ML18152A248
| ML18152A248 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 09/29/1993 |
| From: | Belisle G, Branch M, Tingen S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A249 | List: |
| References | |
| 50-280-93-22, 50-281-93-22, NUDOCS 9310120016 | |
| Download: ML18152A248 (21) | |
See also: IR 05000280/1993022
Text
'
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/93-22 and 50-281/93-22
Licensee: Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
lnspect;on Conducted:~ 9, 1993,
Inspectors:
~~~
through September 4, 1993
M. W. Branch Senior Resident
Inspector
~s;d:it'1'nspector
Approved by: fl~
G.
.Beli,Section Chief
Division of Reactor Projects
SUMMARY
Scope:
i/2.9/q 3
Date Signed
~/1...1/ Cf>
Date Signed
~d
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, Hurricane Emily response, maintenance
inspections, employee concerns program questionnaire and fibrous material in
containment.
During the performance of this inspection, the resident
inspectors conducted reviews of the licensee's backshifts, holiday or weekend
operations on August 9, 16, 18, 19, 22, 24, 25, 30, 31 and September 1, 1993.
Results:
One violation discussed below was identified.
In the operations area, the following items were noted:
The failure to adequately evaluate and investigate the Unit 1 reactor
coolant system leakage was identified as Violation 50-280/93-22-01
{paragraph 3.c).
The conduct of unit startups from Hot Shutdown to 2% reactor power with
the controls invoked by Virginia Power Administrative Procedure-0108 was
considered a strength {paragraph 3.e).
2
In the plant support (radiation protection) area the following items were
noted:
The failure to properly post a surface contamination area in violation
of plant procedures was identified as Non-cited Violation
50-280/93-22-02 (paragraph 3.d).
Weaknesses associated with improper use of yellow and magenta rope
normally used for Health Physics posting was noted in several areas of
the station (paragraph 3.d).
In the maintenance area, the following items were noted:
A weakness was identified with the adequacy of the licensee's startup
assessment.
It involved not evaluating the need to inspect the Unit*2
steam generator drain assembly welds while the plant was in cold
shutdown (paragraph 3.c).
The licensee's investigation of how the degraded Train B master safety
injection relay caused the August 27 reactor trip was timely.
The
investigation would have been more complete if the source of the 38
volts that caused the relay to chatter would have been identified
(paragraph 5.a).
An Unresolved Item was identified associated with Emergency Service
Water building degraded flood barriers (paragraph 5.b) .
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D.\\ Christian, Assistant Station Manager
- J. Costello, Station Coordinator, Emergency Preparedness
- J. Downs, Superintendent of Outage and Planning
- D. Erickson, Superintendent of Radiation Protection
- A. Friedman, Superintendent of Nuclear Training
- B. Hargrave, Nuclear Materials
- M. Kansler, Station Manager
- C. Luffman, Superintendent, Security
- J. McCarthy, Superintendent of Operations
- A. Meekins, Supervisor of Administrative Services
- A. Price, Assistant Station Manager
- V. Shifflett, Licensing
- B. Shriver, Director, Corporate Nuclear Safety
- E. Smith, Site Quality Assurance Manager
- D. Sonvners, Corporate Licensing
- J. Swientoniewski, Supervisor, Station Nuclear Safety
- E. Turko, Superintendent of Engineering
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- Attended Exit Interview
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 operated at or about 100% power until it was shutdown to repair a
suspected SG primary manway cover leak on August 21.
As discussed
below, an UE was declared at 4:43 a.m., on August*21 when it was
determined that the RCS leakage was from a non-isolable pipe weld joint
on the B SG channel head drain assembly instead of the SG manway.
The
unit was returned to power on August 30 and was at full power at the end
of the inspection period .
Unit 2 began the reporting period in a forced outage to repair leaking
pressurizer safety valves. The unit was returned to power on August 19
2
and operated until August 23 when it tripped from approximately 98%
power as a result of a failed main generator voltage regulating circuit.
The unit was returned to power on August 25 and tripped again on August
27 as a result of a degraded Train B SI master relay. The unit was
returned to power on September 3 and at the end of the inspection period
the unit was operating at 97.5% power.
3.
Operational Safety Verification (71707, 42700)
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
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain awareness of the overall operation
of the facility. Instrumentation and ECCS lineups were periodically
reviewed from control room indication 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.
a.
Licensee 10 CFR 50.72 Reports
1).
August 17 NOUE, (Loss of Emergency Monitoring Equipment).
On August 17, the licensee made an emergency one hour 10 CFR
50.72 call to report a NOUE declaration due to a loss of
power to the primary and backup meteorological towers.
The
UE was declared at 6:35 a.m., and was terminated at 10:44
a.m., on the same day when power was restored to the primary
and backup meteorological towers.
The power loss occurred
when a large bird struck the power lines in circuit 448
causing a phase-to-phase short and circuit 448 to
deenergize.
Power restoration was accomplished after the
damaged power lines in circuit 448 were repaired.
At the time of this event, circuit 448 was the sole power
source to the primary and backup meteorological towers.
The
alternate power supply was unavailable due to maintenance
activities.
During this event several small brush fires occurred outside
the PA when attempts were made to reenergize circuit 448.
The brush fires were immediately extinguished.
2).
August 21 NOUE (Unit 1 Shutdown for RCS Leak).
At 4:43 a.m. on August 21, 1993, the licensee declared a
NOUE based on non-isolable RCS pressure barrier leakage
requiring a plant shutdown per TS 3.1.c.4. The UE was
terminated at 2:43 a.m., on August 22, 1993, after RCS
3).
4).
3
temperature was reduced below 200 degrees F.
This event is
described in detail in paragraph 3.c.
August 23 Unit 2 Reactor Trip
On August 23 the licensee made a non-emergency four-hour 10
CFR 50.72 report due to a Unit 2 automatic reactor trip
caused by a turbine generator trip. The automatic reactor trip occurred at 5:19 a.m. from 97.5% power.
The turbine
generator experienced an excitation loss of power which
resulted in tripping the turbine generator due to loss of
electrical field. All ESF performed as designed and the
plant's response was as expected. All rods inserted into
the core.
The IRPI for rod M-10 initially indicated 35
steps after the reactor trip but drifted to O steps within
approximately twenty minutes.
The slow response of rod M-10
IRPI is a recurring problem.
This is also discussed in
IR93-20.
The minimum RCS pressure and temperature achieved
during the trip was 1840 psi and 530 F respectively. All
AFW pumps automatically started on low-low SG level. The
MSTVs remained open during the event and decay heat was
removed by the main steam dump valves via the main
condenser.
The inspectors were notified by the licensee of the trip and
reported to the site. The inspectors verified that the
plant had responded as discussed above and observed selected
recovery activities.
Subsequent troubleshooting identified a faulty phase shifter
card in the turbine generator excitation circuit which
caused the turbine generator to trip. The phase shifter
card was replaced and satisfactorily tested. Unit 2 was
returned to service on August 25.
August 27 Unit 2 Reactor Trip
On August 27 the licensee made a non-emergency four-hour 10
CFR 50.72 report due to a Unit 2 automatic reactor trip.
The automatic reactor trip occurred at 5:41 p.m. from 97%
power.
Technicians were in the final stages of completing
SI Train B logic testing when the reactor trip occurred.
All ESF performed as expected and the plant's response was
as expected. Automatic SI initiation did not occur during
the trip nor was it required to initiate. The inspectors
were notified by the licensee of the trip and reported to
the site. The inspectors verified that AFW had
automatically initiated on low-low SG level and operated
until SG levels were recovered.
Following the Unit 2
reactor trip RCS temperature and pressure decreased to 530
degrees F and 1840 psig respectively and were stable.
No
primary safety valves, primary PORVs, secondary safety
b.
c.
4
valves, or secondary PORVs opened during the event.
Decay
heat was removed by the main steam dump valves via the main
condenser.
All rods inserted into the £ore, however,
individual rod position for rod M-10 slowly drifted to zero
following the trip. This has occurred during previous Unit
Troubleshooting indicated that the Train B SI master relay
was defective causing the unit to trip. Troubleshooting the
defective relay is further discussed in paragraph 5.a. The
relay was replaced and the unit was returned to power on
August 30.
5).
August 31 NOUE for Hurricane Emily
At 6:10 a.m., on August 31 the licensee declared a NOUE in
accordance with their emergency plan when the National
Weather Service issued a hurricane warning for Surry County
and coastal areas.
The UE remained in effect until 5:13
a.m., on September 1 at which time the hurricane warning was
canceled.
The response to Hurricane Emily is described in
paragraph 4.
Unit 2 Startup on August 19
On August 19, the inspectors observed the Unit 2 startup and
placing the unit on line. The inspectors noted that briefings for
the startup were thorough and emphasized recent problems.
Specifically, due to recent problems experienced during startups
with maintaining steam generator water levels stable (see IR 93-
20), increased emphases was placed on level control.
On several
occasions during the startup the SRO had the operators maintain
the plant in a stable condition to allow a review and brief of the
next step of the startup. Management involvement and oversight
were evident. Overall the inspectors considered that the
evolution proceed cautiously with no problems.
Co11111unications was
generally good with excellent use of repeat backs.
However, the
inspectors did note that during certain evolutions that required
coordination between several operators, no one person was in
charge.
For example when bypassing steam around the MS isolation
valves and when increasing turbine load, several different
operators gave orders to the valve and turbine operators
respectively.
The licensee does not use a designated phone talker
in the control room to conmunicate with auxiliary operators in the
field during startups. These observations were discussed with the
licensee and the licensee stated that they would perform a review.
Unit 1 Shutdown to Repair RCS Leakage
At 9:00 p.m., on August 20, 1993, a normal Unit 1 shutdown from
100% power co11111enced to repair a leak that appeared to be coming
from a mechanical joint on the B SG primary side manway cover.
5
The leak was detected on June 25, 1993, by an increase in
containment radiation monitor readings.
The RCS leakage was
subsequently classified as a 0.2 gpm identified leak based on a
limited visual observation that was restricted due to radiation
levels in the area and the presence of mirror insulation. The
licensee monitored the leak with closed circuit TV after it was
identified. A slight increase in leakage was noted by the close
circuit TV monitor on August 15 and preparations to shutdown the
unit were initiated. The licensee was originally scheduled to
take the unit off-line for repairs on July 10, 1993 but elected to
maintained it operating due to the hot weather load demands
followed by an unscheduled Unit 2 shutdown.
Unit 2 was shutdown
on August 6, 1993, to correct problems with Pressurizer Safety
Valves.
Following the repairs and the return of Unit 2 to
commercial operations on August 19, 1993, the licensee elected to
shut down Unit l for repairs.
Unit l was shutdown on August 21, and radiation levels were
reduced after the shutdown. A closer visual inspection of the
leakage was performed after the mirror insulation was removed.
The leakage was determined to be coming from a non-isolable leak
in a 3/4-inch weld joint on the SG channel head drain valve
assembly.
This drain valve assembly was in close proximity to the
SG manway and the leakage was directed to the SG manway and
escaped around the insulation seams.
At 4:43 a.m., on August 21 the licensee declared an UE based on
non-isolable RCS pressure barrier leakage requiring a plant
shutdown per TS 3.1.c.4. The UE was terminated at 2:43 a.m. on
August 22 after RCS temperature was reduced below 200 degrees F.
A few drops of leakage continued as the licensee preceded with
closing the loop stop valve and draining the loop for repairs.
The licensee inspected the failed weld. A preliminary failure
analysis indicated that the crack was attributable to
transgranular stress corrosion. The weld was repaired and the SG
was returned to service.
The drain valve assemblie~ on the other
two Unit l SGs were inspected by LPT and determined to be
acceptable. Since the failure of the Unit l drain valve assembly
weld could be a generic issue, the licensee considered what
actions would be necessary to evaluate similar Unit 3 weld joints.
After the Unit 2 August 23 reactor trip, the drain valve
assemblies on all three Unit 2 SGs were dimensionally checked and
examined for gross leakage.
No signs of leakage were observed.
However, the insulation covering the potentially effected weld
joints was not removed to allow a visual examination since the
licensee considered that the insulation removal and reinstallation
was too hazardous with the plant in hot shutdown.
The Unit 2
piping and the SG shell wall temperatures were approximately 540
degrees F.
It was not possible to perform LPT weld inspections.
Based on the size of this piping (i.e. 3/8 and 3/4 inch) these
welds were not required to be included in the ISi program.
The
6
licensee is continuing to evaluate the event for possible future
long term corrective actions.
The licensee's basis for not removing the Unit 2 insulation to
perform a visual inspection or LPT was that the temperature of the
SG was too hot.
However, the licensee did not perform any
additional verification of the acceptability of the Unit 2 welds
even though the unit was subsequently cooled to less than 200
degrees F to perform PMT for the failed relay as discussed in
paragraph 5.a. Managements' failure to recognize or evaluate the
need to perform the inspections while the unit was cooled down was
considered a weakness.
There was no commitment tracking item
assigned to ensure that during forced outages or mode changes the
inspections would be performed.
The inspectors reviewed the above events and monitored the
licensee's Unit 1 shutdown activities.
TS 3.1.c.4 required that
the reactor shall be brought to a cold shutdown condition and
corrective action taken prior to resumption of unit operations if
it is determined that leakage exist through a non-isolable fault
which has developed in a RCS component body, pipe wall, vessel
wall, or pipe weld.
TS 3.1.c.l required that any indication of
possible RCS leakage be investigated and evaluated.
The licensee
evaluated the leakage and categorized it as identified leakage
although the insulation covering the weld was not removed to allow
positive leak site identification.
As a result, Unit 1 operated
at power outside TS 3.1.c.4 from 12:52 p.m., on June 25, 1993,
through 2:38 a.m., on August 21, 1993, for a total of 57 days,
with non-isolable leakage in a RCS pipe weld on the B SG channel
head drain assembly.
The failure to adequately investigate and
evaluate the RCS leakage is identified as Violation 50-280/93-22-
0l, Failure to Properly Investigate and Evaluate RCS Leakage.
d.
Improperly Controlled Contaminated Area
During a routine tour on August 16, the inspectors noted a rope
and radiological sign posted across the normal access to the Unit
1 valve pit 12 foot elevation indicating a contaminated area.
There were two additional access points to get into the areaj
although they were not convenient due to piping obstructions. A
radiological boundary was not installed at these other two
accesses.
The inspectors reviewed the survey map which indicated
that there were several places in the area that were contaminated
(1000-3000 DPM) and a radiological boundary was installed to
prohibit general access into the area.
The inspectors notified
the HP supervisor of this condition and a proper boundary was
installed to prevent inadvertent access to the area.
RPR 93-79
was issued by HP documenting that a contaminated area boundary was
not properly posted on all sides to prevent inadvertent access.
Section 6.2.4.a.2 of HPAP-1061, Radioactive Contamination Control,
revision 1, required barrier materials be used as required to
clearly designate a contaminated area boundary.
The failure to
7
properly post the contaminated area in the Unit 1 valve pit 12
foot elevation was identified as NCV 50-280/93-22-02.
This NRC
identified violation is not being cited because criteria specified
in Section VII.B of the NRC Enforcement Policy were satisfied.
This event was fully discussed with HP personnel and procedure
changes are being considered.
During the inspection period the inspectors noted several
instances where yellow and magenta radiological barrier rope was
not appropriately used.
In both instances the rope was being used
for purposes other than a radiological barrier.
In one instance
the rope was utilized to secure a fire hose.
The other instance
involved securing a drain hose.
Station procedures do not
specifically prohibit the use of yellow and magenta rope for non-
radiological purposes but the inspectors consider it is prudent to
restrict use of the rope to radiological purposes.
The inspectors
discussed the issue with the RP Superintendent and during
subsequent tours noted that yellow and magenta rope was being
appropriately utilized as a radiological barrier.
The use of
yellow and magenta radiological barrier rope for purposes other
that a radiological barrier was identified as a weakness.
The
licensee agreed that using yellow and magenta rope for non-
radiological barrier purposes was inappropriate.
e.
Unit 2 Startup on August 25
The inspectors monitored portions of the August 25 Unit 2 startup.
The startup was performed in accordance with 2-GOP-1.4, Unit
Startup, HSD to 2% Reactor Power.
Starting a unit from HSD and
increasing power to 2% was considered an infrequently conducted or
complex evolution which required that additional controls be
invoked in accordance with VPAP-0108, Infrequently Conducted or
Complex Test or Evolutions.
Examples of controls invoked by VPAP-
0108 are that a senior operations manager monitor the evolution
and that a senior operation manager brief the personnel involved
on managements' expectations for accomplishing the evolution.
This evolution was thoroughly briefed by the unit SRO and a senior
operations manager.
During the briefing, safe operation was
emphasized as the top priority. It was evident that the unit SRO
was in charge of the evolution and this portion of the startup
progressed slowly and smoothly.
The conduct of unit startups from
HSD to 2% reactor power along with the additional controls invoked
by VPAP-0108 was considered a strength.
At approximately 2% reactor power operators transitioned from 2-
GOP-1.4 to 2-GOP-1.5, 2% Reactor Power to Max Allowable Power.
The remainder of the startup was not considered a complex or
infrequently conducted evolution and was conducted in a less
formal manner than the portion of the startup where the reactor is
taken critical. Issues associated with command and control was
discussed in IR93-15 and paragraph 3.b of this report.
4.
8
Within the areas inspected, one violation and one NCV were identified.
Hurricane Emily Response (93702)
As discussed above at 6:10 a.m. on August 31 Surry declared an UE when
hurricane warnings were issued for Surry County and coastal areas.
Station personnel had been preparing for the hurricane for several days
in advance of its approach.
The licensee had initiated O-AP-37.01,
revision 2, Abnormal Environmental Conditions and Associated Operations
and Corporate checklist. The AP provided instructions for preparing the
units and station for abnormal environmental conditions.
Included in
the AP were instructions to increase surveillance and monitor status if
hurricane force winds were expected within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Additionally, the
AP required shutting down one unit and then the second unit 24 and 12
hours, respectively, prior to the hurricane arriving onsite. The
licensee never officially anticipated that the hurricane would affect
the site based on their meteorological monitoring and the hurricane's
projected path.
The inspectors reviewed the licensee's response to the hurricane warning
and conducted walkdowns of the plant and surrounding areas.
The results
of that walkdown along with plant design information germane to flooding
and possible wind damage is as follows:
Walkdown results
Inside the PA, the area was generally clean.
However, there were
racks of gas bottles stored outside and there were miscellaneous
large construction materials such as welding machines, plate
steel, pipe, grating, etc., that had been tied with rope.
The switchyard was not designed to withstand hurricane force
winds.
In the area between the switchyard and the intake canal
there were sheet metal cable tray covers that were loosely
fastened that would probably come loose under high winds.
The roofs throughout the plant were generally clear of loose
material. However, several of the roofs were constructed of
loosely fitted concrete tiles that would probably become missiles
under design basis hurricane force winds of greater than 137 mph.
The licensee considered these to be acceptable.
In the event of
high winds creating missile hazards, safe shutdown emergency
equipment would function as designed.
Design Information
Buildings design information and a list of equipment and buildings
susceptible to damage from high winds were discussed in section 3
of IR93-15 .
5.
- - - - ~ ~
9
Flood information is described in section 2.3 of the UFSAR with
critical equipment in the service water pump house being at the 18
foot above mean sea level elevation.
Service water canal level requirements for inventory are 28-30
feet and are based on two concerns; low water in the James River,
which would cause problems in making up water to the intake canal,
and high water in the James (i.e., no DP for SW gravity flow).
The Regional IRC was activated on August 30 at 4:40 p.m., to monitor the
status of the hurricane.
Two NRC regional inspectors and a supervisor
were dispatched to the site with emergency supplies and communication
equipment.
The two regional inspectors remained at the site to aid the
resident inspectors and the regional supervisor reported to the Virginia
Power Corporate EOF.
The three resident inspectors also reported to the
site. The site was continuously manned by NRC personnel from 6:45 a.m.,
on August 31 to 3:00 p.m., on September 1.
The Regional IRC was
deactivated at 9:30 a.m., on September 1.
The site TSC and OSC and corporate EOF were manned from 10:00 p.m., on
August 31 through 5:30 a.m. on September 1.
In addition, the site was
manned with extra security personnel during this time period.
Within the areas inspected, no violations were identified *
Maintenance Inspections (62703) (42700)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
a.
Bench Testing Unit 2 Train B Master SI Relay
As previously discussed in paragraph 3.a(4), the Unit 2 automatic reactor trip that occurred on August 27 was attributed to the
Train B master SI relay, 02-RP-REL-SIAB, being degraded.
The
reactor trip occurred when I&C technicians were in the final
stages of completing a monthly Train B SI logic test. Following
the trip, the inspectors walked down the SI cabinets with the I&C
technicians who performed the SI logic testing. At the time of
the trip, the SI cabinet doors were open and an l&C technician
observed the Train B SI master relay move.
This relay was a
Westinghouse model MG-6 relay.
The degraded relay was original
equipment.
The degraded SI master relay was removed and bench tested. The
inspectors witnessed the bench tests. The relay is normally
deenergized and when a SI signal is generated, the relay energizes
and changes state. Bench testing results identified that the
relay was cycling (chattering) at approximately 38 volts. The
inspectors witnessed the relay chattering at approximately 38
volts when tested. This relay is a 120 volt ac relay that
b.
10
normally changes state at approximately 70 volts. Eight new MG-6
relays were similarly tested and the new relays did not chatter
prior to changing state at 70 volts. It was concluded that the
relay was degraded in that it chattered at 38 volts prior to
changing states at 70 volts.
As previously discussed the I&C
technician observed the relay move when the trip occurred which
indicated that the relay was chattering. The licensee attempted
to determine the source of the 38 volts that caused the relay to
chatter but was unable to identify the source.
The relay has three sets of NO contacts, each set of contacts
actuates an SI slave relay. The SI master relay was actuated and
the time for each contact to close was monitored.
Testing results
indicated that contacts 3-6 closed first. Contacts 3-6 closure
opens the reactor trip breakers. Other SI components actuate when
contacts 3-6 close. These components were already in their SI
position or state when the reactor trip occurred.
For example,
when contacts 3-6 closed, an automatic start signal was sent to
the C HHSI/charging pump.
However, when the reactor trip occurred
the C HHSI/charging pump was already operating.
The licensee
concluded that when the Train B SI master relay chattered contacts
3-6 were the only contacts on the relay that latched and opened
the reactor trip breakers. This explained why other SI component
actuations did not occur when the relay chattered and the unit
tripped.
The inspectors concluded that the licensee's investigation was
thorough and timely in identifying why the degraded Train B master
SI relay caused the August 27 reactor trip breakers to open
without subsequent actuations of other safety equipment.
However,
the investigation would have been more complete if the 38 volt
source that caused the relay to chatter would have been
identified. The inspectors also walked down Unit 1 and 2's SI
cabinets in the switchgear room and noted that in Unit 1 there
were six WR tags installed on the cabinets documenting that
specific relays had chattered. Approximately half of the WRs
stated that relays were chattering when SI test switches were
operated. There were no WR tags on the Unit 2 SI cabinets for
chattering relays.
ESW Pump House Hurricane Flooding Protection Equipment
Section 2.3.1.2.2 of the UFSAR states that in the event of a
hurricane, the ESW pump building is protected against flooding by
installing watertight seal plates (stop logs) in front of the
doors and watertight wells over the louver openings on the side of
the building.
In preparation for hurricane Emily, these stop logs
and watertight wells were installed on August 31.
The inspectors
walked down the ESW building after the stop logs and watertight
wells were installed. The inspectors noted that the watertight
wells would not have prevented flood water from leaking into the
----
- - - -
11
building. There was a gap around the perimeter of each well where
it butted up against the building. Also, all bolts that secure
the wells to the building were not installed. The inspectors
noted that the stop logs for the doorways did not fit securely in
the opening and questioned if they could prevent flood water from
leaking into building.
On September 1, the inspectors monitored the licensee removing the
stop logs and water tight wells and noted the following
deficiencies:
The gaskets on the watertight wells were deteriorated and
appeared to be dry rotted.
Many bolt holes on the watertight wells did not match up to
the bolt holes on the building.
The louvers had a grating welded over the opening. This
grating prevented a watertight seal between the building and
well.
Maintenance personnel documented the deficiencies noted with
installing the watertight wells and stop logs in a memorandum
dated September 2 and in a DR.
The inspectors questioned whether
the ESW pump building would have been adequately protected against
flooding caused by a hurricane with the deficiencies noted. Until
the licensee completes their evaluation of this issue, this is
identified as URI 50-280,281/93-22-03.
c.
MOV 1-SI-MOV-18628 Deferred Maintenance
During a Unit 1 valve pit walkdown, the inspectors noted a WR tag
installed on the declutch lever for MOV l-SI-MOV-18628.
The WR
was annotated that the MOV would not automatically return to the
electrical mode of operation after the handwheel was declutched
and manually operated. This condition was identified during the
Unit 1 spring 1992 RFO and the maintenance to repair the MOV was
deferred to the upcoming 1994 spring RFO.
DR S-92-0740 dated
April 24, 1992, was issued when the condition was first
identified.
Valve l-SI-MOV-18628 is the 8 LHSI pump suction from the RWST.
The valve is normally open.
On low RWST level, the valve
automatically shuts when LHSI pump suction realigns to the
containment sump.
The inspectors were concerned that if the 1-SI-
MOV-18628 declutch lever was inadvertently moved, the MOV would
declutch and not operate electrically when required.
The
inspectors discussed this concern with the licensee. The licensee
considered the MOV fully operable in that the MOV has been
satisfactorily stroke tested every quarter and that the chances of
12
the declutch lever being inadvertently moved are remote because
the MOV is located in a secluded area.
At the end of the inspection period the inspectors requested the
licensee to operate the declutch lever on 1-SI-MOV-1862B with the
inspectors present in order to determine if it is possible to
inadvertently declutch the MOV.
The inspectors will followup on
this issue during the next inspection period.
Within the areas inspected, a URI was identified.
6.
Employee Concerns Program Questionnaire (TI 2500/028)
7.
The inspectors conducted a survey of the licensee's program associated
with raising safety concerns.
The survey results are contained in
Attachment 1 to this report. The format of the TI survey was modified
slightly for clarity.
Within the areas inspected, no violations were identified.
Fibrous Material In Containment (Bulletin 93-02)
The inspectors reviewed the licensee's actions taken to address NRC
Bulletin No. 93-02, Debris Plugging of Emergency Core Cooling Suction
Strainers.
The bulletin required the licensee to identify fibrous air
filters or other temporary sources of fibrous material not designed to
withstand a LOCA, which are installed or stored in containment.
The licensee responded to this bulletin in a letter dated June 9, 1993.
The response stated that temporary fibrous material is not stored or
utilized in either containment while a unit is operating. The response
also stated that permanent fibrous material installed inside the
containments was evaluated to not block or clog ECCS suction strainers.
The NRC's evaluation of the acceptability of the licensee's responses
was documented in a letter dated July 27, 1993.
The inspectors reviewed EWR 93-032, RS Review of NRC Bulletin Number 93-
02/Surry/1&2, dated May 21, 1993, and verified that temporary and
permanent fibrous material in the containments were evaluated.
EWR 93-
032 did identify that during outages, temporary fibrous material is
utilized in the containments. Temporary filters are installed in the
suction containment air recirculation coolers. The licensee revised 1,2
GOP-1.1, Unit Startup, RCS Heatup From Ambient to 195 degrees F, to
strengthen controls to ensure that these temporary filters or any other
temporary fibrous material were removed prior to startup. The
inspectors reviewed the revised procedures and verified that controls
were adequate.
The inspectors also walked down the Unit 1 containment
during the inspection period and did not identify any temporary fibrous
material or any permanent fibrous material concerns that were not
already addressed by EWR 93-032.
13
Within the areas inspected, no violations were identified.
8.
Exit Interview
The results were summarized on September 8, 1993, with those individuals
identified by an asterisk in Paragraph 1.
The following summary of
inspection activities was discussed by the inspectors during this exit:
Item Number
Status
Description
(Paragraph No.)
VIO 50-280/93-22-01
Open
Failure to Properly
Investigate and Evaluate RCS
Leakage (paragraph 3.c).
NCV 50-280/93-22-02
Closed
Failure to Properly Post the
Contaminated Area in the Unit
1 Valve Pit 12 foot Elevation
(paragraph 3.d).
URI 50-280,281/93-22-03
Open
ESW pump building with the
degraded flood barriers
(paragraph 5.b).
Proprietary information is not contained in this report. Dissenting comments
were not received from the licensee.
9.
Index of Acronyms and Initialisms
CFR
DP
-
F
GPM
HHS!
-
HSD
IR
!RPI -
LHSI
-
ABNORMAL PROCEDURES
CODE OF FEDERAL REGULATIONS
DIFFERENTIAL PRESSURE
DISINTEGRATIONS PER MINUTE
ENGINEERED SAFETY FEATURES
EMERGENCY SERVICE WATER
ENGINEERING WORK REQUEST
FAHRENHEIT
GALLONS PER MINUTE
HEALTH PHYSICS
HIGH HEAD SAFETY INJECTION
HOT SHUTDOWN
INSTRUMENTATION AND CALIBRATION
INSPECTION REPORT
INCIDENT RESPONSE CENTER
INDIVIDUAL ROD POSITION INDICATION
INSERVICE INSPECTION
LOW HEAD SAFETY INJECTION
LOCA -
LPT
MDV
MSTV -
NO
NOUE -
NRC
osc
PSIG -
RWST -
TI
TS
UFSAR -
LOSS OF COOLANT ACCIDENT
LIQUID PENETRANT TEST
MOTOR OPERATED VALVE
MAIN STEAM THROTTLE VALVE
NON-CITED VIOLATION
NORMALLY OPEN
NOTICE OF UNUSUAL EVENT
NUCLEAR REGULATORY COMMISSION
OPERATIONS SUPPORT CENTER
PROTECTED AREA
POWER OPERATED RELIEF VALVE
PREVENTIVE MAINTENANCE TEST
POUNDS PER SQUARE INCH
PERIODIC TEST
RADIATION PROTECTION
REFUELING OUTAGE
REFUELING WATER STORAGE TANK
SAFETY INJECTION
SENIOR REACTOR OPERATOR
TEMPORARY INSTRUCTION
TECHNICAL SPECIFICATION
UNUSUAL EVENT
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VIOLATION
WORK REQUEST
ATTACHMENT 1
EMPLOYEE CONCERNS PROGRAM SURVEY
PLANT NAME: SURRY UNITS 1&2
LICENSEE: VEPCO
DOCKET I: 280,281
A.
PROGRAM:
B.
SCOPE:
1.
Does the licensee have an employee concerns program?
(No)
2.
C011111ents:
The licensee does not have a formal employee
concerns program (ECP) program with dedicated staff and
budget. However,
the licensee has implemented an effective
10 CFR 50 Appendix *e* program that is independent of
productive pressures. Elements of this QA program includes
problem identification, resolution, and root cause
determinations that may involve employee interviews.
Additionally, Industrial Safety Reporting and the licensee's
Human Resource programs including grievance, employee exit
interviews, and Employee Assistance Program (EAP) allows an
employee an avenue to identify problems and discuss
differing opinions/views *
Has NRC inspected the program?
(No) Report# N/A
1.
Is it for:
a.
Technical? (Yes, See #A.l Coanent above)
b.
Administrative? (Yes, See #A.1 C011111ent above)
c.
Personnel issues? (Yes, See #A.1 Conment above)
2.
Does it cover safety as well as non-safety issues?
(Yes)
3.
Is it designed for:
4.
a.
Nuclear safety? (See #A.1 COIIID8nt above)
b.
Personal safety? (See #A.l Conment above)
c.
Personnel issues - including union grievances?
(Yes, See #A.l Conment above)
Does the program apply to all licensee employees?
(Yes)
2
5.
Contractors?
(Yes)
Conwnent:
Contractors are covered under the plant qual;ty
assurance (QA) adm;n;strative control program.
However, the
Gr;evance process and Ex;t Interview process is not extended
to contractors.
6.
Does the licensee require its contractors and their subs to
have a similar program?
(No)
7.
Does the licensee conduct an exit interview upon terminating
employees asking if they have any safety concerns?
(Yes)
Coment:
The licensee's exit interview is directed at
f;nd;ng out why the employee is terminating and does not
specifically ask about safety concerns.
C.
INDEPENDENCE:
I.
What is the title of the person in charge?
N/A
2.
Who do they report to?
N/A
3.
Are they independent of line management?
(The VP Human Resources who is responsible for the
grievance, personnel, and EAP is independent of Nuclear
Operations)
4.
Does the ECP use th;rd party consultants?
N/A, C011111ent:
The licensee's EAP uses a third party
consultant.
5.
How is a concern about a manager or vice president followed
up?
Although not formalized, the licensee indicated that
information would be passed up to the next higher level for
disposition *
3
D.
RESOURCES:
1.
What is the size of staff devoted to this program?
Co11111ent:
The licensee's Station Nuclear Safety group who
administer the deficient report (DR} process and Human
Performance Evaluation System is comprised of 19 people.
There is one industrial safety coordinator and one personnel
supervisor as well.
2.
What are ECP staff qualifications (technical training,
interviewing training, investigator training, other)?
N/A
E.
REFERRALS:
1.
Who has followup on concerns {ECP staff, line management,
other)?
The individual or department responsible for the program
under which the concern was processed would have the
responsibility for followup and resolution.
F.
CONFIDENTIALITY:
1.
Are the reports confidential?
Coament: This itea is not applicable since there is no
formal program.
However, based on recent examples and
discussion with the licensee, all personnel related issues
are handled in a confidential manner, with only the
appropriate level of management involved with resolution}.
2.
Who is the identity of the alleger made known to (senior
management, ECP staff, line management, other)?
C011111ent:
This item is not applicable. However, in
resolution of concerns identified through the programs
discussed above, the licensee has indicated that information
is shared on a need to know basis and than only to senior
management.
3.
Can employees be:
a.
Anonymous? (Yes}
b.
Report by phone? (Yes)
G.
4
FEEDBACK:
1.
Is feedback given to the alleger upon completion of the
followup?
(Co11111ent:
The licensee's DR system ask whether the
originator request feedback as to resolution. The licensee
also indicated that feedback is generally provided to a
known alleger when practical.
2.
Does program reward good ideas?
The licensee has an employee suggestion system, which
evaluates ideas and reward employees if they are
implemented.
3.
Who, or at what level, makes the final decision of
resolution?
Final resolution is decided, for the most part by Station
Management with DR resolution being reviewed by the Station
Nuclear Safety and Operating Conaittee.
4.
Are the resolutions of anonymous concerns disseminated?
If determined to be beneficial to other employees.
5.
Are resolutions of valid concerns publicized (newsletter,
bulletin board, all hands meeting, other)?
Resolutions are publicized if appropriate and practical.
H.
EFFECTIVENESS:
1.
How does the licensee measure the effectiveness of the
program?
DR tracking and trending is performed but for the 110st part
there is no formal ECP and this item is not applicable.
5
2.
Are concerns:
a.
Trended?
Yes, The issue itself is if documented on a DR.
b.
Used? (N/A)
3.
In the last three years how many concerns were raised?
Through the HPES 20 concerns were raised and closed and 17
were substantiated.
Through the grievance process 42 concerns were raised, 22
were closed with 5 being substantiated.
4.
How are followup techniques used to measure effectiveness
(random survey, interviews, other)?
Trending of DRs and grievances are used as well as randoa
HPES interviews.
5.
How frequently are internal audits of the ECP conducted and
by whom?
N/A
I.
ADMINISTRATION/TRAINING:
I.
Is ECP prescribed by a procedure?
No, Conments:
As stated earlier, the licensee does not have
a formal EC program.
The DR, Safety, and personnel process
described above are prescribed by policies or procedures
2.
How are employees, as well as contractors, made aware of
this program {training, newsletter, bulletin board, other)?
The above process are discussed in general through employee
training or brochures.
ADDITIONAL COMMEHTS:
NONE
(Including characteristics which make the program
especially effective or ineffective.)