ML18153A888
| ML18153A888 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/07/1994 |
| From: | Belisle G, Branch M, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A887 | List: |
| References | |
| 50-280-94-02, 50-280-94-2, 50-281-94-02, 50-281-94-2, NUDOCS 9403150283 | |
| Download: ML18153A888 (21) | |
See also: IR 05000280/1994002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
- ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-280/94-02 and 50-281/94-02
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
Inspection Conducted:
January 2 through February 5, 1994
Inspectors:
Approved by:
Scope:
~LJ ~
fin__*
~W. Branc~or Resident
Inspector
,C(.J ~(*,~-, ~
W. Yo~Res1d~nt Inspector
S. G. Ting~n, Resident Inspector
G. A. Belisle, Sect)on Chief
Division-of Reactor Projects
SUMMARY
.1- ?- '!Y:
Date Signed
J-')- '?f
Date Signed
.s-?-<ff.
Date Signed
"3 - 7 -- ,(,./
Date Signed
This routine resident inspection was .conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, review of plant minor modifications, inservice testing, and
action on previous* inspection items. . While performing this inspection, the
resident inspectors conducted reviews of the licensee's backshifts, holiday or
weekend operations on January 6, 7, 21, 22, 23, 24, 25 and February 2 and 3,
1994.
9403150283 i;ggg~80
ADOCK
G
2
Results:
Plant Operations functional area:
Non-cited violation 50-280/94-02-01 was identified for failure to follow fire
seal inspection requirements contained in a surveillance procedure
(paragraph 3;b).
An .Unresolved Item was identified associated with reactor vessel level
indication problems that occurred while shutdown (paragra~h 3.i).
The magnitude qf the Unit 2 turbine runback on January 4 appeared to b~
excessive and challenged the operators. Their response to the event was good:
(paragraph 3.c).
-
The event assessment* of the Unit 2 runback was-thorough (paragraph 3.c).
The Unit 1 shutdown was well tontrolled and command and leadership were
evident (paragraph 3.e).
_The licensee demonstrated their ability to react to the icing conditions at
the low level intake structure that occurred on January 19.- However, the
licensee's cold weather protection program did not anticipate the icing
conditions that occurred during extreme cold weather (paragraph 3.f).
Several examples where personnel had to be prompted to initiate station
deviation reports for conditions adverse to quality were noted.
For the most
part~ operations has exhibited a very low threshold for station deviations and
this recent trend was not typical performance.
Operations management is
reviewing this is~ue with operation personnel (paragraphs 5.c and 7).
Operator response to two events indicated an apparent lack of understanding of
equipment operation.
The first involved a second Unit 2 turbine runbatk when
_load was increased above 70% first stage pressure with a runback signal
present (paragraph 3.c). The other example involved an unlicensed operator
improperly attempting to adjust -the #3 emergency diesel generator reactive
load.
This resulted in briefly operating equipment on the 1-H bus at
undervoltage conditions (paragraph 5.c)~
Maintenance functional area:
The service water- fl ow test to two Unit 1 reci rcul at ion spray heat exchangers
was well organized and conducted (paragraph 3.g).
An Unresolved Item was identified for activities involving a pressurizer
hydrogen burn (paragraph 3.j).
Rod control performance problems continue to occur.
The maintenance performed -
on the Unit 2 rod control system to troubleshoot and repair the step demand
counter indication was efficientlf accomplished and there was good
communications between operations and instrument and control personnel.
-
3
Unit l rod control improvements are being implemented and reliability centered
maintenance data is being utilized (paragraph 4).
A Unit 1 undervoltage and degraded voltige engineered safety feature actuation
surveillance was well coordinated and.controlled. A number of equipment
problems were noted during the 1-H bus test that required correction and
evaluation (paragraph 5.c).
The desigh chinge to waterproof the actuator for l-CW-MOV-106A was
accomplished without any deficiencies noted .. It was evident that the
mechanical and electrical maintenance personnel were prepared to implement
this design change (paragraph 6.a).
Engineering functional area:
The procedures developed by engineering support and utilized to accomplish the
Unit 1 shutdown worked well, in that, operators did not exhibit. significant
difficulties in understanding and performing the procedural steps
- (paragraph 3.e).
The design change pack~ges for implementing minor modifications to .valves
l-CW-MOV-106A and 2-SI-MOV-28628 were good quality and were accomplished by
maintenance personnel without any significant difficulties encountered
(paragraphs 6.a and 6.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. Hayes, Supervisor, Quality Assurance
- M. Kansler, Station Manager
- A. Keagy, Nuclear Materials
C. Luffman, Superintendent, Security
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
R. Saunders, Assistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- J. Swientoniewski, Supervisor, Station Nuclear Safety
- G. Woodzell, Nuclear Training
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
J. York, Resident Inspector
- Attended Exit Interview on February 8, 1994. *
- Attended Exit Interview on March 7, 1994.
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initial isms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period in a power coast-down for refueling.
The unit was shutdown on January 22 for a planned 64-day refueling
outage .
Unit 2 operated at 100% power for most of the inspection period and at
the end of the period the unit had been on lirte for 68 days ..
On
January 4, the unit experienced a turbine runback due to testing on the
NI system (see paragraph 3.c). * On January-19, power was reduced to 92%
2
for a short period of time due to icing conditions at the low level
intake canal (see paragraph 3.f). *
3;
Operational Safety Verification (11707, 42700)
The inspectors conducted frequent tours of the control . room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended pl~nt status meetings and reviewed
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 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 ti assure that potential
safety concerns were properly addressed and reported.
ar
Licerisee 10 CFR 50.72 Reports
(1)
(2.)
On January 7, the licensee made a non-emergency four-hour
10 CFR 50.72 report due to an ERFCS failure that rendered
the SPDS unavailable.
The ERFCS failed at 12:20 a.m. and
was retur*ned to service at 1:45 a.m.
The ERFCs' failure
occurred when a disk drive malfunction rendered the on-line
- data processor inoperable, and. the standby data processor
failed to automatically transfer to the data collection mode
of operation. *Wh~n this condition was identified, personnel
manually placed the standby data processor into operati.on.
This restored the ERFCS to an operable condition.* The disk
drive that had previously malfunctioned was replaced and t~e
data processor was returned to its normal bperating mode.
On February 4, the licensee made a non-emergency four-hour
10 CFR 50.72 report due to discovering a potential leakage
path from Unit 1 contain~eht. While inspecting the SW
piping inside containment, a small hole was found in the
piping downstream of recirculation spray heat exchanger
1-RS-E-18.
The unit was in cold shutdown when the hole was
identifiedi * Calculations performed by*the licensee
. indicated that the hole could have allowed leakage in excess
of that allowed by 10 CFR 50 Appendix J. The hole was
scheduled to be repaired prior to restarting the unit from
the current RFO.
The inspectors performed an initial assessment of the safety
significance of the hole in the SW pipe as it related to
containment integrity. The pipe with the through wall leak,
formed the membrane barrier between the inside containment
atmosphere and the ~ervice water.
In addition to the
- . membrane barrier. the penetration in question was also
isolable and was in-fact isolated by closed containment
isolation val~es.
The SW dischafge piping is monitored by a
3
radiation monitor that would alert the operators to isolate
the RS heat exchanger if necessary.
With the one RS heat
exchange~ isolated, 100% ~ontainment heat removal capacity
would still be available.
At the end of the inspection
period the licensee was still evaluating the issue and an
LER is scheduled to be issued within the 30 day period.
The
inspectors continue to follow the licensee's assessment of
this item.
b.
Unit 1 Cable.Vault Fire Barrier Penetrati-0n Seals
During a routine walkdown of the Unit 1 cable vault upper section,
the inspectors noted that a metal duct was covering a wall area
that contained three HS system fire barrier penetration seals.
This wall was required to be a 3~hour fire resistance rated
barrier in accordance with the Appendix R program.
The inspectors
questioned if the duct or seals installed ar6und the piping
provided the required fire barrier.
The inspectors were informed
that the penetrations were sealed and that the metal duct was not
the design fire barrier.
Because the duct covered the three HS fire barrier penetration
seals, the seals were not able to be visually inspected unless the
duct was removed.
As a result of the inspectors questioning'the
existence of adequate fire seal~, the licensee attempted to
inspect the three penetrations without removing the duct.
The
licensee was unable to verify that the penetration fire seals were
installed. The fire barriers were declared inoperable and a fire
watch was posted in accordance with TS 3.21.B.7 .. The duct was
then removed, and it was concluded that no fire barrier seals
existed in these penetrations.
Fire barrier seals w~re
subsequently installed.
TS 4.18.G.l.a requires that fire barrier penetration seals be
visually inspected every 18 months.
Procedure O-LPT-FP-001, Fire
Barriers, implemented TS 4.JB.G.1.a ana was last performed in
September 1993.
The inspectors reviewed the procedure's
performance copy dated September 1993, and concluded that the
procedure was completed without properly inspecting the three HS
fire ba.rri.er penetration seals. The licensee indicated that
personnel performing the inspections did not properly interpret
the fire barrier inspection requirements contained in O-LPT-FP-001
for inaccessible seals and; therefore, failed to identify that the
seals were not installed.
In order to prevent recurr~nce, the licensee was rev1s1ng
O-LPT-FP-001 to clarify inspection requirements for inaccessible
seals and was planning to provide additional training to personnel
that inspect fire seals to*ensure that inaccessible seals are
properly inspected.
At the end of the inspection period, the
licensee was developing a program to inspect additional mechanical
4
system fire barrier penetration seals in order to determine if
. other seals have been properly inspected.
The licensee had
already implemented an extensive inspection program for electrical
penetration fire seals.
The licensee reviewed the Appendix R Report combustible loading
.analysis for the areas adjacent to the three penetrations and
concluded that there was not a significant operability concern.
The adjacent areas were classified as less than one minute fire
loading zones and therefore would not provide a sufficient
concentration of combustibles from any flames, smok~ or hot gases
generated from a fire. The inspectors' review of the information
provided resulted in similar conclusions.
The insp~ctor~ concluded that the failure to properly irite~pret
procedure O-LPT-FP-001 fire seal inspection requirements was a
violation of TS 6.4.D which requires that procedures be followed.*
This was identified as NCV 50-280/94-02-0l; Failure to Follow Fire
Seal Inspection Requirements. This *NRC identified violation is
not being cited because criteria specified in Section VII.B of the
NRC Enforcement Policy were satisfied.
c.
January 4 Unit 2 Turbine Runback
- on January 4, Unit 2 experienced a turbine runback from 100% to.
appioximately 51% power.
The runback occurred during a special
test of power range NI channel N41.
This test is designed to
gather data to support the September 1994 RFO core reload *. The
NIS runback began immediately after the I&C technicians connected
the test equipment inside the NI drawer.
The plant's response to
the event was as expected, i.e., the steam dumps opened to control
steam pressure and inward rod motion controlled T avg.
However,
the turbine runback to 51 percent power was e~cessive and.
approximately 19 percent greater than designed.
The operators*
started an additional condensate pump and bypassed condensate
polishing to ensure adequate MFWP suction pressure. After plant
conditions were stable, the operatqr attempted to increase turbine
load to close the steam dump valves.
When turbine load increased
above 70% another runback to approximately 55% power occurred
because th_e NIS runback signal was still present. This' second
funback resulted from the operator's lack of understanding*of the
control logic.
The licensee performed Event Assessment 94-01 to identify the root -
causes and any corrective actions associated with the event~
The
inspectors reviewed the assessment which concluded that the NIS
runback was caused by a channel N41 failure. The channel failed
due to installing test equipment that was not grounded.
The
channel failed when the control power fuses blew immediately
following connecting the test device (recorder) to plant
equipment.
The assessment concluded that the test equipment was
not grounded because the test cart receptacle used to energize the
5
test equipment did not provide an adequate ground.
The inspectors
concluded that the assessment was thorough.
Corrective actions
included repl_acing the test cart receptacle and modifying the
_ method of checking test equipment prior to use.
Previously,
pieces of test equipment were checked individually prior to
installation. Under the new method, the test equipment will be
assembled and checked as a unit prior to connection to a plant
system. -
The assessment also concluded that the turbine ran back 19%
further than the design setpoint of 70% of full load. This was -
previously identified as a recurring probl~m and was attributed to
governor valve operating characteristics. A modification to
eliminated this automatic runback feature is scheduled for
implemeritatio~ during the Unit 2 1994 RFO and Unit 1 1995 RFO.-
d.
Unit 1 Containme_nt Integrity Verification
On January 22, the inspectors verified that containment integrity
was not compromised while bleeding steam for temperature and
pressure control when the plant was being maintained in hot
. shutdown.
Specifically, the inspector~ verifted that proper
admini~trative controls ~ere established and maintained while one
of the three MSIV bypass valves was unlocked and throttled open.
Th rot ti i ng of the bypass valve provided for fine temperatu*re
control by restricting the flow path used to bleed steam to the
condenser via the main steam dump valves.
I
The inspectors noted that adequate administrative controls wer~
implemented by procedures, and that an operator was stationed by
the valve with communication to the control room in the event that
the valve would have to be closed for containment integrity.
e.
Unit 1 Shutdown- for RFO
_ On January 21 and 22, the inspectors witnessed the shutdown of
Unit 1 in preparation for the RFO.
The unit ramp down rate was
150 MW/HR and the unit was at 53.5 % power when the shutdown was
initiated. Procedures involved included l-GOP-2.1, Unit Shutdown,
Power Decrease From Maximum Allowable Power to 25% to 30% Reactor
Power, revision 3; )-GOP-2.2, Unit Shutdown, 25% - 30% Reactor
Power to 2% Reactor Power, revision 4; and l-GOP-2~3, Unit
Shutdown, 2% Reactor Power to HSD, revision 3. - Th*e * inspectors*
concluded that the shutdown was well controlled and command and
control was evident. It was clear that the unit SRO was in charge
of the evolution, procedures were followed, and operators
continuously self~checked their actions.
The procedures, upgraded
by engineering support and utilized to accomplish the shutdown,
appeared to work well, in that, operators did not exhibit
significant difficulties in understanding and performing the
procedural steps.
. ***
6
The only time the operators were challenged during the shutdown
was when SG level control was transferred from automatic to
manual.
Although there were several swtngs in SG le~els while in
manual control, operators successfully controlled the level in
each SG within acceptable limits. This control prevented an
automatic reactor trip due to high or low SG level. The
inspectors discussed the manual control mode of maintaining SG
level with operators- and have witnessed similar occurrences during
startups and other shutdowns.
The inspectors concluded that the
feedwater control system's manual operation challenges operatofs.
f.
Problems at Low Level Due to Extreme Cold Weather
On several occasions throughout the inspection period ambient
. temperatures were significantly below normal.
On January 19, ice
buildup on the low level intake canal trash racks and rotating
screens restricted flow to the suction of the CW pumps.
This
condition degraded CW performance which made it difficult for
.
operators to maintain intake canal level.
As immediate corrective
actions, waterbox inlet MOVs were throttled to conserve intake
canal inventory and personnel were stationed at the low level
intake structure to remove the ice from the rotating screen
assemblies. Throttling water box inlet MOVs resulted irr the need
to reduce Unit 2 reactor power.
Intake canal level decreased to
26.2 feet before level was stabilized. Station management manned
the TSC in order to coordinate and implement the following actions
at the low level intake structure to improve CW performance:
The upper stop log was installed in -tne inlet bay to each CW
pump.
Every third basket was removed in each of the rota~ing
screen assemblies.
The upper rotating screen assemblies were covered with
herculite and heaters were placed in the area.
A tug boat was utilized to break ice at the entrance to the
low level intake structure.
Personnel were stationed at the low level intake structure
to monitor conditions.
There were no icing problems at the intake canal high level
structure; however, several actioris were implement~d to prevent
any problems from occurring. The upper stop log was installed in
each inlet bay and every other basket was removed in each of the
- rotating screen assemblies. Herculite and heaters were also
installed at the rotating screen assembles.
The inspectors concluded that the licensee's response to the 1c1ng
conditions at the low level intake structure was effe~tive in
7
improving CW pump performance. This action allowed the units to
stay on line during a period when the electrical demands forced
rotating "black outs" in the ~ervice area.
The cold weather
protection program, implemented several months earlier, had not
anticipated the icing conditions th~t occurred at the low level
intake canal on January 19.
At the end of the inspection period,
the licensee was evaluating revisions to the cold weather
protection program to better anticipate extreme cold weather
,effects on the station.
g.
Service Water Flow To Recirculation Spray Heat Exchangers
On January 24, the inspectors observed portions of the SW flow
test conducted on the Unit 1 RSHXs 1-RS-E-lB and 1-RS-E-lC.
The
test was performed in accordance with special test procedure
- 1-ST-0310, Recirculation Spray Heat Exchanger Service Water Flow,
dated January 21, 1~94. This test had. two purposes:
(1) to
collect data to verify that design basis accident service water
fl ow was adequate to reject design basis containment heat 1 oads,
and (2) to collect data on valves l-SW-MOV~l04B, RS HX B SW INLET
and 104C, RS HX C SW INLET, to support GL 8~-10 reviews.
This
test was performed at the same time the J-bus logic test procedure
l-OPT-ZZ-002 was performed.
The inspectors observed part of the test preparations, the pre-job
briefing, and reviewed the test procedure.
The test was monitored
from both the main control room and the Unit 1 safeguards area by
the inspectors.
Preliminary results identified that the SW flow
through both heat exchangers was good and very little, if any,
blockage exited. The actual calculations are currently being
performed by the engineering organization and will be reviewed by
the inspectors. The test was well organized and progressed
smoothly.
No discrepancies were identified.
h.
Contamination of Worker
While inspecting Unit l RFO activities, the inspectors reviewed a
worker contamination event that occurred on January 27.
When a
contract worker (welder/rigger), who had been handling deck
grating, attempted to exit the containment building, contamination
was detected on his hand by the PCM-1.
His hand was frisked
(8000 cpm) and several decontamination attempts by HP personnel
and by medical personnel were unsuccessful.
The licensee's doctor
placed ointment, bandages and a glove on the worker's hand prior
tri allowing him to leave the site. The worker was given
instruction by HP personnel which included returning to the site
for further decontamination efforts.
HP continued to monitor the
individual and on February 2 *the contamination was no longer
present.
The estimated external extremity dose from the
contamination was 703 mrem.
The estimated internal dose was less
than 0.1 mrem.
The inspectors discussed the worker contamination
event.with*Region II radiological protection personnel and they
8
determined that the licensee's actions were appropriate.
The
NRC's detailed review of this event is documented in NRC
Inspecti6n Report Nos. 50-280, 281/94-05.
i.
Unit 1 Reactor Vessel Level Indication
At approximately _10:40 a.m. on February 1, the level in the
reactor vessel standpipe decreased unexpectedly.
Level in the
standpipe was initially 18.0 feet and-decreased to 16.5 feet over
a ten minute period. Operators.isolated letdown and initiated
makeup to the reactor vessel from the RWST.
The*containment,
auxiliary building and safeguards valve pit were inspected for
leakage and no leakage was identified. A reactor vessel level of
16.5-feet is 1.2 feet above the level designated as reduced
inventory.
Approximately 15 minutes after the lev~l was noted to be
decreasing, Vent/Vent radiation monitors alarmed in the ~lert
range indicating that activity in the containment atmosphere had
incr~ased. Air samples obtained fro~ the containment refueling
floor indicated that the DAC was 1.3;
The DAC prior to this event
was O.
The Vent/Vent peak release rate was calculated to be 8~07%
of TS.
-
.
Level in the reactor vessel was returned to 18 feet and remained
stable. The containment was purged and activity in the
containment atmosphere returned to normal.
The inspectors monitored refilling of the vessel and reviewed the
controlling procedure to verify that level changes and volume
changes were as expected. Additionally, th~ inspectors performed
a walkdown of the standpipe assembly to determine if there were
any obvious eiplanations for the indicated level decreas~.
The
inspectors noted that there was a long torturous path from the
reactor head to where the v~nt piping penetrates the pressurizer.
The reactor vessel head vent was designed to ensure equal pressure
existed between the vented level stand pipe and the vessel. Most
of the head vent piping was disconnected at the time of the
indicated level drop to allow installation of the cavity seal.
However, the vent path described could result in trapping of
pockets of water in several a_reas of the system.
The inspectors
discussed their observations with the licensee to ensure that the
vent pa~h was reevaluated as part of the task teams efforts.
When the event occurred, the reactor vessel head was vented to the
containment via an open ended pipe.
Personnel in containment
noted that water sprayed from the head vent open ended pipe at
approximately the same time the reactor vessel level started to
decrease.
The reactor had been vented to the containment via the
open ended pipe for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> previously and reactor
vessel level indication was stable. Ther~ were no obvious
. **
j.
9
perturbations at the time of the event that could have resulted in
a decreasing reactor vessel level.* The licensee appointed a task
team to investigate this event. *The task team concluded *that the
most prtibable cause for the inaccurate ~tandpip~ level indication
was a restriction in the reactor head vent piping. Subsequent to
the inspection period, testing performed was unable to verify that
this conclusion wa~ correct.
During the last Unit l RFO, a similar decrease in reactor vessel
level occurred when the reactor head was d~tensioned.
Troubleshooting performed at that time did not identify any
blockages in the reactor vessel standpipe assembly. This event
and other reactor vessel-level indication problems were discussed
in NRC Inspection Report Nos. 50-280, 281/92~07.
The reactor vessel standpipe assembly is the sole reactor vessel
level indication utilized when the reactor vessel water level is
maintained below the reactor .head flange.
It should be noted
that there is another level monitor installed as discussed in
Generic Letter 88-17, Loss of Decay Heat Removal.
However, this.
monitor is only used during* mid~loop operations since it's range
- is from the top of the loop piping to the bottom of the loop
piping. This second monitor would be off-scale high during
operations above mid-loop as was the case described above .
As indicated above; problems with the Unit l reactor vessel
standpipe assembly indication continue to occur.
Incorrect
standpipe level indications could result in an unplanned entry
into a ieduced inventory condition or a loss of shutdown cooling.
This contern was discussed with licensee management.
At the end
of the inspection period, the licensee was developi~g a strategy
to identify the cause of the reactor vessel level problems .. Until
the problem's root cause is identified and corrections actions are
taken, this item will b~ identified as URI 50-280/94-02-02, Review
Reactor Vessel Level Problem.
February 3 Unit l Pressurizer Hydrogen Ignition
On February 3, 1994, at approximately 2:38 a.m., spikes were
observed on the pressurizer level instruments.
At the same time,
a loud rumbling sound was heard in containment.
The containment
vent radiation alarm was feceived and containment was evacuated.
At the time of the event, the pressurizer was drained and vented
via open filtered pipes to the containment atmosphere.
Apparently
pressure fluctuations inside the pressurizer caused radioactive.
gases inside the pressurizer to be expelled into containment.
The
highest radiation monitor readings on the containment monitor was
3300 counts per minute and a reading of 8,500 microcurie per
second was noted on the Vent/Vent monitor.
This Vent/Vent level
was estimated to be approximately 30% of TS limits.
One worker
. .
10-
received an estimated 7 mrems *internal exposur*e and a total dose
of 16 mrems.
The cause of the pressurizer pressure increase was investigated by
both the licensee and the inspectors.
The inspectors interviewed
workers involved and conducted an independent inspection of the
_ pressurizer head area.
The inspectors noted that the FME screens
that were taped over the pressurizer side of thi piping where the
three safety valves were removed were discolored and appear~d
burned.
Discussions with the licensee indicated that they were
i~vestigating a possible cause that involved a hydrogen gas burn
in_side the pressurizer. A modification to eliminate the
pressurizer loop seals was in progress. Welding activities
associated with the modification may have ignit~d hydrogen gas
that had tome out of solution and accumulated inside the
pressurizer and associated piping.
The licensee initiated DR S-94-0263 to d_ocument this occurrence.
Additional controls for welding on the primary system were also
imposed.
These required measuring for explosive gases prior to
initiating an arc.
The licensee's initial investigation also
included determining if similar events had occurred at other
nuclear facilities.
On the afternoon of February 3, after
reviewing the preliminary information that was submitted, SNSOC
determined that a hydrogen burn had occurred. The SNSOC also
determined that the event was not reportable based on a review of
their emergency plan and 10 CFR 50.72 and 50.73.
However, a *
voluntary LER wil 1 be submitted to alert the industry of the
occurrence.
The inspectors cbntinue to follow the licensee's investigation and
root cause determination of this event. This item is identified
as URI 50-280/94-02-03, Evaluation of Pressurizer Hydrogen Burn.
Issues that need resolving included, determining the source of the
hydrogen since the RCS had been degassed to< 4 cubic
centimeters/Kilogram during the plant shutdown/cooldown
evolutions. Additionally, welding procedures were being reviewed
.to determine why there were no precautions to monitor for
explosive gases prior to welding on the RCS.
The licensee was
al so considering utilizing industry data to evaluate the
pressurizer stresses associated with this event.
Within the areas inspected, one non-cited violation was identified.
4.
Maintenance Inspections (62703, 42700)
During the reporting period, the inspectors _reviewed the following
maintenance activities to assure compliance with the appropriate
_ procedures.
11
Rod Control Activity
Unit 2 shutdown bank.B group 2 step demand counter was identified to be
malfunctioning while performing a routine control rod exercise.
surveillance test on January 26.
Operators noted that upon releasing
the rod motion lever, the step demand counter indicated that shutdown
bank B group 2 rods continued to move inward one extra step.
On that
same day the shutdown bank B group 1 and 2 step demand counter driver
card was replaced ard shutdown bank B rods were exercised. During the
exerctse, the group 2 rod step demand counter continued to indicate th~t
rods moved inward one additional step when the rod motion lever was
released.
In. addition, the group 1 rod step demand counter indication
malfunctioned during the exe~cise. The group 1 rods were inserted to
212 steps and then withdrawn.
The step demand counter indicated
properly during r*od insertion but remained at 212 steps when rods were
withdrawn.
The plant process comput~r, which provides redundant group 1
movement demand indication, and the IRPis indicated that rod motion
occurred as required.
Prior to performing corrective maintenance on January 28, the SNSOC
convened to approve the work instructions.
The inspectors attended the
SNSOC meeting.
Du~ing the meeting, thi maintenance department presented
detailed troubleshooting instructions that included installing test
equipment to monitor logic cabinet and step demand couriter performance
and replacing the shutdown bank B step demand driver card.* SNSOC did
not approve these troubleshooting instructions because a less intrusive
method of repair/troubleshooting was desired.
SNSOC concluded that
replacing the step demand driver card and group 2 step demand counter
was a more prudent course of action.
On January 28 the inspectors witnessed replacing the shutdown bank B
group 2 step demand count~r and shutdown bank B group 1 and 2 step
demand counter driver card. This maintenance was accomplished in
accordance with troubleshooting WO 281688 and procedure O-ICM-RD-CAB-
001, Rod Control System Power Cabinet and Logic Troubleshooting and
Maintenance, revision 0.
The inspectors noted that the maintenance_ was
efficiently accomplished and communications between operations and I&C
personnel were good.
An I&C supervisor, maintenance engineer and
training instructor assisted the I&C technicians performing this
- maintenance.
Following replacement of the components,* all control rods were exercised
in accordance with 2-0PT-RX-005, Control Rod Assembly Partial Movement.
During this test, the shutdown bank B group 2 step demand counter
indicated correct rod movement.
However, the group 1 step demand
counter continued to indicate 212 steps when rods were withdrawn to 225
steps. At the end of the inspection period a vendor representative was
providing site support for the licensee's continued review and
corrective ,actions for this malfunction.
12
TS 3.12.E.1.a indirectly addresses the operational requirements for rod
step demand counters and states that above 50% power, the IRPI system
_ shall be operable and capable of determining the control rod positions
to within twelve steps of their respective group _step demand counter
indications. The inspectors noted that when the group step demand
counters did not provide proper indication or were deenergized for
.maintenance either process computer indication for group 1 rods was
utilized or control rods were rendered immovable but still trippable and
a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Leo.was entered in accordance with TS 3.12.C.3.
Recurring rod control problems are being reviewed by the licensee as a
station level one priority. The inspectors attended a meeting where the
system engineer made proposals to station management to correct some of
~
the more frequent problems.
A plan for Unit 1 rod control improvements
was discussed which included RCM recommendations as well as component
replacement based on industry NPRDS failure hi story.
The inspectors observed I&C personnel performing Unit 1 rod control card
inspection and replacement.
The inspectors were shown several firing
cards that were replaced because of heat damage and loose soldered
components.
Based on the observed card conditions, their replacement .
was warranted.
When combined with other card inspections and component
replacements, rod control system reliability improvements were expected
by the licensee.
Within the.areas inspected, no violations Were identified. -
5.
Surveillance Inspections (61726, 42700)
Dtiring-the reporting period, the tnspectors reviewed surveill~nce
activities to assure compl ianc*e with the appropriate procedures and TS
requirements.
a.
Unit 1 Control Rod Test
On January 13, from the control room the inspectors witnessed -
operability test of the control rod assemblies' drive mechanisms
and control circuits. This test was performed biweekly using
procedure l-OPT-RX-005, Control Rod Assembly Partial Movement,
revision 1, dated January 12, 1994.
The inspectors observed the
reactor operators manually moving the rods 12 steps, recording the_*
position of the rods, and observing that the appropriate alarms
were activated.
At the termination of the test, a documentation
review was made.
No discrepancies we_re identified.
b.
Ch1lled Water Pump A 1ST
On January 14, the inspectors witnessed testing the A chilled
water pump in accordance with O-OPT-VS-001, Control Room Air
Conditioning System Pump and Valve Inservice Testing, revision 5.
The purpose of this test was to place the A chilled water pump
into service at a specified flow rate and measure pump vibration
. ***
13
and differential pressure.
The testing results indicated that the
pump operated satisfactorily. The inspectors monitored th.is
testing from MER 3, MER 5, and the control room.
The inspectors
verified that the instrumentation used to obtain test data was
calibrated and the procedure was followed. * No discrepancies were
identified .
. c.
Unit I J-Bus and H-Bus Logic Testing
On January 24, the inspectors witnessed portions of the Unit I
J-Bus logic testing as specified in procedure l-OPT-ZZ-002.
The
test consisted of two basic parts. The first was a simulated
high-high containment pressure initiated SI. This part was
.
followed by a simulated loss of off-site power.
During the LOOSP
~ortion of the test the r~nning EDG picked up the emergency bus
electrical loads and powered the bus while selective ESF loads
sequenced back ont~ the bus.
The test was well coordinated and
the pre-evolution briefing was extensive and well articulated.
The inspectors monitored the control room_portion of the test as
well as communications between the test director and the many data
gathering stations in other areas of the plant. Several equipment
problems were noted and documented on DRs including S-94-0136 for
the tripping of l-VS-F-58A which was not an expected action based
on system alignment for the test. -Additionally, the inspectors
noted that while the 1-J bus was being powered solely by the
- 3 EDG the unlicensed operator created a low voltage condition on
the bus while attempting to adjust VARs.
Step 6.4.8 of procedure
I~OPT-ZZ-002 required that a voltage between 4000 and 4400 Vac be
maintained by the EDG and* for the operator to adjust if necessary.
The operator attempted to adjust the VAR reading by lowering the
voltage regulator setting. With the EDG as the sole source of
power to the bus, this action did not regulate VAR loading;
however, it did result in a low voltage condition.
The licensed
operator in the area noted the condition and voltage was returned
within the specified values.
The inspectors expected a DR to be written on the above low
voltage condition but, after several days, one had not been
written. The inspectors informed the SNS supervisor responsible
for the DR system that per VPAP-1501, Station Deviatioh Reports,
the observed condition would meet the threshold for a DR to be
written.
On January 27, DR S-94-0169 was written to document the
occurrence and evaluate the impact of the undervoltage condition
on plant equipment that was energized from the 1-J bus. This was
identified to licensee management as an example of where
Operations threshold for documenting conditions adverse to quality
may need adjusting. Discussions with the SNS supervisor revealed
that their review of recent events had also identified the
possibility of a negative trend in DR identification. Operation
management held discussions with their personnel and the
inspectors will continue to monitor this area.
14
The 1-H bus testing was monitored on January 25 and during that*
test a number of equipment problems were noted and documented on
DRs.
Examples of the items identified include the following:
1) DR S-94-0148, Terminal 112 inside UPS 1A2 was glowing red; 2)
DR S-94-151, Containment isolation valve 1-DA-TV-lOOA did not
indicate fully closed; 3) DR S-94-152, Containment isolation valve
l-CC-TV-105A failed to close and would not close with push-button;
4) DR S-94-150, Breaker for Recirculation Spray pump l-RS-P-2A did -
not close when it was sequenced back on the bus following the
undervoltage test; and 5) DR S-94-153, Breaker for SW valve_
l-SW-MOV-102A tripped on thermal overload. These conditioris were
_ noted on the test procedure discrepancy list as well and will
require resolution prior to the satisfactory completion of the
surveillance test before unit restart.
Withih the areas inspected, no vi-0lations were identified.
6.
Review of Plant Minor Modifications (37828)
a.
Modification to Waterproof Unit 1 MOV Operator
The inspectors monitored portions of DCP 93-17, Modify CW_ -
Limitorque Motor Operators-Submersible/Surry/Units 1 and 2.
The
purpose of this design ch~nge was to modify the eight condenser CW
inlet MOV actuators to make them watertight. Watertight actuators
would enhance MOV operation if these actuators were to become
submersed in water during a turbine building flood.
The
inspectors witnessed the modifications implemented by the design
change and the testing. associated with l-CW-MOV-106A.
This design
change was accomplished by WO 266884, Protedure o~MCM-0305-01,
Limitorque Size SMB-0 Through SMB-4 Overhaul, revision 5 and DCP
93-17.
-
This modification involved replacing several actuator gaskets and
0-rings, installing RTV on the actuator's motor end bell joint and
fasteners, and installing electrical quick disconnect fasteners at*
the power leads to the actuator.
Following reassembly, an air
drop test was performed in accordance with O-NAT-M-004, Generic
Hydrostatic/Pneumatic Test Procedure, revision 1. The actuator
was pressurized to 4.5 psig and the acceptance criteria was that
pressure could drop no more than 0.5 psig within _one hour~
The
actuator failed the initial air test. Several minor leaks were
identified and r~paired.
Following these repairs the actuator was
satisfactorily tested. The MOV was also satisfactorily stroked
timed and diagnostically-tested.
The inspectors noted that this design change was accomplished on
l-CW-MOV-106A without any deficiencies noted. It was evident that
the mechanical and electrical maintenance personnel were prepared
to properly implement this design change.
I
15
b.
Modification to Increase Unit 2 MOV Operator Torque Output
The inspectors witnessed changing the motor and worm gear shaft*
gears on Unit 2 MOV 2-SI-MOV~2862B.
The licensee's GL 89-10
review identified that during a combination of high ambient
temperature and reduced voltage, the overall gear ratio of the
motor operator did not produce the desired torque.
Based on this
review, the motor operator gear set was replaced with gears that
produced a higher operator torque output. This modification also
- resulted in a slower strok~ time.
This modification was accomplished in accordance with DCP 92-83~3,
Misc Limitorque Motor Operator MODS/Surry/1&2, revision 5;
Procedure O-MCM-0304-02, Limitorque SMB-00 Overhatil, revision 3;
O-ICM-15050-01, Limitorque SMB Operator Disconnect and Connect,
revision 1; and WO 280451.
The inspector attended the SNSOC
meeting that approved this design change and safety evaluation,
monitored portions of the motor operator gear set replacement and
witnessed portions of the post modification testing.
Prior to disassembling the actuator, a torque wrench was utilized
to operate the MOV in order to determine the torque required to
- . operate 2-SI-MOV-2862B.
The testing re~ults ide~tified that it
took less than 25 ft-lbs of torque to operate the quarter turn
plug valve.
Vendor information on this valve stated that
approximately 40 ft-lbs of torque was required to operate the
valve.
The licensee concluded that 40 ft-lbs of torque applied to
a new valv~, and as it aged, less torque was required.
In
addition, 2-SI-MOV-2862B had been satisfactorily stroke tested on
a quarterly basis. The valve history indicated that there were no
operational problems associated with the valve.
The licensee-
concluded that 2-SI-MOV-2862B was operational prior to
implementing the design change.
The inspectors agreed with the
licensee's conclusion that the valve was operable .. The inspectors
concluded that the design change package adequately implemented
the modification to 2-SI-MOV-2862B.
Within the areas inspected no violations were identified.
7.
Unit 1 Inservice Testing
On January 22, the inspectors witnessed/reviewed portions of two 10-year .
ISi pressure tests.
ASME Code Section XI, requires that every 10 years
piping systems be hydrostatically tested to determine integrity. The
licensee substituted the pressure test for the hydrostatic test required
by the code by invoking ASME Code Case N-498.
The NRC endorsed this
Code Case through revision 9 of Regulatory Guide 1.147; Inservice
Inspection Code Case Acceptability, ASME Sect ion XI Division 1.
The first test-witnessed by the inspectors was a VT-2 visual inspection
of two sections of SI piping located in the Auxiliary Building between
valves l-SI-150 and 1-SI-174 and their respective containment
16
- penetrati6ns.
The stated test pressure was 2135 psig with th~ normal
system operating pressure being 2235 psig. While performing the test,
the actual pressure obtained through throttling the manual valves was
approximately 2500 psig based on the.local gage. This was due to the
sensitivity of the manual valves.
Th~ inspectors questioned the
adequacy of the test pressure and concluded that it was satisfactory.*
The second test reviewed by the inspectors was a four-hour system
pressure test of the excess let-down heat exchanger.
The inspectors
noted through a review of the operator, logs that approximately 39.
minutes after the excess let-down heat exchanger was pressurized with
RCS fluid, radiation monitors l-CC-RM-105 and 106 went into an alert
alarm indicating a possible tube leak. This heat exchang~r had been
suspected as leaking in the past and was only used whenever the normal
let-down path was isolated.
The in~pectors questioned the licensee as
to whether this leak would cause the component to fail the system
pressure test. The inspectors reviewed the completed copy of the
pressure test procedure and found no mention of the indication of the
tube leakage.
The inspectors reviewed the applicable ASME Code Section XI requirement~
and determined that heat exchanger tube *leakage would be rejectable.
Note 6 of the licensee'sSection XI program stated that visually
inspecting the heat exchanger tubes was not required.
However, note 6
also state'd, "Good Engineering Practices will continue to be followed
when the need is recognized".
The inspectors recognize that the system
pressure test of the excess let-down heat exchanger was not structured
to identify tube leakage.
However, "good engineering practice" should
havi required th~t the noted RCS leakage into the CC system be evaluated
and corrected.
On January 27, five days after the occurrence and after
discussion with the inspectors, the licensee initiated DR s~94-0168 to
docum~nt the event. This was identified as another example of
operators' inappropriate threshold for problem identification and was
discussed with the Superintendent of Operations.
WO 262027 scope was
expanded to investigate and repair the tube leakage prior to unit
restart. *
8.
Action on Previous Inspection Items (92701)
(Closed) IFI 50-280, 281/92-17-01, Gas Void Long-Term Corrective Action.
In July 1992, the licensee identified gas voids in the LHSI piping.
Immediate corrective action involved venting the LHSI piping.
The
licensee replaced cold leg check valve 2-SI-85 during the 1993 Unit 2
spring RFO and modified procedure 2-PT-18.11, Cold Shutdown Test of SI
Check Valves to Hot and Cold Legs, to ensure that the SI system was
properly filled and vented.
The inspectors reviewed the 1993 results of
procedure 2-0SP-SI-001, Venting SI Piping, which was performed
quarterly. The review results indicated that gas had not been
identified in the Unit 2 SI piping since the 1993 Spring RFO.
Within the areas inspected, no violations were identified.
17
9.
Exit Interview
The inspection scope and findings were summarized on February 8 and
March 7, 1994, with those persons indicated in paragrap.h 1. the
inspectors described the areas inspected and discussed in detail the
inspection results addressed in the Summary section and those listed
below.
- Item Number
Status
Description
(Paragraph No.}
NCV 50-280/94-02-01
Closed
Failure To Follow Fire Seal
Inspection Requirements
(paragraph 3.b).
URI 50-280/94-02-02 *
Open
Review Reactor Vessel Level
Problem* (paragraph 3.i).
URI 50-280/94-02-03
Open
Evaluation of .Pressurizer
Hydrogen Burn (paragraph 3.j).
IF! 50-280, 281/92-17-01
Closed
Gas Void Long-Term Corrective
Action (paragraph 8).
Dissenting comments were not received from the liceDsee.
Proprietary
. information is not contained in this report.
10:
Index of Acronyms and Inttialisms
cc
CFR
cw
DR
ECCS .
ERFCS
GL
HQ
HS
HSD
IFI
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
COMPONENT COOLING
CODE OF FEDERAL REGULATIONS
COUNTS PER MINUTE
COOLING WATER
DERIVED AIR CONCENTRATION
DESIGN CHANGE PACKAGE
DEVIATION REPORT
EMERGENCY RESPONSE FACILITY COMMUNICATION SYSTEM
ENGINEERED SAFETY FEATURE
GENERIC LETTER
HOUR
HEALTH PHYSICS
HEADQUARTERS
HEATING STEAM
HOT SHUTDOWN
HEAT EXCHANGER
INSTRUMENTATION AND CALIBRATION
INFORMATION FOLLOWUP ITEM
.\\.,
. .
.. . ,
!RPI
ISi
1ST
LCO
LER
LHSI
LOOSP
MER
MFWP
MOV .
MREM
NI
NIS
NPRDs*
NRC
RS
. RTV.
SNS
SNSOC
T AVG
TS
VAC
VAR
VPAP
INDIVIDUAL ROD POSITION. INDICATION
INSERVICE INSPECTION
INSERVICE TESTING
LIMITING CONDITIONS OF OPERATION
LICENSEE EVENT REPORT
LOW HEAD SAFETY INJECTION
MECHANICAL EQUIPMENT ROOM
MAIN FEEDWATER PUMP
MOTOR OPERATED VALVE
MILLI-ROENTGEN
MEGAWATTS
NON-CITED VIOLATION
NUCLEAR INSTRUMENTATION
NUCLEAR INSTRUMENTATION SYSTEM
NUCLEAR PLANT RELIABILITY DATA SYSTEM
NUCLEAR REGULATORY COMMISSION
PERSONNEL CONTAMINATION MONITOR
POUNDS PER SQUARE INCH GAUGE
PERIODIC TEST
REFUELING OUTAGE
RADIATION MONITOR
RECIRCULATION SPRAY
RECIRCULATION SPRAY HEAT EXCHANGER
ROOM TEMPERATURE VULCANIZER
REFUELING WATER STORAGE TANK
SAFETY INJECTION
STATION NUCLEAR SAFETY
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SAFETY PARAMETER DISPLAY SYSTEM
SENIOR REACTOR 0-PERATOR
AVERAGE TEMPERATURE
TECHNICAL SPECIFICATION
UNINTERRUPTIBLE POWER SUPPLY
VOLTS - ALTERNATING CURRENT
VOLTS-AMPERE, REACTIVE
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER