ML18152A188
| ML18152A188 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 02/05/1996 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A189 | List: |
| References | |
| 50-280-95-23, 50-281-95-23, NUDOCS 9602120319 | |
| Download: ML18152A188 (20) | |
See also: IR 05000280/1995023
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-280/95-23 and 50-281/95-23
Licensee: Virginia Electric and Power Company
Innsbrook.Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry land 2
Inspection Conducted:
December 3, 1995 through January 6, 1996
Inspectors:
Approved by:
M:W. ranch' SenlOreSl e ~Spector
D. M . .Kern, Resident Inspector
W. K. Poertner, Resident Inspector
Reactor Projects Branch 5
Division of Reactor Projects
SUMMARY
Scope:
).- ~-9'~
Dateigne
This routine resident inspection was conducted on site in the areas of plant
operations, maintenance, engineering, and plant support.
Results:
Plant Operations
A lack of attention to detail by the chemistry staff while conducting the
Unit l moisture carryover test resulted in an unnecessary plant transient and
is considered a weakness (paragraph 2.2) .
9602120319 960205
ADOCK 05000280
Q
PDR.
ENCLOSURE 2
2
A letdown line leak was attributed to a lack of fusion of an original
construction weld (paragraph 2.3).
The inspectors questioned the adequacy of the Power Operated Relief Valve
(PORV} alarm response procedure which directed that both PORVs be isolated and
declared inoperable upon actuation of one low pressure pressure switch.
The
licensee initiated a DR to review the TS requirement, the alarm response
procedure, and the adequacy of the air system design (paragraph 2.4).
The Unit 2 Low Head Safety Injection System was properly configured and
labeled to support unit operation (paragraph 2.5).
Actions taken by the licensee to address human performance problems were
appropriate (paragraph 2.6.1).
The Quality Assurance Tracking and Trending System was effectively used
(paragraph 2.6.2).
Maintenance
Test personnel were knowledgeable of procedural requirements and good self
checking practices were noted during surveillance testing of the seismic
monitors (paragraph 3.1) .
Skill-of-the-craft practices for draining Reactor Coolant Pump (RCP} motor
upper reservoir oil to clear high level alarms appeared to be a major
contributor to a RCP IA motor bearing high temperature condition.
Immediate
corrective actions taken to address the elevated RCP motor upper thrust
bearing temperatures were appropriate.
Interim RCP motor temperature
trending, high bearing temperature alarm setpoint reduction, and reservoir oil
level inspections were prudent (paragraph 3.2).
Maintenance department actions to evaluate followup issues which surfaced
during the RCP IA motor oil loss assessment were slow and indicated a lack of
issue ownership (paragraph 3.2).
Engineering
The decision to develop a documented design basis to preserve the containment
drainage features was prudent (paragraph 4.1.2).
Plant Support
The emergency drill conducted December 6, demonstrated the ability to
prioritize tasks and identify accident mitigation activities. However,
weaknesses in implementation were still apparent (paragraph 5.1).
Radiation Protection (RP) oversight for multiple containment entries to
address RCP motor oil leakage was excellent.
In addition, RP technicians were
instrumental in identifying a source of RCP motor oil leakage within
containment (paragraph 5.2).
-
- --- - ...
- --***
' .
i
3
Containment entries to evaluate RCP IA motor oil reservoir level alarms
following pump starts have been a routine occurrence for a known problem.
The
repeated entries have been a significant contributor to total personnel
radiation exposure (paragraph 5~2).
'-
Multiple examples of failure to follow RWP requirements associated with a
Unit 2 leak repair were identified as a violation (paragraph 5.3) .
.. *
REPORT DETAILS
Acronyms used in this report are defined in paragraph 8.
1.0
PERSONS CONTACTED
Licensee Emplovees
2.0
- Ashley, J., Administrative Services
- Benthall, W., Supervisor, Procedures
- Biron, M., Station Nuclear Oversight
Blake, H., Jr., Superintendent of Nuclear Site Services
- Blount, R., Superintendent of Maintenance
- Butrick, P., Radiation Protection
- Chris, M., Superintendent of Operations
- Christian, D., Station Manager
Costello, J., Station Coordinator, Emergency Preparedness
- Cramer, R., Nuclear Site Services
- Cross, R., NS&L, Procedures
- Dahn, D., Inservice Inspection, NOE
Erickson, D., Superintendent of Radiation Protection
- Garber, B:, Licensing
Garner, R., Outage and Planning
Hayes, D., Supervisor of Administrative ~~rvices
Lovett, C., Supervisor, Licensing
Luffman, C., Superintendent, Security
- McCarthy, J., Assistant Station Manager, Operations and Maintenance
- McConnell, F., Materials
- McGinnis, J., Station Nuclear Safety
- Medlin, G., Maintenance, Welding
- Miller, D., Radiation Protection
- Miller, G., Corporate, Licensing
- Moore, W., Operations
- Ringler, M., Engineering
Saunders, R., Vice President, Nuclear Operations
- Savage, K., Maintenance
- Savedge, R., Security *
- Shriver, B., Assistant Station Manager, Nuclear Safety and Licensing
- Sloane, K., Superintendent of Outage and Planning.
- Sommers, D., Supervisor, Licensing - Corporate
- Sowers, T., Superintendent of Engineering
Stanley, B., Director, Station Nuclear Oversight
- Steed, T., Radiation Protection
Swientoniewski, J., Supervisor, Station Nuclear Safety
Other licensee employees contacted included office, operations,
engineering, maintenance, chemistry/radiation, and corporate personnel.
PLANT OPERATIONS (40500, 71707, 92901)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
- .- ...
- '
-*
. i
.
<
2
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability. Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
2.1
Plant Status
2.2
Unit 1 operated at 100 percent power until December 7 when power was
reduced to less than 30 percent due to high chlorides in the SGs.
The
unit returned to full power on December 8 and operated at 100 percent
for the remainder of the period.
Unit 2 operated at 100 percent power throughout* the period.
Unit 1 Power Reduction Due to High SG Sodium and Chloride
At 1:23 a.m. on December 7, during conduct of the Unit 1 moisture
carryover test per 1-ST-0314, Steam Generator Moisture Carryover
Measurement, revision 2, high sodium and chloride levels were identified
in the SG samples. Action Level 2 limits (100 ppb) were exceeded which
required that power be reduced to less than 30 percent within six hours
per the Nuclear Plant Chemistry Manual.
At 2:30 a.m., a power reduction
commenced but was terminated at 96.5 percent power pending results from
backup samples.
At 4:25 a.m., the power reduction was continued and
power was*reduced to less than 30 percent at 10:00 a.m.
This power
reduction was of concern since Unit 1 had elevated RCS activity because
of previous fuel clad defects and RCS activity did increase when 100
percent power was restored.
During the moisture carryover test, SG blowdown, condensate polishing
and the chemistry on-line monitoring systems were removed from service.
Condenser hotwell samples obtained at 3:05 a.m., did not indicate any
increase from the levels prior to commencing the test.
SG blowdown was
returned to service at 3:20 a.m. to aid in SG cleanup and chemistry
personnel continued investigating the cause of the excursion.
and chloride levels peaked at approximately 144 ppb and 260 ppb,
respectively. During the power reduction hotwell sodium levels
increased from .22 ppb to .8 ppb.
Based on the increased hotwell sodium
levels, chemistry personnel recommended that the condensate polishing
system be returned to service. At 12:30 a.m. on December 8 sodium and
chloride levels decreased below Action Level 1 limit of 10 ppb, and the
unit was returned to 100 percent power.
The licensee determined that the high sodium and chloride levels were
due to concentration in the SGs of the sodium and chlorides from the
hotwell.
Prior to commencing the moisture carryover test, the chemistry
department calculated the expected concentrati-ons of contaminants in the
SGs and determined that Action Level 2 conditions would not be achieved
3
for the duration of the test. The chemists' calculation was an informal
calculation based on concentration factors posted on the chemistry
supervisor's office and was not independently reviewed or verified. The
concentration factors used were derived from mass balance studies and
assumed a SG blowdown rate of 60 gpm.
However, during the test, SG
blowdown was isolated. The licensee initiated a root cause evaluation;
however, the evaluation had not been completed as of the end of the
inspection period.
The inspectors will review the evaluation when
completed by the licensee.
The lack of attention to detail by the
chemistry staff, which resulted in an unnecessary plant transient, is
considered a weakness.
2.3
Unit 2 Letdown Line Leak
2.4
At 2:43 a.m. on December 13, Unit 2 RCS unidentified leakage increased
from 0.181 gpm to 0.604 gpm.
Due to an increase of greater than 0.2 gpm
unidentified leakage, the operators initiated another leakrate
calculation and commenced component walkdowns outside containment.
Health physics personnel were also notified to sample containment
atmosphere.
At 3:01 a.m., the backup leakage calculation was completed and indicated
0.722 gpm unidentified leakage.
At 6:15 a.m., a containment entry was
made to identify the source of the increased RCS leakage.
The
inspection determined that a welded tee connection immediately
downstream of the letdown orifice isolation valves was leaking.
The
leak location allowed the leak to be isolated by securing normal letdown
and charging.
The excess letdown system was placed in servite at 6:56
a.m., and normal letdown and charging was isolated at 6:57 a.m.
The
initial system isolation from the control room using remotely operated
valves did not stop the leakage from the letdown system due to leakage
past the valve seats. Subsequently, manual isolation valves inside
containment were closed to isolate the letdown system to allow repair.
The system was completely isolated and drai~ed at 8:50 p.m.
The leaking
weld connection was weld repaired and normal letdown and charging was
re-established at 5:23 a.m. on December 15.
The licP.nsee determined
that the weld in question was original construction and that the cause
of the weld failure was lack of fusion between weld passes.
Both Unit 2 PORVs Inoperable
At 3:40 a.m. on December 26, annunciator D-C-6, Pressurizer Power Relief
Valve Low Header Pressure, was received in the Unit 2 control room.
Based on the annunciator response procedure, the operators declared both
Unit 2 PORVs inoperable and entered TS 3.1.A.6.
TS 3.1.A.6 requires
that with both PORVs inoperable and not capable of being manually cycled
within one hour, restore at least one PORV to operable status or close
the associated block valves and remove power from the block valves.
The
TS also requires that the unit be placed in hot shutdown within the next
six hours and that RCS average temperature be reduced to less than 350
degrees F within the following six hours. This new TS requirement was
implemented in June 1995.
The PORV block valves were shut and
-*
2.5
4
deenergized at 4:39 a.m., and preparations were commenced to perform a
containment entry to investigate PORV air pressures.
A containment entry at 5:40 a.m. determined that the PORV air bottle
pressures and regulator downstream pressures were above the alarm
setpoints. The air bottle for PORV 2-RC-PCV-2455C was reading 1400 psi
and was swapped with the spare air bottle to increase air pressure to
2500 psi. Based on the satisfactory air pressures, the licensee
declared both PORVs operable, reopened the block valves at 7:07 a.m.,
and initiated a work request to determine the cause of the alarm.
The
air bottle regulators associated with both PORVs were adjusted.
The low
pressure alarm cleared when the regulator for PORV 2-RC-PCV-2456 was
~djusted.
The safety related portion of each PORV air line is physically
independent and contains two pressure switches that can actuate the low
pressure alarm; however, the control room alarm is common to both PORV
air systems.
Air system pressure indication is not available outside
containment and a containment entry is required to determine system
operating parameters.
The system pressures are monitored monthly during
unit operation.
The inspectors questioned the adequacy of the PORV
alarm response procedure which directed that both PORVs be isolated and
declared inoperable upon actuation of one low pressure pressure switch.
The licensee initiated a DR to review the TS requirement, the alarm
response procedure, and the adequacy of the air system design.
The
licensee had not completed the review as of the end of the inspection
period.
The inspectors will review this item further during future
inspections.
Low Head Safety Injection System Walkdown
During the inspection period, the inspectors performed a detailed
walkdown of the accessible portions of the Unit 2 LHSI system to verify
operability. The inspectors verified that the as-built configuration
matched the plant drawings.
The inspectors verified proper valve
position, labeling, instrumentation operability, housekeeping, freeze
protection, and*electrical breaker position. The inspectors determined
that the Unit 2 LHSI system was properly configured and labeled to
support unit operations.
2.6
Self Assessment
2.6.1 Station Standdown
On December 7, the licensee conducted a site human performance day.
All
non-essential work activities were secured for the day and meetings were
conducted by all site groups to discuss human performance.
The meetings
included a video presentation concerning teamwork, discussions on
avoiding complacency, presentations on excellence in human performance,
and discussions on recent human performance errors that have occurred at
Surry.
In addition to the group meetings, a survey/questionnaire was
also issued to the plant staff to allow feedback to site management.
- -* ~-
,#
- .
5
Preliminary review of the survey responses identified three areas for
improvement.
The areas identified included conununication,
interdepartmental teamwork, and administrative barriers. The inspectors
consider the actions taken by the license~ to address human performance
problems were appropriate.
2.6.2 Quality Assurance Tracking and Trending System
The QATTS system is used by station oversight personnel to track
findings, observations, and selected discrepancies identified by the
oversight organization to ensure corrective _action is accomplished.
However, QATTS does not initiate corrective action.
In NRC IR No. 50-
280, 281/95-22 the inspectors observed that QATTS item M-95-01640, which
addressed a PT program weakness, was not being tracked or corrected in a
timely manner.
This item was placed in the QATTS system for tracking,
but had no corresponding action item assigned within the licensee's
corrective action process.
The inspectors reviewed the current QATTS
open *item data base to determine whether open QA issues were being
properly tracked at the station following the recent Station Oversight
Organization reorganization.
QADI-l.7CNS, Tracking Program, revision 4 describes the QATTS system.
Responsibilities are clearly defined and the program is described in
general detail. The inspectors observed that the instruction has not
been updated to reflect its operation under the new Station Oversight
Organization. The station oversight manager informed the inspectors
that corporate QA personnel were currently updating the procedure. A
nuclear oversight specialist has recently been assigned to track QATTS
open items until the QADI-l.7CNS revision is complete.
The inspectors reviewed the open item database with the nuclear
oversight specialist and determined that the QATTS system was being
effectively tracked.
Item M-95-01640, which had been two months overdue
for review, was an isolated case. Oversight nuclear specialists were
making detailed observation entries and using the QATTS system in a
meaningful way to track various performance trends. The inspectors
reviewed the latest monthly Nuclear Oversight Organization Open Audit
Finding Report and noted that audit findings were being tracked in a
timely manner.
The inspectors concluded that the QATTS system was
effectively used.
2.7
Open Item Followup Review
The inspectors reviewed applicable licensee updates and responses to
previously identified regulatory issues.
The purpose of this review was
to verify description accuracy, determine generic applicability and
cause, and to evaluate ariy precursor events and the effectiveness of
corrective actions.
(Closed) URI 50-280, 281/94-06-01: Not Performing a 10 CFR 50.59 Safety
Evaluation For Administrative Control of Plant Equipment.
)
- '-,
'
-~
- 1
i !
. l
l
6
This URI involved an interpretation of 10 CFR 50.59, as it applied to
administrative control of plant equipment described in the UFSAR.
As
documented in NRC IR 50-280, 281/94-06, the inspectors questioned the
adequacy of the 10 CFR 50.59 review that was performed for procedure
1-EPT-0902-01, Fire Protection Low Pressure Carbon Dioxide System Puff
Test, dated September 15, 1993.
Specifically, the procedure instructed
that a normally locked open valve (l-FP-1052) be closed for the test and
that an operator be stationed to reopen the valve if necessary.
The
procedure was approved with only a 10 CFR 50.59 screening which
indicated that a Safety Evaluation (SE) was not necessary.
The
inspectors considered that the licensee was operating the system in a
manner different from the automatic system described in Section
9.10.2.2.7 of the UFSAR and that a SE was required pursuant to 10 CFR
50.59(b)(l). The safety significance of the event was minimal and the
licensee subsequently performed a SE which indicated that the practice
was acceptable.
However, this example when combined with the licensee's
NOV response dated July 31, 1992, involving similar issues indicated
that a misunderstanding of the requirements existed between the licensee
and the NRC .
The licensee had interpreted the NRC's position to include the need to
perform 10 CFR 50.59 SEs for all operational activities described in
general UFSAR descriptive information. During recent discussions with
licensee management, the inspectors clarified the NRC's position and
informed management that it was never the intent to apply such a broad
interpretation to the SE requirements.
However, for the example
described in the URI, a SE would be required prior to substituting
manual operator action for an automatic function described in the UFSAR
unless the equipment is considered inoperable and appropriate actions
taken.
No violations or deviations were identified.
3.0
MAINTENANCE (62703, 61726)
3.1
During the reporting period, the inspectors reviewed the following
maintenance and surveillance activities to assure compliance with the
appropriate procedures and TS requirements.
Seismic Instrumentation Surveillance Testing
On December 11, the inspectors monitored the performance of portions of
procedure PT-31.3, Seismic Instrumentation Status Check Recording,
revision 1.
The stated purpose of this procedure was to ensure the
operation and calibration of the SMA-3 Strong Motion Accelerograph
System.
This system is common to both units and this test is performed
on a monthly basis. Test results were satisfactory, and at the
completion of the test, the inspectors verified that test cassettes were
removed and the active tape cassettes were reinstalled. Test personnel
were knowledgeable of procedural requirements and good self checking
practices were noted.
j
~
\\
1
l *
' ,.
i'
3.2
7
Reactor Coolant Pump Motor Oil Leak
Background
The inspectors have noted that operators often receive the RCP motor oil
reservoir hi-low level alarm upon starting certain RCPs.
Abnormal motor
oil reservoir level may indicate CCW inleakage or an oil loss which is a
precursor to RCP motor bearing overheating.
Electricians enter
containment to locally determine whether the motor oil reservoir level
is high or low.
Electricians typically find the oil level one-inch high
and use skill-of-the-craft practices to drain oil and restore normal
motor oil reservoir level. -Oil samples have contained no indication of
CCW inleakage.
Based on discussions with the vendor, system engineers
have determined that RCP startup dynamic effects cause motor oil
reservoir 1 eve 1 to increase by abo~,t eight ga 11 ons { one inch on the
local sight glass) which actuates the level alarm.
This dynamic effect
is only characteristic to some of the RCP motors.
RCP Motor Thrust Bearing High Temperature
On December 7, control room operators received the Unit 2, RCP lA motor
upper thrust bearing high temperature alarm.
Bearing temperature
indicated 180 degrees F {normal is 135 degrees F).
Electricians entered
containment to further investigate the high temperature alarm.
The
motor upper bearing oil reservoir level indicated four gallons low on
the local sight glass. Electricians added four gallons of oil, but the
sight glass level did not change.
In addition, the electricians
tightened three loose RTD connectors and the indicated motor thrust
bearing temperature immediately dropped to 163 degrees F.
Visual
inspection of a RCP motor oil sample revealed no.indications of oil
overheating or thrust bearing damage.
Operators continued to monitor
the motor upper thrust bearing temperature on an accelerated basis.
Task Team Evaluation and Maintenance Activities
A task team was formed on December 9 to evaluate RTD indication
reliability and possible oil leakage from the motor upper bearing oil
reservoir.
The inspectors observed various maintenance activities and
attended task team meetings to determine whether licensee response to
the elevated RCP motor upper thrust bearing temperature was appropriate.
The team conferred with the vendor throughout their evaluation.
The
task team developed an action plan and directed maintenance activities
to address the following immediate safety concerns; (1) restore normal
motor upper thrust bearing oil reservoir level and cooling, (2)
determine whether an active oil reservoir leak exists, (3) evaluate
potential fire hazards resulting from RCP motor.oil leakage, and (4)
restore the RCP motor oil reservoir low level alarm to service.
Temperature continued a gradual increase, reaching 186 degrees Fon
December 9.
The vendor confirmed that bearing damage would not occur
below 200 degrees F.
Personnel stay times and the amount of oil added
per containment entry were limited due to heat stress and radiation
j
' ; .
/
8
exposure considerations. The motor upper thrust bearing temperature
dropped incrementally during five oil additions (28.5 gallons total) and
eventually stabilized at 131 degrees F.
The high temperature alarm
setpoint was lowered from 175 to 150 degrees F to provide earlier
warning to operators in the event bearing temperature increased.
The team concluded that the motor upper thrust bearing was now covered,
but that motor oil reservoir level remained 20-30 gallons below normal.
Sight glass oil level indication was unchanged, indicating four gallons
low.
Following additional discussions with the vendor, the team
suspected that an equalization hole in the level instrument standpipe
was blocked.
Due to standpipe configuration, this blockage would
prevent the standpipe from indicating accurately.
The motor oil
reservoir low level alarm in the control room was therefore rendered
Electricians added an additional 23 gallons to restore the motor upper
thrust bearing oil reservoir to normal operating level.
The team
concluded that oil reservoir level had actually been about 52 gallons
below the normal operating level with the motor upper thrust bearing
partially uncovered when the high temperature alarm was first received.
In conjunction with the last oil addition, electricians raised the RCP
motor oil reservoir low level alarm switches to make the system
insensitive to a plugged standpipe equalization hole. This action
restored motor oil reservoir low level alarm operability .. Electricians
independently developed the low level alarm plan and proposed it to the
team.
The inspectors discussed the alarm restoration work with the
electrical super~1sor and considered it a positive interim solution.
Each RCP motor has an attached oil leakage collection system to reduce
the potential for fire inside containment. A small leak from the oil
leak collection tank sight glass was subsequently identified and
isolated.
The team observed that this leak was minor and not a likely
cause for the 52 gallons of reservoir oil loss. Electricians found no
further external oil leaks in the vicinity of the RCP or the bearing
lift pump support system.
Motor upper thrust bearing temperature and
oil reservoir level remained stable for the following two weeks
confirming that a significant active oil leak did not exist. Fire
protection engineers determined that the spilled oil external to the oil
leak collection tank did not present a fire hazard.
Followup Corrective Actions
The inspectors noted that the initiating event which caused the RCP
motor oil loss had not been identified. Skill-of-the-craft practices
for draining RCP motor upper reservoir oil to clear high level alarms
appeared to be a major contributor to the RCP motor thrust bearing high
temperature condition. Additionally, the inspectors questioned whether
vendor recommended RCP motor modifications were adequately communicated
within the licensee organization. A vendor modification to expand the
equalization hole had not been implemented on the RCP IA motor.
The
team identified several items for further review including the potential
~i -
9
for plugged equalization holes on other RCP motors, modifications, leak
identification, prestartup RCP inspections, and RCP startup dynamic
influences on motor oil level indication.
In addition, the electrical
department was assigned to evaluate current practices for draining RCP
motor oil and to propose procedural guidance for this activity.
The team leader informed the inspectors that root cause analysis and
actions to preclude recurrence were being developed separate from the
task team through the DR process.
The inspectors reviewed associated
DRs S-95-2916, S-95-2927, and S-95-2952 and noted that the assigned
responses were overdue with no extensions requested.
In addition, the
DRs did not appear to fully encompass the task team's initial
observations.
The Maintenance Superintendent informed the inspectors
that recent personnel reassignments within the maintenance department
may have contributed to the DR response delays.
The maintenance
department subsequently requested DR response extensions and initiated a
category 2 RCE to.determine the RCP motor thrust bearing high
temperature initiating event and ~ctions to preclude recurrence.
The
inspectors concluded that these actions were slow to develop and a lack
of issue ownership was evident.
Conclusions
The inspectors concluded that the immediate corrective actions taken to
address the elevated RCP motor upper thrust bearing temperatures were
appropriate.
Interim RCP motor temperature trending, high bearing
temperature alarm setpoint reduction, oil reservoir level alarm
restoration, and reservoir oil level inspections were good.
Root cause
analysis and action to preclude recurrence appeared slow and lack of
issue ownership was evident. The inspectors informed station management
that timely and successful RCE and DR resolution was important from a
radiological aspect in addition to RCP reliability concerns.
No violations or deviations were identified.
4.0
ENGINEERING (37551, 92700, 92903)
4.1
Open Item Followup Review
The inspectors reviewed applicable licensee's updates and responses to
previously identified regulatory issues, as well as, LERs submitted to
the NRC.
The purpose of this review was to verify description accuracy,
determine generic applicability and cause, and to evaluate any precursor
events and the effectiveness of corrective actions.
In addition,
applicable LERs were also reviewed with respect to the requirements of
~
10 CFR 50.73 and the guidance provided in NUREG 1022, Licensee Event
Report System, and its associated supplements .
- * 'C. ~:
10
4 .1.1 (Closed}
LER 280/94-05, Steady State Reactor Power Exceeded Operating License
Limit, describes Unit 1 power operation above the licensed reactor power
limit during power ascension from a refueling outage on March 30, 1994.
The steam flow transmitters had been respanned during the refueling
outage.
However, the SFR based FLOWCALC program was not properly
revised to reflect this change.
Inadequate processes to implement
instrumentation and computer program changes resulted in the unit
operating at an average power of 100.5 percent for an eight hour period.
Reactor power remained below 102 percent and within the power level
assumed in Surry Station accident analysis.
Based on the limited
magnitude and duration of the power excursion, the inspectors concluded
that this event had minor safety significance. This event is further
documented in NRC IR No. 50-280, 281/94-11.
The LER accurately
described the event and addressed the reporting criteria specified in
The effectiveness of the corrective actions will be
evaluated during the closeout inspection of VIO 50-280/94-11-01.
4.1.2 (Closed) URI 50-280, 281/94-31-01, Containment Design Feature.
This item involved operation of Unit 2 for a complete fuel cycle (cycle
11) with the reactor cavity fuel transfer canal drain valves closed.
The inspectors questioned the acceptability of that practice and were
provided additional information from the licensee's NAF organization.
Since the information provided did not appear to address how containment
design features, associated with spray drainage return flow pathways to
the containment sump, were documented and preserved, the inspectors
requested that the licensee's provided information be reviewed by NRC
staff familiar with containment design features and requirements.
On October 3, 1995, the NRC staff met with the licensee on site for the
purpose of reviewing the above issue. At the meeting, the licensee
discussed the various flow paths that would provide the means for spray
drainage fluid to return to the containment sump.
These flow paths are
provided by various miscellaneous structural features sud as the
ductwork containing non-watertight dampers, shielding plugs and access
ways having non-watertight closures.
(One of these flow paths had been
previously demonstrated as a valid flow path during a refueling event in
which water leaked from the refueling cavity into the reactor cavity and
out of the reactor cavity onto the containment floor via a nontight
access plug.}
These flowpaths would rely on leakage past non-tight
closures.
However, if the closures were indeed watertight, the
additional entrapment volume corresponding to the higher coolant piping
penetrations is relatively small.
Based on these flowpaths, the
licensee determined the maximum credible fluid entrapment was 71,000
gallons, corresponding to flooding of the reactor cavity to the minus
(below grade} 7 foot 2 inch level in the containment. This entrapment
volume is accounted for in the existing NPSH calculations. The licensee
estimated that the lost fluid volume due to fuel transfer canal
entrapment would result in a reduction of sump level of less than two
inches and that the associated NPSH reduction would not be significant.
11
The licensee documented these findings earlier in an internal memorandum
dated November 22, 1994.
With an entrapment volume of 71,000 gallons, adequate NPSH would still
have been available. Based on a conservative effective containment
diameter of 115.4 feet, the reduction in containment floor water level
corresponding to removal of 71,000 gallons of drainage water is 0.90
feet.
Existing NPSH calculations (Table 3.6.2-5 of August 30, 1994,
amendment application) indicate that sufficient excess margin is
available to acco11111odate this reduction in water level assuming that the
sump fluid temperature is not increased as a result of the entrapment.
The staff felt that it was reasonable to assume that the temperature and
thus the vapor pressure of the unentrapped sump water would not increase
due to entrapment of spray liquid.
Subsequent to the inspectors' identification of the URI the licensee
determined that the refueling transfer canal drain valves should remain
open during unit operation.
The licensee is developing a documented
design basis for the containment drainage features to preserve this
function during any subsequent modification. This item was prudent and
was being tracked by the licensee under CTS item 3307.
No violations or deviations were identified .
5.0
PLANT SUPPORT (71750, 92904)
The inspectors conducted facility tours, work activity observations, personnel
interviews, and documentation reviews to determine whether license programs
met regulatory requirements in the areas of radiological protection, security
and fire protection. Radiological areas were properly posted.
5.1
Emergency Drill
The inspectors observed the Surry emergencv plan training exercise
conducted December 6.
The purpose of the training exercise was to
provide emergency response personnel the opportunity to practice and
demonstrate their ability to activate, implement, and evaluate portions
of the Surry Emergency Pl an and implementing procedures.
The focu*s i tern
of this emergency drill was accident mitigation and damage control.
An
Exercise Weakness (EW) (50-280, 281/95-10-01) had been identified
previously concerning damage control not being expeditiously managed to
perform prioritized tasks designated for accident mitigation.
The inspectors reviewed the drill scenario and observed activities
conducted at the OSC throughout the drill. The drill scenario developed
included a stuck open SG safety relief valve. This portion of the drill
was identical to the previous scenario that identified the exercise
weakness.
The licensee implemented an accident mitigation team concept
as a result of the previously identified weakness.
The SG safety relief
valve failure was identified as an accident mitigation task and an
accident mitigation team was initiated from the OSC to gag the relief
valve.
The team was formed and dispatched expeditiously; however, when
5.2
5.3
12
the team arrived at the relief valve, all the equipment necessary to gag
the relief valve was not present in the field.
The OSC also dispatched
a team to repair an auxiliary feedwater pump withou~ the knowledge of
the TSC.
The TSC had directed the OSC to ~lan a task to repair the pump
and the OSC understood the direction to mean plan and work the task.
The drill demonstrated the ability to prioritize tasks and identify
accident mitigation activities. However, weaknesses in implementation
were still apparent and recognized by the licensee. The inspectors will
review this area again during the next emergency exercise or practice
drill.
RP Coverage for RCP Motor Oil Leak Investigation
Containment entries to evaluate and correct the RCP IA motor upper
thrust bearing high temperature condition discussed in paragraph 3.2
presented a high risk for excessive personnel radiation exposure.
SNSOC
reviewed and approved the RWPs as required by VPAP-2101, Radiation
Protection Program, revision 7-PSl, for high risk evolutions.
Management determined that reactor power would not be reduced to
minimize personnel radiation exposure during this job.
The unit
remained at full power during this work.
The inspectors discussed RWP
95-2-1137 and 95-2-1138 in detail with the RP department manager and
observed RWP briefings. The RWP was thorough, briefings were detailed,
and RP technicians closely monitored each individual's accumulated dose
throughout the multiple containment entries performed on these RWPs.
oversight was excellent.
In addition, RP technicians were instrumental
in identifying a source of RCP oil leakage within containment.
RCP motor oil leak evaluation and correction was a significant
accumulated radiation dose activity. Total personnel exposure for this
job was 4.233 REM and the maximum individual dose was 424 mREM.
The
inspectors noted that containment entries to evaluate RCP IA motor oil
reservoir level alarms following pump starts have been a routine
occurrence which resulted from known dynamic conditions for this RCP
motor.
The repeated entries have been a significant contributor to
total personnel radiation exposure. Station management informed the
inspectors that the need for frequent containment entries would be
evaluated during the ongoing RCE.
RWP Implementation for RCS Letdown System Leak Repair
On December 14, workers performed a containment entry to accomplish a
letdown system leak repair while Unit 2 was at 100 percent power.
Surry
has a subatmospheric containment requiring personnel to use SCBA oxygen
bottles for containment entry.
The work plan was established for a five
person work team comprised of one RP technician, two welders, one design
engineer, and one NOE technician. The RP technician served as the team
leader. Following the RWP brief and the operations pre-entry brief, one
person was removed from the work team due to questions regarding his
containment entry qualification status. The work team went ahead with
the containment entry and letdown system repair without stopping to
13
reevaluate the work plan. During the repair, the design engineer had
trouble breathing, appeared anxious, and requested to immediately exit
containment.
The HP technician escorted the e1igineer to the containment
airlock while the remaining two workers continued the weld repair.
Immediately following repair completion, the inspectors and the licensee
determined that several RWP requirements were violated.
The inspectors
reviewed the event to determine causal factors and evaluate licensee
followup activities.
The licensee initiated DRs S-95-2967, -2968 and -2970 and a RCE to
investigate the event and to recommend corrective actions.
Based on
interviews, document review, and discussions with the RCE.team the
inspectors determined the following:
The RWP 95-2-1140 pre-evolution brief was incomplete.
Protective
clothing requirements were not discussed as specified in the RWP
briefing checklist developed using HP-1081.20, Radiation Work
Permits: RWP Briefing and Controlling Work, revision 3.
Workers did not read and understand the RWP as required by
VPAP-2101, Radiation Protection Program, revision 7-PSl, prior to
entering the RCA.
RWP 95-2-1140 required two sets of PCs for welding and grinding .
Green fire retardant welding PCs were required as the outer PC
set. The two workers who performed welding and grinding
activities failed to wear the required second set of PCs.
Upon
exiting containment, one worker was determined to be contaminated.
RWP 52-2-1140 required continuous RP coverage for all team members
during this work activity in a locked high radiation area.
Two
welders continued their work for approximately 15 minutes without
RP coverage while the RP technician assisted the design engineer
to the containment air lock. The welders misunderstood the RP
technician's hand signal to evacuate containment in a group.
Both
the welders and the RP technician failed to verify what each other
was ~ctually doing.
The team leader failed to maintain control
over the entire team.
The welders failed to verify that they had
RP coverage and failed to evacuate containment when a team member
had to be evacuated for personnel safety.
The process for tracking personnel stay time as contained in
VPAP-0106, Subatmospheric Containment Entry, revision O-PS3, was
not uniformly understood and implemented.
The RCE team preliminary findings were consistent with the inspectors'
observations.
The inspectors expressed concern that this event
indicated more than an RP supervisor's failure to properly brief workers
on RWP requirements~ Several individuals failed to demonstrate personal
accountability with regard to implementing VPAP-0106, VPAP-2101, and
H~-1081.20 responsibilities. Station safety engineers informed the
inspectors that the RCE would address the above issues, as well as,
'I
- -
---
-- --
14
additional concerns raised by the RCE.
The RCE was in progress when
this report period closed. Preliminary RCE findings*appeared well
focused.
TS 6.4.8 requires procedures for personnel radiation protection be
prepared consistent with 10 CFR 20.
Further, workers must adhere to
these procedures for all operations involving personnel radiation
exposure.
VPAP-2101 is the implementing procedure for the radiation
protection program at Surry. HP-1081.20 provides instructions for
developing RWP briefing checklists and conducting RWP briefings. The
above listed observations identify several examples where personnel
violated RWP requirements established by VPAP-2101 and HP-1081.20.
A
NCV was previously documented in NRC IR No. 50-280, 281/95-21 for
failure to follow RWP procedures. Corrective actions for the NCV failed
to preclude this event.
The multiple personnel violations of RWP
requirements are identified as VIO 50-281/95-23-01, Multiple Personnel
Violations of RWP Requirements.
5.4
Open Item Followup Review
The inspectors reviewed licensee updates and responses to previously
identified regulatory issues to assess the effectiveness of corrective
actions .
5.4.1 {Open) EW 50-280, 281/95-10-01, Damage Control Teams Were Not Timely
Dispatched.
This item is discussed in paragraph 5.1. This item will remain open
pending further review.
5.4.2 {Closed) URI 50-280; 281/93-30-01, MER-5 Power Supply Cable Fire Barrier
Adequacy.
This issue is discussed in detail in NRC IR 50-280, 281/93-30, and
involved the acceptability of the licensee's approach to qualifying the
newly installed power supply cables for MER-5 equipment to the fire
protection requirements of 10 CFR 50 Appendix R.
The licensee had
attempted to install a three hour qualified fire wrap on the cables but
space limitations only allowed the installation of a one hour wrap.
With only a one hour wrap, the requirements of 10 CFR 50, Appendix*R,
section III.G.2.c were not satisfied since the emergency switchgear room
was not protected by an automatic fire detection and suppression system.
The licensee had attempted to disposition this item internally by
performing engineering evaluation no. 25, Evaluation of Lack of an
Automatic Fire Suppression System in Unit 2 Emergency Switchgear Room
Surry Power Station, revision 0.
The inspectors questioned the licensee
as to the need for an exemption to the 10 CFR 50, Appendix R
requirements prior to declaring the fire barrier operable.
The licensee
elected to maintain a fire watch.in the area until this issue was
resolved.
' I
15
Subsequent to identification of the URI, the licensee submitted a 10 CFR
50, Appendix R exemption request to the NRC staff for review. After
meetings with the NRC staff, the licensee w:thdrew their exemption
request because they believed that they could preserve the alternate
shutdown capability required by Appendix R without the need for
equipment cooling provided by the chillers that were powered by the
electrical cables in question. After attempts to demonstrate alternate
shutdown capability without equipment cooling failed, the licensee tried
to upgrade their one hour wrap to a three hour barrier by performing
qualification testing. This testing did not allow an upgrade of the as
installed fire barrier to a three hour qualification.
The licensee is currently maintaining the area fire watch which
satisfies the intent of the Fire Protection program.
The URI is
considered closed based on the use of fire watches.
Several proposals to modify the as installed design to meet 10 CFR 50,
Appendix R requirements are being considered.
Until a modification is
finalized, this is identified as IFI 50-280, 281/95-23-02, Modification
of MER-5 Power Supply Cable Fire Barrier to Eliminate Need for Fire
Watch.
One violation was identified.
~ .6.0
OTHER NRC PERSONNEL ON SITE
None
7 .0
EXIT
The inspection scope and findings were summarized on January 11, 1996,
by D. M. Kern with those persons indicated by an asterisk in
paragraph 1.
The inspectors 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.
~
Item Number
50-280, 281/94-06-01
LER
50-280/94-05
50-280, 281/94-31-01
Status
Closed
Closed
Closed
Description and Reference
Not Performing a 10 CFR 50.59
Safety Evaluation For
Administrative Control of
Plant Equipment
(paragraph 2.7)
Steady State Reactor Power
Exceeded Operating License
Limit (paragraph 4.1.1)
Containment Design Feature
(paragraph 4.1.2)
- ,* '. :*,
,_
..
~
Item Number
50-281/95-23-01
EW
50-280, 281/95-10-01
50-280, 281/93-30-01
IFI
50-280, 281/95~23-02
8.0
16
Status
Open
Open
Closed
Open
Description and Reference
Multiple Personnel Violations
of RWP Requirements
{paragraph 5.3)
Damage Control Teams Were Not
Timely Dispatched
(paragraph 5.4.1)
MER-5 Power Supply Cable Fire
Barrier Adequacy
(paragraph 5.4.2)
Modification of MER-5 Power
Supply Cable Fire Barrier to
Eliminate Need for Fire Watch
{paragraph 5.4.2)
CFR
DR
CODE OF FEDERAL REGULATIONS
STATION COMMITMENT TRACKING SYSTEM
DEVIATION REPORT
EW
F
FLOWCALC
gpm
IFI
IR
LER
LHSI
MER
mREM
MWT
NAF
NRC
osc
PC
ppb
psi
EXERCISE WEAKNESS
FAHRENHEIT
FLQYDATE CALCULATION
GALLONS PER MINUTE
HEALTH PHYSICS
INSPECTION FOLLOWUP ITEM
INSPECTION REPORT
LICENSEE EVENT REPORT
LOW HEAD SAFETY INJECTION
MECHANICAL EQUIPMENT ROOM
MILLI RADIATION EQUIVALENT MAN
MEGAWATTS THERMAL
NUCLEAR ANALYSIS AND FUELS
NON-CITED VIOLATION
NET POSITIVE SUCTION HEAD
NUCLEAR REGULATORY COMMISSION
OPERATIONS SUPPORT CENTER
PROTECTIVE CLOTHING
PUBLIC DOCUMENT ROOM
POWER OPERATED RELIEF VALVE
PARTS PER BILLION
POUNDS PER SQUARE INCH
PERIODIC TEST
QUALITY ASSURANCE
.l I
. ,._
- -,,
l
- 1
!
I
I
- i
QATTS
SE.
SFR
- SNSOC
TS
VPAP
17
QUALITY ASSURANCE TRACKING AND TRENDING SYSTEM
RADIATION CONTROLLED AREA
ROOT CAUSE EVALUATION *
REACTOR COOLANT PUMP
RADIATION EQUIVALENT MAN*
RADIOLOGICAL PROTECTION
RESISTANCE TEMPERATURE DETECTOR
RADIATION WORK PERMIT
SELF CONTAINED BREATHING APPARATUS
SAFETY EVALUATION
STEAM FLOW RATE
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
- VIOLATION
VIRGINIA POWER ADMINISTRATIVE PROCEDURE