ML17300A885
| ML17300A885 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 05/15/1987 |
| From: | Ball J, Fiorelli G, Ivey K, Richards S, Sorensen C, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17300A883 | List: |
| References | |
| TASK-2.E.4.2, TASK-2.F.1, TASK-TM 50-528-87-10, 50-529-87-11, 50-530-87-12, GL-85-06, GL-85-22, GL-85-6, IEB-86-003, IEB-86-3, NUDOCS 8706050256 | |
| Download: ML17300A885 (51) | |
See also: IR 05000528/1987010
Text
U. S.
NUCLEAR REGULATORY CGYMISSION
REGION
V
Report Nos:
Docket Nos:
License
Nos:
Licensee:
Facilit
Name:
50-528/87-10,
50-529/87-11,
50-530/87-12
50-528, 50-529,
50-530
Arizona Nuclear
Power Project
P. 0.
Box 52034
Phoenix,
AZ. 85072-2034
Palo Verde Nuclear Generating Station Units 1,
2 5 3.
Ins ection Conducted:
February 23, through April 4, 1987.
Inspectocs:
Rl
R.
Zimme
, Senior
esi ent
nspector
J.
a
,
ident Inspector
/5 d'7
at
i ned
/s'7
at
gned
iore
,
es
ent
nspe tor
a
gne
Approved By:
K. Ivey
si ent Inspect r
orens,
rogect Insp
tor
S.
c
r s,
ie
,
ng
eering
ection
at
Si
ne
/s 8
Dat
igne
Mz~ gT
e
igned
Summary:
Ins ection
on Februar
23, throu
h A ril 4, 1987,
Re ort Nos.
50-52
-10
50-529
8 -11,
an
5 -530 8 -12
t
g
8706050256
870521
- DOCK 05000528
6
Areas Ins ected:
Routine, onsite, regular
and backshift inspection
by
t e four resident inspectors,
and one regional inspector.
Areas
inspected
included: followup of previously identified items; review of
plant activities; plant tours; engineered
safety feature
system
walkdowns; surveillance test witnessing; plant maintenance; initial fuel
load witnessing;
preoperational
test results
review; overall startup test
program; operational staffing; quality assurance
for measuring
and test
equipment
(NIENTE); inoperable pressurizer
heater control switch;
pressurizer
level control problems; verification of containment
inte rit
eneric letter followup; TMI Action Plan Items; 50.55(e)
reports
(DERs); design
changes;
licensee
event report followup; and
periodic and special
reports
review.
Ouring this inspection the following Inspection
Procedures
were covered:
25401,
30702,
30703,
35744,
35750,
36301,
37301,
61715,
61720,
61726,
62703,
70322,
70324,
70326,
70532,
70534,
70537,
70539,
70548,
70554,
71302,
71707,
71710,
72400,
72500,
72524,
90712,
92700,
92701,
92703,
92719,
93702,
94300.
Results:
Of the 20 areas
inspected,
two violations were identified.
Failure to remove from service
a piece of measuring
and test equipment
which was overdue for calibration - paragraph
8; and fai lure to satisfy
a
Technical Specification associated
with pressurizer
heater operability-
paragraph
9.
DETAILS
Persons
Contacted:
The below listed technical
and supervisory
personnel
were
among
those contacted:
Arizona Nuclear
Power Pro ect
"R. Adney
~J. Allen
- L. Brown
R, Buckhalter
"J.
R.
Bynum
B. Cederquist
J.
Dennis
W.
Fernow
- D. Gouge
- J.
G.
Haynes
- W.
E.
Ide
W.
Jump
J. Kirby
A. McCabe
0 ~ Nelson
- R. Nelson
G. Perkins
~J. Pollard
F. Riedel
- T. Shriver
L. Souza
"E.
E.
Van Brunt, Jr.
R. Younger
"0. Zeringue
Operations
Superintendent,
Unit 2
Operations
Manager
Radiation Protection
and Chemistry Manager
Outage
Management
Superintendent,
Unit 3
PVNGS Plant Manager
Chemical
Services
Manager
Operations
Supervisor,
Unit 1
Training Manager
Operations
Superintendent,
Unit 3
~ Vice President,
Nuclear Production
Corporate guality Assurance
Manager
Startup
Manager,
Unit 3
Project Transition Manager
Assistant Startup
Manager,
Unit 3
Operations
Security Manager
Maintenance
Manager
Radiological Services
Manager
Operations
Supervisor,
Unit 2
Operations
Supervisor,
Unit 3
Compliance
Manager
Assistant guality Assurance
Manager
Executive Vice President
Operations
Superintendent,
Unit 1
Technical
Support
Manager
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
"Attended the Exit Meeting on April 3, 1987.
Previousl
Identified Items
Unit 1
Closed
Enforcement
Item
528/85-26-04):
Overtime Controls.
The licensee
issued
Procedure
Change Notice No.
2 to procedure
10AC-OZZ07, "Overtime Limitations" on January
19, 1987.
This change
increased
the unit staff governed
by the overtime controls to
include engineering
personnel
involved in taking measurements
or
making physical
changes
or adjustments
to installed safety related
equipment.
This item is closed.
Unit 2
a.
Closed
Followu
Item
529/86-26-01:
Non-Class
Blowers
Coolin
Radiation Monitors.
This matter dealt with the
use of air blowers to cool radiation
monitors to extend the operating lives of the instruments.
New
circuit boards
which are rated for higher temperature
operation
have
been purchased
and are being installed in the Unit 2
Technical Specification effluent monitors.
Plans are'to
replace
the boards in similar radiation monitoring units in
both Units 1 and
3 in the near future.
This item is closed.
b.
Closed
Enforcement
Item
529/86-32-04):
Licensee
Event
Re ort
LER
Failed to Include Cause of Valve Failure.
The inspector
reviewed documentation
which supported
the
completion of actions
taken
by the licensee
in connection with
the referenced violation.
These actions
included the
inspection
and cleaning of mufflers on similar solenoid valve
mufflers as installed
on SGB-500/, training of craft personnel
on the need for thoroughly documenting work performed
and
observations
made,
and the issuance
of a supplement
to Unit 2
LER 86-46 describing the cause of the failure of valve
SGB-500(.
A modification package for the removal of the
mufflers has
been
issued for each of the three units.
The
actions are considered
consistent with the licensee's
response
to the violation.
This item is closed.
C.
Closed)
Followu
Item
529/86-32-06
- Maintenance
and Testin
on Valve SGB-UV 222.
This matter is related to followup actions taken by the
licensee to confirm the cause for the dual position indication
related to valve
SGB-UV 222 during an actuation
on
September
22,
1986.
The inspector
observed
work 'documents
associated
with the reed switch adjustment
on the valve and the
successful
retest of the valve stroke
and position indication.
This item is closed.
d.
Closed
Followu
Item
529/86-32-07
- Combustible
Gas
Prep erational
Test Problem.
This matter dealt with a licensee
commitment to conduct
training discussions
related to radiation controls with plant
personnel
as
a result of a radiation airborne incident which
occurred during the testing of the Unit 2 hydrogen-oxygen
monitor system.
Discussions with several
radiation staff
members
and maintenance
personnel
by the inspector
determined
that discussions
dealing with radiation controls
have
been
conducted
since the incident.
Several
such training sessions
were conducted prior to the Unit 2 extended
maintenance
outage.
Plans
are to continue these
discussions
as part of the "equality
Talk" sessions
held routinely by the plant staff.
This item is
cl osed.
Unit 3
a.
(Closed
Followu
Item (530/86-03-03
- Redundant
Class lE
Racewa
Mounted on a
Common
Su
ort.
b.
This item dealt with a concern raised during the
NRC
headquarters
Construction
Assessment
Team
(CAT) inspection of
Unit 3 conducted
in January,
1986 relating to the mounting of
class
1E raceways
of redundant trains
on a
common support,
and
a perception that
a single failure could possibly
effect more
than
one train of equipment required for safe
shutdown
adversely.
Engineering evaluations
including walkdowns of
plant areas
were performed
by the licensee to assure
that
potential
hazards either by fire or high energy missiles
were
accounted for in the plant design.
A review of the licensee's
evaluations
and confirmatory walkthroughs of plant areas
by the
inspector identified no discrepancies
in the licensee's
analyses.
Based
on this review, the inspector
concluded that
it appears
the licensee
has adequately
assessed
the impact of a
single failure of a raceway support
on redundant trains of
safety-related
equipment.
This item is closed.
Closed
Fol 1owu
Item
530/86-03-08:
Seismic
ualification of
Diesel Generator
Control Cabinets.
This item dealt with a concern raised during the
NRC
headquarters
CAT inspection of Unit 3 conducted in January,
1986, relating to the seismic qualification records for the
class
1E diesel
generator control cabinets.
In particular,
certain documentation
was not found which was
needed
in order
to adequately
determine the resolution of test discrepancies
found during the initial seismic test.
At the time of the
inspection,
the licensee
committed to update the qualification
records to reflect later retest results.
During this
inspection,
the inspector
reviewed documentation
of the retests
.
that were conducted
and concluded the licensee
had adequately
addressed
the original test discrepancies.
This item is
closed.
C.
Closed
Followu
Item
530/86-03-14
HVAC Exhaust For
Installation Acce tance Criteria.
This item dealt with a concern raised during the
NRC .
headquarters
CAT inspection of Unit 3 conducted in January,
1986, relating to a lack of clear acceptance criteria for the
tightening of the nuts anchoring the diesel
generator
exhaust
fans to the Diesel
Generator
Building on fabreeker
pads
using
embedded
anchor bolts.
This concern
was documented
by the
licensee
on Corrective Action Report
(CAR) S-86-13.
During
this inspection,
the inspector
reviewed the response
given to
the
CAR and the actions
taken
by the licensee
which included
revision to construction specifications to clearly define the
acceptance criteria for these installations
and confirmation
that the fans installed in all three units met the criteria.
Based
on the action taken
by the licensee
and the inspector's
review, this item is closed.
Closed)
Followu
Item
530/86-03-21:
Thermal
Loadin
of
Structural Steel.
This item dealt with questions
raised during the
NRC
headquarter's
CAT inspection of Unit 3 conducted
in January
1986
as to whether thermal effects
on seismic category I steel
structures
had been adequately
considered
in the plant design.
This matter was referred to
NRR for resolution.
In Supplement
No.
10 of NUREG-0857, "Safety Evaluation Report Related to
Operation of Palo Verde Units 1, 2,
and 3",
NRR documented its
conclusion
based
on additional information provided by the
licensee that the licensee's
approach
to handling thermal
effects
was acceptable.
Based
on the conclusion
reached
by
NRR, this item is closed.
Closed
Followu
Item
530/86-03-22
Desi
n Chan
e
Documentation.
The original concern involved several
instances
where
a design
change
was
made
and referenced
to a specific design
document
without changes
being made to other applicable design
documents.
Also involved were documentation
errors
on certain
Field Change
Requests
(FCRs).
The licensee
requested
Bechtel, in writing, to address
these
concerns.
Bechtel
responded
by stating that the problems
identified were strictly associated
with specific valves that
were procured
under the
Non Traditional Acquisition program.
This program allowed
a quicker acquisition time because
components
were acquired
from nuclear power plants that had
been cancelled
and therefore,
components
acquired
under this
program
had already
been certified.
Approximately 63 valves were identified in Unit 3 which were
acquired in this manner.
The valves were inspected
and design
documents
were reviewed to ensure
conformance to the as-built
condition.
Where design
documents
were not in agreement with
the as-built,
changes
were issued.
Also, the documentation
errors associated
with the
FCRs were
determined to be minor in nature.
Since the only way to change
an
FCR is to issue
a new one to supercede
the old one,
a
decision
was
made not to issue
new FCRs.
The inspector
found this response
to be acceptable
and this
item is closed.
(Closed
Followu
Item
530/86-20-01):
Valve 0 erator
Dama
e
Followin
Primar
H drostatic Testin
.
This item concerned
the affects of a solid plant transient
event which occurred
subsequent
to the reactor
coolant system
initial, primary hydrostatic test
when
pump
was started
during the system
cooldown.
During this event,
the
valve motor operator for an isolation valve located
on one of
the two shutdown cooling lines was
damaged.
At the time of the
event,
the cause of the
damage
sustained
by the valve operator
had not been completely evaluated.
During this inspection,
the
inspector
reviewed the actions
taken
by the licensee
in
determining the root cause for the valve damage
and what if any
other
damage
may have
been sustained
by the piping system.
Further,
the inspector's
review considered
what generic
implications this event might have to similar installations.
The licensee,
based
on
a detailed examination of the valve
operator
and
a review of installation records for the affected
valve, concluded that the operator-to-valve
yoke bolts/nuts
had
been under-torqued.
The loose bolting is considered
to have
left the valve in a weakened condition such that the piping
vibration that was experienced
during the starting of the
pump shook the valve operator to a degree that
it sustained
damage that would not normally be expected to
occur during such
an upset condition.
The licensee
performed
a
detailed walkdown of the piping system.
Ho other discrepancies
were noted.
Subsequent
inspection of 100 other valves
identified some other instances
in which, when retorqued,
slight bolt movement occurred;
however, in most cases
no
movement
was found.
The licensee
concluded that slight
movement
was not necessarily
indicative of under-torquing
during initial installation.
The licensee
concluded in Startup
Field Report SI-171 that based
on sample size the failure to
properly torque the valve bolting did not appear to be
a
generic
problem or to have affected the operability of other
valve installations.
Items identified by the licensee
as not
meeting specific torque requirements
have
been
reworked.
Based
on the corrective actions
taken by the licensee
and the
inspector's
review, this item is closed.
(Closed
Followu
Item (530/86-26-01:
Si nificant
E ui ment
Problems Identified Durin
Hot Functional Testin
.
This item related to concerns
by the inspector associated
with
several
equipment
problems that developed during Hot Functional
Testing.
These
included
a problem with a leaking letdown heat
exchanger
nozzle;
instrument nozzle which
also developed
a leak; the unanticipated
opening of a main
steam isolation valve (MSIV); and,
problems with the vital AC
inverters.
During this inspection,
the inspector
reviewed the
actions
taken
by the licensee to correct and define the root
cause for these
problems.
Both the leaking nozzle
on the
letdown heat exchanger
and
on the steam generator
were repaired
and
a root cause
analysis
performed
by the licensee.
The
analysis of the leaking heat exchanger
nozzle indicated that
fatigue and an inadequate
weld design contributed to the
failure while the failure of the steam generator
nozzle
has
been attributed to damage
sustained
during construction
activities.
Problems with the vital
AC inverter were corrected
by the licensee
by a modification to the inverter circuitry
which lessened its sensitivity to momentary voltage
perturbations
on the
DC bus.
Troubleshooting of the MSIV by the licensee;
however, did not
determine
what caused
the unanticipated
opening of the valve.
By letter dated March, 20,
1987, the licensee
committed to the
NRC to reperform troubleshooting efforts during post core hot
functional testing in an effort to duplicate the previous
event.
The inspector will continue to monitor the licensee's
efforts in this event.
Based
on the inspector's
review of
actions taken
by the licensee
and the commitments
made, this
item is closed.
3.
Review of Plant Activities
a.
Unit 1
Unit 1 was restarted
and entered
Mode 1 on March 4, 1987,
ending
an unscheduled
45 day outage for steam generator
tube
plugging.
Power was reduced to Mode
2 on March
5 to repair
valve and hanger
damage
which resulted
from a water
hammer
in
the heater drain tank high level
dump lines.
The unit entered
Mode 1 again
on March 6 and was increasing
power when
a turbine
trip was received
on high moisture separator
reheater
(MSR)
water level.
Work on the
MSR level control
was completed
and
power raised to 100K on March 7.
For the period from March 7
to March 27, reactor
power was increased
and decreased
as
necessary
for condenser
tube plugging,
steam generator water
chemistry problems,
and condensate
demineralizer
problems.
Full
power operation
was maintained
from March 27 to the end of this
reporting period.
b.
Unit 2
C.
Unit 2 restarted
from a 59 day scheduled,
maintenance
outage
on
March 9, 1987.
Two outages of short duration were required
on
March 11 and March 17 to locate
and plug main condenser
tube
leaks.
The plant was restarted
on March 20 and power raised to
50K.
Loss of a heater drain
pump and erratic operation of the
pressurizer
level instrumentation
(paragraph
10) resulted in
50K power operation until March 28 when the pressurizer
level
control instrumentation
was repaired.
A short period of
operation at 85K was required
on March 30 due to an inoperable
control element
assembly calculator.
Following repairs,
power
level was raised to lOOX and full power operation
was continued
through the end of the reporting period.
Unit 3
During this report period,
the licensee
performed final reviews
of system construction completion
and preoperational
testing,
~
and completed surveillance testing of systems
required for
initial entry into Mode 6.
On March 25, 1987, the licensee
was
issued
a low power operating license permitting the licensee
to
commence
loading fuel.
On April 4, 1987,
the licensee
entered
Mode
6 with placement of the first fuel assembly in the reactor
vessel.
During this report period, repairs to the "B" Diesel
Generator
engine block and crankcase,
which were
damaged during
preoperational
testing,
were also completed
and reassembly
of
the diesel
engine
begun.
d.
Plant Tours
The following plant areas
at Units 1,
2 and
3 were toured by
the inspector during the course of the inspection:
Auxiliary Building
Containment Building
Control
Complex Building
Diesel Generator Building
Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
1.
0 eratin
Lo s and Records
Records
were reviewed against
Technical Specification
and administrative control pro-
cedure
requirements.
The inspector
reviewed several
recent night orders at Unit
2 which were considered
to be bordering
on providing
direction to the operators
by a means for which the
procedure
change
process
was intended.
The inspector
discussed
the matter with licensee
management
and
concluded that additional administrative direction was
warranted
to ensure that night orders
were not used in
place of initiating procedural
changes.
The licensee
acknowledged
the inspector's
comments
and revised
paragraph
10.5 of administrative procedure
"Conduct of Shift Operations",
shortly after the
completion of the inspection period, to clearly state that
night orders
are not to be used to make changes
to safety
related procedures.
Night orders will continue to be
reviewed
as part of the routine inspection
program;
2.
Monitorin
Instrumentation
Process
instruments
were
observed for correlation
between
channels
and for con-
formance with Technical Specification requirements.
3.
observed for conformance with 10 CFR 50.54. (k), Technical.
Specifications,
and administrative procedures.
E ui ment Lineu
s
Valve and electrical
breakers
were
verified to be in the position or condition required
by
Technical Specifications
and Administrative procedures
for
the applicable plant mode.
This verification included
routine control board indication reviews
and conduct of
partial
system lineups.
5.
E ui ment Ta
in
Selected
equipment, for which tagging
requests
had been initiated,
was observed
to verify that
tags were in place
and the equipment
was in the condition
specified.
6.
General
Plant
E ui ment Conditions
Plant equipment
was
observed for indications of system
leakage,
improper
lubrication, or other conditions that would prevent the
associated
system
from fulfillingtheir functional
requirements.
7.
Fire Protection
Fire fighting equipment
and controls were
observed for conformance with Technical Specifications
and
admi nistrati ve procedures.
8.
for conformance with Technical Specifications
and admin-
istrative control procedures.
9.
10.
~Secorit
Activities observed for conformance with
regulatory requirements,
implementation of the site
security plan,
and administrative procedures,
included
vehicle and personnel
access,
and protected
and vital area
integrity.
Plant Housekee
in
Plant conditions
and material/-
equipment storage
were observed to determine the general
state of cleanliness
and housekeeping.
Housekeeping
in
the radiologically controlled area
was evaluated with
respect
to controlling the spread of surface
and airborne
contamination.
Radiation Protection Controls
Areas observed
included
control point operation,
records of licensee's
surveys
within the radiological controlled areas,
posting of
radiation
and high radiation areas,
compliance with
Radiation
Exposure
Permits,
personnel
monitoring devices
being properly worn, and personnel
frisking practices.
No violations of NRC requirements
or deviations
were identified.
4.
En ineered Safet
Feature
S stem Malk Gown - Units 1
2 and
3
Selected
engineered
safety feature
systems
(and systems
important to
safety) were walked
down by the inspector to confirm that the
systems
were aligned in accordance
with plant procedures.
During
the walkdown of the systems,
items
such
as hangers,
supports,
electrical cabinets,
and cables
were inspected
to determine that
they were operable,
and in a condition to perform their required
functions.
The inspector also verified that the system valves were
in the required position and locked as appropriate.
The local
and
remote position indication and controls were also confirmed to be in
the required position and operable.
Unit 1
Portions of the following systems
were walked
down on the indicated
date.
~Setem
System,
Trains "A" and "B"
Date
March 20
Containment
Spray System,
Trains "A" and "B"
Diesel Generator,
Trains "A" and "B"
February
23,
March 18
March
5
Essential
Cooling Mater System,
Trains "A" and "B"
March 18
High Pressure
Safety Injection System,
Trains "A" and B"
March 18
Supplemental
Protective
System
125V
DC Electrical Distribution,
Channels
"A" and "B"
April 2
March
5
Fire Suppression
System (Fire Pumps,
Supply and Discharge Valving)
February
25
Unit 2
Portions of the following systems
were walked down on the indicated
dates.
~Setem
Fire Suppression
System (Fire Pumps,
Supply and Discharge Valving)
Date
February
25
Safety Injection Tanks
March
6
10
Essential
Trains
"A" and "B"
System,
Train "8"
March
13
March 20
Control
Room Emergency Ventilation
System, Trains "A" and "B"
125V
DC Electrical Distribution,
Channel
"A"
March 24
March 31
Unit 3
Portions of the following systems
were walked
down on the indicated
dates.
~Ss ten
Diesel Generator
System - Train "A"
125V
DC Electrical Distr ibution Channel
IIAII and
IIC II
Date
April 1
March 30
No violations of NRC requirements
or deviations
were identified.
5.
Surveillance Test Witnessin
- Units 1,
2 and
3
'a ~
Surveillance tests
required to be performed
by the Technical
Specifications
(TS) were reviewed
on a sampling basis to verify
that:
1) the surveillance tests
were correctly included
on the
facility schedule;
2)
a technically adequate
procedure
existed
for performance of the surveillance tests;
3) the surveillance
tests
had been
performed at the frequency specified in the TS;
and 4) test results satisfied
acceptance
criteria or were
properly dispositioned.
b.
Portions of the following surveillance tests
by the inspector
on the dates
shown:
Unit I
were witnessed
Procedure
73ST-9CL03
Descri tion
Log Power Functional Test
Containment Airlock Seal
Leak Test
Diesel Generator
"A" Test
4.8.1.1.2.A
Dates
Performed
February
26
February
27
February
27
Main Steam Line Isolation
Val ves Surveillance 4.7.1.5
March 3
72ST-9RX02
PPS Bistable Trip Units
Functional Test
Moderator Temperature
Coefficient At Power
March 4,
31
April 1
March 19
Unit 2
ESFAS Train
B Subgroup
Relay
March 21
Monthly Functional
Test
Procedure
42ST-CH06
73ST-9CL03
Unit 3
Procedure
32ST"9PK04
31ST" 9DG01
Descri tion
Excore Safety Linear Channel
quarterly Calibration
Charging
Pump Operability
Test
CEA Reed Switch Functional
Test
Containment Airlock Seal
Leak Test
CPC Channel
"C" Functional
Test
Descri tion
60-Month Surveillance of
Station Batteries for
3E PKC-F13 - Channel
"C"
Diesel
Engine Inspection
- Train "A"
31-Day. Surveillance of
Diesel Generator - Train
I IAlI
Dates
Performed
February
24
February
24
February
26
March 3
March 31
Dates
Performed
March 2
Mar ch 23
March 24
43ST"3CH02
Boron Injection Flowpaths
March 24,
28
- Shutdown
32ST-9PK03
92-Day Surveillance of
Station Batteries for
3E PKC-F13 - Channel
"C"
18-Month Surveillance of
Station Batteries for
3E PKC-F13 - Channel
"C"
March 26
March 27
12
Refuel ing Machine
Load
Test
March
27'o
violations of NRC requirements
or deviations
were identified.
6.
Plant Maintenance - Unit 1
2 and
3
a 0
During the inspection period, the inspector
observed
and re-
viewed documentation
associated
with maintenance
and problem
investigation activities to verify compliance with regulatory
requirements,
compliance with administrative
and maintenance
procedures,
required
QA/QC involvement, proper
use of safety
tags,
proper equipment alignment
and
use of jumpers,
personnel
qualifications,
and proper retesting.
The inspector verified.
reportability for these activities was correct.
b.
The inspector witnessed portions of the
activities:
following maintenance
Unit 1
o
Monthly Auxiliary Relay Cabinet
Inspection
o
Replacement
of Fuel
Lines on the
"A" Diesel Generator
Dates
Performed
February
26
February
26,
27
o
Clean
and Inspect
Fuses
in the
Plant Protection
System
(PPS)
Cabinets
February
27
o
Troubleshoot
Heater Drain Tank
High Level
Dump Valve
March 5
o
Rework of Damaged
Pipe Supports
on Heater Drain Tank Lines
March
5
o
Instrument
Loop Check of
Engineered
Safety Feature
(ESF) Equipment
Rooms
Smoke
Exhaust
System
March 20
o
Troubleshooting of Emergency
Response, Facility Data Acquisition
and Display System
(ERFDADS)
Problems
March 26
o
Troubleshoot
and Rework/Replace
Problem with Control
Room
Annunciator Window 1B15D
March 31
o
Replace
Various Westinghouse
"SCPB" Circuit Breakers
March 31
0
13
Unit 2
Deecri tion
Dates
Performed
o
Replacement of the Outer
140'ontainment
Airlock Door Seal
March
3
o
Replacement
of Containment
Spray Injection Valve
UV 572
o
Installation of a High
Temperature Circuit Board
Into the
RU 31 Radiation Monitor
March
5
April 1
No violations of NRC requirements
or deviations
were identified.
Disablin
of En ineered Safet
Feature - Unit 1
On January
20, 1987, Unit 1 was in Mode 4, proceeding to cold
shutdown following the identification of a tube leak in Steam
Generator
(S/G) No. 1.
The faulted steam generator
was isolated
and
the cooldown was accomplished
through
S/G No.
2 to the main
condenser.
Night orders
were issued to maintain forced circulation
with reactor coolant
pumps until the S/G No.
1 metal temperature
dropped to about
90 degrees
F.
Although permitted by procedure,
in
the past forced circulation had not normally been maintained this
far into the cooldown.
Mith the average
temperature
at about
250 degrees
F and steam generator
pressure
at
25 psia, pretrips were received for all four channels
of main steam
isolation system
(MSIS) actuation.
The cause of the pretrips
was
the proximity of the actual
pressure
to the pretrip
setpoint,
aggravated
by the maintenance
of forced circulation
through the steam generators.
The MSIS setpoint is variable,
allowing manual control over the setpoint to permit a controlled
plant shutdown,
including depressurization
of the steam generators.
The variable setpoint is reduced in 200 psia increments until
essentially
a zero setpoint is reached,
discounting instrument
inaccuracies
and drift.
Following receipt of the MSIS pretrips,
the
operating
crew evaluated
the condition and elected to simulate
signals to the steam generator
pressure
bistables
to prevent
a
possible
MSIS as secondary
pressure
continued to drop.
Technical Specification (TS) 3.0.3
was voluntarily entered
since the
safety feature
was required operable
by TS 3.3.2 until Mode 5 entry.
Operations
supervision,
above the shift supervisor,
was not
consulted
regarding the decision to simulate bistable inputs
and to
voluntarily enter into TS 3.0.3.
ANPP procedure
"PPS
Bistable Input Simulation" was
used to input the simulated signals;
however, the procedure
stated,
in paragraph
1. 1.2, that only
bistables
not required
by TS 3.3.2 for the plant mode at that time
may receive simulated signals to prevent actuation.
The
significance of this issue is still under evaluation
by the staff
and will be addressed
in future correspondence.
Thus, the issue is
unr esol ved (528/87-10-01).
1
14
Following the
NRC review of this event,
as
documented
in Licensee
Event Report 87-07,
a confirmatory action letter (CAL) was
transmitted to the licensee
on March 6, 1987 to address
the Region
V
concern regarding the method by which TS 3.0.3 was entered.
The
addressed
the following actions
taken or planned
by the licensee:
o
A planned revision to the appropriate administrative
procedure
to preclude intentionally entering
TS 3.0.3 unless justified by
emergency conditions or as otherwise authorized
by approved
procedure es.
o
The need to promptly ensure plant personnel
including
supervision, fully understand
the licensee's
policy for
voluntary entry into TS 3.0.3.
Additionally, a meeting
was held in the
NRC Region
V Office on March
ll, 1987, at which time the above event
was reviewed with
appropriate
licensee
personnel
in detail.
The meeting included
discussion of the following issues:
o
Had the night order been
supplemented
with a preshift briefing
to explore possible
problems which might be encountered
during
the cooldown, the potential for a MSIS actuation
may have
been
foreseen.
This is accented
by the fact that a forced
circulation cooldown as addressed
in the night order
had not
previously
been performed.
o
Plant personnel
should fully understand
that when unusual
conditions arise they should stop the evolution in progress, if
practicable,
until the situation is evaluated
by higher levels
of supervision.
o
The event
was
due in part to a plant design conflict with
Technical Specifications.
Technical .Specification 3.0.3
was
used
as
an operational
convenience
to temporarily deal with the
conf 1 ict.
The inspectors
reviewed the technical details of the event to
ascertain
whether the plant had been placed in an unsafe condition
or whether
any technical specification
requirements
had been
violated.
The following observations
were
made:
At the time of the event,
the reactor
was completely shutdown,
with all control rods inserted,
and the reactor coolant system
borated to cold shutdown conditions.
The automatic
MSIS feature,
on low steam line pressure
is
provided primarily to terminate or mitigate
a reactivity
addition accident, caused
by a main steam line break
and the
resulting primary cooldown.
At the time of the event,
the ¹1
was already isolated.
The ¹2 Steam Generator
pressure
was approximately
25 psia.
The main steam line design
operating pressure
is approximately
1000 psia, therefore the
15
probability of a steam line break at 25 psia appears
to be
extremely remote.
With the reactor coolant system borated to cold shutdown
conditions,
the reactivity addition resulting from an
uncontrolled
cooldown would not result in a restart accident.
Water injection capability was available to rapidly recover
from any reactor coolant system contraction resulting from a
cooldown.
A review of other pressurized
water reactor
technical
specifications
(San Onofre, Oiablo Canyon, Trojan) indicates
that similar MSIS features
based
on low system line pressure
are not required in mode 4.
Palo Verde technical specification limiting condition for
operation
(LCO) 3.0.3,
which was intentionally entered
when the
LCO governing the
MSIS feature
was
no longer met, requires that
action
be taken within one hour to place the unit in a cold
shutdown condition (Mode 5), within the subsequent
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
At the time of the event,
the licensee
was already preparing to
enter
Mode 5,
and did enter
Mode 5 one hour and eighteen
minutes later.
Based
on the above,
the inspectors
concluded that the specific event
had
no direct safety significance
and that no technical
specification violation had occurred.
However, the inspectors
maintained that this event was very significant from the aspect that
a required engineered
safety feature
was disabled without
appropriate
management
oversight
and procedural
control.
In followup of the
CAL, the inspector
reviewed the licensee's
revision to ANPP procedure
40AC-9ZZ02, "Conduct of Shift Operation",
procedure
change notice
(PCN)
No. 8, which stated that voluntary
entry into TS 3.0.3 is prohibited unless justified by an emergency
condition or as authorized
by approved procedures.
The inspector
also reviewed training records
associated
with the licensee's
policy
regarding
TS 3.0.3 voluntary entry,
as well as providing personnel
direction to stop the performance of an activity and contact
supervision
when problems arise.
The inspector
s review of training
records
was ongoing at the conclusion of the inspection period.
This item (528/87-10-02) will remain
open pending 1) completion of
the training records
review by the inspector,
and 2) followup of the
licensee's
consideration
of the remaining potentially generic
issues
discussed
above
and in the
NRC letter
dated
March 13,
1987 from Mr.
J. Martin (NRC) to E.
Van Brunt, Jr.,
(ANPP) dealing with:
o
The benefit of preevolution briefings for new,
unusual
or
complex evolutions;
o
Whether additional conflicts exist between
aspects
of the plant
design
and Technical Specification;
and,
16
o
Whether provisions of the Technical Specifications
are being
implemented in a manner other than originally intended.
Calibration of Measurin
and Test
E ui ment - Unit 1
On March 31,
1987, during a tour of the Fuel Building, the inspector
noted that flowmeter EG-4092 (Brooks Rotometer)
had
a calibration
due date of March 13,
1987.
This flowmeter
was being used
on
a grab
sample cart which was connected to radiation monitor RU-145 (Fuel
Building Exhaust)
~
Further investigation revealed that RU-145 had
been inoperable
since
March 20,
1987 and the grab samples
were being
taken to comply with the actions of Technical Specification
(TS)
Limiting Condition for Operation
(LCO) No. 3.3.3.9.
The inspector
discussed this item with M&TE personnel
and reviewed calibration
documentation
to verify that the calibration due date
was March 13,
1987.
The flowmeter was
on a six month calibration frequency
and
was last calibrated
on September
8, 1986.
Procedure
"M&TE User's Administrative Requirements"
defines
M&TE that is overdue for calibration
as nonconforming
M&TE.
The responsibility for ensuring that
M&TE has not exceeded its
calibration
due date lies with the user.
The segregation
and
tagging out-of-service of nonconforming
M&TE is the responsibility
of the user
and the
M&TE custodian.
The failure to identify,
segregate,
and tag out-of-service
nonconforming
M&TE is contrary to
TS 6.8. 1 and the above administrative procedure,
and is considered
a
violation (528/87-10-03).
Ino erable Pressurizer
Heater Control Switch - Unit 2
At 5:00
PM on March 20, the operating staff determined that Control
Room switch HS-100, which is used to energize
a bank of class
1E
powered
backup pressurizer
heaters,
was inoperable.
The staff
confirmed that the breaker could be closed locally and consequently
the heater
bank could be energized.
The hand switch for the other
heater
bank was operable.
The staff believed that this satisfied
the
LCO in paragraph
3.4.3. 1 of the Technical Specifications
which
required at least
two groups of pressurizer
heaters
capable of being
powered from Class
1E buses.
The staff was
unaware of the
surveillance
requirement in paragraph
4.4.3. 1.3 of the Technical
Specifications
which required
an ability to connect the heaters
to
their respective
buses
manually from the Control
Room, until it was
questioned
by the inspector
on March 27.
A review of the matter
revealed
the Control
Room switch to be inoperable until 3:00
PM on
March 24,
a period of 94 hours0.00109 days <br />0.0261 hours <br />1.554233e-4 weeks <br />3.5767e-5 months <br />.
The unit remained in Mode 1 during
this time.
The action statement
associated
with the referenced
LCO
requires
the heater
bank (includes switch control) to be restored to
an operable
status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the unit must be placed in
Mode
3 in the following six hours.
Exceeding the specified
Technical Specification time interval is considered
a violation of
the Technical Specification operability requirement
(529/87-11-01).
Pressurizer
Level Control - Unit 2
17
Following plant startup
on March 9, plant operators
experienced
erratic operation
on both
110X and
110Y pressurizer
level control
channels.
The control
system
had been recalibrated
during the
recent extended
maintenance
outage
and the initial rationale for the
erratic operation
was attributed to the
need for system tuning
following the outage work.
When system control adjustments
were not
successful,
investigative efforts were initiated to determine what
conditions could be contributing to the sluggish
response
of level
control.
Several
tests
were conducted
wherein reactor pressure
was increased
about
50 psig above
normal over varying periods of time.
Level
response
to the pressure
increase
on both channels
were comparable,
but increasingly less
responsive
when the time duration during which
reactor pressure
was increased
was shortened.
Following
confirmation that steady level control
was acceptable
but level
control during transient conditions
was not, channel
110Y was
declared
inoperable for failure to meet Technical Specifications 3.3.3.5
and 3.3.3.6,
remote
shutdown
instrumentation,
respectively.
Channel
110X had been declared
inoperable previously,
when its level transmitter
was replaced.
With both channels
the most limiting action statement
associated
with the above
LCOs required returning one of the two
channels
to an operable
status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The control response
during the pressure
increase tests
suggested
that the sensing lines, which contained
7/32" orifices, could be
partially plugged.
Both sensing lines were flushed, following which
both channel
responses
returned to normal.
Ouring the flushing of
Channel
110Y, material which was black in color, magnetic
and
resembled
magnetite,
was observed to discharge
from the line.
Following completion of the surveillance tests
on both Channels
110X
and 110Y, each of the pressurizer
level channels
was returned to an
operable condition prior to exceeding
the Technical Specification
action statements
of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> for two inoperable
channels
and seven
days for one inoperable
channel.
Both level channels
have
been operating normally since the flushing
of the sensing lines.
The licensee's
actions in this matter are still under review by the
NRC and this item will remain
open until the review is completed
(529/87-11"02).
No violations of NRC requirements
or deviations
were identified.
Loadin
Considerations
- Unit 1
On March 20, 1987, during a general
tour of Unit 1, the inspector
noted that scaffolding had been erected
around class
1E cable
raceways
in the Train "B" switchgear
room.
Also, two boards
(approximately
3 feet square)
were lying on the cable
raceway
and
were tied to the scaffolding.
This scaffolding was erected to
18
support
an instrument
'loop check
on the
ESF equipment
rooms
smoke
exhaust
(W.O. 206700).
Discussion
and review of this situation with licensee
work control
and scaffolding personnel
revealed that the boards
were to be used
by mai'ntenance
personnel
to stand
on and access
a damper located
over the cable tray.
The inspector
expressed
a concern
over the
additional
loading on the raceway supports after noting that
a
safety analysis
accounting for the transient
loading provided by the
scaffolding and boards
had not been performed.
The licensee
has previously performed
a bounding calculation to
account for the transient
use of lead blanketing
on piping.
However,
no such calculation
had been performed for cable
raceway supports.
The licensee
committed to complete
a bounding calculation for the
loading effect on the worst case
cable support
by April 24,
1987
'urther,
the licensee
has also committed to evaluate
the need for
bounding calculations for other transient
loading situations.
This item will remain unresolved
pending the completion of the
licensee's
calculations
and the correlation to the specific instance
identified (528/87-10-04).
Verification of Containment Inte rit - Units 1 and
2
Prior to entry into Mode 4 on March 1 and 4, 1987, respectively,
the
inspector verified that the licensee
had established
containment
integrity.
For each unit, the inspector:
o
Witnessed the satisfactory
completion of Procedure
"Airlock Local
Leak Rate Test".
I
o
Verified, through field observations,
that all mechanical
barriers
and isolation valves associated
with ten containment
were in their proper position.
o
Verified the operability of the Containment
Spray system
by a
field walkdown of system
components
and
a review of the
system's
Control
Room indications.
No violations of NRC requirements
or deviations
were identified.
Initial Fuel
Load Witnessin
- Unit 3
The licensee
entered
Mode
6 on April 4,
1987.
The initial fuel
loading was witnessed
by the inspector to verify that the activities
were performed in conformance with Technical Specifications.
The
inspector
observed fuel loading activities from the spent fuel
machine in the Fuel Building; refueling machine in Containment;
and,
the Control
Room.
The activities were compared to the requirements
of procedure
73IC-3RNOl, "Initial Fuel
Load" and to the Technical
Specifications.
The inspector verified that:
c
V'
19
o
On a sampling basis,
the prerequisite
Mode
6 and the "At All
Times" Technical Specifications
had been completed prior to the
start of fuel handling.
o
The crew complement
was staffed with qualified personnel
in
accordance
with Technical Specifications.
o
The senior reactor operator in charge of fuel handling was in
constant
communication with the Control
Room.
o
The inverse multiplication plots were being calculated
and
plotted by the reactor engineering
group.
o
The boron concentrations
in the reactor coolant system
and
Refueling Water Storage
Tank were within limits.
o
A fuel management
control board
was set
up to identify the
location of each fuel assembly
as it was
moved from the Fuel
Building to the reactor vessel.
The test director was observed
to be supervising
the fuel movements
from the Control
Room
location.
o
Initial fuel load procedure
changes
were implemented in
accordance
with administrative controls.
No violations of NRC requirements
or deviations
were identified.
14.
Prep erational
Test Results
Review - Unit 3
The inspector
reviewed the completed test procedures
and test result
reports for the following system preoperational
tests:
Procedure
90HF"3ZZ01
91P E-3DG01
91PE" 3EC01
91P E-3EW01
91PE" 3SP01
91P E-3SGOl
91P E-3SG04
91HF" 3RC02
02,
03, 04,
05 and
06
02
93PE-3PE01
93P E"3SA01
Precore
Hot Functional Testing
Diesel Generator
System
Essential
Chilled Water System
Essential
Cooling Water System
Essential
Spray
Pond System
Main Steam Isolation Valves and Bypass
Valves
Steam Generator Isolations
Main Steam Isolation Valves and Bypass
Valves
Hot Functional Test
Pressurizer
Performance
Excore Nuclear Instrumentation
Control
System
Precore
CEDM Performance
Diesel Generator Electrical Test
Integrated Test of Engineered
Safety Features
The inspector verified that activities such
as test data
acquisition, test exception resolution, test report issuance,
test
modifications
and acceptance criteria verification had been
0
20
accomplished
in accordance
with the licensee's
FSAR commitments
and
administrative controls.
No violations of NRC requirements
or deviations
were identified.
Overall Startu
Test Pro
ram - Unit 3
The inspector
reviewed the post core testing program for Unit 3.
The
administrative controls
such
as test conduct, test procedure
review
and approval, test results
review and approval,
document control,
test program organizational
structure
and administration,
and use of
measurement
and test equipment,
were found to be essentially
the
same
as those
used in Units 1 and 2.
Revisions to the procedures
were found to be limited to minor changes
which did not affect
commitments.
Test controlling procedures
associated
with initial fuel load,
initial criticality, post core hot functional testing
and power
ascension
testing are expected to be the
same
as those
used in
Unit 2.
The licensee
has prepared
FSAR changes
which would
eliminate certain testing in Unit 3 based
on successful
tests
in
Units 1 and 2.
This includes elimination of a loss of offsite power
test,
atmospheric
dump valve/steam
bypass
valve capacity tests
and
Core Protection Calculator/Core
Operating Limit Supervisory
System
verification tests at
20% and
80%.
The licensee is also seeking
relief with regard to requirements for establishing equilibrium
xenon conditions prior to physics testing.
The licensee
does plan
on conducting
a remote
shutdown test from outside the Control
Room
at the
20% plateau.
Specific test procedures
for Unit 3 shall
be
reviewed by the inspector
as they are
made available prior to test
conduct;
No violations of NRC requirements
or deviations
were identified.
Desi
n Chan
es - Unit 3
The inspector selected
a representative
sampling of design
change
packages
(DCPs) for Unit 3.
The inspector
chose
DCPs from the
mechanical, electrical,
and
I&C groups.
The inspector
reviewed the
DCPs to ensure that the changes
were properly reviewed
and approved;
revisions
were properly reviewed
and approved,
acceptance
tests
were
performed
as required;
and,
independent
design verifications were
performed
as required.
No violations or deviations
were identified.
0 erational Staffin
- Unit 3
During this inspection,
the inspector
reviewed the qualifications
and level of experience
of managerial
and operations
support staff
personnel
responsible for the performance of maintenance,
instrument
calibration,
and surveillance testing in Unit 3 for conformance to
the licensee's
FSAR commitments to ANSI/ANS 3. 1-1978.
On a station
level, this included
a review of the qualifications
and experience
21
of the individuals currently holding the following staff positions:
Plant Maintenance
Manager,
Mechanical
Maintenance
Supervisor,
Electrical, Maintenance
Supervisor,
and
I8C Maintenance
Supervisor;
and
on a unit specific level, the qualifications
and experience
of
the unit Mechanical
Maintenance
Superintendent,
Electrical
Maintenance
Superintendent
and I8C Maintenance
Superintendent
and
four mechanics,
four electricians
and four I8C technicians
working
in Unit 3.
All were found to meet or exceed
the minimum specified
requirements.
No violations of NRC requirements
or deviations
were identified.
ualit
Assurance for Measurin
and Test
E ui ment
M&TE - Unit 3
During this inspection,
the inspector
reviewed the licensee's
program
and procedures
for the control
and calibration of measuring
and test equipment
(M&TE) used in the performance of safety-related
maintenance,
calibration and surveillance testing of permanent plant
equipment in Unit 3.
The program
and administrative controls
associated
with the
use of M&TE
are the
same for all three units at
Palo Verde and
as
such
have
been
reviewed during previous
inspections.
The following program
and administrative control
procedures
were again reviewed
as
a part of this inspection with
emphasis
placed
on the review of recent
changes:
34P R-OZZ01
34AC-OZZ04
34AC"9ZZ07
Measuring
and Test Equipment
(M8TE) Control
Program
Control of Nonconforming Measuring
and Test
Equipment
(M8TE) and Calibration Standards
Control of Automated Measuring
and Test Equipment
(M&TE) Calibration Programs
Control of Shipping,
Packing
and Receiving Inspection
of M8TE and Calibration Standards
M&TE Users Administrative Requirements
M&TE Work Control
The inspector also reviewed
a selection of generic calibration
procedures
for specific pieces of M&TE.
The inspector
peyformed
an
inspection of the licensee's
M&TE calibration and storage
facilities.
The inspector,
in particular inspected
the areas
in
Unit 3 where
M&TE is stored
and discussed
with licensee
personnel
in
Unit 3 the manner
in which pieces of M&TE are checked out and usage
recorded.
A sample of different pieces of M&TE including electrical
multimeters,
pressure
and torque wrenches
were examined for
indication of current calibration.
During the course of this
inspection,
the inspector did note
a sizeable
backlog in the number
of out-of-tolerance
notices awaiting final evaluation
by the
licensee.
This was discussed
with the licensee.
The licensee
did
present
the inspector with some evidence that the backlog was
diminishing; however, the inspector indicated to the licensee that
continued effort in this area
appeared
warranted.
The inspector
will follow the licensee's
actions to reduce the backlog of out-of-
tolerance
notices
(530/87-12-01).
22
No violations of NRC requirements
or deviations
were identified.
19.
TMI Action Plan Items - Unit 3
a.
Closed) II.E.4.2 - Containment Isolation
De endabilit
NUREG 0737, Clarification of TMI Action Plan Requirements,
lists six different criteria that should
be met by licensee's
to ensure
containment isolation dependability.
There should
be diversit
in
arameters
sensed for
initiation of containment isolation.
Per the Unit 3 Proof and Review Technical Specifications,
two different parameters
are
sensed for contaiment
isolation.
Containment pressure
of 3.0 psig or pressurizer
pressure
of 1837 psia will initiate a containment isolation
actuation signal
(CIAS).
A CIAS can also
be initiated
manually.
2)
Determine which
s stems enterin
Containment
are essential
and which s stems
are nonessential
and modif their
containment isolation accordin
1
The licensee's
definitions of essential
and nonessential
were documented
in the Lessons
Learned
Implementation
Report (LLIR) and were found acceptable
by NRR,
as
documented
in the Palo Verde Safety Evaluation Report
(SER), with two exceptions.
Seal injection and charging
lines were considered
to be essential
systems
by the
licensee
and are not isolated
on a CIAS.
Valves. CH-HV-524
and CH-HV-255 can manually isolate these lines from
Containment but were originally not supplied with Class
power.
NRR required that these
valves
be supplied with
Class
1E power.
The inspector verified that
a
modification has
been completed,
which supplies
Class
power to these valves.
All other non-essential
systems
are automatically isolated
on
a CIAS. This was verified by
reviewing procedure
93PE-3SAOl, "Integrated Test of
Engineered
Safety Features".
3)
Resettin
the
CIAS should not result in the automatic
reo enin
of containment isolation valves.
The inspector verified by review of procedure
that containment isolation valves
do not reopen
when a
CIAS is reset.
4)
The containment
ressure
set oint that initiates
a CIAS
should
be reduced to the lowest
ractical.
23
For Palo Verde, the original setpoint
was
5 psig and was
subsequently
lowered to 3 psig.
5)
Containment
ur e valves that do not satisf
certain
o erabilit criteria must be sealed
closed
and verified to
be closed at least ever
31 da s.
The inspector verified that surveillance test procedure
implements this for the containment
purge
valves.
6)
Containment
ur e valves should close
on a hi
h radiation
sicinal.
The inspector verified that area radiation monitbrs
RU-37
and
RU-38 initiate a containment
purge isolation actuation
signal
(CPIAS) at a setpoint of 2.5 mrem/hr.
The inspector
was satisfied that the licensee
had properly
implemented this TMI Action Plan Item and it is closed.
b.
Closed
II.F. 1.2D Post Accident Monitorin
Instrumentation
Containment
Pressure
Monitor .
The inspector verified that the licensee
has installed
two
dedicated
containment pressure
transmitters,
with a range of -5
to +180 psig, to monitor containment pressure after an
accident.
The transmitters
were supplied
by Rosemount
and
qualified both seismically
and environmentally per Rosemount
Procedure
1802,
Revision A.
This was documented
per
program
number 13-JM-311.
The inspector also verified that procedure
92GS-OZZ80 performed
the generic calibration of these
Rosemount pressure
transmitters.
The licensee
has satisfactorily implemented this TMI item and
it is closed.
As part of the inspection of these
TMI items, the inspector
reviewed
the portions of the Palo Verde
SER dealing with these
two THE Action
Plan Items.
The inspector verified that commitments
made
by the
licensee
in the Palo Verde LLIR concerning these Action Plan Items,
which were referenced
by
NRR in the
SER in determining acceptability
of the licensee's
proposed actions,
had in fact been
implemented.
No violations or deviations
were identified.
20.
Com arison of As-Built Plant to
FSAR Descri tion - Unit 3
The following systems
were reviewed to verify that the as-built
plant conforms to the commitments
contained in the
FSAR:
0
24
High Pressure
Safety Injection
Low Pressure
Safety Injection
Containment
Spray
Iodine Removal
Safety Injection Tanks
Essential
Cooling Water
The inspector
reviewed portions of isometric drawings,
Technical
Specification
(TS) surveillances,
and performed detailed field
walkdowns using the Piping and Instrumentation
Diagrams
(PAID) and
FSAR descriptions for the listed systems.
The field walkdowns
included piping, valve,
and instrumentation installation
and
numbe'ring,
including Control
Room indications
and controls,
where
applicable.
In all cases
reviewed,
the isometric drawings reflected the as-built
status of the plant.
However, the inspector identified three
cases
where the
PKIDs did not reflect the as-built installation.
In each
instance
the
P8 ID was in error.
One
P8 ID had not been revi sed when
a plant change
was
made.
The others
had been
drawn incorrectly on
the original revisions.
The inspector considered
the drawing
discrepancies
to be of a minor nature.
The licensee
reviewed these
instances
and concluded that they had
no effect on the operability
of the systems.
However, the licensee
implemented
drawing changes
at each unit to bring the P8IDs in conformance with the as-built
plant design.
The inspector also verified by sampling, that
TS
surveillances
for the reviewed systems
could be performed in the
as-built plant.
No violations of NRC requirements
or deviations
were identified.
21.
Followu
of Generic Letters - Units 1
2
and
3
a.
Closed
Generic Letter 85-22: Potential for Loss of Post-LOCA
Recirculation
Ca
abc lit
Due to Insulation Debris Slocka
e
The inspector observed that the licensee
had pursued
the review
recommendations
discussed
A
~ report summarizing the licensee's
evaluations
was noted by the
inspector to address
emergency
core cooling system
(ECCS)
design
based
on debris effects,
degree of screen
blockage,
hydraulic performance,
and venting as
recommended
The report concluded that the existing
sump design
meets
the requirements/guidance
Revision
1
and Standard
Review Plan, Section 6.2.2,
Revision 4.
This item
is closed for Units 1, 2,
and 3.
b.
Closed
Generic Letter 85-06:
ualit
Assurance
Guidance
For
E ui ment That Is Not Safet -Related.
25
On June 1, 1984,
the Commission -approved publication of a Final
Rule,
regarding the reduction of risk from
anticipated transients
without scram
(ATMS) events for
light-water cooled nuclear power plants.
Section 50.62(d) of
the rule required that each licensee
develop
and submit
a
proposed
schedule for meeting the requirements
of the rule.
This generic letter (GL) was issued to provide explicit quality
assurance
guidance for non-safety-related
equipment
encompassed
by the
ATMS rule.
The licensee
provided their initial response
on October 12,
1985,
and stated that they are
a participant in
the Combustion Engineering
Owners
Group
(GEOG) program for
compliance with the
ATMS Rule.
The licensee
adopted
an initial
schedule
based
on the
GEOG program completion.
However,
on
February
24,
1987, the
NRC extended
the deadline for
implementation of the
ATMS rule requirement to no later than
the thir d refueling outage after July 24,
1984.
The current
implementation
schedule
for Palo Verde Units 1, 2,
and
3 is
prior to the third refueling after July 24, 1984, for each
unit.
The inspector verified that the licensee's
review and response
to this
GL was adequate
and timely.
Therefore, this item is
closed for Units 1, 2, and 3.
22.
Followu
I.E. Bulletin 86-03: Potential
Failure of Multi le
Pum
s
Due to Sin le Failure of Air-0 crated Valve in Minimum Flow
Recirculation Lines - Unit 1
2
and
3
.
This Bulletin discusses
findings at several
plants whereby the
minimum flow recirculation lines for'oth
ECCS trains were returned
to a common header
and utilized .common air operated
valves to
isolate the line.
It was determined that
a single valve failure in
this recirculation line could prevent
minimum pump flow during
conditions in which the reactor coolant system pressure
was higher
than the shut off head of the
ECCS pumps.
Mithout minimum flow, the
pumps could overheat,
become
damaged,
and not able to perform their
intended safety functions.
The bulletin directed the licensee
to
review their
ECCS system to determine if a failure in the minimum
recirculation flow line could effect both trains of ECCS.
The
inspector
performed
an independent
review of the
ECCS systems
using
plant piping and instrumentation
drawings
and by walking down the
respective
High Pressure
Injection (HPSI),
Low Pressure
Injection
(LPSI) and Containment
Spray
(CS) systems for both trains.
Each
pump has
a miniflow line with a normally open, motor-operated
valve.
Each valve is supplied with Class lE power and fails-as-is
(open)
upon
a loss of power.
The miniflow lines for each train combine
into a single header for each train with a solenoid operated
isolation valve in each line.
These valves are powered from the
Class
1E 125V
DC system
and are energized to open.
The headers
then
combine into a single line going to the Refueling Mater Tank (RMT).
There are
no valves in this line.
26
The licensee
concluded that there is no single failure that would
cause multiple trains of ECCS
pumps
or valves to become
and
no actions
were required.
The inspector verified that the
licensee's
review and response
to this item was comprehensive
and
timely.
Therefore, this item is closed for Units 1, 2,
and 3.
23.
Licensee
Event
Re ort
LER
Followu
- Units 1 and
2
a e
The following LERs associated
with operating
events
were
reviewed by the inspector.
Based
on the information provided
in the report, it'as concluded that reporting requirements
had
been met, root causes
had
been identified,
and corrective
actions
were appropriate.
The below
LERs are considered
closed.
Unit 1
LER NUMBER
DESCRIPTION
LERs 86"55-00,
01
Late Surveillance
Due to Hydramotor
Actuator Failure
LER 86-62-00
Late Surveillance
Oue to Communication
Error
LER 87-01-00
LER 87"07-00
Disabled
ESF Function (Documented in
paragraph
7)
Unit 2
LER NUMBER
DESCRIPTION
ESF Actuation Caused
By a Voltage Spike
LER 86-38-00
LCO Entry Oue to Inoperable
LER 86-42-00
Surveillance Test Performed
Late
Oue to
Personnel
Error
LERs 86-46-00,
Inadvertent
SIAS Oue to Manual Actuation
Ol
Handswitch Malfunction
LER 87-01-00
Personnel
Error Caused
Control
Room Ventilation
Monitors to be Inoperable
No violations of NRC requirements
or deviations
were identified.
24.
Followu
of 10 CFR 50.55
e
Re orts
DERs
- Unit 3
'a 0
The inspector reviewed
a sample of OERs that the licensee
had
dispositioned
as
Not Reportable
under the criteria of 10 CFR 50.55(e).
This review was conducted in order to evaluate
the
thoroughness
of the licensee's
analysis
and the validity of the
conclusions.
The following DERs were reviewed:
I
~
~
27
86-01
86-05
Nozzle-to-Shell'Welds
on
ASME III Tanks
and Heat
Exchangers
Weld Discrepancy
on
CE Supplied Transmitter
Racks
86-08
86-20
Grinnell ¹2 Sway Strut Clamp Interference
Do Not Meet Required
Specifications
86-30
Equipment gualification Problems with Various
Fuses,
Terminal Blocks,
and Wiring
Each
DER provided
a complete description of the discrepant
condition and the evaluation of safety significance.
Also, the
root cause
and corrective action for each condition were
appropriately identified.
These
DERs are therefore
closed.
In
addition,
based
on the thoroughness
and completeness
of the
reports the inspector
reviewed, all other
DERs that have
been
dispositioned
as Not Reportable
are closed
and are listed
below.
86"03
Failure of Fire Hazards Analysis to Identify
Spaces
Between Buildings as Separate
Fire Areas
86-09
86-10
86-11
86-16
86"22
86-23
86-25
PASS Deficiencies
Saturation of Radiation Monitoring Instruments
gualification of Skinner Solenoid Valves
Lack of Calculations for Conduit Supports
Redundant Fault Current Protection
Broken Nut on ¹1
SG Sliding Base Support Forging
Wrong Conversion Factors
on RU-1 Radiation
Monitor
86-26
86-32
86-41
Softer Than Required
Nuts with Heat Trace
6C
Discrepancies
Found Between
Pipe Support Designs
and Stress
Analysis Calculations
Required
May Not Have Been Incorporated
on
Some Limitorque Operators
87"01
87-05
Brown-Boveri Circuit Breakers with Possible
Damaged Wires in Wire Harnesses
Potential
Problems with g-Class
Actuators
v
28
87-08
Possible
Problems with Limitorque Wire
Degradation
in g-Class
DC tlotors
b.
Finally, the inspector
reviewed
and closed the following
Reportable
DERs:
85-38 Deficiencies Identified Durin
Audit of General
Electric
Com an
.
A safety concern
was identified by the licensee
wherein
was processing
the purchase
of safety grade materials
as
commercial
grade.
The root cause
was attributed to a
change in a
GE computer program in June,
1985 that
triggered the processing
of Class
1E orders
as commercial
grade.
As part of their corrective action,
GE committed
to review all spare
and replacement
procurements
supplied
to Palo Verde.
All suspect
material
has either
had the
purchase
order cancelled,
been returned to GE,
has
been
subsequently certified, or been quarantined
unti 1
certification could be established.
In only two cases
were commercial
grade material actually installed in Class
lE applications.
Two terminal blocks were installed in
safety grade switchgear in Unit 3.
The licensee
has
committed to relacing these parts with qualified terminal
blocks per
WOs 184631
and 188339, prior to fuel load.
This
DER is closed.
2)
86-31 Loose Diesel Generator
Rotor Windin s
While doing normal maintenance
of the Unit 3 "B" Diesel
Generator,
the licensee
discovered that the copper
windings of one of the rotor poles were loose.
Centrifugal force had apparently
broken the resin
bond and
the wires separated
from each other.
The root cause
was
attributed to improper application of the resin
bond on
the wire-wound rotor pole.
The defective rotor pole piece
was replaced.
The licensee
also discovered
loose pole piece fasteners
during the examination of the defective rotors.
The
vendor supplied the proper torque values for the fasteners
and they were retorqued
by the licensee.
The licensee's
corrective action for these deficiencies is
considered
adequate
and this
DER is closed.
3)
86-47 Diesel Generator
En ine Failure
The Unit 3 "B" Diesel Generator failed catastrophically
during the performance of a fully loaded 24-hour run as
part of a preoperational
test.
29
The diesel
engine sustained
major damage to cylinders,
pistons,
connecting
rods, articulating rods
and other
components.
The root cause
was determined to have resulted
from a
layer of electroplated
iron on the surface of one piston
rod.
This electroplated
iron was
used to repair the
overmachining of the surface.
A crack was initiated in
the iron and it propagated
into the base metal.
The
piston rod thus failed and was ejected out the side of the
diesel
engine.
Corrective action for this event included replacement
of
any iron plated piston rods in all other diesel
generators
at the Palo Verde site.
In addition, all the remaining
rods in both diesels
in Unit 3 have
been ultrasonically
tested
and
no crack indications identified.
Repair of the "B" Diesel Generator is ongoing and will be
followed by the resident staff.
This
DER is closed.
No violations of NRC requirements
or deviations
were identified.
25.
Review of Periodic
and
S ecial
Re orts - Units 1 and
2
Periodic
and special
reports
submitted
by the licensee
pursuant to
Technical Specifications 6.9. 1 and 6.9.2 were reviewed
by the
inspector.
This review included the following considerations:
the report
contained
the information required to be reported
by
NRC require-
ments; test results
and/or supporting information were consistent
with design predictions
and performance specifications;
and the
validity of the reported information.
Within the scope of the
above,
the following reports
were reviewed by the inspector.
Unit 1
Monthly Operating Report for January,
1987.
1-SR-86-053
Reactor Trip in Units 1 and
2 due to Loss of Startup
Transformer
1-SR-86-068
Seismic Monitoring Instrumentation
1-SR-86-069
RVLMS
1-SR-'86-069-1
One Inoperable
Channel of RVLMS
1-SR"86-079
Reactor Trip and
Due to Spurious
Reactor
Coolant
Low Flow
1"SR-86-085
Notice of Unusual
Event Due to SIAS from Feedwater
Control
Problems
30
1-SR-86-087
RU-1 Removed
from Service for Calibration
1-SR-86-089
RU-146 Out of Service Greater
Than 72 Hours
1-SR-86-097
RU-145 Out of Service
1-SR-86-093
Containment
Area
Rad Monitor Inoperable for Greater
Than 72 Hours
1-SR-87-005
Radiation Monitoring Unit Inoperable
Oue to Closed
Valve
1-SR-87-009
Tube Plugging
Unit 2
Monthly Operating
Report for January
and February,
1987.
2-SR-86-028
Radiation Monitor Inoperable for Greater
Than 72
Hours
2-SR-86-030
RU-1 Inoperable for Greater
Than
72 Hours
2-SR-86-031
RU-142 Failure
2-SR-86-032
Containment
Rad Monitor
Inoperable Greater
Than
72 Hours
2-SR-86-033
RU-146 Failure
2-SR-86-036
RU-1 Inoperable Greater
Than
72 Hours
2-SR-86-037
RU-1 Inoperable Greater
Than 72 Hours
2-SR-86-039
RU"1 Inoperable Greater
Than 72 Hours
2-SR-87-001
RU-144 Inoperable for Greater
Than 72 Hours
No violations of NRC requirements
or deviations
were identified.
26.
Unresolved
Items
Unresolved
items are matters
about which more information is re-
quired to determine whether they are acceptable,
violations or
deviations.
Unresolved
items addressed
in this inspection are
contained in paragraphs
7 and ll of this report.
The inspector
met with licensee
management
representatives
period-
ically during the inspection
and held an exit on April 3, 1987.
31
The scope of the inspection
and the inspector's
findings,
as noted
in this report,
were discussed
and acknowledged
by the licensee
representatives.
L