ML14181A615
| ML14181A615 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 10/05/1994 |
| From: | Christensen H, Ogle C, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A612 | List: |
| References | |
| 50-261-94-23, NUDOCS 9410190023 | |
| Download: ML14181A615 (17) | |
See also: IR 05000261/1994023
Text
C,
REU4
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W., SUITE 2900
U
ATLANTA, GEORGIA 30323-0199
Report No.:
50-261/94-23
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson Unit 2
Inspection Conducted: August 21 - September 24, 1994
Inspectors:
- 2
L4
/C 9
W/ T. Orders, Senfor
sident Inspector
Date Signed
R
lge, Re~ den Inspector
D
Signed
Approved by: ?0oCh
.0.2Christensen, Chief
Date Signed
Reactor Projects Section lA
Division of Reactor Projects
SUMMARY
Scope:
This routine, unannounced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation,
operator overtime, and followup.
Results:
An apparent violation was identified involving the failure to properly
establish containment integrity (Paragraph 3.b); a second apparent violation
was identified involving pressurizer cooldown rates in excess of Technical
Specification Limits (Paragraph 3.d); a violation was identified involving the
failure to follow the physical security plan (Paragraph 3.e); an unresolved
item was identified involving the exhaust air quality through ASCO solenoid
valves (Paragraph 4.b); a second unresolved item was identified involving the
adequacy of control room exhaust damper testing (Paragraph 4.b); and a
weakness was identified with the routine use of overtime (Paragraph 3.c).
9410190023 941005
PDR ADOCK 05000261
G
REPORT DETAILS
1.
Persons Contacted
S. Billings, Technical Aide, Regulatory Compliance
- W. Brand, Supervisor, Environmental Radiation Control
- M. Brown, Manager, Design Engineering
- A. Carley, Manager, Site Communications
M. Chmielecki, Manager, Computer Support
B. Clark, Manager, Maintenance
- T. Cleary, Manager, Mechanical Maintenance
D. Crook, Senior Specialist, Regulatory Compliance
J. Eaddy, Manager, Environmental and Radiation Support
- F. Eckert, Manager Integrated Scheduling
- J. Epperly, Manager, Craft Resources
- C. Gray, Manager, Materials and Contract Services
- D. Gudger, Specialist Regulatory Affairs
- S. Harrison, Manager, Environmental Radiation Control
- M. Herrell, Acting Plant Manager
- S. Hinnant, Vice President, Robinson Nuclear Project
K. Jury, Manager, Licensing/Regulatory Programs
- J. Kozyra, Project Specialists, Licensing/Regulatory Programs
- R. Krich, Manager, Regulatory Affairs
A. McCauley, Manager, Electrical Systems, Technical Support
- D. Nelson, Manager, Outage Management
E. Shoemaker, Manager, Mechanical Systems, Technical Support
- D. Taylor, Plant Controller
G. Walters, Manager, Support Training
- R. Warden, Manager, Nuclear Assessment Section
- W. Whelan, Industrial Hygiene and Safety Representative
- L. Woods, Manager, Technical Support
Other licensee employees contacted included technicians, operators,
engineers, mechanics, security force members, and office personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Plant Status
The unit operated throughout the report period at or near full power
with no major operational perturbances.
3. Operational Safety Verification (71707)
a.
General
The inspectors evaluated licensee activities to confirm that the
facility was being operated safely and in conformance with
regulatory requirements. These activities were confirmed by
direct observation, facility tours, interviews and discussions
with licensee personnel and management, verification of safety
system status, and review of facility records.
2
The inspectors reviewed shift logs, Operation's records, data
sheets, instrument traces, and records of equipment malfunctions
to verify equipment operability and compliance with TS. The
inspectors verified the staff was knowledgeable of plant
conditions, responded properly to alarms, adhered to procedures
and applicable administrative controls, cognizant of in-progress
surveillance and maintenance activities, and aware of inoperable
equipment status through work observations and discussions with
Operations staff members. The inspectors performed channel
verifications and reviewed component status and safety-related
parameters to verify conformance with TS. Shift changes were
routinely observed, verifying that system status continuity was
maintained and that proper control room staffing existed. Access
to the control room was controlled and operations personnel
carried out their assigned duties in an effective manner. Control
room demeanor and communications were appropriate.
Plant tours were conducted to verify equipment operability, assess
the general condition of plant equipment, and to verify that
radiological controls, fire protection controls, physical
protection controls, and equipment tagging procedures were
properly implemented.
b.
Mispositioned Containment Isolation Valves
On August 29, 1994, with the unit at 100 percent power, an SRO
conducting a walkdown, observed that 9 normally closed main steam
line drain valves were open. Following this discovery, the
control room was notified, the valves were repositioned, and a
partial valve lineup for the main and reheat steam system was
conducted. No other valves were found to be in the incorrect
position. An ACR was generated to address this event.
The mispositioned valves were:
MS-19
SG "A" Steam Line Before Seat Drain Root
Isolation
MS-19A
SG "A" Steam Line Before Seat Drain Isolation
MS-21
SG "A" Steam Stop V1-3A After Seat Drain Root
Isolation
MS-28
SG "B" Steam Line Before Seat Drain Root
Isolation
MS-28A
SG "B" Steam Line Before Seat Drain Isolation
MS-30
SG "B" Steam Stop V1-3B After Seat Drain Root
Isolation
MS-37
SG "C" Steam Line Before Seat Drain Root
Isolation
MS-37A
SG "C" Steam Line Before Seat Drain Isolation
MS-39
SG "C" Steam Stop V1-3C After Seat Drain Root
Isolation
-3
These valves, along with six others, are used to drain the MSIVs
and the associated upstream steam piping. The drains are arranged
2-lines per steam header with 3 valves each in the before seat
drain lines and 2 valves each in the after seat drain lines.
According to the main steam system drawing, the Q-boundary ends
immediately after the root isolation valve in each of the drain
lines.
During plant startup, the valves are opened to drain the main
steam piping in the vicinity of the MSIVs. The valves are also
used to dissipate steam for RCS temperature.control while the unit
is in hot shutdown and during plant startup. All 15 valves are
closed during startup by a step in GP-005, Power Operation, which
designates the valves by number and name.
In response to this event, the inspectors reviewed the ACR
generated for this event as well as the licensee's documentation
relating to containment integrity. The inspectors also
interviewed the SCO and in-plant SRO responsible for aligning the
MSIV before and after seat drain valves during the plant startup
on August 6, 1994.
Finally, the inspectors reviewed the completed
GP-005 as well as the containment integrity valve lineup
procedure, OP-923, Containment Integrity.
On August 30, 1994, during this followup, the inspectors
determined that 3 of the mispositioned valves were designated as
containment isolation valves in the UFSAR and the licensee's
Generic Issue Document 90-181, Reactor Containment Isolation.
Specifically, the root isolation valves for the before seat
drains, MS-19, MS-28, and MS-37, were listed as containment
isolation valves in both references. The potential implications
of this discovery were discussed with licensee management later
that day. At approximately 8:05 a.m. on August 31, 1994, the
licensee determined that the 3 mispositioned containment isolation
valves represented a condition that was possibly outside the
design basis of the plant.
This determination was based on the
licensee's conclusion that although one closed manual valve
existed in the drain lines downstream of the containment isolation
valves, the valves were not seismically qualified. Hence, no
credit for the lines remaining intact downstream of the root
valves (containment isolation valves) could be taken.
Accordingly, at 8:56 a.m. that morning, the licensee made a one
hour non-emergency notification to the NRC pursuant to 10 CFR
50.72 (b)(1)(ii)(B).
On August 31, 1994, licensee personnel determined from a review of
the MSIV drawing that the valves identified as the MSIV after seat
drain root isolation valves, MS-21, MS-30, and MS-39 were in fact,
upstream of the MSIVs. The licensee determined that the plant
main steam drawing was in error since it showed the after seat
drain root isolation valves downstream of the MSIV seats. The
4
implication of this discovery was that a total of six containment
isolation valves had been open with the unit at 100% power.
From their review of this event, the inspectors determined that
apparently, a communications error between the in-plant SRO and
SCO resulted in the 9 valves listed above not being closed during
the August 6, 1994, startup.
As described by both SROs involved, the in-plant SRO was in the
field directing the efforts of A~s during the plant startup.
During the course of the startup, the SCO directed that the in
plant SRO close the before and after seat drains for the MSIVs.
The in-plant SRO assumed that this order was to isolate the drain
lines to control RCS temperature. The inspectors were advised
that when the drain lines are isolated to control RCS temperature,
only the downstream valves (MS-40, MS-41, MS-42, MS-43, MS-44, and
MS-45) are closed. The in-plant SRO told the inspectors that he
directed the A~s to close these six valves and witnessed them
being closed. In fact, the SCO intended that all 15 valves in the
MSIV before and after seat drain lines be closed to comply with
step 16 of GP-005. The in-plant SRO stated that he had a working
copy of GP-005 in his possession and had been using it during the
startup but admitted that he did not consult it for closing the
drain valves since he did not recognize this as a step in the GP.
At shift turnover, signatures were transferred from working copies
of the GP to the master control room copy. The in-plant SRO told
the inspectors that it was at this point that he recognized the
communications failure. However, based on his recollection that
the drain lines were isolated as a result of a control room order
and his personal observation of the AO actions, he signed the
master copy of GP-005 to reflect that all 15 valves were shut.
The in-plant SRO also advised the inspectors that fatigue
associated with lengthy work hours the day of the startup and
earlier that week may have contributed to his error. The
inspectors reviewed the in-plant.SRO's timecard for the week
before the startup and security logs for the day of the startup.
These records indicated that the in-plant SRO worked 59 hours6.828704e-4 days <br />0.0164 hours <br />9.755291e-5 weeks <br />2.24495e-5 months <br /> the
week before the startup, was off the day before the startup and
was on site for approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> the day of the startup. The
inspectors were provided the administrative approvals granted per
PLP-15, Program for Nuclear Power Plant Staff Working Hours, which
authorized extended hours for this individual on August 3 and
August 6, 1994. As a result of these approvals and the day off on
August 5, 1994, the in-plant SRO appeared to be in compliance with
TS requirements for working hours the day of the startup.
The inspectors concluded that the failure to immediately verify
the position of the other drain valves when the communications
failure was recognized, represented a failure on the part of the
in-plant SRO.
5
During the course of their initial review of this event, the
licensee determined that selected necessary changes to plant
procedures and documents to support the Containment Isolation GID
which was completed in January 1994, had not been made. The GID
was developed and implemented-in January 1994 to formally
establish the plant's containment isolation design basis. It was
undertaken as a result repetitive problems associated with
inconsistencies in various plant documents on the exact
containment boundaries. The GID is a detailed document which
identifies and provides the supporting rationale for the
containment isolation boundaries for each containment penetration.
The cause for the disparity between some plant procedures and the
GID was not formally reviewed by the inspectors in this
inspection. The subject was reviewed by the Event Review Team
chartered by the licensee to investigate this event, and was the
topic of an enclosure to the team's (draft) report. The Event
Review Team noted that while the GID received the appropriate
design verification and safety reviews, no formal process existed
to ensure that changes to plant procedures would be implemented in
a timely fashion. Most importantly, OP-923 was not revised to
reflect the appropriate main steam drain valves as containment
isolation valves coincident with the issuance of the GID in
January 1994. The inspectors were informed that 3 of the 6
mispositioned containment isolation valves were identified on a
proposed change to OP-923 which had not been completed at the time
of the mispositioning.
To ensure that the existing plant containment isolation
configuration regarding manually closed containment isolation
valves met licensing basis requirements, the licensee completed a
safety review on containment isolation configuration on
September 3, 1994. This included a review of the valve lineup
conducted per OP-923. Valves listed in the GID as containment
isolation valves, but not included in OP-923 had been verified to
be in the correct position during a licensee walkdown on
September 2, 1994. No valves were reported to be found in the
incorrect position. The safety review concluded that the existing
configuration of the plant's manual containment isolation valves
meets the license requirement.
Overall; the inspectors concluded that six containment isolation
valves remained open between August 6, 1994 and August 23, 1994,
while the unit operated at full power.
Technical Specification 3.6.1 requires that containment integrity
be established whenever the reactor is not in a cold shutdown
condition. Additionally, GP-005, Power Operation, required the
nine drain valves to be closed during power operations.
From August 6, 1994, until August 29, 1994, containment integrity
was not properly established in that the MSIV Before and After
Seat Drain Valves, containment isolation valves, were open instead
6
of closed. During this period, the reactor was operating at
power. Additionally, the Containment Isolation GID was not
adequately implemented.
This is identified as an Apparent Violation, 94-23-01:
Failure To
Properly Establish Containment Integrity.
c.
Operator Overtime
The resident inspectors performed a review of H. B. Robinson's
program for controlling staff working hours, based on their
observations that licensed operators were working what appeared to
be a routine and in some cases excessive overtime.
Robinson Specifications Section 6.2.3.b requires that
administrative procedures be developed and implemented to limit
the working hours of plant Staff who perform safety related
functions.
The site's overtime plan is delineated in procedure PLP-015,
Program For Nuclear Power Plant Staff Working Hours. The stated
purpose of the procedure is to provide the instructions and
controls necessary to comply with Generic Letter No. 82-12,
"Nuclear Power Plant Staff Working Hours," and other regulatory
guidance regarding the limitation for nuclear power plant staff
overtime and work hours.
In general, Generic Letter No. 82-12 required that licensees of
operating plants include in their administrative procedures
provisions regarding required shift staffing, the objective of
which, was the prevention of situations where fatigue could reduce
the ability of operating personnel to keep the reactor in a safe
condition.
PLP-015, requires that enough plant operating personnel be
employed to maintain adequate shift coverage without routine heavy
use of overtime. The objective is to have operating personnel
work a normal shift, based on their work schedule while the plant
is operating. However, in the event that unforseen problems
require substantial amounts of overtime to be used, or during
extended periods of shutdown for refueling, major maintenance, or
major plant modifications, on a temporary basis, the following
guidelines are to be followed:
An individual should not be permitted to work more
than 16
hours straight, excluding shift turnover
time.
7
.
An individual should not be permitted to work more
than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 24
hours in any 48-hour period, not more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in
any seven day period, all excluding shift turnover
time.
.
A break of at least eight hours should be allowed
between work periods, including shift turnover time.
.
Except during extended shutdown periods, the use of
overtime should be considered on an individual basis
and not for the entire staff on a shift.
Briefly restated, overtime should be used in unforeseen activities
on a temporary basis, and should not be routine.
The procedure states that in the event that unusual work
conditions or emergencies require personnel to exceed scheduled
hours and/or work in excess of the established Technical
Specifications limits, the Plant Manager or his designee must
approve it.
The inspectors performed a detailed review of the amount of
overtime worked by licensed operators this calendar year. The
review indicated that the operating crews had routinely worked 18
20 percent overtime. Some licensed individuals had overtime rates
as high as 30 percent.
The inspectors reviewed documentation of plant management approval
to allow the operators to work this overtime, and detected no
cases in which management approval was not obtained, nor where the
requirements of Technical Specification 6.2.3.b had not been met.
The inspectors were concerned that the operators were working
routine overtime which is not in keeping with the intent of
Technical Specification 6.2.3.b. These observations were
discussed with licensee management who agreed that the documented
overtime was routine, but informed the inspectors that recent
actions had been taken to minimize the use of operator overtime.
The goal in mind was for 10 percent or less.
The inspectors concluded that this routine use of overtime is
marginally acceptable and is considered a weakness. The
inspectors will monitor the licensee's efforts to reduce routine
use of overtime.
d.
Excessive Pressurizer Cooldown Rate
Unresolved Item, URI 94-22-01, documents the inspectors'
inspection activities associated with pressurizer cooldown rates
which were apparently in excess of TS limits. These cooldown
rates occurred while collapsing the pressurizer bubble on
February 26, 1994, during a plant shutdown. At 10:30 a.m. on
August 19, 1994, after a preliminary verification of the
inspectors' observations, the licensee entered an operability
determination on the pressurizer. The operability determination
was completed on August 22, 1994 and concluded that the
February 26, 1994 transient
"...
did not damage the structural
integrity of the pressurizer or surge line and that continued
operation is acceptable."
This conclusion was based on an initial
assessment of the transient data by Westinghouse and a
satisfactory RCS hydrostatic test which was conducted during the
startup after the cooldown. It was also documented in the
operability package, that a more detailed analysis of the
transient by Westinghouse would be forthcoming. An ACR was
generated to address the event.
In response to this issue, the inspectors reviewed portions of the
operability package as well as the results of the initial
Westinghouse assessment of the February 26 cooldown data. The
inspectors also examined the results of a licensee review of
previous pressurizer cooldowns conducted to determine if similar
transients had occurred. The ACR was still being evaluated by the
licensee at the end of the inspection period, thus a final version
was not reviewed.
The licensee's preliminary analysis of the pressurizer transient
contained in the August 22, 1994, operability package, established
the following pressurizer cooldown/heatup rates:
Steam temperature cooldown:
212F/hr
Water temperature cooldown:
207F in 46 minutes (270F/hr)
Surge line heatup:
101F/hr.
The inspectors independently reviewed the February 26 data and
determined the following regarding the pressurizer cooldown/
heatup:
Steam temperature cooldown:
Exceeded 200F/hr from
5:53 p.m. to 6:10 p.m.
Maximum rate observed in one
hour 212F/hr
Water temperature cooldown:
Exceeded 200F/hr from
5:35 p.m. to 6:07 p.m.
Maximum rate observed in one
hour 240F/hr
Surge Line Temperature:
Exceeded 200F/hr from
6:02 p.m. to 6:07 p.m.
Maximum rate observed in one
hour 215F/hr
Shorter intervals were more
erratic. For example: 164F @
5:56 p.m. to 360F @ 6:01 p.m.
or 196F in 5 minutes or
470F/hr heatup rate.
The inspectors used moving 1-hour intervals to obtain the cooldown
rates identified above. No effort was made to identify
pressurizer cooldown rates over shorter intervals. The inspectors
noted from a licensee memo documenting their review of prior
pressurizer cooldown transients, that similar cooldown rates
excursions in excess of the 200F/hr TS 3.1.2.3 limit had occurred.
The licensee documented 3 such occurrences between August 1989 and
November 1993. In these instances, the timeframe of the apparent
excessive pressurizer cooldown rates was reported by the licensee
as ranging from 4 to 18 minutes. Multiple instances of excessive
cooldown rates were reported in two of the subject cooldowns.
(The licensee indicated that the results of this initial review
were preliminary and that the data from these cooldowns was
provided to Westinghouse for further analysis.)
The licensee also
determined that sufficient data was not available in seven of the
pressurizer cooldowns to reconstruct a cooldown rate. For the
remaining cooldowns, the licensee review noted that the available
data or method of cooldown made excessive pressurizer cooldown
rates unlikely. The inspectors did not independently review
temperature data for pressurizer cooldowns prior to the
February 26, 1994, cooldown.
Technical Specification 3.1.2.3 limits the maximum pressurizer
cooldown rate to 200 degrees Fahrenheit per hour. Additionally,
Precaution and Limitation 3 of General Procedure, GP-007, Plant
Cooldown From Hot Shutdown To Cold Shutdown, specifies that the
maximum pressurizer cooldown rate shall not exceed 200 degrees
Fahrenheit per hour.
On February 26, 1994, the pressurizer cooldown rate exceeded 200
degrees Fahrenheit per hour when operators were collapsing the
pressurizer bubble. Pressurizer water space, steam space, and
surge line cooldown rates all exceeded the Technical Specification
limit with maximum cooldown rate observed approaching 240 degrees
Fahrenheit per hour.
The excessive pressurizer cooldown of February 26, 1994, is
identified as an Apparent Violation, 94-23-02: Pressurizer
Cooldown In Excess of Technical Specification Limits. URI 94
22-01 is closed
e.
Failure To Follow Security Procedures
On September 15, 1994, during a routine tour, the inspectors
observed that one of two individuals encountered had no visible
security badge. When questioned, the individual produced an
10
"escort required" badge from his pocket. The other individual
also had an "escort required" badge. These individuals informed
the inspectors that their escort was in an adjacent restroom.
(The individuals were approximately four feet from the door of the
restroom. The door to the restroom was closed when the inspectors
made their observations.) The inspectors accompanied the
individuals into the restroom and confirmed that the responsible
escort was indeed present. Based on the inspectors' observations,
it was estimated that the two individuals were not under the
control of the escort for approximately one minute.
Licensee Physical Security Plan, paragraph 4.5, Escorts, states
"Personnel authorized entry to the protected area as Escorted
Personnel shall be escorted." Additionally, paragraph 3.2.1.6,
Picture Badge System states, "while in the protected area, badges
will be displayed in a conspicuous manner on the upper front
torso, preferably in the vicinity of the collar at shoulder
height."
On September 15, the licensee failed to comply with the above
requirements, in that, the NRC Inspectors observed that:
1)
An assigned escort left two visitors unattended in the
turbine building while he used an adjacent restroom.
2)
One of the two visitors failed to display his security badge
on his upper front torso while in the protected area. The
badge was in the visitor's possession in his pocket.
These two examples constitute a violation, VIO 94-23-03:
Failure
To Follow Physical Security Plan.
Three violations were identified.
Except as noted above, the
area/program was adequately implemented.
4.
Maintenance Observation (62703)
a.
General
The inspectors observed safety-related maintenance activities on
systems and components to ascertain that these activities were
conducted in accordance with TSs, approved procedures, and
appropriate industry codes and standards. The inspectors
determined that these activities did not violate LCOs and that
required redundant components were operable. The inspectors
verified that required administrative, material, testing,
radiological, and fire prevention controls were adhered to. In
particular, the inspectors observed/reviewed the following
maintenance activities detailed below:
WR/JO 94-BTTOO1
Calibrate MDAFW Pump B Discharge
Pressure Gauge
WR/JO 94-BYE191
Calibrate RWST LI 969 and LT 969
WR/JO 94-ANIQI
Replace Control Room Exhaust Damper
Air Solenoid Valve
b.
Control Room Exhaust Damper Maintenance
On September 8, 1994, the inspectors witnessed maintenance on
control room exhaust damper CRD1A accomplished in accordance with
WR/JO ANIQI.
The maintenance effort consisted of replacing the
ASCO solenoid valve in the instrument air line to remedy a 30
second delay observed in the damper operation. The actuator, air
filter/regulator, and solenoid valve for the damper were removed
to facilitate the maintenance.
Overall, the repair efforts were satisfactory. Positive
attributes noted included involvement by the I&C supervisor during
the task and a questioning attitude on the part of the technicians
regarding difficulties in reconnecting the instrument air lines.
This questioning attitude resulted in the discovery and repair of
improperly configured connections in the instrument air tubing.
As part of this inspection, the inspectors reviewed Engineering
Evaluation, EE 94-133, Equivalency Evaluation For Control Room
Damper Solenoid Valves SV-6521 and SV-6522. This EE was performed
to allow the use of a replacement ASCO solenoid valves in the
damper control circuit which had different elastomer materials.
The replacement solenoid valves had ethylene propylene elastomers
while the installed solenoid valves had Viton elastomer materials.
The EE stated that the replacement valve was identical in all
other respects.
The ASCO literature enclosed in the EE noted that "Ethylene
propylene... has the distinct disadvantage that it cannot be used
with petroleum-based fluids or fluids so contaminated (such as
lubricated air)."
The EE addressed this caveat by stating that
instrument air is provided from non-lubricated air compressors and
that prefilters are provided in the system to remove oil and
water. Additionally, the EE noted that as described in the FSAR
the instrument air design basis is to supply oil free air, free of
foreign materials. Based on these arguments the EE concluded "it
has been demonstrated that the air supply to the subject valves
does not contain lubricated air, therefore, the use of ethylene
propylene elastomers for the subject valves will not present any
adverse concerns."
To confirm the validity of the premise for this conclusion, the
inspectors reviewed analyses of instrument air samples which
revealed methane, total gaseous hydrocarbons and oil mist/
12
particulate in small but measurable quantities. Following
inspector questioning, the licensee provided additional
information which demonstrated that the replacement valves
remained acceptable despite the air quality test results.
The inspectors concluded that the EE failed to adequately address
the impact of known instrument air contaminants documented in
existing test results on the replacement solenoid valve. While
the safety significance of this failure was minimal, this is
considered a weakness.
The manufacturer's literature provided to address the inspector's
concerns on instrument air contaminants contained a precaution
regarding the ASCO valves used in nuclear power plant
applications. The precaution stated that the quality of the air
flowing through the ASCO valve during both the exhaust and
pressurization cycles must meet the ASCO recommendations.
As configured in the control room damper installation, the damper
actuator is continually pressurized by instrument air supplied
through the ASCO solenoid valve. To close the damper, the
instrument air between the solenoid and the actuator is vented
through the solenoid and the actuator spring closes the damper.
Hence, the air in contact with the actuator is vented back through
the -ASCO solenoid. During the performance of the maintenance, the
inspectors noted an oily residue in the bottom of the instrument
air connection to the actuator (This material was subsequently
removed by the I&C technicians with swabs.) A review of the
actuator technical manual indicated that a DuBois MPG-2 grease or
equal is used in the actuator. On September 15, 1994, the
inspectors questioned the licensee on their compliance with the
ASCO recommendation on exhaust air quality given the observed oily
residue in the actuators air connection. Pending the licensee's
evaluation of this question, this will be tracked as an unresolved
item, URI 94-23-04:
Exhaust Air Quality Through ASCO Solenoid
Valve.
The inspectors also questioned the adequacy of the licensee's
testing of the exhaust dampers following the repair effort. The
inspectors' questions initially centered on the need to test the
capability of the CRD1A damper to seal following actuator removal
and installation. The inspectors were provided sufficient
information to demonstrate that a degradation in the sealing
capability of the damper following the observed maintenance was
unlikely. However, the inspectors questioned the licensee's
previous testing program for the exhaust dampers. The inspectors
were advised by the licensee that no testing was performed to
demonstrate the capability of a single exhaust damper to provide
sufficient isolation to allow control room pressurization. In as
much as the system was designed to remain operable following a
single active failure, the inspectors questioned the lack of a
test to demonstrate that the CR could be pressurized given the
13
failure of one exhaust damper to close. Pending further
inspection, this item will be tracked as an Unresolved Item,
URI, 94-23-05: Adequacy Of Control Room Exhaust Damper Testing.
No violations or deviations were identified. Except as noted above, the
area/program was adequately implemented.
c.
Surveillance Observation (61726)
The inspectors observed certain safety-related surveillance
activities on systems and components to ascertain that these
activities were conducted in accordance with license requirements.
For the surveillance test procedures listed below, the inspectors
determined that precautions and LCOs were adhered to, the required
administrative .approvals and tagouts were obtained prior to test
initiation, testing was accomplished by qualified personnel in
accordance with an approved test procedure, and test
instrumentation was properly calibrated. Upon test completion,
the inspectors verified the recorded test data was complete,
accurate, and met TS requirements, test discrepancies were
properly documented and rectified, and that the systems were
properly returned to service. Specifically, the inspectors
witnessed/reviewed portions of the following test activities:
OST-401
Emergency Diesels (Slow Speed Start)
(EDG A Only)
No violations or deviations were identified.
5.
Review of LERs (30703)
a.
(Closed) LER 92-010-00 and LER 92-010-01, Technical Specification
violation due to inadequate surveillance testing.
LER 92-010-00 and LER 92-010-01 which dealt with surveillance
testing of auxiliary feedwater flow were reviewed to determine if
the information provided met NRC requirements. The determination
included: adequacy of description, verification of compliance with
Technical Specifications and regulatory requirements, corrective
action taken, existence of potential-generic problems, reporting
requirements satisfied, and the relative safety significance of
the event. These LERs are closed.
b.
(Open) LER 94-13-00, EDG Fire Of June 6, 1994
This voluntary LER 94-13-00, which is being generated by the
licensee, involves an incident which occurred on June 6, 1994. A
small fire occurred on the "A" Emergency Diesel Generator (EDG)
during a test run. The fire was first observed by the System
Engineer who reported it to the Control Room at 11:39 a.m. The
site Fire Brigade was activated but during diesel load reduction,
the fire went out. The fire was reported out at 11:44 a.m.
14
There were no injuriesor equipment damage, nor was offsite
assistance required. Because the fire occurred on safety related
equipment, the site Emergency Plan required that an ALERT
condition be declared. Since no further emergency actions were
required after the fire was extinguished, the ALERT was terminated
shortly after being declared. The small fire was caused by lube
oil leaking from the engine where the exhaust manifolds attach to
the engine casing. The licensee subsequently determined that the
torque which had been applied to the bolts which secure the
manifolds to the engine had relaxed due to apparent thermal cycle
induced compression/crushing of the exhaust manifold gasket
material. A subsequent inspection of the disassembled exhaust
system also identified that the exhaust heat shield in the area of
the fire had been installed upside down. In this configuration,
the exhaust heat shield formed a small reservoir into which the
leaking oil had accumulated. This small accumulation of oil had
apparently resulted in the fire on June 6. The exhaust manifolds
were reinstalled and torqued to the proper value. A surveillance
program to monitor the EDGs for oil leakage was implemented as an
interim corrective action until long term corrective actions could
be identified and implemented.
After repairs were completed on June 9, 1994, the "A" EDG was
satisfactorily run with no leakage observed at the cylinder to
exhaust manifold interface, and the diesel was returned to
service.
The resident inspectors have routinely monitored the EDG's during
surveillance tests performed since June 9, 1994. It has been
noted that both EDG's continue to have oil leaks in the previously
identified exhaust manifold areas.
The licensee, as part of their Integrated Emergency Diesel Action
Plan, is communicating with other owners of Fairbanks Morse EDG's
to determine the extent of the problem, and to identify and
correct the root cause. The resident inspectors will continue to
monitor the diesels and the licensee's efforts to correct the
problem.
6.
Licensee Action on Previous Findings (92701, 90702)
(Closed) VIO 90-11-01, Inadequate Procedures To Implement TS
Surveillance.
This violation pertained to the lack of procedures to facilitate the
testing of power range high flux and two-out-of-three loop low flow
reactor trip logic channels.
A review of corrective actions indicated that the licensee has
implemented procedure changes to facilitate the required testing, and
performed an independent study to determine if there were other examples
15
of TS requirements which had not been implemented due to procedural
deficiencies. The independent study has been completed. This item is
closed.
(Closed) VIO 92-34-01, Failure To Follow Procedure While Performing
Spent Fuel Pool Cooling Surveillance.
This violation involved the performance of a single point temperature
calibration instead of a three point which was required. Corrective
actions included personnel counseling, and the installation of new
temperature indicating equipment which is easier to maintain. This item
is closed.
7.
Exit Interview (71701)
The inspection scope and findings were summarized on September 23, 1994,
with those persons indicated in paragraph 1. The inspectors described
the areas inspected and discussed in detail the inspection findings
listed below and in the summary. There were no dissenting comments
received from the licensee. The licensee did not identify as
proprietary any of the materials provided to or reviewed by the
inspectors during this inspection.
Item Number
Description/Reference Paragraph
Apparent Violation 94-23-01:
Failure To Properly Establish
Containment Integrity
(Paragraph 3.b).
Apparent Violation 94-23-02:
Pressurizer Cooldown In Excess of
Technical Specification Limits
(Paragraph 3.d).
Violation 94-23-03:
Failure To Follow Physical Security
Plan (Paragraph 3.e).
Unresolved Item 94-23-04:
Exhaust Air Quality Through ASCO
Solenoid Valve (Paragraph 4.b).
Unresolved Item 94-23-05:
Adequacy Of Control Room Exhaust
Damper Testing (Paragraph 4.b).
8.
List of Acronyms and Initialisms
ACR
Adverse Condition Report
Auxiliary Operator
CFR
Code of Federal Regulations
CR
Control Room
EE
Engineering Evaluation
GID
Generic Issue Document
LCO
Limiting Condition for Operation
16
LER
Licensee Event Report
Motor Driven Auxiliary Feedwater Pump
MS
NRC
Nuclear Regulatory Commission
Refueling Water Storage Tank
SCO
Senior Controls Operator
Senior Reactor Operator
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Violation
WR/JO
Work Request/Job Order