ML18153C700
| ML18153C700 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/31/1991 |
| From: | Branch M, Fredrickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153C698 | List: |
| References | |
| 50-280-91-18, 50-281-91-18, NUDOCS 9108160225 | |
| Download: ML18153C700 (17) | |
See also: IR 05000280/1991018
Text
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/91-18 and 50-281/91-18
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: June 9 - July 6, 1991
Inspectors: ~
z3'v:
M. ~'
Senior Resident Inspector
~"fat:
J. W. Yokesident Inspector
c::? h ~
&=*
S. G. Ting~dent Inspector
Accompanying
Inspector
~e,l: r H~;iand, Se:for Resident
Approved by:__,,,.\\ ,,-=-----=-j---=~~-.--,,....-.,..."*_*, "L-_---7_*>,.._~--,,,,...,.-,-=--*..,,,"-.,...~.,...--..,..------
, P. E. Fredrickson, Section Chief<::......:
Division of Reactor Projects
SUMMARY
Scope:
{.~
- 7/~/9/
Da1:egned
~//?,I
D eSi7gned
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, and plant procedures. During
the performance of this inspection, the resident inspectors conducted review of
the licensee's backshift or weekend operations on June 9, 16, and 23, and
July 3 and 6, 1991.
Results:
In the operations area, a violation with three examples was identified for a
failure to follow or provide adequate procedures associated with reactor
coolant system filling procedure, 2-0P-5.1.1, dated May 10, 1991, and reactor
coolant system venting procedure, 2-0P-5.1.2, dated May 10, 1991 (paragraph
3. C).
In the engineering/technical support area, a non-cited violation was identified
associated with the failure to implement design output assumptions regarding
calibration requirements for instrumentation (paragraph 5.b).
2
In the_ safety assessment/quality verification function_al area, a weakness was
identified regarding the failure to q>n"trol a condition of the orig_inal safety
evaluation associated with coritrol rod guide tube insert flexures inspection
and correction.
This resulted in the operation of Unit 2 for two cycles with
possible loose parts and degraded core components (paragraph 3.a}.
In the security functional area, a weakness was identified associated with the
operability* of some of the security equipment arid its possible impact on
operations (paragraph 3.d).
In the operations functional area, a str~ngth was identified regarding the
procedural controls associated with reactor coolant system reduced inventory
operations.
During a previous inspection (50-280,281/91-14), the inspectors
had jdenti_fied that numerous procedures were necessary to perform the reduced
inventory evolution.
Prior to entering. reduced inventory during this report
period, the licensee consolidated procedures and established a periodic check-
list to be used to evaluate reduced inventory operations (paragraph 3.f).
1.
Persons Contacted
Licensee Employees
REPORT'DETAILS
R. Allen, Supervisor, Shift Operations
W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
.
. D .. Christi.a*n, Ass.istant Station Manager
.
J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Health Physics
R. Gwaltney, Superintendent of Maintenance
M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
- C. Luffman, Superintendent of Security
- G. Marshall, Operations Maintenance Coordinator
J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
- H. Royal, Supervisor, Nuclear Training
- E. Smith, Site Quality Assurance Manager
T. Sowers, Superintendent of Engineering
- G. Thompson, Supervisor, Maintenance Engineering
- NRC Personnel
- M. Branch, Senior Resident Inspe~tor
- 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 listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period in power operation. * The unit operated
- at or about 100% power for the duration of the inspection period.* The
tu~bine control system cont~nued to be operated in manual due to problems
associated with the turbine main speed controls.
Unit 2 began the reporting period with startup physics testing in progress
and at approximately 30 percent power.
On June 11, 1991 the unit was
shutdown for repairs, due to* an unlatched control rod.
The licensee's
investigation and control rod repairs are discussed in section 3.a of this
report .. The unit returned to power on Ju~y 4 ..
2
3.. Operational Safety Verification (71707 & 42700) .
a.
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, TS, and LCOs; examination of panels
containing instrumentation and other reactor protection system
elements to determine that required channels were operable; and
review of* control room operator logs, operating orders, plant
deviation reports, tagout logs, temporary modification logs, and tags
on components to verify compliance with approved procedures.
The
inspectors also routinely accompanied station management on plant
tours and observed the effectiveness of their influence on activities
being performed by plant personnel.
On June 8, the licensee notified the NRC residents that analysis of
the Unit 2~ cycle 11 flux map taken at approximately 32 percent power
inditated that the RCCA in core location F6 was fully inserted rather
than withdrawn to its _demand position .of 166 steps. The subject RCCA
is an interior D control bank control rod.
The flux map analysis
determined that the ~verage incore quadrant tilt was ll percent.
In
addition, the flux map indicated that the core peaking factors were
well within the TS limits.
Further analysis and testing resulted in
the conclusion that the RCCA in core location F6 was fully inserted
and unlatched from its driveshaft. . The control rod was declared
inoperable on June 8, and the unit operated at approximately 30
percent power under the requirements of TS 3.12 until the licensee
started ramping the unit down at 2305 hours0.0267 days <br />0.64 hours <br />0.00381 weeks <br />8.770525e-4 months <br /> on June 10.
The inspectors reviewed the safety evaluation* used to assess the
operation of Unit 2 with the control rod unlatched from its
driveshaft and for .support of a procedure change to insert the RCCA
driveshaft in core locatio"n F6 to a demand position of 80 steps
withdrawn.
The demand position of the D bank rods was approximately
170 steps .. The consequence of insertion of the driveshaft by normal
control rod insertion or by tripping the rod were considered in order
to determine what position the subject RCCA driveshaft should be left
at during interim power operation. Westinghouse. recorrnnended that the
driveshaft be inserted from its required bank position of 170 steps
to 80 steps withdrawn.
The basis -for this recommendation was that
significant cross flows are encountered in the control rod guide tube
below the BO-steps-withdrawn location.
The cross flows could cause.
lateral movement and vibration of the unlatched driveshaft and could
result in damage to the control rod guide tube, the driveshaft-or the
RCCA hub~
The basis for lowering the driveshaft to*80 steps, rather
than remaining at 170 steps was to limit the height of the drop in
the event of a reactor trip,- thereby limiting the force which could
be applied to the RCCA hub and fuel assembly.
3
After the unit was placed in cold shutdown and the reactor vessel
head was removed, the F6 drive rod was removed from the guide tube on
June 17.
The compo*nents of the guide tube were examined with a
remote camera for possible damage.
This examination revealed damage
on the si~th guide card from the top in the guide tube.
The damaged
guide card was evaluated as acceptable and should not impe~e the
movement of the F6 control rod after it was relatched.
To remove the F6 drive rod from the guide tube, the guide tube insert
must be removed from the top of the guide tube.
The insert is held
in pl ace by four fl exures.
During the remova 1 of F6 guide tube
insert, one of the fl~xures was broken off and another was bent.
Remote camera examination of this area on the guide tubes for the
other 47 control rod locations revealed bent or broken flexures on 11
control rod locations.
The worst case location had three broken
flexures.
All of the broken parts were recovered.
The inspectors reviewed the licensee's investigation of the damaged
control rod guide tube insert flexures.
Unit* 1 had exhibited a
similar problem durin~ an upper internals inspection in October 1984.
The licensee replaced the Unit 1 flexures with an improved design and
Westinghouse performed a safety -evaluation for the continued
operation of Unit 2 with possible failed control rod guide tube
flexures.
This evaluation* concluded that even with a 100 percent
failure of the guide tube fl exures * and_ the loose parts they might
generate, Unit 2 could continue operation without creating the
possibility of a new accident or increasing the probability or
consequence of a previously evaluated accident.
In a letter dated June 25, 1991; Westinghouse stated that they had
reviewed the 1985 safety analysis and that it was still valid to
,support Unit 2 startup without replacing the recently identified
failed flexures.
During a conference call on Jun~ 27, 1991, bet~een
the licensee, Westinghouse, and the NRC, discusstons were held con-
cerning the defective flexures and Westinghouse's safety analyses. A
consensus was reached that operating the unit without repairing or
replacing the guide tube insert flexures was acceptable.
However,
the NRC requested additional information from Westinghouse for a
generic applicability review.
The inspectors * noted that the 1985 safety evaluation performed by
Westinghouse to support Unit 2 operation restricted the analysis to
the end of cycle 8 .. * At that time it was expected that an inspection
of the Unit 2 condition would have occurred and the flexures would
have been reevaluated or replaced.
At the time of discovery of the
recent failures, Unit 2 was starting up from cycle 11 refueling and
the inspections or replacements had not occurred.
The licensee was
unable to explain how the internal commitment to inspect Unit 2
during cycle 7 or 8 outage was missed.
The failure of the licensee
to control a condition of the original safety evaluation resulted in
4
operation of Unit 2 for two cycles with .possible loose parts or
degraded core components and is considered.a weakness.
The inspectors reviewed the licensee's 10 CFR 50.59 analysis as*well
as the core inspection results.
With exception of the weakness
discussed above no additional problems were identified.
b.
Weekly Inspections
c.
The inspectors conducted weekly inspections in the following areas;
operability verification of selected ESF systems by valve alignment,
breaker positions, condition Of equipment or component, and
operability of instrumentation and support items essential to system
actuation or performance. - Plant tours were conducted which included
observation of general plant/equipment conditions, fire protection
and preventative measures, control of activities in progress,
radiation protection controls, physical security controls, missile
hazards, and plant housekeeping conditions/cleaniness.
The
insp~ctors routinely noted the temperature of the AFW pump discharge
piping to ensure increases in temperature were being properly
monitored and evaluted by the licensee *
Biweekly Inspections
The inspectors conducted biweekly inspections in the following areas;
verification review and walkdown of safety-related tagouts in effect;
review of sampling program (e.g., primary and secondary coolant
samples, boric acid tank samples, plant liquid and gaseous samples);
observation of control room shift turnover; review of implemenation
of the plant problem identification system; verification of selected
portions of containment isolation lineups; and-verification that
notices to workers are posted as-required by 10 CFR 19.
During review of control room logs for June 15, the inspectors noted
that operations personnel had found the reactor head vent valve
2-RC-36 closed.
This valve was required to be open to ensure
accurate RCS standpipe level indication whenever RCS level was below
the range of the pressurizer level instrument.
The licensee
documented the configuration problem on DR S-91-0941.
The initial
investigation indicated that the valve had been closed by a -
contractor personnel working on the reactor vessel head.
The
licensee indicated that the person involved was interviewed. and
counseled.
Additionally, the licensee indicated that other valves in
the area were checked and no Other out-of-position valves were found.
The inspectors monitored the RCS fill and vent on June ~8 and July 1 .
. The inspectors monitored procedure use and operator performance
- during these evolutions.
The
procedures monitored and the
inspectors comments are as follows:
5
(1)
2-0P-5.1.1, Filling The Reactor Coolant_ System, dated May 10,
1991..
This procedure was recently rewritten to the new format and
incorporated several industry recoll'D"llendations for criticality.
control associated with dilution.
The procedure had been
verified and validated by operations personnel as required by
the procedure development process.
During performance of the procedure on June 28, the inspectors.
noted that the CRO. was not marking the.SR flox charts at the 15
and 30 minute intervals as required .by step* 5.11.3 of the
procedure.
The audible SR indication was working at the tim~ of
the :fill.
The inspector questioned the SS as to why this was
not being performed and the SS indicated that they had not
realized that the new procedure required that action.
The SS
indicated _that*the control room had received the procedures just
prior to performance and were not familiar with the changes.
Technical Specifications 6.4.A and 6.4.D requires, in part, that
detailed written procedures with appropriate check-off lists. and
instructions be provided and that these procedur~s be followed.
Procedure 2-0P-5.1.1 was .not followed during loop filling, in
that step 5.11.3, associated with marking SR indication every 15
and 30 minutes was not being performed.
Failure to follow
procedure 2-0P-5.1.1 is identified as the first example of a
violation,
50-280,281/91-18-0l,
Operational
Procedure
Adherence/Adequacy, with Three Examples.
A det~iled review of procedure 2-0P-5.1.1 indicated an
additional
problem associated with
procedure
quality.
Specifically, step 5.2 contains the following caution~
(
11CAUTION
11
The loops should not be isolated for the fill.
Filling with the loops -unisolated ensures that the boron
concentration in the reactor vessel and loops will be equal).
This caution was fol.lowed by steps 5.2.1 through 5.2.6 which
requires a verification that the loop isolation valves are open.
However, each of the steps state that if the valves are closed
then N/A the step.
This process basically removes the caution
from the procedure.
Procedure 2-0P-5 .1.1 dated May 10, 1991 was
not adequate, in that the caution associated with having the
loop stop valves open during RCS filling is circumvented by
the procedure option to N/A steps 5.2.l through 5.2.6 associated
with yerificatidn that the valves are o~en prior to filling.
Failure to provide an adequate procedure for control of loop
stop valve position is identified as the second example of
a violation,
50-280,281/91-18-01,
Operational
Procedure
Adherence/ Adequacy, with Three Examples.
The inspection did
note that for the RCS fil1 being performed the valves were open
and the intent of the caution was accomplished.
(2)
6
.
.
2.:.oP-5.1.2, Venting the Reactor Coolant. System, dated May 10,
1991.
This proc~dure was also a newly developed procedure and had been
verified and validated by operations.
This procedure, as well
as procedure 2-0P-5 *. 1.1 discussed above, contained precautions
and limitations that allowed the SS to authorize alteration of
sequence and to N/A portions as required.
On July 1, operations* personnel had elected to use proce.dure
2-0P-5.1.2 to start a RCP.
The procedure had been performed i.n
its entire~y earlier for system venting and the operator was
utilizing only the steps in the procedure associated with
starting the RCP.
Prbcedure 2-GOP-1.1, Unit Startup, RCS Heatup
From Ambient To 195 degrees F, dated May 24, 1991 was also being
used in parallel with 2-0P-5.1.2.
The inspector noted that
procedure 2-0P-5 .1. 2 contained two precautions that were not
being followed.
Specifically, precaution 4.4 required that the
. red tag not b~ removed fr6m the RCP breaker until just before
starting the RCP and precaution 4.5 prohibited starting a second
RCP with one a 1 ready running. ,However, the inspector observed
that all three RCP red tags had been cleared with the bfeakers
racked in ind the operator was starting a second RCP with one
already running.
The inspector questioned the SS as to what
procedure was in effect and if it was acceptable to perform the
evolution in the manner described above.
The SS indicated that the precaution associated with the red
tags was N/A since it had been previously performed.
The SS
also informed the inspector that he had exited procedure
2-QP..:5.1.2, which prohibited running two RCPs by applying N/As,
and had entered procedure 2-GOP-1.1 which did not prohibit
running two p_umps simultaneously.
The inspector
discussed
these concerns with the* Superintendent of Operations and the
author of 2-0P-5 .1. 2 to determine the acceptabi 1 i ty of the
practice and the basis for the precautions.
The procedure author indicated that the basis for the precaution
of starting a second RCP with one running was for reactor
overpressure concerns when the plant is in a water solid
condition, i.e., no bubble in the pressuriz~r~
The basis for
the red tag precaution was to prevent inadvertently starting a
pump prior to ensuring that the RCS had been filled and pressur~
ized.
Starting a second pump during this evolution did not
result in system overpressurization.
The Superintendent of Operations indicated that he would check
with the NSSS on the acceptability of the practice of starting a
7
. second RCP in a water solid condition. _ He also indicated that
- since 2-GOP-1.1 did not specifically prohibit the operation of
two pumps, the second pump was- started to increase the heatup
rate to expedite the startup schedule *.
The inspector revi~wed the basis for the cold overpressure TS
(3.1.G) to determine if it specifically prohibited the operation
of more that one RCP in a water solid condition.
The basis
indicated that the size of a single PORV could protect the
reactor vessel from over pressurization when the transient is
limited 'to either (1) the start of an idle RCP with the
secondary water temperature of a sG*less than or equal to 50
degrees F above the RCS cold leg temperature or (2) the start of
a charging pump and its irrjection into a water solid RCS.
The
basis did not discuss the acceptability of operating more than*
one RCP while in a water solid condition.
The inspectors also reviewed procedure O-DRP-004, Precautions,
Limitations and Setpoints, dated October 16, 1990.
Section 5.4
of that procedure contained many precautions a~sociated with the
RCS system, one that is directly related to this issue.
Precaution 5.4.17 indicated that if all RCPs have been idle for
more than five minutes and RCS temperatu~e is greater than the
charging* and seal injection water temperature, the first RCP
should not be started until a steam bubble has.been formed in
the pressurizer.
The precaution further stated that the ~team
bubble will minimize the pressure transient when the.cold water,
which was previously injected into the loop, is circulated and
rapidly heated.
Procedure 2-0P~5.1.2 dated May 10, 1991 was not
properly implemented,. in that precauti ans associated with
clearing RCP red tags and starting a second RCP with one pump
already running during water solid plant operations were not
adhered to.
Failure to follow procedure 2-0P-5.1.2 is identi-
fied as the third example of a violation, 50-280,281/91-18-0l,
Operational Procedure Adherence/Adequacy, with Three Examples.
Additionally, the inspector used Station Admi ni strati ve Procedure
VPAP-501,
Procedure
Admi ni strati on
Centro l
Program,
dated
February 25, 1991 as a basis for determining program compliance.
Section 6~7.2, entitled Procedure Adherence, requires that procedures
be followed.
The procedure also allows the use of ~/As to complete a
procedure, if specifically allowed by the procedure or if it is
obvious to the supervisor.
The latter case, requires the procedure
to be noted as to why the steps are not applicable.
However,
VPAP-501 does not allow a procedure, written for a specific
evolution, to be used as guidance or to be selectively applied by
ignoring prerequisites, initial conditions, or precautions .
8
d.
Physical Security Pr~gram Inspections
e.
In the course of monthly activities, the inspectors included a review
of the 1 i censee
I s phys i ca 1 security program.
The performance of
various shifts of the security force was observed in the conduct of
daily activities including: * protected and vital areas access .
- controls*; searching of personnel, packages and vehicles; badge
issuance and retrieval; escorting of v.isitors; and patrols and
compensatory posts.
The following conditions were noted:_
During the inspection period, the inspectors noted that the
1 icensee 1 s security group was having *to compensate for degraded
security equipment.
This condition existed for most of the
inspection period, and involved*mainly access control equipment.
The
licensee explained that problems had been experienced with outdated
equipment and plans were being made to upgrade.
The inspectors also
noted that the egress control equipment intended to detect unknowing
badge removal was not working.
The licensee indicated that the
equipment would be removed and that the posted officer as well as the
exiting employee would be relied on to ensure compliance.
Additionally, the inspectors noted that on one occasion the entrance
portal was control led by a single officer. _ This individual was
trying to monitor the X-Ray as wel 1 as ensure proper use of the
explosive and metal detectors.
Once noted, the licensee took prompt
and effective corrective action. A related issue involving security
equipment was also identified by the inspectors.
Specifically,
during times of continued use of the security computer for printouts
and personnel accountability the access to several areas of the plant
is greatly delayed.
This condition could complicate area accessi-
bility during an emergency and may delay operator followup of operat-
ing transients. Operations personnel can use emergency keys to gain
access to these areas.
However, the operators do not routinely carry
these keys and would have to return to the tontro l room or ca 11 *
security for access.
Licensee 10 CFR 50.72 Reports
On June 24, at 1245 hours0.0144 days <br />0.346 hours <br />0.00206 weeks <br />4.737225e-4 months <br />, the licensee reported to the NRC that at
about 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br /> on Sunday, June 23i a 12-year old *boy drowned in the *
station discharge canal.
The licensee indicated that the boy was
fishing with relatives prior to slipping into the water and had
climbed past signs and around a fence that prohibited entry into the
area. This area was within the owner controlled area, but outside the
protected area.
The body was recovered at about 2200 ho_urs on
June 23.
f.
Reduced Inventory Conditions - Unit 2
On June 25, Unit 2 entered a reduced inventory condition in order to
replace check valve 2-SI-79.
This valve is the loop A cold leg high
and 1 ow head* safety injection check valve and was i den ti fi ed as
.g
having excessive seat leakage.
Repair of fhjs valve is discussed in
paragraph 4.b.
Prior to entry into the condition, the inspectors
conducted a review of the licensee's implemented actions with regards
to- the requirements of GL 88-17, Loss of Decay Heat Removal.. No
discrepancies were noted during the review.
The specific items
reviewed were: *
GL 88-17 ~ The inspectors reviewed the subject letter including
the licensee I s response* to the letter dated January 6, 1989,
with supplemental responses dated February- 3, September 29, and
October 31, 1989, and October 5, and November 16, 1990. *
Administrative Controls - The inspectors discussed controls and
procedures in affect to control reduced inventory operation with
operations supervisory personnel.
In addition, the governing
document for reduced inventory, 2-0P-3.4, Draining the Reactor
Coolant System, dated June 13, 1991, required a pre-job briefing
to ensure that operations personnel were aware of the required
controls and procedures.
Containment Closure Activity -
The licensee's procedures
required that the status of the containment configuration be
established and verified prior to entering a reduced inventory
condition.
In addition,-_ the proJ:edure for loss of RHR
capability directed containment closure action be initiated and
continued until the RHR system is returned to service and normal
core conditions are verified. *The inspectors verified that the
licensee has prepared procedures to. reasonably assure that
containment closure would be achieved prior to the time when
core uncovery could occur.
RCS Temperature - The inspectors verified that the controlling
procedure for draining the RCS, 2-0P-3.4 required at least two
operable incore temperature indicators, one from each ICCM
train, prior to draining the RCS to a reduced 1nventory
condition.
The ICCM provides continuous indication of incore
temperature.
RCS Level Indication - The licensee has installed two means of
level indication which provide continuous readout in th~ control
room.
Both systems are calibrated and provide a low level alarm
for loss of level. - Procedure 2.;..QP-3.4 also requires that an.
operator be stationed at the reactor vessel standpipe to monitor
level locally during the draining evolution.
RCS Perturbations - The inspectors verified that the licensee's
procedure, - OC-28, Assessment of Maintenance Activities for
Potential Loss of Reactor Coolant Inventory, dated January 22,
1991, required operations assessment of work on systems for
po ten ti al. 1 oss of reactor cool ant inventory during reduced RCS
inventory conditions.
No. maintenance other than 2-SI-79 was
10
planned that could affect reactor coolant inventory during this
reduced inventory evolution.
RCS Inventory Addi ti on - The inspectors verified that procedure
2-0P-3.4 required at least two available and operable means of
adding inventory to the RCS in addition to the RHR system.
The
procedure requires that .in a reduced inventory condition, one
charging/safety injection pump and one low head safety injection
pump must be available wtth. appropriate flowpaths to the core.
Loop Stop Valves - The licensee util_izes RCS loop isolation
valves for loop isolation.
Nozzle dams are not used.
During
the reduced inventory evolution, the licensee ensured that the
reactor vessel was adequately vented by maintaining all three
loops unisolated with their loop bypass valves open.
Contingency Plans to Repower Vital Busses - The Unit 2 vital and
emergency electrical distribution system receives offsite power
. from the B and C reserve station servict;! transformers during
normal plant operations. The RHR pumps and the. CC_W pumps (which
cool .the RHR heat exchangers) operate off stub busses attached
to the 2J and 2H emergency buss es.
The stub busses are shed
during degraded or uridervoltage situations, but can be
reconnected to the emergency busses by closing a breaker.
The
equipment for the two additional means for adding inventory to
the RCS, the charging pumps and the low head safety injection
pumps, are powered off the 2H or 2J emergency buss es.
During
normal operations, the number 2 EDG supplies power to the 2H
emergency bus in case of a degraded or undervoltage situation,*
and the number 3 EOG supplies power to the 2J bus.
During this
period, the licensee had the B and C reserve station service
transformers powerihg. the emergency busses, and the number 2 and
3 EDGs avaiJable as emergency power sources.
.
.
The 1 icensee* completed the replacement of check valve 2-SI-79 on
June 28, and commenced RCS filling.
Reduced inventory was exited at
1130 hours0.0131 days <br />0.314 hours <br />0.00187 weeks <br />4.29965e-4 months <br />.
During reduced inventory opera ti ans the equipment
performed as expected and the operators were aware of plant and
equipment status at all times.
A strength regarding the procedura 1 controls associated with RCS*
reduced inventory operations was identified.
During a previous
inspection (50-280,281/91-14), the inspectors had identified that
numerous procedures were necessary to perform the reduced inventory
evolution.
Prior to entering reduced inventory during this report
period, the 1 i censee con so 1 i dated procedures and es tab 1 i shed a
periodic checklist to be used to evaluate reduced inventory
operations.
Within the areas inspected, one violation with three examples was
identified ..
. ,*
11
4.
Maintenance Inspections (62763 & 42700)
During. the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures.
The following maintenance activities were reviewed:
a.
Repair of Drain Line From Regenerative Heat Exchanger
- On June 20, Unit 1 reported an unidentified leak rate of 0.987 gpm.
This leak rate was confirmed by additional leak rate calculations
with similar results.
A w~lkdown of containment revealed the leak
was located in the regenerative heat exchanger room on a drain line
tee.
Opera tors isolated the leak and thus al so the RCS letdown fl ow
path until the repair could be made.
After draining the line, it was purged with nitrogen to give a
backing gas for welding.
Dye penetrant inspection indicated a pin
hole in the tee-to-pipe socket weld.
The repair was performed using
work request No. 3800112835.' The weld defect was removed by grinding
and removal was assured by dye* penetrant inspection.
The area was
then repaired using shielded .metal arc welding (welding procedure
technique No. PlOl-803) and austenitic stainless steel weld metal
E-308; heat No~ 04828-05-01.
Mechanical corrective maintenance
procedure MCM-1801-01, Piping/Components Repair/Replacement~ Rev. 2,
dated February 27, 1990, was used. * Visual and dye penetrant inspec-
tions were performed on the repair.
Operators returned the normal
RCS 1 etdown fl ow path to service and observed that there was no
leakage in the area of the repair.
The inspectors reviewed the documentation for the repair and the
welder qualifications. The weld filler metal qualification cduld not
be located at the time of the inspection, but will be reviewed during
the next inspection period.
b.
Repair of Check Valve 2-SI-79
The inspectors followed the replacement of check valve 2-SI-79. This
valve had exhibited a leak in excess of 20 gpm when tested at 300
psig.
The licensee decided -to replace the check valve when
disassembly and inspection revealed no obvious cause for the leakage.
Work order No. 3800112591 and mechanical maintenance procedure No.
MCM-1801-01, Piping/Components Repair/Replacement,* dated February 27,
1990, were utilized for the replacement.
The inspectors reviewed the tagout items and the weld travelers.
Gas
metal arc welding process was used with QC inspecting the* fit up and
root pass.
The licensee performed visual and radiographic inspection
on the root pass with dye penetrant and radiographic inspection being
performed on the completed weld. * One-eighth inch diameter ER-316
sta-inless. steel weld wire, heat Nos. 26568 and CT. 5839, was used.
12
The inspectors reviewed the material test .reports against the
appro~riate ASME Code sections. The sy~tem hydrostatic test for thi~
- replacement was performed to the requirements of Table IWB-5220-:-l of
Section XI of the ASME Code.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections. (61726 & 42700)
During the reporting period, the_ inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as
follows:
...
Test prerequisites were met.
Tests were performed in accordance with approved-procedures.
Procedures satisfied the surveillance requirements.
Adequate coordination *existed among personnel involved in the test .
Test data was properly collected and recorded *
The following surveillances were either reviewed or observed:
a.
Motor Driven AFW Pump Testing
On June 24, the inspectors witnessed the performance of periodic test
1-PT-15.18, Motor Driven Auxiliary Feedwater Pump 1-FW-P-38, dated
February 14, 1991.
The purpose of this test was to demonstrate
operability of pump l~FW-P-3B.
The inspectors observed parts of the
performance of this test from both the safeguards area and the main
contra 1 room.
The results of -the test were reviewed by the
inspectors and no discrepancies ~ere noted.*
b.
Section XI Pump Testing Program
On May 30, 1991, the licensee informed the inspectors that the flow
instrumentation used for testing pumps in accordance with the Surry
ASME Section XI pump test program may not meet the code-required+/-
2 percent accuracy.
The licensee had committed to install many new
flow instruments during the refueling outage to satisfy code require-
ments and believed that th~ instruments were in compliance with the
code accuracy requirements when a previous code relief, associated
with instr_ument accuracy, was allowed to expire.
The licensee described their interim corrective actions to evaluate
the affected equipment operability as follows:
13
(1)
Add the worst case instrument unc:ertainty to each affected
instrument loop and then verify that pump operability was still
valid.
(2) Evaluate the actual instrument loop accuracy and determine if .
the 2 percent unce.rtainty was exceeded for any of the equipment.
(3) Change
the calibrati6n procedures and recalibrate the
instruments prior to the next scheduled pump performance test.*
( 4)
Inform the NRC of any. cases where the actua 1 1 oop accuracy
exceeded the required 2 percent value and to request code relief
if required.
On June 3, the licensee submitted the results of their initial
review.
This review indicated that pump operability was evaluated by
applying the maximum potential loop uncertainty of between 2.5 and
3.19 percent to the last pump performance test.* The licensee's
submittal indicated that in each case the measuted flow rate remained
above the Action Level" per ASME Section XI.
The .licensee further
indicated that the impact of the actual loop uncertainties would be
reviewed and if the value exceeded the required 2 percent limit, a
specific interim relief request for each affected pump would be
submitted.
On June 7, the licensee submitted their interim relief request.
In
that request, the 1 icensee. indicated that 12 instrumen.t loops
exceeded the ASME Section *x1 required 2 percent accuracy requirements
at the time that they were used to verify pump performance.
The
systems involved included RHR, ISRS, AFW, CCW, LHSI and SW and
therefore the requirements of TS 4.0.3 were violated since pumps in
these systems are required to be tested with instrumentation that
satisfies the ASME Section XI accuracy requirements.
On July 1, the licensee submitted LER 91-010 to document the above
violation of TS 4.0.3.
The inspector reviewed the licensee actions
associated with this event as well as the information provided in the
LER.
The LER attributed the cause of the violation to interface
problems between project engineering and the organization that was
performing the instrument calibration.
The design engineer's
assumptions, associated with instrument and calibration tolerances,
were not communicated to the implementing organization.
The above condition, which was discovered by the* licensee, is
identified as NCV 50-280,281/91-18-02, Failure to Ensure Implementa-
tion of Design Outp~t.
This licensee identified violation is not
being cited because the ~riteria specified in Section V.G.1 of the
NRC Enforcement Policy were satisfied.
.
I
14
6.
Exit Interview
The inspection scope and results were summarized on July- 9, 1991 with *
those individuals identified by an asterisk in paragraph 1. The following
summary of inspection activity was discussed by the inspectors during this
exit.
Item Number
Description and Reference
VIO 50-280,281/91-18-01
Failure to follow or provide adequate
procedures with 3 examples, (paragraph 3~c).
NCV 50-280,2~1/91-18-02
Licensee identified violation for a failure
to ensure implementation of design output
associated with ASME Section XI instrument
accuracy, (paragraph 5.b).
The licensee acknowledged the inspection conclusions with no dissenting
comments.
The 1 i censee did not i den ti fy as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
7.
Index of Acronyms amd Initialisms
ccw
CFR
CRO
DR
EOG
F
GPM
GL
ICCM
LER
LCO
LHSI
N/A
NRC .
. PORV
RCCA
AMERICAN SOCIETY FOR MECHANICAL ENGINEERS
COMPONENT COOLING WATER
CODE OF FEDERAL REGULATIONS
CONTROL ROOM OPERATOR
DEVIATION REPORT
ENGINEERED SAFETY FEATURE
FAHRENHEIT
GALLONS PER MINUTE
GENERIC LETTER
INCORE COOLING MONITOR
INSIDE RECIRCULATION SPRAY
LICENSEE EVENT REPORT
LIMITING CONDITIONS OF OPERATION
LOW HEAD SAFETY INJECTION
NOT APPLICALBLE
NON-CITED VIOLATION
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
NUCLEAR STEAM SYSTEM SUPPLIER
POUNDS PER SQUARE INCH
POWER OPERATED RELIEF VALVE
QUALITY CONTROL
ROD CLUSTER CONTROL ASSEMBLY
REACTOR COOLANT PUMP
- '
- I
SR *
ss
TS
VPAP
- -
15
SAFETY INJECTION
SOURCE RANGE
SHIFT SUPERVISOR
TECHNICAL SPECIFICATIONS
VIRGINIA POWER ADMINISTRATIVE PROCEDURES