ML18153C923
| ML18153C923 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 01/29/1992 |
| From: | Branch M, Frederickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153C921 | List: |
| References | |
| 50-280-91-37, 50-281-91-37, NUDOCS 9203090261 | |
| Download: ML18153C923 (14) | |
See also: IR 05000280/1991037
Text
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
-ATLANTA, GEORGIA 30323
50-280/91-37 and 50-281/91-37
Licensee:
Virginia Electric and Pow~r Compiny
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
through January 4, 1992
S. G. Tingen, Resident Insector
"
Approved by: ' f~ \\I l-v..v t "-1.,__
Scope:
P. E. Fredrickson, Section hief
Division of Reactor Projects
SUMMARY
)~'2.<g'-~'2_
Date Signed
l -L.~ -'1 '2.
Date Signed
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Date Signed
} ~ J-p\\ - "I L--'
Date Signed
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, design change review, and
action on previous inspection findings.
During the performance of this
inspection, the resident inspectors conducted review of the licensee's*
backshift or weekend operations on December 20, 24, 28, and 29, 1991, and
January 2, 1992.
Results:
In the engineering and technical support area, the licensee's failure to
request NRC relief to continue plant operations without repairing a leaking-
weld joint on the ASME Class 2 letdown line is identified as a violation
(paragraph 4.c).
In the operations functional area, Technical Specifications did not clearly
indicate operability requirements for the charging pump intermediate seal
9203090261 920203
ADOCK 05000280
G
2.
-coolers; however the inspectors concluded that the seal coolers were being
properly operated (paragraph 3.b).
In the operational functional area, the operators response to the January 2
runback and manua 1 reactor trip due to two dropped rods is cons i_dered a
strength.
However, the magnitude_ of the turbine run back cha 11 enged 'the
operators ability to maintain the unit at power during the transient (paragraph
3 .c).
-
The January 2 Unit 1 manual reactor trip, which occurred after 379 days of
continuous operation, * resulted from improper control of trouble shooting
activities and is considered a weakness (paragraph 3.c).
The cause or dropped rod [: .. 5 on Unit 1 was attributed to degradation of the CRD -
coil stack. This sam~ type of failure also resulted in a forced outage on Unit
2 in August, 1991 due to degradation of the CRD coil stack for rod D-4 and may
be indicative of.~quipment failures due to aging (paragraph 3.c).
In the surveillance area, the missed TS surveillance was determined to have
occurred prior to the implementation of corrective action violation 280/91-06-01
and therefore an additional violation is not appropriate (paragraph 6.a):
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
R. Allen, Supervisor, Shift Operations
- M. Bowling, Manager Nuclear Licensing and Programs
- W. Benthall, Supervisor, licensing
R. Bilyeu, Licensing Engineer*
D. Christian, Assi~tant Station Manager
- J. Downs, Superintendent of Outage and Planning
o.*Erickson, Superintendent of Health Physics
- R. Gwaltney, Superintendent of Maintenance
- L. Hartz, Quality Assurance, Corporate Manager
- M. Kansler, Station Manager
T. Kendzia, Supervisor; Safety Engineering
- J. McCarthy, Superintendent of Operations
- A. McNeil) Design Engineer
- J. O'Hanlon, VP Nuclear Operations
- A. Price, Assi,tant Station Manager
- R. Scanlan, Licensing
- E. Smith, Site Quality Assurance Manager
- T. Sowers~ Superintendent of Engineering
G. Thompson, Supervisor Maintenance Engineering
Other Personnel
- R. Etchyson, Visitor to Virginia Power
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
J. York, Resident Inspector
- Attended exit interview
Other licen*see 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 began the reporting period in power operation.
On January 2, day
379 of continuous operation, the unit experienced a turbine runback to
approximately 67 percent power when rod E-5 dropped into the core.
Later
2
in the same day, the unit was manually tripped from approximately 56%
power when rod H-2 {the second rod) dropped into the core.
This trip
is further discussed in paragraph 3.c.
At the end of the inspection
period, the unit was in coJd shut down in order to replace the coil stacks
on rod E-5.
Unit 2 began the reporting period in power operation.
On December 11, the
unit was shutdown in order to repair a reactor coolant leak on the RTD
bypass manifold flow element.
The RTD manifold flow element leak is
discussed further in paragraph 5.b.
On December 17, the unit was
restarted.
Later in the day, the unit experienced an automatic reactor trip from approximately 25% power which is discussed in paragraph 3.a.
The unit was restarted -on December 18, and was at 100% power on
December 19.
The unit was at power at the end of the inspection period,
day 17 of continuous operation.
3.
Operational Safety Verification (71707, 42700, 64704)
The- inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiven~ss and adherence to approved
procedures.
The inspectors attende*d pl ant status meetings and reviewed
operator logs on a daily basis to verify operations safety and compliance
with TS and to maintain awareness of the overa 11 operation of the
facility.
Iristrumentation and ECCS lineups were periodically reviewed
from control room indication to assess operability.
Frequent plant tours
were concjucted 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 reporteq.
a.
Licensee 10 CFR 50.72 Reports
On December 10, at 4:22 a~m., the licensee reported to the NRC that
ERFCS had became ;~operable at 3:00 a.m.
The purpose of the ERFCS is
to provide plant monitoring and data acquisition in order to aid .in
the evaluation of the reactor plant's safety status during emerg~ncy
conditions. Jhe ERFCS was reforned to service at 7:30 a.m.
On December 18, at 2:35 a.m., the licensee reported to -the NRC that
at 10:45 p.m. on December 17, Unit 2 experienced an automatic reactor trip from approximately 25% power.
During a reactor startup, SG
levels were being controlled manually.
After 6perato~s transferred
SG level control to automatic, the B MFRV began to oscillate
excessively.
The B SG level control was returned to manual; however,
level in the B SG reached the high level turbine trip*setpoint. This
resulted in a automatic turbine trip followed by an automatic reactor
- -
3
trip.
The main feed pump tripped and both motor driven AFW pumps
auto started as required~
Also, all rods inserted and SG blowdowri
isolated *as required.
No primary or secondary relief valves lifted
after the reactor trip. Troubleshooting and repair of the B MFRV is
discussed in paragraph 4.d. *
On January 2, at 8:30 p.m., the 1 icensee reported to the NRC that
Unit 1 had experienced a manual reactor trip from 56% power at.4:49
p.m. - The reactor trip is discussed in paragr~ph 3.c.
b.
Operation of Charging Pump Intennediate Seal Coolers
During the previous inspection period, a leak developed in the Unit 2
charging pump intermediate seal. cool er, 2-SW-E-lA.
The .1 eak did not
render the seal cooler inoperable; however, it was an operational
inconvenience because SW was leaking into the CC system.
To prevent
the CC expansion tank from overflowing, operators were routinely
having to drain the CC expansion tank.
The seal cooler was then
isolated by shutting the manual SW and CC valves on the inlet and
outlet lines.
The redundant intennediate seal cooler 2-SW-E-lB was
aligned for operation.
The inspectors questioned the operability of
the isolated intermediate seal cooler and were infonned that the seal
tooler was considered operable becaus~ operators could valve the seal
cooler in if required. Also, the.inspectors were infonned that it is
a nonnal con.figuration to operate with one intermediate seal cooler *
operating and SW secured to the other redundant intennediate. seal
cooler and that operator manual action has always b~en fequired to place
the alternate redundant intermediate seal cooler in service.
The
inspectors were infonned that during design base LOCA containment
sump recirculation mode of operation, radiation levels in the area of
the intennediate seal coolers would prohibit operators from entering
.
the area.
TS 3.3.A.7.c requires that two charging pump intermediate seal
coolers be operable when a unit is critical.
TS 3.13.B.3 requires
that one charging pump intermediate seal cool~r be operating and the
spare charging *pump intermediate seal cooler be operable when reactor
coolant exceeds a temperature of 3_50F and a pressure of 450 psig.
TSs J.3.B.7 and 3.13.B.4.b state that one charging pump intermediate
seal cooler or other passive component may be but of service provided
the system may still operate at 100% capacity and repairs are
completed within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Section 9.4.3.4 of the FSAR st~tes that
two full-capacity charging pump intermediate seal coolers are
installed in eich unit to provide 100% redundancy for the charging
pump cooling water system.
This section of the FSAR does not
describe operation of the system with SW or CC iso*lated to the
intennediate seal coolers; however, the FSAR system diagram doesshow
the inlet valve to one of the s~al coolers as shut.
.
c.
4
The inspectors requested NRC staff assistance. in detennining
operability of a charging pump* intermediate seal cooler when SW
and/or CC was secured.
The staff concluded that TSs and FSAR did not
- clearly specify how the system was required to operate and should be
changed to reflect what is actually required. Also, the staff review
of the system design requirements indicated that only one inter-
m~diate seal cooler per unit is required and that the iecond seal
cooler in each unit was the equivalent of a spare *.
During this inspection period, the licensee replaced the Unit 2
charging pump* intermediate seal cooler with the tube leak, and
changed the method of operation of the seal coolers by aligning SW to
both seal coolers in each unit.
At the end of the inspection
period, the seal coolers were operating with SW and CC flowing
through the coolers.
The licensee has initiated a study to evaluate
the need for the charg,ng pump intermediate seal coolers.
Past
operating experience indicates that operation without these coolers
does not adversely effect charging pump performance.
Unit 1 Reactor Runback and Manual Trip
At 7:54 a.m. on January 2, rod E-5 dropped into the core resulting in
a turbi_ne runback from 820 MWe to 335 MWe.
This was approximately~
60 percent turbine runback.
Reactor power decreased from iOO percent
to approximately 67 percent.
Operators considered that the magnitude
of this runback was excessive.
The licensee was investi~ating the
cause of the excessive turbine run back.
The inspectors cone l uded
that the magnitude of the turbine runback challenged the operators
ability to maintain the unit at power during the transient.
At 4: 49 p_.m. on January 2, Surry Unit 1 .was manually tripped from 56
. percent power when rod H-2 dropped during attempted rod motion.
Earlier on the same day rod E-5 had also dropped and was still on the.
bottom of the core when the sec_ond rod dropped.
With two dropped
rods, abnormal operating procedure O-AP-1.00 requires tht reactor to
be manually tripped.
During the transient the AMSAC system actuated
on low SG levels, and it tripped the rod drive MG set breakers.
.
Several equipment problems occurred, they included; 1) erratic IR NIS
indication on both channels,. 2) SG PORV~ did not respond to demand,
and 3) several indication and control related problems associated
with the turbine EHC and valve position system occurred. *
The licensee's trouble shooting determined that it would be necessary
to go to cold shutdown to replace the CRD coil *stack for dropped rod
E75.
This same type of failure also resulted in a forced outage on
Unit 2 in August, 1991, due to degradation of the CRD coil stack for
rod D-4.
During the Unit 1 1990 fa 11 refue 1 i ng outage, the CRD
stationary coil on rod K-10 was also identified as degraded and was
replaced.
The licensee has requested Westinghouse to perform failure
analyses for rods D-4 and E-5 degraded coil stacks in order to
determine if these equipment failures w'ere due to aging *. * The cause
5
of dropped rod H-2 was attributed to the removal of a CRD movable.
coil fuse during the troubleshooting* of rod E-5 and this fuse was
common to the movable coils associated with both of the rods
involved.
When rod motion was attempted on rod H-2 for delta-flux
control, the H-2 rod dropped when its stationary coil was deenergized
with the movable coil not bei.ng energized because of the *removed
fuse.
The pre-planned troubleshooting package did not recognize that
the fuse being pulled to isolate rod E-5 also effected rod H-2 as
well.
Because of this failure to recognize the tie betweE!n the two
rods, operational restrictions on rod motion were not implemented and
~~sulted. in dropping of the second rod and placing the plant in an
unanalyzed condition. The relationship of the fuse to other rods was
not intuitively obvious and this may have contributed to the *
confusion on the pait of the parties involved with planning of the
troubleshooting activities.
However, the resulting transient*
challenged the operating crew and resulted in the plant being in an
unanalyzed condition not protected by automatic equipment actuation.
The troubleshooting activities associated with this activity is
considered a weakness.
The licensee is currently in~estigating the eq~ipment problems noted
above and will correct them as well as accompl.ish other repairs prior
to returning the unit to power.
The inspectors are following the
licensee corrective actions and will review the post trip report
prior to the unit returning to power.
Operator performance during the Unit 1 reactor runback and trip and
the Unit 2 reactor shutdown, startup and trip was good.
Although
operators were frequently challenged, they continued to safely
operate the plant without making any significant errors.
When
operator errors do occur, the cause of the errors are aggressively
pursued and corrected.
For example, on November 20, 1991, a valve
sequencing error occurred when an opera tor returned a turbine
building instrument air tank to service following maintenance.
This
event was thoroughly investigated by the 1 icensee and was attributed
to an inadequate prejob brief. -As a result, the operations
department strengthened prejob briefs.
~ithin the areas inspected, no violations were identified.
4.
Maintenance Inspections (62703, 42700, 71500)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the .appropriate procedures~
The following maintenance activities were reviewed.
a.
Visual Inspection of CW Expansion Joints
During the NRC .exit meeting on November 21, 1991, the 1 icensee
corrrnitted in part to visually inspecting the condenser outlet
6
waterbox rubber EJs. * An engineering work request (EWR No.91-139)
was written to cover this work.
TMs *EwR stated that soft and spongy
areas, thin or exposed areas, cracking, leaking, and-bulging areas
needed to be reported and evaluated.
During a previous inspection period, the inspectors observed the
visual examination of the B waterbox outlet EJ for Unit 1. There was
some bulging; concavity, sponginess, and 1i near separations foun_d
during the internal visual examination.
Examination of the outer
surfaces of the EJ revealed spongy areas, several thinned areas, an
area where the outer ply was separated (almost one quadrant in .
lerigth) and exposing two metal reenforcing rings.
On~ ~f the rings
had rusted approximately halfway through the -diameter.
-
As a result of this inspection on Unit 1, the licensee decided to
inspect the same B waferbox on Unit 2.
Visual inspection of the
inside of this joint revealed only three* tears that exposed the
fabric.
The external inspection revealed a number of soft spots but
only one area approximately five inches long where the metal
reenforcing ring was exposed.
As a result of these inspections and
discussions with the vendor, the licensee concluded that significant
degradation to these EJs had occurred.
A justification for continued
operation (no. C-91-0006 dated November 29, 1991) was completed by
the licensee *and reviewed by the inspectors.
The licensee decided to inspect the remaining six EJs (three for each
unit) and has modified the bottom periphery of the existing EJ
shields.
This modification was designed to reduce the flow from
approximately 13,000 gpm to approximately 3,000 gpm or less from a
ruptured expansion joint. The inspectors followed the inspections of
the remaining expansion joints and noted that there were varying
degrees of degraded conditions similar to those found on the first
two EJ inspected.
The most degraded condition was found on the first
joint inspected, 1 B.
The 2 A EJ was in the best condition with just
a shallow linear area.
Documentation showed that this joint was
replaced in 1981.
The inspectors reviewed the licensee modificatioh to the EJ shields
and verified that the modification was completed on all eight joints
{4 per unit).
The inspectors did note that the rubber seal used in
the modification ~as torn in several areas on most of the installa-
tions.
The licensee indicated that the rubber seal was not rel,ied
upon in their calculation for the amount *Of water that would pass
through the opening.
The licerisee
1s flow calculation was based on an
opening of 1/8 inch around the circumference of the expansion joint~
The inspectors consider that the iicensee improvements in this area
should reduce the amount of flow below the original value considered
in the initial !PE assumptions and the flow from a failed EJ should
be limited to the capacity of the TB sump pumps.
7
b.
Repair of Leak on a Unit 2 RTD Manifold Flow Element
The licensee made a Unit 2 containment entry on December 3, 1991, in
order to 1 oca te the source of a gradua 11 y increasing 1 ea k.
Additional entries and insulation removal identified the leak to be
on flow element 2-RC-FE-2492.
A threaded plug used to close one of
the unused openings on the flange was leaking.
A Code case, N-3,
cla.rifying the Code of record for Surry B 31.1-1955, stated that
screwed connections in which threads provide the only seal shall not**
be penni tted in nuclear piping sys terns.
Therefore this threaded
connection did not meet the requirement of the original construction
Code.
The licensee di_d not immediately recognize t,he need to submit*
a ~equest for. relief from the ASME Code Requirements of Section XI,
1980 Edition, Winter 1980 Addendum.
However, after discussions with
the NRC staff, the licensee submitted a request for relief and cited
the requirements of 10 CFR 50.55a(g)(6)(i) which in part states, that
the Commission will evaluate determinations of impracticality, and
may
grant reli~f and may
impose alternate req~irements.
Additionally, the residents referenced the.licensee to the guidance
in Generic.Letters 90-05 and 91-18
which discusses situations of
this nature .
c.
Repair of Leak on Unit 1 Letdown Line
On December 13 the licensee noted a step change in the unidentified
RCS leakage on Unit 1.
The PT-10 , rea~tor coolant leakage, (TITLE)
. test results indicated that leakage had increased from approximately
0.2 gpm to approximately 0.37 gpm.
This value was still well below
the TS limits of 1.0 gpm unidentified leakage.
In accordance with
the requirements of PT-10 the licensee increased the leakage
monitoring activity and attempted to locate the source of the
leakage.
The 1 icensee made several containment entries and noted
leakage at a welded joint on the eves letdown line.
The licensee.
made plans to isolate, drain, and repair weld the joint in accordance
with station procedures.
During the attempts to isolate and drain the line for weld repairs
the licensee noted that the isolation valves were leakihg past their
seats.
The amount of leakage that was being funneled with a
partially opened drain valve was above the TS limit of 1 gpm and the
licens*ee entered the TS LCO action.
The licensee exited the LCO
action after the dr~in valve was reclosed and the RCS leakage was
verified as being within the TS l.imits.
During the period of time
that letdown was isolated the excess letdown system was being used.
The 1 i censee did not want to utilize* the excess 1 et down system for an
extend~d period since there was RCS to CC system leakage in the heat
exchanger and this leakage was causing the CC system activity to
increase.
On December 20 the 1 icensee returned the Unit 1 letdown
system to service without repairing the leak on* the welded ASME class
2 piping system.
This leak did not meet the Code* requirements in
IWA-5250 of Section XI of the ASME Code, and the licensee did not
d.
8
submit a request for relief from Section XI as required by 10 CFR
50.55a(g)(6)(i).
No engineering evaluation was perfonned to
determine the extent of the defect. _ Further guidance for obtaining
relief i's provided in Generic *Letter 90-05.
This is identified as
the Violation 280/91-37,.0l, Failure to Follow the Requirements of
10 CFR 50.SSa(g).
-
On December 24, the licensee isolated the 'effected line using a
manual valve in ~ddition to the isolation v~lve which had excessive
seat leakage during the first attempt.
The licensee completed the
weld repairs on Dec~mber 26, and the system was returned to service
on December 27.
The licensee did not agree with the inspectors findings as noted in
the violation above.
The licensee's stated position was that the RCS
leakage* TS apply to situations of identified leakage found during
plant operations.
The inspectors referred the licensee to GL 91-18
which provides
NRC guidance on requirements associated with
operability and ensuring the* functional capability of a *system or
component.
Section 6.15 of the guidance, titled Operational Leakage*
speciftes the NRC's position on leakage identified during operations
as well as during ISI inspections.
The NRC's 'guidance specifies that
upon discovery of leakage from Class 1, 2 or 3 component pressure
boundary, the licensee should declare the component inoperable.
Additionally, the guidance further indicates that section IWA-5250 of
ASME section XI would not allow acceptance of a through wall leak and
other sectfons- of the guidance requires the licensee to request NRC
approval for relief_ from code requ-irements.
The licensee position
was discussed with NRC management, as required by the GL guidance,
and it WQS detennined that the licensee was requireed to obtain NRC
relief in order to operate with through-wall defects in ASME Code
Class 2 piping.
Troubleshooting Feedwater Control_Valve 2-FW-FCV-2488
On December 17, Unit 2 was starting back up to power after an outage
to repair RTD bypass instrument leak discussed in Paragraph 4~b.,
when the B feedwater regulating valve started oscillating open and
closed.
This resulted in -a rise in the level in the B steam
generator, a turbine trip, and a reactor trip;
The inspectors observed the troubleshooting on this valve using work
order no. 38000121938 and procedure 2-PT-2.34, Functional Testing of
Main Feedwater Regulating and Bypass Valves, dated July 29, 1989.
The licensee replaced the valve positioner and ran several regulatof
pressure versus valve movement curves for all three valves., These
curves are still undergoing analysis by the maintenance engineering
group.
In addition, the inspectors observed the replacement of the
packing for this va 1 ve using the same work order and procedure
0-MCM-0412-05,
Chesteron R~pack Without Lantern Rings, dated
October 10, 1991.
No deficiencies were noted.
9
Within the areas inspected, one violation was identified (Paragraph 4.c).
5.
Design Change Review
During several of the Unit 1 outage planning meetings the licensee has
indicated that the RTD bypass manifolds will be removed during the
upcoming February, 1992 Unit 1 refueling outage.
The licensee's proposed
modification is needed since the bypass manifolds have historically been
contributors to personnel exposure and have resu 1 ted in severa 1 forced
plant shutdowns and mode changes due to system leakage.
The licensee's
proposed design change 91-05-1, describes the modifications of the piping
as well as the electrical systems that are necessary_to process the signal
from the new RTDs which are being installed directly in the thermowells
mounted in the hot and cold legs of the RCS.
elimination per design change 91-05-1 identified several concerns.
The
concerns i.nvol ved changes in the equipment time response character, sti cs
as well as the acceptability of perfonning this modification under the 10
CFR 50.59 umbrella without prior NRC approval. * The licensee's proposed
modification contained a statement that the response time. used by
Westinghouse in the Surry accident analysis for OT and OP delta-T trips is
six seconds.
The proposed modification also states that the response time
for the new narrow range RCS temperatu~e measurement system will be held
to this 1 imi t.
Since the Surry TS was silent on equipment time response, the* inspector
reviewed FSAR chapter 14 accident analysis to detennine if a time response
for OT and OP delta-T was specified.
FSAR Section 14.2.2 accident
analysis for uncontrolled control-rod assembly withdrawal at power
specified a method of analysis (section 14.2.2.1) which insured that DNBR
was not exceeded during -the accident.
The method of analysis specified
several assumptions and initial conditions that -were made as part of the
analysis. Section 14.2.2.1.3 contains the following statement:
"The reactor trip on high nuclear power is assumed to actuate ~ta
conservative value of 118% of nominal full power.
The delta T trips
include all adverse instrumentation and setpoint errors.
The delay
for trip signal actuation are assumed at their maximum values, that
is, 0.5 sec for the high nuclear power trip and 3.5 sec for the delta
- Ttrip."
This time response of 3.5 seconds appears to be the value that was assumed
and reviewed as part of the licensing basis for Surry.
To install a
modification that increases this time response to 6 seconds appears to be
a reduction in the margin assumed as the basis for technical specifica-
tions.
Therefore, the modification should be considered an unreviewed
safety question per the requirements* of io CFR 50. 59.
The Surry TS does
not specify system time response and therefore the other provisions .of
lOCFRS0.59 regarding TS changes also was considered by the licensee not to
, apply.
10
The inspecto~s discussed their concerns with.the licensee's nuclear fuel
and analysis engineering group who were perfonning the 10CFR50.59 analysis
for the proposed modification. The NFA representative indicated that they
were perfonning the 50.59 using the guidance of NSAC-125, Guidelines for
10 CFR 50.59 Safety Evaluations.
The NFA representative also indicated
that although the FSAR original safety analysis indicated-a time response
time of 3.5 seconds, the licensee had submitted several reanalyses to the
NRC to support other license amendments and had used a 6 second time
response although the change in time response had not been highlighted.
The licensee indicated that changing the time response of the OT and OP
delta-T trips was not considered a reduction in.margin per 10 CFR 50.59
and therefore the ~edification was not considered an unreviewed safety
- question and did not require Cof111!1ission approval.
The licensee interprets NSAC~125 as allowing the flexibility of changing
assumptions used in ace i dent analysis as long as the parameter (i.e. DNBR)
is not' exceeded.
This could include setpoints and time response
assumptions that have not been incorporated into a specific TS limit.
This interpretation of reduction_ of margin is different from what has been
previously allowed by the NRC and may not b*e acceptable.
The inspectors have discussed the above issue with the NRC staff. The NRC
staff's review of the proposed Surry modifications conclucled that since
the six seconds c~trently assumed by the licensee's analysis is unchanged
by the modification, a reduction in margin has not oc~urred.
The NRC is
currently modifying their guidance in the area of 10 CFR 50.59 and this
new guidance will address the applications of NSAC-125 as well.
Within the area~ inspected, no violations were identified.
6.
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.
Perodic Test 1-PT-17.1
Station deviation report S-91-1816 reported that during a QA audit of
the ISI program it was identified that l-PT-17.1, Containment Spray
System, missed its 92 days plus 25*percent performance window by 20
days when it was performed on May 14, 1991.
This constitutes a
missed surveillance per the litensee's TS 4.0 since the allowable
grace period between survei 11 ances was exceeded.
The licensee
identified that the PT had been performed on January 1, 1991, and
then was performed ~gain on May 14, 1991.
The frequency of the PT
was changed from monthly to quarterly by PAR 91-118 on January 24,
1991 and an administrative error was made concerning recording the
last time.the PT was performed.
This example of missed surveillance
11
.
,
was similar to two other examples that were sited by Violation no.
280/91-06-01 that was issued after this January, 1991 date.
The
- corrective action program for that violation was implemented on*
June 1, 1991.
Since the missed PT, l-PT-17.1, occurred before the
corrective action program was implemented, an additional .violation
will not be issued.
Within the areas inspected, no violations were identified.
7.
Action on Previous Inspection Findings (92701, 92702)
(Closed) TI 280,281/2500-20, ATWS Mitigation System.
In report no. 90-41,
the inspectors discussed inspection of the newly installed ATWS mitigation
system for Unit 1.
At the end of that inspection the inspectors noted
that after the system was installed and placed in* service several
annunciators for this system were activated.
Subsequence followup
revealed a problem with a defective program logic card.
This problem was*
corrected and the system was returned to service.
The inspectors also
followed the installation of the Unit 2 ATWS mitigation system.
Followup
by the inspectors, including discussions this inspection period with the
sys tern engineer, rev ea 1 no apparent pr.ob l ems with the ins ta 11 ed sys terns
for both units and this TI is considered closed.
Within the areas inspected, no_ vioilations were identified.
8.
Exit Interview
The inspection scope and results were surrmarized on January 8, 1992, with
those individuals identified by an asterisk in paragraph 1.
The following
surrmary of inspection activity was discussed by the inspectors during this
exit.
Item Number
VIO 280/91-37-01
TI 280,281/2500/20
ATWS MITIGATION
SYSTEM
Status
OPEN
CLOSED
Description and Reference
Failure to meet requirements of
Section XI of ASME Code and seek
relief UNDER 10 cfr 50.55{g)(6)(i).
Followup inspections concerning
ATWS Mitigation System
The licensee acknowledged the inspection conclusions.
However, the
licensee indicated that they did not agree with the NRC
1 s interpretation
of the need for ASME code relief to operate with pressure barrier leakage
that would be allowed by their TS.
The licensee's corporate licensing
manager indicated that the utility considered that the NRC's position
represented a Backfit.
Details of the licensee's position on this issue
are discussed in paragraph 4.c.
12
9.
Index of Acronyms and Initial isms
ATWS MITIGATION SYSTEM ACTUATION CIRCUIT
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
ANTIC I PATED TRANS IT WITHOUT SCRAM
COMPONENT COOLING
CFR
CODE OF FEDERAL REGULATIONS
CONTROL ROD DRIVE
eves
CHEMICAL AND VOLUME CONTROL SYSTEM
CIRCULATING WATER
DEPARTURE NUCLEAR BOILING RATIO
EJ
EXPANSION JOINT
ERFCS
EMERGENCY RESPONSE FACILITY COMPUTER SYSTEM
ENGINEERING WORK REQUEST
FINAL SAFETY ANALYSIS REPORT
GL
GENERIC LETTER
GPM
GALLONS PER MINUTE
IR
INTERMEDIATE RANGE
!PE
INDEPENDENT PLANT EVALUATION
INSERVICE INSPECTION
LCO
LIMITING CONDITION OF OPERATION
LOSS OF COOLANT ACCIDENT
MAIN FEEDWATER REGULATING VALVE
MOTOR GENERATOR
MWe
MEGAWATI ELECTRIC
NFA
NUCLEAR FUEL AND ANALYSIS
NIS
NUCLEAR INSTRUMENTATION SYSTEM
NON-CITED VIOLATION
NRC
NUCLEAR REGULATORY COMMISSION
OP
OVER PRESSURE
OVER TEMPERATURE
PROCEDURE ADMINISTRATIVE REVISION
POWER OPERATED RELIEF VALVE
PERIODIC TEST
RESISTANCE TEMPERATURE DETECTOR
T
TEMPERATURE
TURBINE BUILDING
TI
TEMPORARY INSTRUCTION
TS
TECHNICAL SPECIFICATIONS