ML14191B116
| ML14191B116 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 05/18/1989 |
| From: | Dance H, Garner L, Jury K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14191B115 | List: |
| References | |
| 50-261-89-08, 50-261-89-8, GL-88-17, NUDOCS 8906050210 | |
| Download: ML14191B116 (17) | |
See also: IR 05000261/1989008
Text
PkREG,
1
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
.1
101 MARIETTA ST., N.W.
ATLANTA, GEORGIA 30323
Report No:
50-261/89-08
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H.. B. Robinson
Inspection Conducted: March 11. - April 17,
1989
Inspectors:
A.,2
.
.4
'l
L. W. Garner, Seni
Resfent Inspector
D te
igned
K. R., Jury, Resident insoctor
Date S gn d
Approved by: /
Q
4:
H. C. Danc , Section Chief
Date ig ed
Reactor Projects Section 1A
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation,
system walkdown, onsite followup of events at operating power reactors, mid
loop operations, dry storage of spent nuclear fuel, onsite review committee,
drawing system verification, and followup on previous inspection items.
Results:
One violation was identified involving a failure to follow a procedure.
A
personnel error by a licensed operator resulted in a reactor trip, paragraph
6.a.
Using TI 2515/101 as a guide, the inspectors verified that the licensee's
actions prior to and during mid-loop operations, successfully addressed the
recommended expeditious actions of Generic Letter 88-17, paragraph 7.
A failure of an Electro-hydraulic power supply resulted in a reactor trip. The
failure appeared to be a result of aging balance of plant equipment, paragraph
6.b.
83906050210 B9051B
ADOCYK 05000261
0
PNU
2
The practice of lifting leads to unnecessarily defeat safeguard logic to
preclude inadvertent ESF logic actuations during shutdowns was discussed with
plant management, paragraph 4.
A drawing system verification was conducted in accordance with Resident Action
Item 88-01. No areas of significant concern were identified, paragraph 10.
During this inspection period, the first dry shielded canister containing spent
fuel was successfully loaded into the horizontal storage module, paragraph 8.
Housekeeping practices. in the cointainment vessel need
improvement as
demonstrated by the various miscellaneous pieces of debris and trash observed
during a management inspection, paragraph.2.
REPORT DETAILS
1. Licensee Employees Contacted
R. Barnett, Maintenance Supervisor,' Electrical
C. Bethea, Manager, Training
R. Chambers, Engineering Supervisor, Performance
D. Cracker, Supervisor, Radiation Control
- D. Crook, Senior Specialist, Regulatory Compliance
- J. Curley, Director, Regulatory Compliance.
R.1
- C. Dietz, Manager,
uronson Nuclear Project Department
R. Femal, Shift Forema~n, Operations
W. Flanagan, Manager, Design Engineering
W. Gainey, Support Supervisor, Operations
D. Knight, Shift Foreman, Operations
D. McCaskill, Shift Foreman, Operations
R. Moore, Shift Foreman, Operations
- R. Morgan, Plant General Manager
D. Myers, Shift Foreman, Operations
D. Nelson, Maintenance Supervisor, Mechanical
- M. Page, Acting Manager, Technical Support
D. Quick, Manager, Maintenance
D. Seagle, Shift Foreman, Operations
- J. Sheppard, Manager, Operations
R. Steele, Acting Supervisor, Operations
H. Young, Director, Quality Assurance/Quality Control
Other licensee employees contacted
included technicians, operators,
mechanics, security force members, and office personnel..
- Attended exit interview on April 24, 1989.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. -Operational Safety Verification (71707)
The inspectors observed licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory requirements,
and that the licensee management
control
system
was effectively
discharging its responsibilities for continued safe operation.
These
activities were confirmed by direct observations, tours of the facility,
interviews
and discussions with licensee management
and personnel,
independent verifications of safety system status and LCOs, and reviews of
facility records.
2
Periodically, the inspectors reviewed shift logs, operation's records,
data sheets, instrument traces, and records of equipment malfunctions to
verify operability of safety-related equipment and compliance with TS.
Specific items reviewed include control room logs, auxiliary operator
logs, operating orders, and equipment tag-out records.
Through periodic
observations of work in progress and discussions with operations'staff
members, the inspectors verified that the staff was knowledgeable of plant
conditions; responded properly to alarm conditions; adhered to procedures
and applicable administrative controls; and was
aware of equipment
out-of-service, on-going surveillance testing,-and maintenance activities
in progress.
The inspectors observed shift changes to verify that
continuity of system status was maintained and that proper control room
staffing existed. The inspectors also observed that access to the control
room was controlled and operations personnel were carrying out their
assigned duties in an attentive and professional manner. The control room
was observed to be free of unnecessary distractions.
The inspectors
performed channel checks,
reviewed component status and safety-related
parameters, including SPDS information, to .verify conformance with TS.
During this reporting interval, the inspectors verified compliance with
selected LCOs.
This verification was accomplished by direct observation
of monitoring instrumentation,
valve positions, switch positions, and
review of completed logs and records.
Plant tours were routinely conducted to verify the operability of stand-by
equipment; assess the general condition of plant equipment; and verify
that radiological controls, fire protection controls,
and equipment
tagging procedures were properly implemented.
These tours verified the
following: the absence of unusual fluid leaks; the lack of visual
degradation of pipe, conduit and seismic supports; the proper positions
and indications of valves and circuit breakers; the lack of conditions
which could invalidate EQ, the operability of safety-related instrumenta
tion; the calibration of safety-related and control instrumentation,
including area radiation monitors and friskers;
the operability of fire
suppression and fire fighting equipment; and the operability of emergency
lighting equipment.
The inspectors also verified that housekeeping was
adequate (except as noted below) and areas were free of unnecessary fire
hazards and combustible materials.
On April 10,
1989,
the inspectors accompanied plant management during
their closeout inspection of the CV.
This inspection was conducted in
preparation of Unit restart after work had been performed in the CV.
Several items of trash and miscellaneous debris were observed and removed.
These included: small pieces of insulating materials, partial rolls and
loose pieces of duct tape, small plastic bags,
and cable tie wraps. The
need to improve housekeeping practices in the CV was discussed with plant
management.
0II
3
In the course of the monthly activities, the inspectors included a review
of the licensee's physical security and radiological control programs.
The inspectors verified by general observation and perimeter walkdowns
that measures taken to assure the physical protection of the facility met
current requirements.
The inspectors verified station personnel adhered
to radiological controls.
No violations or deviations were identified within the areas inspected..
3. Monthly Surveillance Observation (61726)
The inspectors observed certain surveillance activities of safety-related
systems and components to ascertain that these activities were conducted
in accordance with license requirements.
For the surveillance test
procedures listed below, the inspectors determined that precautions and
LCOs were met, the tests were completed at the required frequency, and the
tests conformed to TS requirements and were accomplished by qualified
personnel in accordance with an approved test procedure.
Upon testing
completion,
the, inspectors verified that the recorded test data was
accurate, complete and met TS requirements,
and that test discrepancies
were properly rectified.
Specifically, the inspectors witnessed/reviewed
portions of the following test activities:
EST-048
(revision 6) Control Rod Drop Test
OST-406
(revision 6) TSC/EOF/PAP Diesel Generator
OST-617
(revision 8) Low Voltage Fire Detection and Actuation
System Zones 24, 25A, 25B, 25C, and 26
OST-910
(revision 11) Dedicated Shutdown Diesel Generator
No violations or deviations were identified within the areas inspected.
4. Monthly Maintenance Observation (62703)
The inspectors observed several maintenance activities on safety-related
systems and components to ascertain that these activities were conducted
in accordance with approved procedures and TS. The inspectors determined
that these activities did not violate LCOs, and that redundant components
were operable.
The inspectors also determined that activities were
accomplished by qualified personnel using approved procedures,
QC hold
points were established where required, required administrative approvals
and tagouts were obtained prior to work initiation, proper radiological
controls were adhered to, and the effected equipment was properly tested
before being returned to service. In particular, the inspectors observed/
reviewed the following maintenance activities:
WR/JO 89-AEDN1 - C S/G Tube Inspection
4
WR/JO 89-AEDS1 - HVH 4 Tube Inspection for Presence of
Biological Fouling
WR/JO 89-ADUB1 - Troubleshooting and Repair of E-H Power Supply
WR/JO 89-AEBK1
For several years,
the licensee has had an established practice of
defeating safeguard actuation logic when safeguards is not required to be
in-service per TS.
Specifically, logics for phase A and B containment
isolation, containment spray, and SI initiation are defeated by lifting
leads from their respective actuation relay coils.
The lifting of leads
and system restoration is controlled by procedure SPP-011,
Removal and
Restoration of SI Actuation.
This procedure contains verification sign
off steps that the lifted leads are reconnected.
However, the verifica
tion is not specified to be an independent process (i.e., the second
person does not necessarily verify the restored connections are tight).
Furthermore,
neither post-maintenance nor functional testing of the
restored system is performed. The manner in which safeguards is defeated
does not result in abnormal indications in the control room; restoration
of the system is strictly governed by administrative controls.
The
failure of these administrative controls is unlikely; however,
the
potential consequences of having safeguards unavailable if needed, are
large (i.e., severe accident).
In the past, utilization of SPP-011 has
sometimes been for reasons other than personnel safety and equipment
protection (i.e., eliminating the chance of an inadvertent ESF actuation,
thereby reducing the number of reportable events).
Defeating safeguard
logic for these other reasons constitutes an unnecessary defeating of
safeguards.
The currently authorized method of and reasons for defeating
safeguards is a poor practice.
The inspectors discussed with plant
management recommended controls for lifted wire leads contained in IEN
84-37, Use of Lifted Leads and Jumpers during Maintenance or Surveillance
Testing.
The inspectors requested that management review under what
conditions SPP-011 should be utilized, and whether development of an
alternate methodology is practical, preferably a method which would
provide indication. that safeguards is defeated.
Management agreed to
review their current utilization of SPP-011.
No violations or deviations were identified within the areas inspected.
5.
ESF System Walkdown (71710)
The inspectors performed a field walkdown of portions of the RHR system
located in the RHR pit and inside the CV.
Additionally, the SI
accumulator discharge piping from the accumulators to the RCS cold legs
was
inspected.
The
inspectors verified that the sub-systems are
configured as shown on drawings 5379-1082 sheet 4 (revision 20) and sheet
5 (revision 25)
and 5379-1484 sheet 1 (revision 16).
Items .examined
included pumps, valves, instrumentation, piping, and pipe supports. The
inspectors verified that all major valves were in their correct position,
5
manual valves were locked as required, instrumentation was valved into
service, and that power was available to MOVs,
as indicated by the RTGB
indicators and MCC breaker positions. Minor seal weepage (approximately 1
drop or less per minute) was observed on both the A and B RHR pumps.
The
licensee was already aware of and evaluating this condition. Additionally,
two conduit clamps on the hard conduit associated with SI-862A, the RHR
suction valve from the RWST,
were observed to be missing and loose.
This
condition was reported to the licensee for correction.
No conditions
which could render these sub-systems incapable of performing their safety
function were observed.
No violations or deviations were identified within the areas inspected.
6. Onsite Followup of Events at Operating Power Reactors (93702)
a. Personnel Error Causes Reactor Scram
On March 22, 1989, at 2:22 a.m., the reactor experienced a low-low
steam generator level trip from 100% power.
All ESF systems
performed
as expected.
The trip occurred when
an operator
inadvertently closed MS-V1-3A, the A main steamline isolation valve,
while performing OST-202,
Steam Driven Auxiliary Feedwater System
Component Test.
Step 7.2.30.3 of OST-202 requires closing MS-V1-8C,
the SDAFW C steam supply isolation valve. During performance of this
step, the nearby MS-V1-3A switch was operated instead of the MS-V1-8C
switch.
Failure to follow procedure OST-202 is a violation:
Failure
to Follow OST-202 Results in a Reactor Scram, (89-08-01).
The licensee performed a post trip review and returned the Unit to
service at 5:27 p.m., on March 22.
The inspectors reviewed the post
trip review and do not have any unresolved concerns.
b. E-H Power Supply Failure Initiates a Reactor Trip
On March 30,
1989, at 3:20 a.m.,
the reactor experienced a turbine
tri.p/reactor trip from 100% power.
The plant responded as expected
to the transient and all
ESF systems functioned as required.
Subsequent investigation by the licensee revealed that both the A and
B E-H +15 Vdc power supplies had blown fuses. Troubleshooting of the
A +15
Vdc power supply
revealed that several transistors were
leaking.
As a result, the licensee replaced five transistors in the
power supply.
Testing of other components in both the A and B E-H
power supplies did not reveal further cause for the failures.
The
licensee determined.that the most probable failure scenario involved
the following sequence:
-
Failure of the transistors in the A +15
Vdc power supply
resulted .in
an excessive output voltage.
6
A sensing circuit detected the overvoltage condition and blew
the A +15 Vdc power supply fuse as designed.
This circuit also
appeared to prepare the B power supply to pick up the load.
-
This preparation or feedback, plus the loading of the B power
supply, coupled with an output voltage set close to its maximum
limit, resulted in the B +15 Vdc power supply output fuse being
blown by its output voltage sensing circuit.
The licensee was unable to verify this failure sequence as the vendor
no longer employed anyone technically familiar with this obsolete
type of power supply.
The original drawings of the power supplies
had been transmitted to the licensee in late 1988; however, they
could not be located.
After repairs were completed, testing was
performed to demonstrate that the +15
Vdc power supplies would
function properly.
Included in this testing was turning the power
supplies on and off one at a time, with the turbine on-line and below
the turbine trip/reactor trip setpoint.
The inspectors witnessed
portions of this troubleshooting and testing.
In addition, the
inspectors attended a special PNSC which evaluated the actions taken
prior to Unit restart.
The inspectors determined that the licensee
performed as thorough a root cause determination as possible with the
information available.
During
the
November
1988 refueling outage,
the licensee had
originally planned to replace the E-H power supplies with a state of
the art model.
However, due to miscommunication with the vendor, all
the required replacement components were not ordered.
The licensee
then attempted to rebuild the power supplies; however, they were
limited to only a partial overhaul due to lack of available parts.
The most likely failure cause was end of life or aging. Much of the
BOP control systems are original hardware which is outdated.
This
situation has
been discussed with plant management.
A study,
initiated earlier this year, is in progress to evaluate what E-H
system improvements need to be made. Results of the study should be
available by the end of 1989.
c. Loose Part in C S/G
On April 2, 1989, at 7:09 p.m., 7:57 p.m., and 8:12 p.m., both the
secondary and primary side LPMS channels associated with the C S/G
alarmed.
The last alarm sealed-in and could not be. reset. Tours of
the secondary side, both inside and outside of the CV, as well as the
primary side of the C S/G, revealed no external cause for the LPMS
alarm.
Evaluation of the audio signals indicated that there was a
loose part in the C S/G hot leg channel head.
As a result, at 3:52
a.m.
the reactor was placed in hot shutdown.
Based upon a
recommendation from
the C RCP was left in service
until preparations were completed to enter the.C S/G.
Retrieval of
7
the loose part required the Unit to be placed in mid-loop operation.
Inspection of mid-loop operations per. TI 2515/101 is discussed in
paragraph 7.
On April 7, during removal of the manway diaphragm, a loose part fell
out of the S/G.
Having prepared for such a potential event, the part
was rapidly retrieved with tongs and placed in a lead pig.
Visual
inspection by a remote monitor identified the piece as a control rod
guide tube support pin nut (split pin nut).
The piece was found to
be approximately 1 inch in length, 0.75 inches in diameter, and 0.25
lbs.
in weight.
The piece was shipped to Westinghouse,
which
subsequently confirmed the piece as being a split pin nut with the
threaded section of the split pin stud contained within. Examination
by a scanning electron microscope of the pin shank fracture face
revealed that the failure of the pin shank-below the threaded area
resulted from stress corrosion cracking.
No previous failures of split pins have occurred at HBR; however,
similar failures have occurred at other plants. The only difference
between this occurrence and other industry occurrences is the long
-service time before failure.
Typically, split pin failures have
occurred within the first four or five years of commercial operation.
HBR has been in operation for eighteen years.
Westinghouse has
performed a safety evaluation, SECL-89-630, which justifies operation
of the Unit until the next refuelina' outage. The inspectors reviewed
this evaluation and attended the special PNSC meeting on April 10,
which reviewed Westinghouse's input and authorized restart of the
Unit. In summary, restart was authorized based upon the following:
(1) Operation with a broken split pin is not a concern since the
remaining section is trapped between the guide tube flange and
upper core plate, thereby still providing lateral support for
the guide tube as designed.
(2) Examination of the C S/G internals, including tubesheet, tube
ends, tube to tubesheet welds, divider plates, and tube sheet to
divider plate welds,
did not reveal conditions that required
immediate repair (initial phase of the inspection was observed
by the inspectors).
(3) Failure of other split pins would not cause damage to the
reactor or its internals which would result in a safety concern.
Transport of a loose part into a S/G would result in a forced
shutdown to remove it.
With regard to item (1) above, prolonged operation could result in
wear of the pin body, thereby allowing a limited amount of lateral
displacement of the bottom of the guide tube.
This could result in
additional RCCA frictional forces with the side of the guide tube,
8
resulting in an increase in scram time for the affected RCCA. Based
upon analysis for similar plants, the maximum scram time is not
anticipated to exceed the HBR TS value. However, as no analysis was
performed
specifically for
HBR,
recommended the
following actions be taken:
(1) verify rod drop times prior to power
operation; (2) review previous rod drop data to assure no increasing
trend of rod drop times; and (3) evaluate.rod stepping tests for
abnormalities.
On April 11,
the licensee performed cold rod drop
tests and subsequently determined that there was not an increasing
trend for any rod.
The inspectors independently reviewed the rod
drop test times since November 1984,
and determined that there was
not a discernible pattern which would indicate degradation of any
RCCA scram time.
Cold rod drop times ranged between 1.14 and 1.30
seconds.
Comparison of previous hot and cold test data indicates
there is no significant difference between the times measured at cold
conditions and those measured at hot conditions.
The licensee anticipates an action plan will be developed by July
1989,
to address this issue during the upcoming refueling outages.
This issue is an IFI:
Review Long Term Resolution of Split Pin
Cracking Issue, (89-08-02).
d. RHR System Leakage Design Basis Not Met
On April 10,
1989, the licensee determined that potential leakage
into the RHR pit could not be successfully isolated under certain
accident conditions as required by the system design basis. Actions
taken by the licensee to address this item,
as well
as the
inspectors'
verification of these actions, will be discussed in
Inspection Report 89-09.
One violation was identified in the areas inspected.
7. Loss of Decay Heat Removal, GL 88-17 (TI 2515/101)
On October 17, 1988, the NRC issued GL 88-17, Loss of Decay Heat Removal.
On January 3, 1989, the licensee submitted to the NRC what actions they
had taken in implementing the eight GL recommended expeditious actions.
The inspectors reviewed the licensee's response and verified that the
actions committed to had been implemented prior to entering mid-loop
operations on April 6, 1989.
The
inspectors verified, via review of the lesson plan,
Mid-loop
Operations and Loss of Decay of Heat Removal,
and training records from
TI-906 and TI-301, that licensed operators were provided training on
previous applicable industry events that occurred during mid-loop
operations. This included the April 10, 1987 Diablo Canyon event, as well
as events at San Onofre 2 and Waterford 3. For each case, the sequence of
events,
safety concerns,
and contributing factors were addressed with
9
emphasis placed on applicability to HBR.
Special topics included
pressurization, vortexing, RHR flow changes, and instrumentation problems.
Through discussions with licensed operators, the inspectors verified they
were knowledgeable of the concerns associated with mid-loop operations.
The procedural changes to address the GL 88-17 action items were developed
subsequent to this training.
The inspectors verified, via interviews with
operations personnel,
that shift training was conducted on the revised
procedures prior to the shifts standing watch during mid-loop operations.
The inspectors consider item 1 of GL 88-17 as being satisfactorily
addressed.
The inspectors reviewed OMM-030,
Control of CV Penetrations During Mid
Loop Operations, revision 0, and GP-008,
Draining the Reactor Coolant
System,
revision 18.
The inspectors verified that these procedures
contain sufficient detailed instructions to establish and maintain CV
integrity as described in GL 88-17.
This meets GL 88-17 item 2. GP-008
also provides the requirements to record four core exit thermocouple
temperatures (one of the designated two trains) every 15 minutes and log
water level values every 15 minutes.
The water level values are taken
remotely from control room instrument LT-403 and locally at the B loop
standpipe (associated with LT-403) and at a standpipe installed on loop C.
The inspectors evaluated the routing of the C loop standpipe to ensure
that no conditions existed to render the indicated level inaccurate.
The
inspectors also visually verified that the B loop and C loop standpipes
provided consistent level data and that this data,
as well as temperature
data was recorded every 15 minutes. In addition, GP-008 provides that one
SI pump and one charging pump must be available with injection pathways,
prior to reducing water level to -36 inches below the RV flange.
These
procedure requirements are sufficient to address items 3, 4, and 6 of GL 88-17.
GP-008 also contains a caution note to: "Avoid any evolution that could
result in perturbation of the RCS while in a reduced inventory condition.
This includes anything that could impact RCS level, the operating train of
RHR,
or any required support equipment."
The inspectors consider this
caution note coupled with the recovery steps provided in AOP-020, Loss of
Residual Heat Removal (Shutdown Cooling), Revision 6, to be adequate to
address item 5 of GL 88-17.
The licensee's response concerning use of aluminum nozzle covers on the
S/G to preclude materials from falling into the RCS is considered adequate
to address item 7 of the GL 88-17.
However, the inspector requested the
licensee to establish measures to ensure this item is addressed if nozzle
dams are used in the future at HBR.
The inspectors determined that
item 8, concerning loop stop valves, is not applicable to HBR, as HBR does
not have loop stop valves.
Based upon the above described inspections, the inspectors considered that
the licensee has taken satisfactory interim measures to address the eight
expeditious actions of GL 88-17 (which preclude or successfully mitigate
10
the loss of decay heat removal during reduced inventory conditions.)
The
inspectors plan to review implementation of the six programmed enhancement
recommendations of GL 88-17 as they are completed.
No violations or deviations were identified in the ares inspected.
8. Loading of First DSC Into HSM (TI 2690/004)
On March.16, 1989, the inspectors witnessed the alignment and loading of
the first DSC containing spent fuel assemblies into the HSM.. . The
inspectors verified that the docking of the trailer and movement of the
DSC into the HSM.was performed in accordance-with procedure ISFS-004,
Alignment and Loading of the Dry Shielded Canister into the Horizontal
Storage Module, revision 4. The inspectors verified that HP practices and
procedures were adhered to during this operation.
Additionally, the inspectors reviewed ISFS-006, Startup Monitoring of the
Horizontal Storage Module, revision 0. ISFS-006 acceptance criteria for
dose rates are less than 200 mrem/hr (neutron + gamma) at center of air
inlets or outlets and front access cover,
and less than 50 mrem/hr
(neutron + gamma)
at other locations.
Data taken indicated that these
acceptance criteria were met.
Maximum total neutron and gamma doses
measured were 40.5 mrem/hr at the front air outlet (200
mrem/hr
allowable),
20.5 mrem/hr on the roof (50 mrem/hr allowable),
and 15.5
mrem/hr at the air inlet (200 mrem/hr allowable).
The maximum neutron
dose measured was 2.5 mrem/hr in front of the HSM. In addition, the air
temperature rise through the HSM was shown to be 28 degrees F, well below
the 100 degrees F allowable.
On April 12,
1989,
a second DSC was loaded into the HSM.
Measured
radiation dose rates for the second DSC were similar to those described
above for the first DSC.
The inspectors plan to periodically monitor
future activities involving the DSCs and their respective loadings into
the HSMs.
No violations or deviations were identified in the areas inspected.
9. Onsite Review Committee (40700)
The inspectors evaluated certain activities of the PNSC to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements. In particular, the inspectors attended
the March 30,
1989 PNSC concerning the E-H power failure, the April 10,
1989 PNSC concerning the loose part in C S/G and RHR pit leakage, and the
April
13,
1989
PNSC concerning the RHR pit leakage issue.
<It was
ascertained that provisions of the TS dealing with membership, review
process,
frequency,
and qualifications were satisfied.
The inspectors
followed
up
on selected previously identified PNSC activities to
independently confirm that corrective actions were progressing
satisfactorily.
11
No violations or deviations were identified within the areas inspected.
10.
Drawing System Verification
The inspectors performed an inspection per RAI 88-01 of the licensee's
drawing control system.
The inspection consisted of:
(1) a drawing
quality review (legibility); (2) current revision verification; (3)
verification that drawings reflect as-built configuration; (4) review of
the drawing backlog requiring changes; and (5) review of controls to
maintain marked up drawings prior to permanent revisions.
Items (1) and
(5) involved review of the controlled copies assigned to the control room.
Item (2) involved controlled copies assigned to the control room and the
EOF.
The drawing control system associated with drawings important to
facility operation was found to be adequate, with minor exceptions.
Legibility of drawings was found to be acceptable.
All major flow path
components on P&IDs were readable.
Cross references.from one line to
another were readable. A small number of vent valves, drain valves and
instrument numbers were legible, although difficult to read.
Examples
include: instrument TE-3092C on G-190199 sheet 1, valve SW-88 on G-190199
sheet 6, instruments TX-1683B and PX-1619 on G-190199 sheet 9, valves
SW-548 and SW-549 on G-190199 sheet 4, and valve CAR-10 on G-190197 sheet
2. On sheet 11 of G-190199, a valve adjacent to valve SW-616 on piping
line 2-CW-280 was not readable.
One example was identified in which the
revision number was not legible (drawing 5379-3232).
Each P&ID maintained
in the control room for major systems are in plastic folders.
This
practice greatly reduces the amount of drawing wear and tear which would
normally otherwise occur. Safeguards System and Reactor Protection System
drawings contain many relay contacts and instrument.numbers which are
difficult to read.
However, by comparing similar components in the other
division, process of elimination, and/or deductive reasoning,
(e.g.
sequence and patterns of labeling nomenclature),
it is possible to deduct
the proper numbers.
This area could be improved.
Eighty-eight drawing revisions were audited for latest revision number by
comparing the field revision with that contained in the master index or
with the current document control drawing.
Discrepancies were not
identified in the control room drawings set; however, the drawings in the
EOF were observed to have three discrepancies.
An outdated revision of
drawing G-1990199 had not been removed.
Sheets 3 and 4 of drawing
5379-1082 were misfiled with HBR2-8255 sheet 5.
Revision 13 of drawing
5379-3238 was filed in the proper place; however, the latest revision,
number 14, was filed in front of the set of drawings. The TSC drawing set
was not audited, as the same individual responsible for the EOF drawings
is also responsible for the TSC drawings. The licensee conducts an audit
program which verifies proper revisions and current condition of each
controlled drawing set.
During review of this program, the inspectors
discovered that the audit scope and frequency were not procedurally well
defined.
Thus,
when drawing personnel were changed in 1987, the audit
12
scope changed due to a misunderstanding of what had been done previously.
The inspectors also determined that the master index (hard copy) had four
erroneous entries (i.e., revision numbers were not updated when the
drawings were issued).
This condition apparently occurred earlier in the
year when reassignment of duties resulted in a different individual being
responsible for maintaining the master index current. In each instance,
the computer-based system, utilized by operations, contained the correct
information.
Selected portions of the SI,
RHR,
and Feedwater Systems drawings were
as-built verified by field walkdowns.
No major discrepancies were
identified.
The P&IDs as structured by the licensee do not contain
instrument vent, drain, and other instrument valving downstream of the
instrument root isolation valves.
The inspectors observed that check
valves were not consistently tagged.
Also, several valve tags were
missing.
Examples include FCV-1424 and-small test vent and drain valves.
With one exception, all configurations were correct as shown.
Flow
element FE-1425C and associated root valves AFW-96 and AFW-97 are shown on
sheet 4 of G-190197 as being located in the AFW pump room.
A November
1988 outage modification moved the flow element to the auxiliary building
hallway.
The inspectors were unable to determine before issuance of this
report if a change had been initiated to correct G-190197.
Revisions to drawings are controlled in accordance with MOD-004,
Plant
Drawing Preparation, Revision, and Approval.
Attachment 6.3 of MOD-004
requires updating of priority A drawings within 28 working days of
submitted changes to drafting.
Priority B drawings are required in 35
working daysand priority C drawings are to be issued within 60 days.
Flow, logic, safeguard, reactor protection, and control wiring diagrams
are assigned a priority A. Valve and instrument lists, as well as piping
and electrical penetration drawings are categorized as priority B.
The
drawings in the control room,
TSC and EOF are generally priority A
drawings.
A review of the outstanding drawing revision index did not
reveal a backlog of priority A and B drawings, (i.e., outstanding A and B
priority drawing revisions were either in process, or the change had just
been received).
Review of revision issue dates for this year indicated
that the' 28 and 35 day requirements were being met.
During the last
refueling outage, priority A and B drawings were completed prior to
declaring modifications operable. Thus, there are no "red-lined" drawings
currently in use.
MOD-004 does provide for issuing a drawing revision
notification to all controlled drawing copy holders if a drawing revision
is not anticipated to be available when needed.
In summary, the drawing control 'system is well maintaining drawings most
likely required to be referenced during normal and emergency operating
situations with only minor exceptions as noted above. The exceptions were
discussed with the licensee for correction as they deem necessary.
No violations .or deviations were identified within the areas inspected.
13
11.
Licensee Action on Previously Identified Inspection Items (92701)
(CLOSED) LER 87-30, Non-redundant Power Supply To Vital Equipment Due to
Original System Design.
On December 20,
1988,
the licensee declared
Modification M-966 operable.
M-966 corrected the single failure design
problem by installing two redundant pressure switches,
PC-600A and
PC-601A, such that each switch is associated with only one division of
SI-862 and SI-863 valves.
Switch PC-600A is wired into the control
circuit for SI-862B -and 863B; switch PC-600B is wired into the control
circuit for SI-862A and 863A.
Hence, the failure of one switch would
affect only the valves of its respective division.
The inspectors
verified that the redesigned circuit meets the single failure criteria,
the switches had been calibrated, and the acceptance test performed was
adequate to demonstrate proper functioning of the valve interlocks.
(OPEN) IFI 88-28-05, Licensee to Develop Methodology to Detect Biological
Growth in HVH 1-4.
During the November 1988 refueling Outage, the
licensee modified the SW System to control the biological growth in the SW
System by chlorination.
The purpose was to reduce the potential for
biological fouling of components served by the SW System (i.e., the CV fan
coolers).
On April 9, 1989, the inspectors witnessed inspection of the
HVH-4 upper tube bundle.
An insignificant amount of what may have been
biological material was observed at the tube edges. This material did not
effect the SW flow through the cooler; however, six tubes were partially
blocked by foreign material,
possibly weld slag.
The small number of
affected tubes have no impact on the operability of the cooler.
Based
upon the inspection, the chlorination program appears to be successfully
controlling biological growth.
During early April,
a monitoring system was installed to help detect
fouling in HVH-4.
This item remains open pending review of the
effectiveness of this system and the effectiveness of the chlorination
system during different seasons.
No violations or deviations were identified within the areas inspected.
12.
Exit Interview (30703)
The inspection scope and findings were summarized on April 24,
1989, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection findings listed
below and those addressed in the report summary. Dissenting comments were
not received from the licensee.
Proprietary information is not contained
in this report.
14
Item Number
Description/Reference Paragraph
89-08-01
-
Failure to Follow OST-202,
Resulting in a Reactor Scram,
paragraph 6.a.
89-08-02
IFI -
Review Long Term Resolution of
Split Pin Cracking Issue,
paragraph
6.c.
13.
Acronyms and Initialisms
Abnormal Operating Procedure
Balance of Plant
CV
Containment Vessel
Dry Shielded Canister
- E-H
Electro-hydraulic
Emergency Operation Facility
Engineered Safety Feature
EST
Engineering Surveillance Test
F
Fahrenheit
Flow Control Valve
Flow Element
GL
Generic Letter
General Procedure
HBR
H. B. Robinson
Health Physics
HSM
Horizontal Storage Module
HVH
Heating Ventilation Handling
IFI
Inspector Followup Item
ISFS
Independent Spent Fuel Storage
LCO
Limiting Condition for Operation
LER
Licensee Event Report
LPMS
Loose Parts Monitoring System
LT
Level Transmitter
Motor Control Center
Motor Operated Valve
mrem/hr
millirem/hour
MS
Nuclear Steam Supply System
OMM
Operations Management Manual
OST
Operations Surveillance Test
Piping and Instrumentation Diagram
Personnel Access Portal
PNSC
Plant Nuclear Safety Committee
Resident Action Item
Reactor Coolant Pump
15
Reactor Turbine Generator Board
RV
Reactor Vessel
Steam Driven Auxiliary Feedwater
S/G
Safety Injection
Safety Parameter Display System
SPP
Special Process Procedure
TI
Temporary Instruction
TS
Technical Specification
Vdc
Volts Direct Comment
WR/JO
Work Request/Job Order