 2
36
137 were less that their required LLDs. No LLDs were specified in
the FSAR for Mn-54, Co-58, or Co-60. No reporting levels for
sediment were specified in the FSAR but doses from shoreline
sediments were well below environmental dose limits. The
calculated total body dose to the maximally exposed individual was
less than one thousandth of a mrem per year.
Fish - Cs-134, and Cs-137 were detected in most of the fish
samples collected during 1995 but the highest concentrations
observed were less than their required LLDs.
Direct Gamma Radiation - Exposures measured at 41 locations during
1995 here not significantly different form exposures measured
during preoperational studies.
Dose estimates calculated from environmental monitoring program data
were in reasonable agreement with dose estimates calculated from
effluent data and were within 40 CFR 190 dose limits. The annual total
body dose estimate to the maximum exposed member of the public,
calculated from the 1995 environmental sampling results, was less than
one quarter of a mrem. The report documented the licensee conclusion
that plant operations had no significant radiological impact on the
health and safety of the general public or the environment.
The inspectors also observed the collection of environmental samples at
3 air sampling stations and 2 dairies. The inspectors determined that
the sampling locations were consistent with their descriptions in the
FSAR and that the samples were in accordance with procedures
CP/0/B/2005/11 "Airborne Radioiodine and Particulate Sampling" and
CP/0/B/2005/10 "Milk Sampling".
Based on the above reviews and observations, the inspector concluded
that the licensee had complied with the sampling, analytical, and
reporting program requirements, that the radiological environmental
monitoring program had been effectively implemented and that plant
operations had no significant radiological impact on the health and
safety of the general public or the environment.
5.9
Environmental Monitoring Quality Assurance Program
TS 6.4.4.f and FSAR section 16.11-6 required the licensee to participate
in an interlaboratory comparison program and to include a summary of the
program results in the Annual Radiological Environmental Operating
Report. The licensee's report for 1995 provided a summary of the
results from the licensee's participation in the Environmental
Protection Agency's (EPA's) Environmental Monitoring Systems Laboratory
Intercomparison Program. The report also included descriptions of the
various types of samples analyzed and the analyses performed, and an
evaluation of the analytical results.
ENCLOSURE 2
37
Fourteen samples were analyzed for a total of 28 analytical results.
Three analytical results exceeded the EPA control limit. The licensee
investigated those analyses, which were performed on the same day, and
determined that the samples had been cross-contaminated. Corrective
actions to prevent recurrenceincluded refined receipt and tracking of
samples, isolation of lab work by potential activity, identification of
specific glassware for specific types of samples, improved cleaning
procedures for glassware and counter surfaces, use of blanks to identify
contamination, and improved procedures for data reviews.
Based on the licensee's overall performance in the EPA crosscheck
program, it was concluded that an effective quality assurance program
had been maintained for analysis of environmental samples.
5.10 Meteorological Monitoring Program
Section 2.3.3.2 of the Final Safety Analysis Report (FSAR) described.the
operational and surveillance requirements for the meteorological
monitoring instrumentation. Near real-time meteorological data were
required to be collected, summarized, and stored by the Operator Aid
Computer (OAC) system. Weekly equipment calibration and maintenance
checks and semiannual calibration checks were required to be performed
by prescribed station procedures.
The inspector reviewed the procedures listed below and determined that
they included provisions for performing the required semiannual
calibration checks on the meteorological monitoring instrumentation.
IP/O/B/1601/011
"Teledyne Geotech Series 21 Wind Speed Module Channel
Calibration"
IP/O/B/1601/012
"Teledyne Geotech Series 21 Model 21.21-1 Wind
Direction Processor Channel Calibration"
IP/O/B/1601/014
"Teledyne Geotech Platinum RDT T/Delta T Processor
Channel Calibration"
The inspector reviewed records of semiannual calibrations of wind speed,
wind direction and air temperature instrumentation performed during
September 1994 and May 1995 and determined that the calibrations were
performed in accordance with the above procedures and at the required
frequency.
Based on the above reviews and observations, it was concluded that
calibration of the meteorological instrumentation had been adequately
maintained.
5.11 Plant Support Followup Issues
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
ENCLOSURE 2
38
5.11.1(Closed) VIO 269,270,287/95-015-01, Failure To Properly Frisk Personnel
This violation involved multiple examples of workers and equipment
leaving the RCA without a proper frisk being performed. The inspector
reviewed licensee corrective actions to the' VIO: the licensee reduced
the number of RCA exit points from 10 to 5; eliminated of the RCA buffer
zone which previously allowed personnel from RCAs and non-RCA to cross
through the same area lending confusion to what personnel and material
must be frisked when exiting the buffer zone; and assigned personnel to
periodically monitor exits to identify any problems with frisking of
personnel or hand held items. The inspector reviewed licensee
monitoring schedules for observing control points and licensee
observation findings. The inspector also observed frisking practices at
control points and did not identify any problems in this area. Based on
licensee actions performed and inspector observations, VIO
269,270,287/95-015-01 is closed.
Within the areas reviewed, Violations and Deviations were not identified.
6.0
REVIEW OF UFSAR COMMITMENTS
A recent discovery of a licensee operating their facility in a manner
contrary to the Updated Final Safety Analysis Report (UFSAR) description
highlighted.the need for a special focused review that compares plant
practices, procedures and/or parameters to the UFSAR descriptions.
While performing the 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.
7.0
OTHER NRC PERSONNEL ONSITE
On April 16 and 17, 1996, Mr. H. Berkow, Project Director, NRR, and Mr.
L. Wiens, Project Manager, NRR were on site for a plant tour and to
discuss issues regarding the licensee's performance during the current
SALP cycle. On April 29, 1996, Mr. E. Merschoff, Director, Division of
Reactor Projects, Region II was on site to tour the Unit 2 Reactor
Building, Auxiliary Building, and the Turbine Building.
8.0
EXIT
The inspection scope and findings were summarized on April 24, 1996 with
those persons indicated by an asterisk in paragraph 1. Interim exits
were conducted on March 21, 1996, and March 28, 1996 .
The inspector
described the areas inspected and discussed in detail the inspection
results. A listing of inspection findings is provided. Proprietary
information is not contained in this report. Dissenting comments were
not received from the licensee.
ENCLOSURE 2
I
39
Item Number
Status
Description and Reference
NCV 269,270,287/96-04-01
Closed
Inadequate Procedure For Adjusting Chevron
Packing (Paragraph 3.3.5)
URI 269,270,287/96-04-02
Open
Potential Inoperability of SSF Due To
Inoperable Isolation Valves (Paragraph
4.1)
VIO 269,270,287/96-04-03
Open
Failure to Follow Procedure for Drawing
Controls (Paragraph 4.3)
VIO 269,270,287/95-15-01
Closed
Failure to Properly Frisk Personnel
(Paragraph 5.11.1)
EEI 269,270,287/94-21-01
Closed
Keowee Air Circuit Breaker (ACB) Air
System Not Controlled as QA Safety Related
System (Paragraph 4.5.1)
IFI 269,270,287/95-30-02
Closed
Propane Issue (Paragraph 4.5.2)
DEV 269,270,287/94-24-05
Open
Improper Code Classification (Paragraph
4.5.3)
IFI 269/94-16-04
Closed
HPI Pump Runout Flow Test (Paragraph
4.5.4)
Closed
LPI Past Inoperable Due to Inadequate
Vendor Information Causing Calculation
Errors (Paragraph 4.5.5)
Closed
Design Deficiency In a Condition Outside
the Design Basis of Containment for a Main
Steam Line Break (Paragraph 4.5.6)
URI 269/96-04-04
Open
Root Cause Assessment of Failures to
Valves 1MS-77 and 1LPSW-254 (Paragraphs
3.3.2 and 3.3.3)
LER 269/95-07, Rev.1
Closed
LPI Technically Inoperable (Paragraph
3.3.3)
8.0
ACB
Air Circuit Breaker
As Low As Reasonably Achievable
American Society For Mechanical Engineers
BHUT
Bleed Holdup Tank
BTO
Block Tagout
ENCLOSURE 2
40
BWST
Borated Water Storage Tank
CFR
Code of Federal Regulations
Component Cooling
Condenser Circulating Water
Counts Per Minute
CR
Control Room
Control Rod Drive Mechanism
Design Basis Accident
D/P
Differential Pressure
Electronic Dosemetry
Apparent Violation
Emergency Feedwater
EPSL
Emergency Power Switching Logic
End Of Cycle
Engineered Safeguards
GL
Generic Letter
GPM
Gallons Per Minute
GPH
Gallons Per Hour
Health Physics
High Pressure Injection
Integrated Control System
I&E
Instrument & Electrical
IFI
Inspector Followup Item
IR
Inspection Report
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
Maintenance Procedure
Main Steam Line Break
MVA
Mega Volts-Amps
Megawatts
Non-Cited Violation
Non-Licensed Operator
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
Oconee Nuclear Station
OEP
Operating Experience Program
Personnel Contamination Exposure
PSID
Pounds Per Square Inch Differential
Pounds Per Square Inch Gauge
Preventive Maintenance
Problem Investigation Process
Radiological Controlled Area
ENCLOSURE 2
44
- I
41
Roentgen Equivalent Man
Radiation Work Permit
Refueling Outage
Significant Operating Event Report
Spent Fuel Pool
SSF
Standby Shutdown Facility
Total Effective Dose Equivalent
Turbine Driven Emergency Feedwater
TS
Technical Specification
Unresolved Item
Violation
Work Control Center
Work Orders
Work Request
ENCLOSURE 2