ML18152A166
| ML18152A166 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 06/10/1991 |
| From: | Fredrickson P, Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A167 | List: |
| References | |
| 50-280-91-10, 50-281-91-10, NUDOCS 9106270082 | |
| Download: ML18152A166 (19) | |
See also: IR 05000280/1991010
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
~eport Nos.:
50-280/91-10 and 50-281/91-10
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
Inspectors:~\\\\,:;::,~,..........~.....,.....~--=~--=-~:--.=.-.,.-.....,...~---.,--~~~~~
()?~*
<fd.
te igned
G/~ C//c;'/
Dake Signed
G /; ~h 1
DateSfgned
Approved
SUMMARY
Scope:
Thi.s routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, and plant surveillance.
In addition, a region
based inspector supported the inspection of testing of the Unit 2 service water
portion of the recirculation spray. system.
During the performance of this
.inspection, the resident inspectors conducted review of the licensee'*s
backshift or weekend operations on April 5, 6, 7, 8, 9, 10, 14, 21, 23, 28, 29,
May 2 , 7 , and 8.
Results:
In the engineering/technical support functional area, the failure to provide
administrative instructions to ensure that design control is maintained for
setpoints was identified as a programmatic weakness (paragraph 4.a).
9106270082 910610
ADOCK 05000~80
Q
2
In the operations and maintenance functional areas, inadequate inter-department
corrmunications between operations and maintenance engineering regarding the
operability of component cooling water pump 1-CC-P-lB*was considered a weakness
{paragraph 3.b).
.
In the opetations functional area, s~veral problems were identified which were
associated with a lack of operator
1s attention to detail and sensitivity to
control of plant configurati~n.
These problems resulted in identification of
NCVs for failure to tag out the correct emergency diesel generator fuel
transfer pump, failure to sample service water to the component cooling water
heat ~xchangei as required by ~he Technical Specifications, failure to properly
control system configuration that technically caused the inoperability of both
trains of a safety system, and failure to properly control the Unit 2 transfer
canal filling process that resulted in an overflow of contaminated water into
clean areas, (paragraph -3.d).
Management involvement in review of the events
and action after the last event appeared effective in refocusing personnel
accountability and attention to detail.
In the engineering/technical support functional area, an NCV
was identified
for failure to assure that proper system configuration was being maintained.
The original plant construction problem which* caused the violation was*
identified during modification of the recirculation flowpaths for the auxiliary
feedwater pumps and could not have been reasonably identified through any
previous station activities.
Good communication was observed between depart-
ments (engineering, construction, and operations) during troubleshooting and
identification of the problem {paragraph 3.d).
In the engineering/technical support functional area, a strength was identified
regarding the licensee's engineering involvement in identifying and resolving
the discrepancy concerning testing of the sample pumps for the recirculation
spray heat exchanger se~vice water radiation monitor and the overall support
provided throughout the test (paragraph 5.a).
.
In the maintenance/surveillance functional area, a weakness was identified**
associated with periodic maintenance on pressure switches.
Pressure switches
installed on systems important to safety were not in a routine calibration
program (paragraph 4;a).
In the maintenance/surveillance functional area, an NCV was identified for
failure to test the emergency diesel generator fuel oil transfer pumps more
. frequently or take corrective action in accordance with the Inservice Test
Program when vibration readings were in the alert range (paragraph 5.b) *
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
R. Allen, Supervisor, Shift Operations
- J. Artigas, Supervisor, Quality, Q.A.
- W. Benthall, Supervisor, Licensing
- R. Bilye~, Licensing Engineer
- M. Bowling, Manager, Nuclear Licensing and Pro_grams
- D. Christian, Assistant Station Manager
- J. Downs, Superintendent of Outage and Planriing
D. Erickson, Superintendent of Health Physics
R. Gwaltney, Superintendent of Maintenance
- M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
- J. Logan, Senior Staff Engineer *
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
- E. Shaub, Licensing Engineer
- R. Saunders, Assistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- T. Sowers, Supe~intendent of Engineering
NRC Personnel
- W. Holland, Senior Resident Inspector
- M. Branch, Senior Resident Inspector
S. Tingen, Resident Inspector-
J. York, Resident Inspector
M. Thomas, Reactor Inspector, Division of Reactor Safety
- Attended exit interview.
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
Acronyms and initial isms used throughout this report are listed in *the
last pa_ragraph.
On May 1 and 2, 1991, the Division of Reactor Projects Branch Chief,
M. Sinkule, visited the Surry Power Station.
Mr. Sinkule toured the Unit
2 containment and held discussions with the residents.
On May 2, Mr.
B. Mallett, Deputy Director, Division of Radiation Safety and Safeguards,
visited the Surry Power Station.
Mr. Mallett and Mr Sinkule discussed
current plant status and ongoing projects with plant m*anagement, toured
the new radwaste processing facility, and toured the station with the
residents and the Surry Station Manager.
2.
2
Plant Status
Unit 1 began the reporting period in power oper~tion. * The unit operated
at power for the duratjon of the inspet~ion period.
Unit 2 began the reporting period in cold shutdown (day 2 of a scheduled
67 day refueling/maintenance outage). During this period the unit entered
reduced. inventory conditions for approximately one day.
This item is
further discussed in paragraph 3.g.
Also the unit was refueled and,
tow a rd the end of the period, the reactor ves se 1 head was being
reinstalled.
Unit 2 remained in refueling sh~tdown condition (reactor
vessel head reinstalled but studs not tensioned - day 44 of the outage)
when the inspection period end~d.
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 are operable; and review
of control room operator logs, operating orders, plant deviation
reports, ta gout logs, temporary modi fi cation 1 ogs, and tags on
components to verify comp 1 i ance 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.
b.
Weekly Inspections
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, niis.sile
hazards, and plant housekeeping conditions/cleanliness.
The
inspectors routinely noted the temperature of the AFW pump discharge
piping to ensure i ncrea~es in temperature were being properly
monitored and evaluated by the licensee.
On May 1, operators logged that the outboard bearing on CCW pump
1-CC-P-lB felt hot and that its bearing oil smelled like tar and
looked deteriorated. The pump was secured, placed in automatic start
and a work request was submitted.
On May 2, operators logged that
pump 1-CC-P-lB had bad oil and was for emergency use only.
On May 3,
--*---~~*---**-
' **
3
the inspectors questioned the operability of pump 1-CC-P-lB, and the
pump was subsequently declared inoperable.
Discussio.n between
operations, maintenance engineerjng, and th~ inspectors revealed that
an oil sample had been obtained from pump 1-CC-P-IR outboard bearing
and maintenance engineering had determined from the oil sample that
the pump bearing was possibly damaged and the pump was inoperable.
On May 2, maintenance engineering considered that the pump was
inoperable but inadequate inter-department co11111uni cations between
operations and maintenance engineering failed to conununicate that
engineering considered the pump inoperable.
TS 3.13 requires that for one unit operation, two CCW pumps* be
The fospectors verified that on May 1-3 the requirements
of TS 3.13 were met with pump 1-CC-P-lB inoperable.
The inadequate
inter-department communications between operations and maintenance
engineering regarding the operability of 1-CC-P-lB was considered a
weakness.
c.
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 implementation
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 10CFR19.
d.
Other Inspection Activities
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear r,ooms,
diesel generator rooms, control room, auxiliary building, cable
penetration areas; Unit 2 containment, *1ow level intake structure,
and the safeguards valve pit and pump pit areas.
RCS leak rates were
reviewed to ensure that detected or suspected leakage from the system
was recorded, investigated, and evaluated; and that appropriate
actions were taken, if required.
The inspectors routinely
independently calculated RCS leak rates using the NRC Independ_ent
Measurements Leak Rate Program (RCSLK9).
On a regular basis, RWPs
were reviewed, and specific work activities were monitored to assure
they were being conducted per the RWPs.
Selected radiation
protection instruments were periodically checked, and equipment
operability and calibration frequency were verified.
During this inspection period, several problems were identified which
were associated with a lack of operator's attention to detail and
sensitivity to control of plant configuration.
The events are
described below.
4
On April 9~ the inspectors were informed by the licensee that one of
the two fuel oil transfer pumps (1-EE-P-lF) for the No. 3 EOG had
been inadvertently tagged out.
This problem was discovered *during
operator rounds on April 9. * Unit 1 entered TS LCO 3.0.1 at that
time.
The tagout was cleared and the pum~ was returned to service
within one hour allowing for exit of the LCO.
The operations super-
intendent conducted a review of the problem and provided a report to
station management on April 10.
The inspectors reviewed the
preliminary report and noted the following:
Planning personnel identified the incorrect pump to be tagged
and also identified the wrong electrical breakei to be tagged.
Licensed operators who initiated the component isolation did not
use good self-checking techniques in the performance of this
evolution. Procedures were available for tagout of the fuel oil*
transfer pumps; however, these procedures were not specifically
written for the work to be performed and, therefore, were not
used.
The inspectors also were informed that CNS would conduct a review of
this event and provide additional *conclusions.
The inspectors were
briefed on the preliminary findings by CNS.
The inspectors consider
that the licensee's review of this event will allow for adequate
corrective action to prevent recurrence.
Failure to tag out the
correct EOG fuel transfer pump is identified as NCV 280/91-10-01~
This licensee-identified violation is not being cited because the*
criteria specified in Section V.G.1 of the NRC Enforcement Policy
were satisfied.
On April 12, the inspectors noted, during a review of operator logs,
that operators identified that a CCW heat exchanger sample was not
taken within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> as required by TS.
This* was a repeat of a
previous similar occurrence.* Corrective action included taking -
samples at six hour intervals.
In addition, prior to the end of the
inspection period, the licensee had installed and placed in operation
the fourth CCW heat exchanger service water radiation monitor, which
eliminated the sampling requirement.
This corrective action was the
permanent solution to a long-standing operational distraction.
Failure to sample the CCW heat exchanger service water as required by
TS is identified as NCV 280,281/91-10-02.
This licensee-identified
violation is not being cited because the criteria specified in
Section V.G.1 of the NRC Enforcement Policy were satisfied.
On April 22, the inspectors noted, during review of operator logs,
that operators identified both_ trains of the auxiliary building
emergency ventilation exhaust fans as inoperable at the same time,
which was in violation of TS.
The problem occurred when operators
tagged out the A train fan at the same time that the B train fan's
emergency power supply was out for maintenance.
This condition
placed Unit 1 in TS 3.0.1 at that time.
Immediate actions were to
5
return the A train fan to service.
The time period when both fans
were technically inoperable was approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
CNS was
requested to review this problem.
Failure to properly control system
configuration resulting in both trains of a safety system being
technically inoperable is identified as NCV 280/91-10-03.
This
licensee identified violation is not being cited because the criteria
specified in Section V. G .1 of the NRC Enforcement Po 1 icy were
satisfied.
On April 23, the inspectors rioted, during review of operator logs,
that operators identified a condition that allowed overflowing of the
Unit 2 fuel transfer canal to the fuel building floor during a
filling evolution. The filling evolution was being accomplished.as a
"skill of the craft" job with no specific guidance on the monitoring
frequency for the fi 11 process.
A licensee review of the event
concluded that the cause* was personnel error.
Corrective action
included discussions with operations personnel on control of
evolutions not requiring written procedures.
Failure to properly
control the Unit 2 transfer .canal filling process resulted in the
overflow of contaminated water into clean areas. This is identified
as NCV 280,281/91-10-04.
This licensee identified violation is not
being cited because the criteria specified in Section V.G.1 of the
NRC Enforcement Policy were satisfied.
The inspectors noted that management attention was focused on each of
the aboveevents and CNS involvement in the review process indicated
an increased corporate awareness and involvement in assuring that
appropriate corrective actions were being taken.
Deviation reports
were written for each event.
In addition, after the April 23 event,
management had all superintendents discuss recent the performances*
and these events with their respective departments~
The inspectors
monitored selected discussions which were held with operating shifts.
The Operations Superintendent's discussions focused on the problems
discussed above and emphasized attention to detail, self-checking, -
and conununications.
The Assistant Station Manager for Operations and
Maintenanc~ was present for these discussions and also talked to the
shifts.
His talk focused on personal responsibility and
accountability.
The inspectors concluded that the discussions were
effective and well received.
On April 19, the licensee determined that a configuration problem
existed for the Unit 2 AFW system since the plant was constructed.
Because of underground crossing of lines during ori gi na l pl ant
construction involving the CST supply to the suction of the Unit 2 B
AFW pump and the CST fill line, an improper isolation resulted from a
modification by a DCP activity.
This occurred during performance
of DCP 87-09-2, AFW Full Flow Recirculation Lines.
The isolation
of the CST fill line resulted in isola{ion of the B AFW pump.
This
condition was contrary to TS requirements for maintaining cross-plant
AFW capabilities. After licensee identification of the problem, Unit
1 entered the TS action statement and inunediate actions were taken to
6
uni sol ate the maintenance fl owpath which was at this time known to be
the AFW pump B suction line from the CST.
Additional licensee
actions included verification that this condition did not exist on*
the Unit 1 AFW pump suction lines from the Unit 1 CST.
The li~ensee
also performed calculations to confirm that adequate NPSH was avail-
able for the Unit 2 B AFW pump from the smaller fill line.
The inspectors reviewed the problem' and the licensee's corrective
actions and concluded that they were adequate.
The review also
brought out the fact that the licensee had fire main backup water
available to the B AFW pump during the. period when its water supply
from the CST was isolated.
The original plant construction
deficiency was identified during modification of the tecirculation
flowpaths for the auxiliary feedwater pumps and could only have been
identified during a modification of this nature.
Good communications
was observed between departments ( engineering, construction, and
operations) during troubleshooting and identification of the problem.
Fai 1 ure *to assure that proper system configuration was being
maintained during modification activities resulted in a violation
when the required cross plant AFW system operability issue was
identified. This is identified as NCV 280/91-10-05.
This licensee
identified violation is not being cited because the criteria
specified in Section V.G.1 of the NRC Enforcement-Policy were
satisfied.
e.
Physical Security Program Inspections
f.
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 to include: protected and vital areas access
controls; searching of personnel, packages and vehicles; badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
No discrepancies were noted.
Licensee 10 CFR 50.72 Reports
On April 26, 1991, at approximately 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br />, the licensee made a
report in accordance with 10 CFR 50.72 for entry in the emergency
plan (UE) due to a TS required shutdowm initiation on Unit 1.
At
2255 hours0.0261 days <br />0.626 hours <br />0.00373 weeks <br />8.580275e-4 months <br /> on April 25, the licensee discovered that the A main
control room chiller would not load and declared the chiller
TS 3.23 requires that all three of the main control room
chillers be operable whenever either unit ts above cold shutdown and
also allows for one control room chiller to be inoperable for a
period not to exceed seven days.
At the time of this event, the
emergency power supply to the B main control room chiller was not
available due to maintenance on the No. 3 EOG.
TS 3.0.2 requires
both normal and emergency power supplies be operable for redundant
I~
7
equipment when a required component is inoperable.
Therefore, when
the A main control room chiller became inoperable, the B main control
room chiller was also declared inoperable.
TS 3.0.2 invoked a
six-hour clock to hot shutdown.
At 0115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br /> on* April 26, the
licensee initiated a controlled shutdown of Unit 1, and declared a
UE.
The A main control room chiller was repaired and returned to
service.
At 0222 hours0.00257 days <br />0.0617 hours <br />3.670635e-4 weeks <br />8.4471e-5 months <br /> the Unit 1 ramp was stopped at 78% power
and the UE terminated.
At 0425 hours0.00492 days <br />0.118 hours <br />7.027116e-4 weeks <br />1.617125e-4 months <br /> the unit was at 100% power.
A review of this evolution indicated that 1 icensee actions were
conservative and in accordance with TS requirements.
g.
Reduced Inventory Conditions - Unit 2
Unit 2 entered a reduced inventory condition on April 4, 1991 in
order to drain the primary side of *the steam genera tors. The
condition was exited on *April 5, 1991.
Prior to entry into this
condition, the inspectors . conducted a review of the 1 icensee' s
responses and implemented actions with regards to the requirements of
Generic Letter 88-17, Loss of Decay Heat Removal.
No discrepancies
were noted during the review.
The specific items reviewed were:
Generic Letter 88-17 - The inspectors reviewed the subject
letter including the licensee's response to the letter dated
January 6, with suppl ementa 1 responses dated February 3,
September 29, October 31, 1989, October 5, and November 16,
1990.
-
Administrative Contrnls - The inspectors discussed controls and
procedures in affect to control reduced inventory operation with
station management.
Containment Closure Activity - The licensee's procedures require
that the status of the containment configuration be established
and verified prior to entering a reduced inventory condition.*
In addition, the procedure for loss of RHR capability di rec ts
containment closure action to be initiated and continued until
the RHR system is returned~~ service and core conditions are
verified normal. The inspectors verified that the licensee has
prepared procedures to reasonably assure that containment
closure will be achieved prior to the time when core uncovery
could occur.
This was done by reviewing 2-0P-3.4, Draining the
Reactor Coolant System, dated March 28, 1991, 2-0P-lG, Refueling
Containment Integrity and RCS Mid-Loop Containment Closure.*
Checklist, dated April 28, 1989, and 2-AP-27, Loss of Decay Heat
Removal Capability, dated March 28, 1991. * Other than the
containment personnel entry hatch, no containment openings will
exist.
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 prior to draining the RCS
8
to a reduced inventory condition.
The inspectors also verified
that the control room operators record the temperatures every
. six hours in their .log as required* by* periodic test 2-PT-36,
Instrument Surveillance.* In addition a supplemental check list,
Control Room Operator Reduced RCS Inventory Relief Checklist,
requires at least two operable core exit thermocouples (i.e. one
from each train).
RCS Level Indication - The licensee has installed one means of
level indication which provides continuous readout in the
control room.
This system is calibrated and provides an alarm
for both low level and. loss of level.
In a letter dated
October 31, 1989, the licensee committed to install a second
means of RCS level indication prior to the end of the current
Unit 2 refueling outage.
Until this second means of level
indic:ation is* installed, the licensee will utilize only one
means of RCS level indication.
RCS Perturbations - The inspectors verified that the licensee
has a procedure, OC-28, Assessment of Maintenance Activities for
Potential Loss of Reactor Coolant Inventory dated January 22,
1991, that allows operations' assessment of work on systems for
potent i a 1 1 oss of reactor coo 1 ant inventory during reduced RCS
inventory conditions.
RCS Inventory Addition - The inspectors verified that procedure
2-0P-3.4 required at least two available and operable means of
adding inventory to the RCS.
These are 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 with appropriate
flowpaths to the core.
Loop Stop Valves - The licensee utilizes RCS loop isolation
valves for loop isolation.
Nozzle dams are not .used.
The
licensee uses a checklist (OC-28) to ensure that the RV upper
plenum is adequately vented when maintenance activities require
opening of an RCS cold leg pressure boundary.
The licensee .will
ensure the reactor vessel is adequately vented by maintaining A
and Bloops unisolated with their loop bypass valves open.
Contingency Plans to Repower Vital Susses - The vital and
emergency electrical distribution system receives offsite power
from the A and C reserve station service transformers during
normal plant operations.
The RHR pumps and the CCW pumps, the
latter provide cooling water to the RHR heat exchangers, operate
off stub busses attached to the 2J and 2H emergency busses..
The
stub busses are shed during degraded or undervoltage situations,
but can be reconnected to the emergency busses by closing a
9
breaker.
The equipment for the two additional means for adding
jnventory to the RCS, charging pumps and low head safety
injection pumps, are powered off the 2H and 2J emergency busses.
During normal operations, the number 2 EOG supplies power to the
2H emergency bus in case of a degraded or undervol tage
situation, and the number 3 EOG supplies power to the .2J bus.
During this period, the licensee will have the A_and C reserve
station service transformers powering the emergency busses, and
the No. 2 and 3 EDGs available as emergency power sources.
Within the areas inspected, five NCVs 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 activities were reviewed:
a.
Instrument Calibrations
During the previous inspection period, discrepancies associated with
the ca 1 i brat ion of the containment spray pump pressure switches were
identified.
These discrepancies involved conflicting and incomplete
information specified in the Units 1 and 2 setpoint documents and
instrument history folders.
During this inspection period,
calibration procedures, setpoint documents, and instrument history
folders were reviewed.
The inspectors reviewed the setpoint DRPs,
1-DRP-005, Instrument Setpoints, dated July 24, 1990, and 2-DRP-005,
Instrument Setpoints, dated July 24, 1990.
The licensee informed the
inspectors that the design basis for all reactor protection and
safeguards setpoints were reverified in 1989 with no discrepancies
noted.
The inspectors did not verify the basis of the setpoints or
the loops' scaling and bias factors but a review of the procedures -
associated with the calibration of reactor protection instrumentation
and SI instrumentation indicated that the procedures were adequate
and contained all the required information necessary for I&C
technicians to accomplish the work.
Reactor protection calibration
procedures reviewed were:
1-PT-2.2A (F-1-415), Reactor Coolant Flow, dated October 31,
1989
2-PT-2.5A (L~2-474), Steam Generator Level, dated October 31,
1989
2-PT-2.4A (P-1-455), Pressurizer Pressure Protection, dated
September 3, 1989
SI calibration procedure 1-PT-2.18 (P-1-927),
B Safety
Injection Accumulator Tank Pressure, dated October 31,1989
10-
Although all the required calibration specifications were contained
in the individual calibration procedures, the setpoint DRPs also
contained calibration specifications for the same instruments~
The inspectors identified discrepancies between the calibration
specifications provided in the calibration procedures and the
setpoint DRPs.
Examples of discrepancies were that the setpoint DRPs
specified incorrect tolerances for the pressure comparaters
associated with the Unit 2 SI accumulators and Unit 1 pressurizer
pressure instruments.
The inspectors a 1 so noted that in many
instances the setpoint DRP did not provide all the necessary
calibration specifications (instrument span, setpoint tolerance, .
reset point, etc.) that were specified in the calibration procedures.
- Since all calibration specifications for ttie reactor protection and
SI instrument calibrations were specified in the procedures, the
instrument history folders and setpoirit DRPs were not utilized by the
I&C technicians to obtain calibration specifications. * The inspectors
concluded that these calibrations procedures were adequate; however
the setpoint DRPs were considered inadequate because. of the
discrepancies noted.
The inspectors reviewed procedure IMP-C-G-35, Pressure Switch
Checkout, dated November 27, 1988.
This is a generic procedure
currently utilized to calibrate pressure switches installed on
safety-related systems throughout the plant. The procedure provides
general guidance but does not provide the pressure switch setpoint
specifications.
The s.etpoint specifications are obtained from the
unit's setpoint DRP.
As discussed in the previous inspection period,
during_ the calibration of pressure switch l-CS-PS-103A, setpoint DRP
and instrument history file setpoint discrepancies were noted.
Tolerances for setpoints and switch reset values were not provided.
Information detailing pressure switch actuation on increasing or
decreasing pressure was also not provided. Technicians were required
to review the e1ectrical schematics in order to determine whether the
pressure switch contacts are required to open or close at the desired
setpoint.
The inspectors reviewed the calibrations of pressure
switches 2-PS-CC-202 and 2-PS-DG-200 and identified findings similar
to the 1-CS-PS-103A calibration findings.
2-PS-CC-202 provides a
control room alarm of low CC pump pressure to the Unit 2 charging
pump sea1 coolers and 2~PS-DG-200 controls the rate of leakage from
the reactor coolant system leakoff into the PDTT.
Based on the
examples reviewed, the inspectors concluded that in the area of
pressure switch calibration specifications, the setpoint DRPs were
inadequate because the required information was not provided and
other information specified in the setpoint DRPs was inconsistent.
The inspectors also reviewed deviation reports that documented
discrepancies associated with RTD, flow, and level instrumentation
calibration procedures and indicated that the Units 1 and 2 setpoint
DRPs wer~ not in agreement.
'*-* --*-:>. .
11
The Units 1 and 2 setpoint* DRPs were issued in July, 1990.
The
purpose of these documents was to provide an official procedure
containing instrument s_etpoint data that had been approved by *sNSOC.
I&C personnel were required to obtain the required calibration
specifications from these documents when the information was not
available in the instrument calibration procedure.
The setpoint
DRPs have been under continuing revision since being issµed.
The
inspectors reviewed SUADM-ENG-04, Setpoint Change Control Program,
dated October 17, 1990, and concluded that administrative
instructions required that instrument setpoints be established or
changed by a prescribed design process.
The licensee stated that I&C
technicians had been informed to initiate an EWR and engineering
would provide the required setpoints.
Discussions with I&C
technicians indicated that this method was burdensome and resulted in
I&C personnel researching instrument history files to. obtain
setpoints which complicated the performance of the instrument
calibration procedure.
During this inspection period, the licensee
had developed a new process for I&C technicians to obtain calibration
specifications when not in the calibration procedure or the setpoint
DRP.
I&C technicians were required to research the instrument
history files and any other necessary documents and drawings to
determine setpoints and forward this information to engineering for
review.
The technicians would perform the calibration and at a *
later date engineering would review the setpoints provided by I&C
and update the setpoint DRP.
If the engineering review of the
I&C-provided setpoints identified that the setpoints were incorrect,
a deviation report would be initiated.
The inspectors concluded that the licensee did have a formal
administrative process for obtaining setpoint specifications when not
provided by a calibration procedure or a setpoint DRP.
However,
during this inspection period, that process was not being used for
those examples of pressure instrumentation setpoints reviewed by the
inspectors. Although the setpoint DRP discrepancies identified by the
inspectors did not result in any significant safety issues, the
inspectors were concerned that required administrative guidelines
were not in place to provide design input of setpoints variances.
This problem appeared to be extensive and is identified as a program-
matic weakness.
The inspectors also
noted that pressure switches 2-PS-CC-202 *and
2-DG-PS-200 had not been in a periodic calibration program.
D~ring
the Unit 2 outage these switches were not able to be calibrated and
were replaced.
The inspectors consider it a weakness in the
licensee
I s periodic maintenance program that pressure switches
installed on systems important to safety were not routinely
calibrated.
When I&C personnel discover that these components were
not routinely calibrated they were adding them to the calibration
program.
12
b.
Replacement of Pressurizer Heater Breakers
On April 25, the inspectors observed the replacement of breaker No. 5
in the pressurizer heater breaker panel.No. 2.
The craft were using
work order 3800110459 and corrective electri~al maintenance procedure
EMP-C-EPL-73, Safety Related Molded-Case Circuit Breakers, dated
April 14, 1987.
The inspectors observed the meggering of the No. 1
breaker in this panel and the signing off and recording of.some of
the vendor information .into steps- of the procedure.
No discrepancies
were identified.
- *
Within the areas inspected, one violation_was 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.
Test proced_ures appeared to perform their intended function ..
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.
Flow Testing of the ~ervice Water Side of the Unit 2 RSHXs
During this inspection period~ the inspectors witnessed flow testing
of Unit 2 RSHXs 2-RS-E-lB and 2-RS-E-lC.
The test was performed in
accordance-with special test procedure 2-ST-301, "Recirculation Spray
Heat Exchangers Service Water Flow Test", dated March 26, 1991~
During Unit 1 RSHX SW flow testing in October, 1990, concerns were
- identified over the control of macrofouling which could limit the
ability of the RSHXs to adequately perform their functions during an
accident.
As a result of these concerns, the licensee performed flow
test verification on the Unit 2 RSHXs.
The Unit 1 testing was
discussed in detail in NRC Inspection Reports *50-280,281/90-30 and
50-280,281/90-36.
-
This Unit 2 test involved removal of service water valves 2-SW-MOV-
204B and 2-SW-MOV-204C and their respective expansion joints.
A
special venturi test spool piece was installed in the place of each
valve to measure SW inlet flow to the RSHXs.
Instrumentation was
al~o installed to measure differential pressure across the RSHXs and
-to gather additional flow data.
13
The inspectors- observed pretest preparations which included
installation and checkout of test equipment and the pretest briefing.
The inspectors reviewed procedure 2-.ST-301,* including the changes,
and found the procedure to be technically adequate.
The inspectors
noted that change 91-47 to the procedure involved adding steps to
test the .RSHX SW radiation monitor pumps 2-SW-P-58 and 2-SW-P-5C
under design conditions.
The inspectors discussed this change with
1 icensee personnel who stated that the pumps were being tested
because there was no documentation to show that the pumps had ever
been tested to demonstrate their capability to provide the required
flow rate under actual RSHX SW flow conditions.
The pumps are
currently being tested quarterly under periodic test procedure
2 ... PT-17.7, Recirculation Spray Heat Exchanger Service Water Radiation
Monitor Pump Test.
Condensate was used to test the pumps during
surveillance testing.
The condensate is applied to the suction of
the pumps through a test and flush connection.
At 0534 hours0.00618 days <br />0.148 hours <br />8.829365e-4 weeks <br />2.03187e-4 months <br /> on April 6, 1991, the test began by initiating SW flow
through the Unit 2B and C RSHXs.
Approximately one minute after
initiation of SW flow, radiation monitor pumps 2-SW-P-58 and
2-SW-P-5C were manually started from the control ,room.
The
. inspectors monitored testing from the control room and the Unit 2
safeguards room.
The inspectors noted that the test instrumentation
indicated that the SW flows appeared to be within the expected
ranges.
The flows were approximately 11,000 gpm through each RSHX
and the differential pressure across each RSHX was approximately
150-155 psig.
The additional instrumentation being used to monitor
SW flow were in close agreement with the values obtained from the
venturi test devices.
The inspectors observed that the control room
flow indicators were erratic and not reliable. For example, control
room flow indicator 2-SW-FI-206B was reading approximately 3000 gpm
less than the venturi test device which was installed for RSHX B.
A
SW flow of approximately 4800 gpm was read from RSHX A flow indicator
2-SW-FI-206A and 3800 gpm was read from RSHX D fl ow i ndi ca tor
2-SW-FI-206D.
There was no flciw through either the A or D RSHXs
because the SW inlet supply valves to these HXs were closed.
Deficiencies related to incorrect control room flow indicators are
being tracked by IF! 280,281/90-30-01.
After the RSHX SW radiation monitor 2-SW-P-58 and SC pumps were
started, the low flow alarm annunciated in the control room.
- The
discharge pressure was 5.5 psig for pump 58 and 6 psig for pump 5C.
Licensee personnel attempted to take SW samples from the sample lines*
but the 58 pump sample line was only dripping and the SC pump sample
line yielded one liter in approximately one and one-half minutes~
The flow rate requirements stated in the FSAR was 5-10 gpm and the
discharge pressure stated in the surveillance procedure was greater
than 25 psig.
Licensee personnel decided to open the condensate
- '.
14
supply, which is nonnally used during su*rveillance testing, to the
pumps but the pumps only showed a slight increase in flow rate and
. discharge' pressure.
The pumps were secured at 0612 hours0.00708 days <br />0.17 hours <br />0.00101 weeks <br />2.32866e-4 months <br /> after.
approximately 45 minutes of operation.
The low flow alarm never
cleared whi'le the 58 pump was running *. The low flow alarm cleared
several times for pump 5C but reannunctated each time after clearing.
The inspectors questioned licensee personnel concerning failure of
the SW radiation monitor pumps to operate properly and 1 icensee
personnel stated that they believed. the vacuum on the discharge
tunnel may be having some affect on the inability of the pumps to
operate properly.
Licensee personnel restarted the pumps after the
Unit 2 discharge tunnel pressure had reached zero.inches Hg atid the
vacuum breaker was opened.
After being started, the discharge
pressure for the 58 pump was 35 psig and a one liter sample was
obtained from the sampl_e line in four seconds.
The low flow alarm
did not annunciate.
The *discharge pressure for the 5C pump was 34
psig and a two gallon sample was obtained in 41 seconds.
The
inspectors questioned whether these flow rates met the design
requirements and licensee personnel stated that when the samples were
taken, the sample lines were not isolated from the Unit 1 discharge
tunnel.
Another sample was taken after the sample line for pump 5C
- was isolated from the Unit 1 discharge tunnel and a two gallon sample
was obtained in 24 seconds.
This flow rate met the design *
requirements and appeared to resolve the problems encountered earlier
i~ the test.
It appeared that while the Unit 2 discharge tunnel was
still under vacuum, it affected the suction pressure to the pumps and.
the pumps were not adequately primed.
The inspectors further questioned 1 icensee personnel concerning
whether a similar concern existed on Unit 1 and, if so, what was
being done to address the Unit 1 concern.
Licensee personnel stated
that a similar problem did exist on Unit 1 and consideration was
being given to opening the Unit 1 vacuum breakers and continuing to
operate with the vacuum breaker open.
The 1 icensee conducted a
safety evaluation of this concern and concluded that in the event of
a DBA, operators would be required to break the discharge vacuum
condition by manually opening a vacuum breaker valve.
A JCO-was
prepared and approved by the SNSOC for operators to accomplish this
task in order to continue operation of Unit 1.
The inspectors
verified.that the JCO was implemented.
During the test, the inspectors monitored RSHX SW flow for six hours.
The Band C RSHX SW flow~ and discharge pressures remained in the
acceptable range.
_The data collected during this test had to be*
evaluated by the licensee's engineering organization in order to
determine whether the data met acceptance criteria. Preliminary data
reviewed by the inspectors appeared to indicate that flow rates were
adequate.
-
,=
15
The inspectors considered the licensee's engineering involvement in
identifying and resolving the test discrepancies of the *RSHX SW
radiation monitor sample pumps and _the overall support provided
throughout the test to be a strength. *
b.
EDG Fuel Oil Transfer Pump Testing
During a tour of the EDG fuel oil transfer pump area, the inspector
noted that No. 2 EDG fuel oil transfer pump 1-EE-P-18 had a work
request tag attached, dated January 25.
The tag stated that vibra-
tions were higher than normal and that the pump was noisy.
The 6 EDG
fuel oil transfer pumps are safety related and c;1re in the licensee's
IST program.
In order to evaluate pump 1-EE-P-18 high vibration
- readings, the inspectors requested the pump's vibration history.
On
January 25, 1991 vi bra ti on readings for pump 1-EE-P-18 exceeded the
IST program normal Vibration limits and were in the alert range.
These pumps are normally tested quarterly, but if pump readings are
in th.e alert range the I ST program requires the pump to be tested
monthly.
The inspectors identified that after the high vibration
readings were obtained on January 25, the pump's test frequency was
not increased to monthly.
The inspectors reviewed the vibration
histories for the five remaining fuel oil transfer pumps and identi-
fied that occasionally vibration readings would be in the alert
range.
Test frequency was not increased to monthly when the vibra-
tion readings were in the. alert range. The inspectors reviewed
2-PT-22.3M, Diesel Generator No. 2 Quarterly Exercise Test.
The
procedure required that pumps 1-EE-P-lB and 1-EE-P-lE vibration
readings be taken but did not require the readings to be recorded nor
did the procedure provide vibration acceptance criteria. Procedures
1-PT-22.3L and 1-PT-22.JN, which tested EDGs Nos. 1 and 3 fuel oil
transfer pumps, were similar.
They required that vibration readings
be taken but. not recorded and they did not provide a vibration
acceptance criteria.
,
Failure to test the EDG fuel oil transfer pumps monthly or take
corrective action in accordance with the IST program when vibration
readings were in the alert range is identified as NCV 280,281/
91-10-06.
This violation is not being cited because the criteria
specified in Section V.G.1 of the NRC Enforcement Policy were
satisfied.
The licensee's corrective actions involved retesting pump
1-EE-P-18 in order to obtain vibration readings.
Procedural changes
were initiated to record vibration readings and to provide an
acceptance criteria.
Within the areas inspected, one NCV was identified.
- . --**-***-'*, ..... ~-~-
,:'
.
..
16
8.
Exit Interview*
The inspection scope and results were summarized on May 14, 1991" with
those individuals identified by an asterisk in paragraph 1. The following
su1Ti11ary of inspection activity was discussed by the inspectors, during this
exit.
Item Number
Description and Reference
NCV 50-280/91-10-01
Failure to tagout the correct EDG fuel
transfer pump.
NCV 50-280,281/91-10-02
Failure to sample the -CCW heat exchanger
service water as required by TS.
NCV 50-280/91-10-03
Failure to
properly control
system
_ configuration
resulting
in
rendering
technically inoperable both trains of a
safety system.
NCV 50-280,281/91-10-04
Failure to properly control the Unit 2
transfer canal filling process which
resulted in overflow of contaminated water
into clear areas.
NCV 50-280/91-10-05
Failure to assure_ that proper system
configuration was being maintained during
modification activities.
NCV 50-280,281/91-10-06
Failure to test the emergency diesel
generator fuel oil transfer pumps monthly or
-take corrective in accordance with the
Inservice Test Program when v1bration
readings were in the alert range.
The licensee acknowledged the inspection conclusions with no dissenting
comments.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this .
inspection.
At a supplement~d exit on June 7, 1991, the licensee
co1T111itted to provide additional information and corrective action to the
setpoint control program problem discussed in paragraph 4.~.
12.
Index of Acronyms amd Initialisms
CFR
CODE OF FEDERAL REGULATIONS
COMPONENT COOLING WATER
CORPORATE NUCLEAR SAFETY
EMERGENCY CONDENSATE STORAGE TANK
DESIGN BASIS ACCIDENT
DESIGN CHANGE PACKAGE
...
~ ,, ..
i
GPM
Hg
IFI
ISi
1ST
LER
LCO
NRC
PDTT *
RV
SNSOC
TS
17
DESIGN REFERENCE PROCEDURE
ENGINEERED SAFETY FEATURE
ENGINEERING WORK REQUEST
FINAL SAFETY ANALYSIS REPORT
GALLONS PER MINUTE
HEAT EXCHANGERS
INSTRUMENTATION AND CALIBRATION
INSPECTOR FOLLOWUP ITEM
INSERVICE INSPECTION
INSERVICE TESTING
LICENSEE EVENT REPORT
LIMITING CONDITIONS OF OPERATION
NON-CITED VIOLATION
NET POSITIVE SUCTION HEAD
NUCLEAR REGULATORY COMMISSION
PRIMARY DRAIN TRANSFER TANK
POUNDS PER SQUARE INCH
RECIRCULATION SPRAY HEAT EXCHANGER
RESISTANCE TEMPERATURE DEVICE
RELIEF VALVE
RADIATION WORK PERMIT
SAFETY INJECTION
STATION NUCLEAR AND SAFETY OPERATING COMMITTEE
TECHNICAL SPECIFICATIONS
Unusua 1 Event