ML18152A242
| ML18152A242 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/29/1992 |
| From: | Branch M, Fredrickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A243 | List: |
| References | |
| 50-280-92-07, 50-280-92-7, 50-281-92-07, 50-281-92-7, NUDOCS 9205190103 | |
| Download: ML18152A242 (17) | |
See also: IR 05000280/1992007
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No~.:
50-280/92-07 and 50-2?1/92-07
Licensee:
Virginia Electric and Power Company
5000 Dom~nion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50~281
Facility Name:
Surry 1 anc\\ 2
License Nos.:
DPR-32*and DPR-37 *
Inspection Conducted:
March 8 through April 4, 1992
Inspectors:
Approved by:
Scope:
. E.F.'ckson, Section Chief
- vision d' Reactor Projects
SUMMARY
DiJ;1~~~a
.., I~, I ~J..
Date Signed
. 'i ~)-; (1 }-
Da~
Signed
V>£/f2--
0'ate*signed
This routine resident inspection was conducted on -site in the areas of
operations, maintenance, surveillance, reliable decay heat removal duri.ng
outages, loss of decay heat removal, and qua 1 i ty veri fi cation and safety
assessment review.
During the performance bf this inspection, the resident.
inspectors conducted *review of the licensee's backshift or weekend operations
on March 11, 14, 15, 16, 21, 22, 28, 29, and April 2 and 4, 1992.
Results:
In the operational functional area, failure to align the No. 3 e~ergency diesel*
generator speed dial .scribe marks in accordance with the governoring procedures
was identified as Non-Cited Violation 280,281/92-07-01, Failure to Follow
Procedure When Testing No. 3 ~mergency_ Diesel Generator (paragraph 3.b).
In the operational functional area, weaknesses involving procedure adequacy,
and operator and shift technical advisor attention to detail were identified
when returning the No. 1 emergency diesel generator to service following relay
testing (paragraph 3.b).
9205190103 920429
ADOCK 05000280
G
2
In the operational functional area, Violation 280/92-07-02 was identified for
failure to establish adequate containment integrity when conducting refueling
operations {paragraph 3.c).
.
.. *
..
In the* maintenance functional ar*ea,* over the past year the licen~ee decreased
the number of open nonoutage* co.rrective maintenance work*orders by one~half and
the average age of these work orders by two-thirds (paragraph 4.a}.*
In th~ maintenance. furi~tional area, Violation 280/92-07-03 was identified for
the failure to prevent foreign mateiial from* entering the service water system
while maintenance was performed during the previous refueling outage (paragraph
5.a).
In the. safety assessment/quality verification area, the -Critical Parameter
Assessme*nt Matrix enhanced the licensee's ability to monitor the status of
plant parameters and systems important to safety during an outage.
During the
current outage, the licensee reev~luated the need to dr~in the reactor coolant
system to mid-loop level in order to drain steam generator tubes and concluded-
that draining to mid-loop was not necessary.
The elimination of this
previously routine mid-loop evolution was a another enhancement to outage plant
safety (paragraph 6).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Liceniing Engineir
- H. Blake, Superintendent of Sit~Services
D. Christian, Assistant Station Manager
- *J. Downs, Superintendent of Outage and Planning
A. Fletcher, A_ssistant Superintendent of Engi-neering
R. Gwaltney, Superintendent of Maintenance
D. Hart, Supervisor, Quality Assurance
- M. Kansler, Station Manager
- A. Keagy, Superintendent of Materials
- J. McCarthy, Superintendent of Operations
- J. McGinnis, Human Performance Evaluation System Coordinator
- A. Price, Assistant Station Manager
- R~ F. Saunders, Assistant Vice President-Nuclear, Corporate
- E. Smith, Site Quality Assurance Manager
- T~ Sowers, Superintendent of Engineering
- G. Woodzell, Senior lnstructor
NRC Personnel
M. Branch, Senior Resi~ent Inspector
- S. Tingen, Resident Inspector
- J. York, 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 list~d in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period in a *refueling outage and continued in
thls mode throughout the inspection petiod. At the end of the inspection
period the unit was in day 36 of a 64 day outage.
Unit 2 began the reporting period in power operation.
The unit was at
power at the end of the inspection period, day 108 of continuous
operation.
2
3. Operational Safety Verification (71707,42700)
The inspectors conducted *frequent tours of the control room to verify
. proper staffing, operator attentiveness and adnerence to approved
procedures.* The inspectors attended plant status meetings and reviewed*
operator logs on a daily basis to verify operations.safety and compliance
.with TS and *to maintain awareness of the over a 11 opera ti on 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,
radi ol og i cal work practices, pl ant secliri ty programs and housekeeping.
Deviation reports were reviewed to assure that potential safety concerns
. were properly addressed and *reported.
a.
Licensee 10 CFR 72 Reports
b.
On March 17, at 2:32 a.~~~ the licensee report~d to the NRC that a
contractor was transported off site by the station ambulance.
The
contractor slipped on a wet floor .in the Unit 1 containment and*
injured his back.
The individual exited the containment under his
o~n power and was not contaminated.
On March 18 at 4~4j p.m., the litensee reported to the NRC*that the
No. 3 EDG automatically started due to personnel error. Maintenance
personnel were pulling cable in an energized Unit 1 J emergency bus
undervoltage 'panel and bumped a relay inside the panel causing the*
EOG to start.
An actual undervoltage condition did notexist and the
. No .. 3 EOG did not 1 oad on either of its emergency buses.
On Mar~h 23, at 5:20 p.m., the licensee reported tti the NRC that a
contractor was transported offsi te by the station.ambulance.
T.he *
individual had abdominal pains and was not contaminated.
On March 25, at 3:17 p.m., the license~ reported to the NRC that a
fisherman was tr.ansported offsite by the station ambulance.
The
individual was fishing in the station**s SW discharge canal and fell
into the canal.
The individual was conscious when pulled fr*om the
canal and was not contaminated. -
On March 31, at 6:27 p.m., the licensee report~d to the NRC that
three contractor~ were contaminated at approximately the same time
while erecting scaffolding in the Unit 1 containmeht.
The source of
contamination was insulation dust that became airborne after bei~g
bumped.
Whole body' counts and bioassay evaluations performed on*
. three individuals inaicated no internal contamination.
EOG Restoration Problems
During the inspection period, the No. 1 and 3 EDGs were taken out of
servic~ for maintenance.
On several occasions after completion -of
the maintenance, operators did not properly restore the EDGs.
3
On March 26, fol lowing maintenance, the 'No. 3 EDG was test~d in
accordance wi.th procedures O-OP-EG-001, Number 3 EDG, dated Ma~ch 25,
1992, and O-OPT-EG-6.l, Number 3 EOG Exercise Test, dated May 29,
1991.
At the completion of the test, No. 3 EDG_was declared fully
Two days later on March 28, operators noted that the
scribe marks on the No. 3 EOG. governor speed control dial were not
aligned;
The system engine~r was contacted and informed operati~ns
that a new governor was installed during the previous maintenance.
He stated that the speed control dial was at the correct setting, and
since it was a new governor, it needed to be rescribed.
Later that
day, the speed control dial was rescribed to ag_ree with the new
setting.
Step 5.3.12 of O-OP-EG-001 requires that the speed control dial.
scribe marks be aligned.
As ,a result of a corrective action
implemented in response to Violation 280,281/91-24-0l, the procedure
contains a verification that the scribe marks are aligned.
The
inspectors reviewed O-OP-EG-001 and verified that step 5.3;12 was
initialed by operators as being completed.
The inspector~ concluded
.that in order to comply with O-OP~EG-001 the ~cribe marks on the
speed control dial needed to be changed to the new setting or the
procedure changed to. recognize that the scribe marks were not
aligned.* It was concluded that although the procedure was not
. followed, the EDG was fully operable.
Failure to align the No. 3 EDG
speed dial scribe marks in accord~nce with O-OP-EG-001 was identified
as NCV 280,281/92-07-01, Failure to Follow Procedure When Testing No.
3 EOG.
This NRC identified violation is not being cited because *
criteria specified in Section V.A of the NRC Enfor*cement Policy were
satisfied.
On March 27, No. 1. EDG was placed in exercise in order to perform
scheduled relay testing and adjustment in accordance with. procedure
1-EMP-P-RT '."36, Protective Relay Maintenance for EOG No. 1 Differ-
entia_l Relays, dated May 28, 1987.
On March 28, this evolution was
completed and the No. 1 EDG was returned to service and considered
fully operable.* Approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> later, on March 29, during a
walkdown of the control board, a the control room operator noticed
that the No. 1 EDG auto start disabled alarm was energiz~d.
Further
investigation revealed that the No. 1 EOG non-auto alarm was also
_en~rgiied.
The EDG was declared inoperable.
The cause of alarms was
determined to be the EDG's exciter field breaker being in *the tripped
position.
The licensee concluded that the exciter field breaker was
tripped during the performance of l-EMP-P-RT-36 and that the EOG was._
inoperable while the exciter field breaker was in the tripped
position.
However, no TS LCO action statement time restraints were
exceeded.
The inspectors identified*weaknesses *involving procedure
adequacy and attention to detail as a result of this event.
Procedure l-EMP-P-RT-36 did no~ provide instructions to restore the
exciter field breaker to its nor~al positi9n after being repositioned
by the procedure.
Also; for approximately one and a half s~ifts,
the operators and STAs failed to identify an energized control room
- C *
4
- alann indicatjng that the No. 1 EOG was inoperable during annunciator
board walkdowns.
Evaluation of Loss of Containment Refueling Integrity
On Apri 1 3, the 1 i censee detenni ned that containment integrity for
refueling was violated during the on-loading of fuel elements into
the the Unit 1 reactor vessel.
Breaches in containment involved
d*irect paths. from the containment to the environment via the FW and
MS line~ associated with the A and B SGs.
Details of the breached
containment condition and contributing causes are. provided below *.
Detaili of the Breaches
The first direct path from containment to the environment
existed via openings in the B SG whil.e at the same time work was
being performed on the B SG MSTV (1-MS-TV-101B) and its bypass
check valve (1-MS-117).
The hand ho)e covers were removed from
the B SG and the inte~na1s had been previously removed from the
MSTV which is located in the main steam line between the SG and
the turbine building.
There is a bypass. line around the MSTV
for warming up the MS piping, and this bypass line has a manual
valve and a downstream check valve (1-MS-117)'.
At the time of
fuel movement on April 2 the bonnet of 1-MS-117 was removed and .
a FME cover with no gasket was installed. This closure was not
in accordance with the refue 1 i ng integrity procedure 1-0P-lG,
Refue 1 i ng Con ta i riment Integrity And RCS Mid-Loop Containment
Closure Checklist, dated March 19, 1992, and would not have
provided a positive barrier from the environment.
This path
through 1-MS-117 was not recognized by operations or maintenance
planning in that, procedure 1-0P-lG did not tnclude this valve
in the verification.
Also, during the time of fuel movement an
active WO for removing valve 1-MS-117 was being worked and
pipi~g cuts for valve replacement had been started.
The second path from contain~eni ~o the environmerit involved an
open 3/4 inch drain valve (l~FW-9) on the A SG FW line at the
same time that the MSTV (1-MS-TV-lOlA) had its- internals.removed
with a wo6den FME cov~r installed on the ~onnet of the valve .
. The path would have been from the containment into the 3/4 inch
FW drain valve into the SG out through the MS line and to the
environment through the improp~rly sealed wbod~n blank on the
MSTV._
The FW drain valve had.been prevjously tagged open for
anticipated FW valve work and it was n6t realized at the time of
establishing refueling integrity in that, the barrier was
thought to b~ an intact SG inside containment since work on the
A MSTV was authorized and scheduled to work in parallel with
fue 1 movement.
While investigating thi~ event, the inspectors discovered that
during the core off-load between March 17 and 20 the second leak
5
path.through the FW drain valve also existed .. This conclusion
was determined throu~h interviews and .was bas~d on the time of.
tagging open 1.:.FW-9 { 3/l0/92.) and when work was being performed
on 1-MS-TV-lOlA.
This valve had only a* wooden* FME cover
installed..
The inspectors determined through interviews and review of work
logs, that although the openings on the valves in safeguards
were not sealed in accordance with the requirement of the*
refueling integrity procedure, 1-0P-lG; the openings were
covered at all time during fuel movement.
2.
Consequence of Loss of Containment Refueling ln.tegrity'
TS 3.10 provides *requirements and restrictions that are.
necessary for refueling activities.
The basis of this TS is to
ensure that refueling unit cortditions conform to the conditions
assumed in the accident analysis for a fuel handli.ng accident.
The fuel handling accident is described in section 14.4.1 of the
UFSAR which includes. several cases of releases from the
containment.
Case 3, which is the most limiting for offsfte
release but still well below the 10 CFR part 100 c"riteria,
involves a release from a fuel handling accident.without
isolation of the containment purge system.
Case 3 assumes that
all of the radionuclides released from a fuel handling accident
that reaches the surface of the water are rel eased from
containment through charcoal filters that remove 70 percent of
the iodine.
The licensee's NA&F group performed a ~pecial an~ly~is of the
Apri 1 2, 1 oss of refueling integrity event and compared the
results with the the UFSAR analyzed events.
The licensee's
analysis detenni.ned that the consequences of a fuel handling.
accident during the fuel movement of April 2 would be limited to
a dose much less than* that eva 1 uated in the UFSAR.
This
determination was based on two pri nci pa 1 reasons.
First the
April 2, loss of integ*rity occurred 34 days after shutdown
rather that 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> as assumed in the UFSAR analysfs~
The
second difference was that the release assumed in the UFASR was
an~entire release of activity in the containment through the 70
. percent effi ci.ent fi 1 ters due to venti 1 ati on system not *
isolating.
Theref6re, the release volume through the improperly
sealed openings would be much less than the total release volume
assumed in the UF"SAR analysis.
- The licensee's analysis also concluded that for the April 2,
event there was no pressure driving head to force any activity
through the openings.
The analjsis determined that there was no*
credible mechanism for significant containment pressurization~ *
Even with a complete loss of RHR, th*e cavity flooded and two
fuel elements in the core,. it would have taken many hours before
6
the RCS temperature reached saturation.
The boiloff rate would
be *slow and would not result in any significant containment
pressurization.
The licensee performed a second analysis for the March 17
through 20 event.
This analysis also concluded ~hat there was
no *pressure driving _head to force any activity through the
opening and that th~ total release volume through the improperly
sealed opening would be less that the total released volume
assumed in the UFSAR analysis.
The inspectors and the NRC staff reviewed the- licensee _analysis
and agree that for the conditions described, the consequences of
the events were bounded by the UFSAR analysis;-
However, as
discussed in the basis for TS 3.10, controls of refueling
activities have to be in place and properly controlled to ensure
adequate protection at all times and for all situations.
3.
Contributing Causes of the Los.s of Refueling *Containment
Integrity
The inspectors reviewed the licensee's program for establishing
and controlling refueling containment integrity as required by
The licensee's controls of the initial condition for
fuel movement is specified in refueling procedure OP-FH-01,
- . Refueling Operations," dated March 6, 1992.
This procedure
requires the establishment of refOeling containment integrity
which is accomplished by completion of procedure 1-0P-lG.
This
- procedure is also used as a surveillance procedure for periodic
reverification of integrity with each of the three zones being
verified twice a week.
The integrity established and maintained by 1-0P-lG is a single
barrier outside of containment.
Therefor~, for the case of the
breach that occurred from the A SG, while work. was being *
performed on 1-MS-TV-lOlA in parallel with refueling activities,
it is *not clear that procedure 1-0P-lG was appropriate.
The
barrier established was inside rather than outside as described
in the procedure.
The inspector's interviews with operation
personnel determined that there was no clear trail as towhat
was done to verify the integrity of the A SG boundary inside
containment. Additionally, it could not be determined if the FW
line for the A SG which had the tagged ope~ 3/4 inch drain valve
was included in the barrier verific~tion.
For the breach of the
barrier associated with work on valve l-MS-117 ," procedure
1-0P-lG did recognize the need for boundary extension due to
.removal of the internals of trip valve 1-MS-TV-1018.
Also, it
. was determi__ned that procedure 1-0P-lG re qui red the use of
special order tags for ensuring that barriefs associated with
7
temporary blanks are in. place but did not require valve
- boundaries to be tagged.
As noted in * the sequence of events, work on severa 1 * of the
. valves that were being used for boundaries was authorized and in
some cases ongoing.
Operations and work planning groups were
trying to perform parallel tasks an.d control the moving
boundaries by verbal job holds or the use of special tags that
were intended to recapture the equipment to be used for barriers
even though authorized work re 1 eases were outstanding.
The
inspectors determined,*that due. to the outage scope and schedule
there were more work-around.maintenance it~ms being performed
this ou*tage than during previous outages. . These work-around
maintenanc~ items were also being done for the SW lines th~t
penetrated containment.
No instances of breach of integrity was
identified with the. SW work, and it appears that management had
recognized the potential problems in this area and concentrated
on better controls.
The containment refueling integrity breaches that occurred
during the Unit_ 1 core off-load ~nd portions of the core on-load
were identified as Violation 280/92-07-02, *Failure to Establish
Containment Refueling Integrity in Accordance with TS 3.10.A.1
. and Failure to Follow Procedure in Accordance with TS 6.4.D .
. Within the areas inspected one NCV and one cited violation were
identified.
4.
Maintenance Inspections (62703, 42700,)
During. the reporting* period,* the inspectors reviewed maintenance
- . activities to assure compliance with .the appropriate procedures.
The following maintenance activity was reviewed.
a.
Maintenance Backlog
On March 24, the inspectors requested the status of the current
maintenance backlog and were provided the following information .
8
CORRECTIVE MAINTENANCE
NUMBER
Nonoutage corrective maintenance work orders (less minor work)
403
These WOs require action to repair or restore
functional capability of failed equipment.
Nonoutage corrective maintenance average age in days
88
Nonoutage minor corrective maintenance-work orders
1168
These WOs do not require engineering, tagout or
detailed maintenance procedures
Outage corrective maintenance work orders
These WOs do not include minor work.
2277
PREVENTIVE MAINTENANCE
Open nonoutage preventive maintenance work orders
Open outage preventive maintenance work orders
Deferred preventive maintenance work orders
-639
1120
22
Over the SALP assessment* period the licensee decreased the number of open
nonoutage corrective maintenance work orders by one~half and the average
age of these work orders by two-thirds.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726, 42700)
During the reporting period, the .inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and TS
requirements.
The following surveillance activity was reviewed:
a.
Flow Testing of the Service_ Water Side of the Unit 1 RSHXs
During this inspection perio*d, -the inspectors witnessed flow testing
of Unit 1 RSHXs 1-RS-E-lB and 1-RS-E-lC. The test ~as performed in
accordanc~ with special test procedure l-ST-299, Recirculation Spray
Heat Exchangers Service Water Fl ow Test, dated December 12, 1991.
This test had three purposes:
(1) to co*l lect data to verify that
design basis accident SW flow is adequate to remove design basis heat
loads from containment, (2) to collect data to develop a calibration
curve for the new V-cone flow elements, and (3) to functionally test
modifications to the 58 and 5C SW radiation monitoring pumps .
-.
9
The pretest preparations, w~ich included i~stallation and checkout of
test equi pmerit and -the -pretest briefing, -were observed.
The
inspectors reviewed test procedure l-ST-299 and found the procedure
to be technically adequate~
The test began on March 16 at_l:36 a.m.
and was moni tared by the inspectors from both t_he control* room and
the Unit 1 safeguards area. The second objective of the special test
was successful, i.e., enough data was collected for a calibration
curve.
The third obje~tive was also successful. This objecttve was
identified d~ring the flow testing on Unit 2 on April 6, 1991, when
. the radiation monitor pumps on each of the SW outlet pipes fai-1 ed to
self prime.
Two different modifications were evaluated during the
test.
One modifitation involved the increase in size of the suction
line from three-fourths of an inch in diameter to two inches in
diameter and ihe installation of a check valve in the discharge line.
A second modific~tion involved the installation of a suction tank and
the installation of a check valve in the discharge line.
Each
modification was insta1led in a separate pump.
Both modifications
achieved acc_eptable results and the licensee decided to install the
larger size suction line/check ~alve combinations for these pumping
systems.
The preliminary test results for the adequacy of the SW fl ow showed
that the flow rate through the C RSHX was slightly less than
anticipated and the flow through the B RSHX was significantly less
than anticipated.
The preliminary calculations using the
conservative criteria of calculation_ ME-0266 revealed that- thi SW
flow in the C RSHX was approximately 20 percent blocked and the flow
in the B was approximately 55 percent blocked.
A* calculation was
performed that showed the heat transfer capability was such that both
of these RSHXs were co*ns i dered operable using a SW temperature of 92
degrees Fahrenheit and for the entire 18 mon_th period that Unit 1 had
operated.
Unit 2 was considered operable also because this unit had
_been placed in service five months later than Unit 1 and should have
less blockage potential due to fouling.
The inspectors accompanied licensee personnel to perform a visual
inspection of the B RSHX once the elbow .to vessel was removed.
This
inspection revealed that a rain jacket and rain pants wefe present in
the tubesheet area and* were the apparent reason for the 1 ow flow
(there were very few hydroids. present).* Durin.g a meeting on
March 30, the licensee postulated that this rain jacket and pants had
been left in the pipe during the previous- pipe coating operation
because there appeared to be a small amount of the coating on tbe
rain jacket.
A review of DCP no. 90-26-1, Heat Exchanger Service
- _Water Piping Cleaning and Recoating/Surry/Unit 1, dated October 2,
1990, indicated that FME controls were in effect at the time the
piping was last coated.
This* is identified as VIO 280/92-07-03,
Failure _to Prevent Foreign *Material Exclu.sion in the SW System.
6.
10
b.
Reactor Head Vent Flow Pith Verificatiori
Prior to removal of ' the Unit 1 reactor head, the * RCS was
depressurized with level being maintained at about the ejghteen. foot
level which is slightly below the ~eactor head flange.
This was not
a reduced inventory condition.
The only visible means of RCS level
indi~ation at this level was th~ RCS standpip~ assembly and the unit
was in this condition for approximately a week.
For the first part*
of the week, level in the standpipe properly responded when fillihg
and draining reactor coolant from the vessel; however, at the end of
the week, the standpipe level was not i.ndicatirig properly when
filling the reactor from the VCT.
After securing from a filling
evolution it would take an additional twenty minutes for reactor
level* to stabilize.
On March 15, level in the reactor vessel
unexpectedly dropped one foot in level. Operators ilTITlediately added
approximately 1000 gallons to the vessel to. restore level.
Subsequent investigation revealed that the level dropped when the
last reactor head stud was detentioned. Detentioning the head vented
the top of the reactor vessel to containment atmosphere causing level
to drop.
The reactor head was then removed and standpipe assembly
secured.
- In order for the standpipe assembly to indicate properly the reactor
head has to be vented to the pressurizer.
Piping and tygon tubing
are utilized to accomplish this task.
On March 19, this line was
flow tested with air in accordance with procedure l-TOP-4014, Reactor
Head Vent Flow Path, dated. March 18, 1992.
This testing was*
accomplished in the Unit 1 containment and was witnessed by the
inspectors.
The testing was accomp 1 i shed in accordance with the
procedure and did not identify any blockages. Several days later the
standpipe assembly was tested and satisfactorily operated.
At the
end of the inspection period, the 1 i censee had not reso 1 ved the
reason for the standpipe level perturbations.
After fuel is loaded.
into the co*re, the reactor head wi 11 be i nsta 11 ed and the standpipe
- . assembly will be ~laced back into servite. The licensee will monitof
the standpipe assembly and if the problem reoccurs will attempt to
troubleshoot while the standpip~ is in service.
Within the areas inipected~ one violation was identified.
.
.
Reliable Decay Heat Removal .During Outages (TI.2515/113)
(Closed) 280 ,281/TI/2515/113
The inspectors reviewed 1 i censee procedures
to ensure reliable OHR capability during plant outages.
Implementation of
requirements ~nd condu~t of certain activities during the current Unit 1
RFO were reviewed for accuracy.
TSs 3.1.d, 3-:10.6 and 3.10.7 specify
minimum OHR requirements when RCS temperature is 1 ess that 350F.
The
1 i censee utilizes procedures and management oversight of day to day outage
activities to ensure reliable OHR..
-
STA~OI-22, Surry Power Station CSD/RSO Critical Parameters, dated March 4,
1992~ was developed by the licensee to provide an independent method for -
11
monitoring the status of plant parameters a*nd sy~tems important to safety
. during an outage.
The STA evaluates* and categorizes the critical
parameters and develops a Critical Plant Parameter Assessment Matrix on a
daily basis.
The matrix is distributed to management for review.
The
inspectors also review the matrix.
One of the purposes -0f this matrix~ is
to summarize and evaluate the status of systems required to provide DHR.
STA-01-22, also requires the develQpment of the CSD/RSD Critical Parameter
Seven Day Look Ahead Matrix.
The Outage and Planing d~partment is
required to provide SNS with a schedule of events for the upcoming week.
SNS evaluates and categorizes the status of critical ,plant parameters
based on the schedule.
This matrix also sunmarizes and evaluates- the
status of systems required to provide DHR and is distributed to mana~e~ent
for review.
Operation during redu.ced inventory operations is discussed- in paragraph *
7. AP-27, Loss of Decay Heat Removal*Capability, dated March 8, 1991,
is utilized for loss of RHR during reduced inventory operations, and is
also utilized on loss of RHR during bther cold shutdown operations.
AP-27
provides alternative methods of DHR including natural* circulation and
several methods of feed and bleed~
Also, during CSD and RSD conditions,
. STA
1s are required to monitor RCS inventory and leakrate in accordance
with 1-0PT-RC-10.2, RCS/CSD Inventory balance, dated March 19, 1992.
Calculations are performed each shift in order to identify RCS leakage *.
Operations_ personnel
perfor~ walkdowns * daily in accordance with
.
. OPT-RC-10.1, RCS Leakage Walkdown at Cold Shutdown, dated May 6, 1991*, in
order to identify anyRCS leakage to atmosphere.
Occasionally, a nonstandard backfeed. electrical lineup is utilized during
outages. * This is considered a special evolution, therefore, an SRO is
assigned *to coordinate this evolution.
Procedures are also utilized ..
Whenever there is fuel in the reactor, offsite power and emergency power*
are available to one emergency bus and offsite power or emergency power is
- available to the other emergency bus.
The vital bus distribution system
is designed such that the vital buses remain energized during battery or
. DC bus maintenance.
Also, the licensee declares an EDG in6perable when
its field flashing source is removed for maintenance.
The inspectors concluded that the licensee's controls to ensure that decay*
heat removal capability is maintained during CSD/RSD are adequate and will.
continue to monitor these controls throughout the Unit 1 outage.
The
Critical Parameter Assessment Matrix which was recently . implemented,
S ignifi Cantly enhanced the 1; Censee IS *ability to monitor the Status Of
plant parameters and systems important to safety during an outage.
During the current outage, the licensee reevaluated the need to drain the
.RCS to mid-loop level in order to drain the SG tubes and concluded that
draining to mi.d-loop was* not necessary.
The elimfoatfon of this *
previously routine mid-loop evolution was a another enhance~ent to outage
plant safety.
Within the areas inspected, no violations were identified.
12
7.
GL 88~17~ Loss of DecaY Heat Removal (TI 2515/103)
(Closed) 280,281/TI/2515/103
GL 88-17 discussed expeditious actions and
program enhancements that licensees should implement to increase plant
safety when operating a plant at reduced inventory or mid-loop conditions.
In letters to the NRC dated January 6, February 3, September 29, and
October 31, 1989, October 5, and November 16, 1990, and November 14, 1991, *
the licensee responded to GL 88-17 *. In a letter dated July 26, 1991, the
NRC informed the licensee that their responses met the intent of GL 88-17.
The inspectors reviewed the 1 i censee' s response _to v,eri fy that the
licensee had implemented actions and program enhancements as corrmitted.
!Rs 286,281/90-30 ~nd 39 and 91-10, 14, and 18 dis~ussed implementation of
GL-88-17 commitments.
The inspectors concluded that the h_ardwa*re
-procedure changes were performed as corrmitted but noted the following:
In the licensee's February 3, _1989, response, the licensee stated
that a hard piped reactor vessel level indication system was
installed and operable.
During the present Unit 1 outage the
inspectors walked this system down.
The portion of this system that
contains the standpipe assembly was hard piped.
However, the portion
of the sys*tem that. vents the reactor vessel head contained one inch.
diameter har_d pipe with approximately twenty .feet of tygon tubing
connecting the hard piping to the . top of the pressurizer.
The
inspectors concluded that if steam formed in the reactor vessel, then
the reactor vessel standpipe level indicati9n system would not
indicate properly because the tygon tubing would melti or the small.
diamete.r head vent piping would not pass sufficient flow _to provide
an adequate vent path.
The licensee does utilize ~n ultrasonic
reactor vessel level indication system that measures RCS cold leg
level which is in addition to the standpipe assembly.
This system
would indicate properly with steam in the reactor vessel. During the
- pre~ent Unit 1 RFO~ the ultrasohic re~ctor vessel level indication
system has not been operable due to spiking problems and theref6re
has not been used. Procedures only require that the ultrasonic. level
indication system be in service* when entering a reduced inventory
condition.
The GL requires that controls be established to assure that
containment closure can be achieved in the event that a 1 oss of
cooling occurs.
The GL also states that if RCS boiling occurs, a
potential exists for incfeased containment temperature and pressure .
. The licensee is in the process of evaluating the potential for
increased containment press~re in the event of a loss of RCS cooling.
Present procedures that establish containment closure* utilize
containment barriers that have not been evaluated for containment
~ressure requirements.
In. the October 31, 1989, res~onse to the GL, the.licensee stated that
the annunciator for high temperature at the RHR di~charge to RCS is
13
an aid in monitoring RHR system performance and identifying abnonnal
conditions.
The inspectors noted that this alann ocurrs at 340F.
The inspectors consider that with* the RCS system depressurized, an
alarm at 340F is too high for providing indication of*a loss of core
cooling *. The inspectors discussed this issue with the licensee, and
the .licensee was in-the process of revising procedures to lower this
alarm setpoint when the inspection period ended.
Within the areas inspected no violations we~e identified.*
8 *.
Safety Assessment and Quality ve*rification
During. the previous inspection period, the inspectors* monHored the
licensee's program for the review of generic industry issues and
experience.
This review was documented in IR 280,281/92~04 and indicated
that the appropriate level of corporate screening. of information was
occurring.
During this inspection period, the* inspectors reviewed the
process that the site uses to implement or evaluate the corporate
reco111T1endations for improvement.
The inspectors also.selected for review,
several items that had been forwarded to the station for implementation.
The site review process is controlled by procedure -VPAP 3002, Operating
Experience Review, dated 11-30-90.
Section 6.2.8 of this procedure
specifies the method that the station should use to handle industry
operating experience.
The procedure specifies that the SNS group is
responsible for the bnsite .implementation of the process and requires that
a station deviation be initiated if the-initial SNS review determines that
an item_ is directly applicable to _the station and may require immediate
corrective action.* In addition to receiving OE items from the corporate
process, the station al so directly routes industry experience for
infor~atfon to those departments th~t may be involved.
Although the extra
r~uting of information may be redundant to the process described iri IR
_ 280,281/92-04, personnel interviewed by the inspectors felt that it was a
safety net to the OE process. and provides more timely notification to
involved parties.
Within the areas inspected, no violations were identified.
9.
Ex_it Interview
_The inspection scope and results were summarized on, April 14, 1992, with
. those individuals identified by an asterisk in paragraph 1.
The following
summary of inspection activity was discussed by the inspectors during this
exit .
14
Item Number
NCV 280,281/92-07-01
Status
Closed
Description and Reference
Failure to Follow Procedure
When Testing No. 3"EDG (paragraph
3.b.).
VIO 280/92-07-02
Open
Failure to Establish Containment
Integrity in Accordance with TS 3.10.A.1 and Failure to Follow
Procedure in Accordance with TS 6.4.D {paragraph 3.c.).
VIO 280/92-07-03
Open
Failure to Prevent Foreign
Material From Entering Service
Water System (paragraph 5.a.).
TI 280,281/2515/113
Closed
Reliable Decay Heat Removal
During Outages (paragraph 6)~
TI 280,281/2515/103
Closed
GL 88-17, Lo~s of Decay Heat
Removal (paragraph 7).
10.
Index of Acronyms and Initialisms
CFR
CSD
-OHR
EOG
F
GL
IR
LCO
MS
MSTV
NCV.
NRC
RSD
CODE OF FEDERAL REGULATIONS
COLD SHUTDOWN
DIRECT CURRENT
DESIGN CHANGE PACKAGE
ENGINEERED SAFETY FEATURE
FAHRENHEIT
FOREIGN MATERIALS EXCLUSION
GENERIC LETTER
INSPECTION REPORT
LIMITING CONDITION FOR OPERATION
MAIN STEAM TRIP VALVE
NONCITED VIOLATION
NUCLEAR REGULATORY COMMISSION
OPERATING EXPERIENCE
REFUELING OUTAGE
REFUELING SHUTDOWN
RECIRCULATION SPRAY HEAT EXCHANGER
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
. SNS
- _
TI
TS
VCT*
VPAP-
WO _
15
STATION NUCLEAR SAFETY
- - -
SENIOR REACTOR OPERATOR
TEMPORARY INSTRUCTION
TECHNICAL SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
VOLUME CONTROL TANK
VIOLATION
VIRGINIA POWER ADMINISTRATIVE *PROCEDURES
WORK ORDER