ML20214W973
| ML20214W973 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 06/01/1987 |
| From: | Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20214W911 | List: |
| References | |
| 50-369-87-14, 50-370-87-14, IEB-86-003, IEB-86-3, IEIN-85-094, IEIN-85-94, NUDOCS 8706160277 | |
| Download: ML20214W973 (16) | |
See also: IR 05000369/1987014
Text
~~
T' *
T
,
- km neig, "
UNITE 3 STATES
"
- .s '
g
'o
NUCLEAR RE!ULATORY COMMISSION
[
REGION 11
_n
,
g
, j:
101 MARIETTA STREET,N.W.
4
- '
s
ATLANTA, GEORGI A 30323
\\;....*/
- Report Nos:.50-369/87-14.and 50-370/87-14
'
Licensee: Duke Pcwer Company
'422 South Church Street
Charlotte, NC 28242
Facility Name: McGuire Nuclear Station-1 and 2
Docket Nos: 50-369 and 50-370.
Inspection Conducted
April 21, 19 7 - May 22, 1987
b
o7f/#2
Inspectors:
a
Date' Signed
W. Ordle'rs, Senp
ident Inspector
sz W e
h/An
A
S. Gue'nther, Resident nspe or
"Date' Signed
.
4!///2
Approved by: _ T. A. Pe'ebTes, S'ection Chief
D' ate Signed
~
Division of Reactor Projects
SUMMARY.
This routine unannounced inspection involved the areas' of operations
Scope:
safety verification, surveillance testing, maintenance' activities,. follow-up of
~
previous enforcement actions, refueling activities, design change activities,
and independent inspection in the fire protection area.
-
~
Results: Of the areas inspected, two , viol.ations were. . identified:
-
failure to document transient operating, cycles and'make Special_ Reports as
required by the Technical Specification,s;
,
-
failure to maintain the Technical Specification Actio( Item Logbook as
required by plant procedures; and
.
One Deviation was also identified in the area of plant fire protection.
~
t
f
8706160277 870603
ADOCK 05000369
G
<
,
_.
.
.
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- T. McConnell, Plant Manager
B. Travis, superintendent of Operations
- D. Rains, Superintendent of Maintenance
- B. Hamilton, Superintendent of Technical Services
- N. McCraw, Compliance Engineer
- M. Sample, Superintendent of Integrated Scheduling
- N. Atherton, Compliance
- G. Gilbert, Operations Engineer
- J. Snyder, Performance Engineer
- D. Brandes, Design Engineering
- T.
Lyerly, Instrumentation and Electrical
- W. Reeside, Operations Engineer
- E. Estep, Project Engineer
Other licensee employees contacted included construction craftsmen,
technicians, operators, mechanics,
security force members, and office
personnel.
- Attended exit interview
2.
Exit Interview (30703)
The inspection scope and findings were summarized on May 22, 1987, with
those persons indicated in paragraph 1 above. Two violations concerning
multiple examples of failure to follow an Operations Management Procedure,
and failure to document and report transient operating cycles were
discussed.
A' deviation from an NRC commitment regarding the plant's fire
protection equipment, unresolved items regarding auxiliary feedwater
system pressure switch ' testing, D/G operability, and post maintenance
valve testing were also discussed.
The licensee did not identify as
proprietary any of the information reviewed by the inspectors during the
course of their inspection.
3.
Unresolved Items
An unresolved item (UNR) is a matter about which more information is
required to determine whether it is acceptable or may involve a violation
or deviation.
Three new unresolved items were identified during this
report.
4.
Plant Operation (71707)
The inspection staff reviewed plant operations during the report period,
to verify conformance with applicable regulatory requirements. Control
room logs, shift supervisors' logs, shift turnover records and equipment
.
.
2
removal ~ and restoration records were routinely perused. Interviews were
conducted with plant operations, maintenance, chemistry, health physics,
and performance personnel.
Activities _within the control room were monitored during shifts and at
shift changes. Actions and/or activities observed were in the main,
conducted as prescribed in applicable station administrative directives.
The complement of licensed personnel on each shift met or exceeded the
minimum required by Technical Specifications.
Plant tours taken during the reporting period included, but were not
limited to, Unit 2 reactor building, the turbine buildings, auxiliary
building, Units 1 and 2 electrical equipment rooms, Units 1 and 2 cable
spreading rooms, and the station yard zone inside the protected area.
During the plant tours, ongoing activities, housekeeping, security,
equipment status and radiation control practices were observed.
a.
Unit 1 Operations
,
Unit 1 operated at essentially full power for the entire reporting
period.
b.
Unit 2 Operations
Unit 2 entered the reporting period at full power and maintained that
status until about mid-day on April 30, 1987.
At 10:43 a.m.
that
morning, channel "A" of the solid state protection system (SSPS) was
removed from service for periodic testing in accordance' with
PT/0/A/4601/08A. Action Statement No. 14 of Technical Specification (TS) 3.3.2 allows one channel of SSPS to be bypassed for up to two
hours for surveillance testing, provided the other channel is
operable. Problems were encountered during the channel
"A"
testing
,
sequence and troubleshooting efforts were initiated. At 12:43 p.m.,
the allowable surveillance testing period expired and the shutdown
requirements of TS 3.3.2, Action Statement No. 14, were invoked. A
controlled shutdown was initiated, a notification of unusual event
(NOUE) was declared and the appropriate notifications were made. The
power reduction continued until approximately 3:00 p.m., when channel
"A"
of SSPS was returned to an operable status. An output circuit
board, which was designed to produce a main generator trip in
response to a main turbine trip (but is not used in the McGuire
System) was found to have failed and was replaced. The entire SSPS
channel was successfully tested prior to making the operability
declaration, exiting the TS action statement and terminating the
NOVE.
Reactor power level was stabilized at about 45's following this
transient and was maintained at that approximate level until the
morning of May 1, when a scheduled refueling shutdown was initiated.
The unit was taken off line at 3:39 p.m. on May 1 and subsequently
- _ - _ _ _ -
_ _ _ _
_
- _ _ _ .
~_
.#
_
i
!
-3.
.
entered Modes 2 - (startup) and 3' (hot standby) . at 3:56. p.m.
and
e4:00.p.m.,
respectively.
The' . reactor coolant- system cooldown
. continued without incident and Modes 4 (ho't shutdown) and.5'(cold
shutdown) were. achieved at 3:49 a.m. and 11:52 a.m., respectively, on
May 2.
A problem regarding the documentation .of entry into. a TS-
,
- Limiting . Condition. for 0peration (LCO) action statement, as.. required
_,
by Operations Management Procedure
2-5,; during the change in
operating modes, is discussed elsewhere'in this report.
On the-morning of May 3, the . unit was in Mode 5 with valve 2NC34, a
pressurizer power . operated relief valve (PORV), aligned, in1the low-
pressure mode when at 10:42 a.m. , the "B" reactor coolant (NC)- pump
was started in order to initiate a crud release and cleanup. The
resulting pressure transient caused 2NC34 to lift at about 368-psig.
and remain open for approximately three seconds prior._to reseating'at
about.300 psig NC pressure.
The incident detailed above prompted the~ inspector to investigate the
-documentation of this and previous plant transients.
In the review-
it was determined that . Technical Specification 5.7.1. requires that.
specified components (e.g., reactor coolant system, reactor vessel)
be' maintained within the cyclic or transient limits of Table 5'7-1.
' Further, Technical Specification 6.10.2. requires that records of-
1 transient or operational cycles for those unit components identified
'in Table' 5.7-1 be retained for the duration of the unit Operating
License.
Station -Directive 3.1.23, " Documentation of Allowable Operating
_
' Transient Cycles", implements the program for documenting transients-
at the McGuire Nuclear Station as required by the TS. Included'among
the transient' cycles to be maintained and documented are NC System
heatups and cooldowns,- NC- System leak tests and normal pressurizer
PORV operation.
A cursory review of the plant's Masten Files on May 7 revealed the
absence of Transient Cycle Reports for the following transients:
.(1) Unit 1 Pressurizer PORV INC34 Operation on August 27, 1986.
(2) Unit 1 NC Heatup on September 5, 1986.
.(3) Unit 1 NC Side Leak Test on September 7, 1986.
(4) Unit 2 Pressurizer p0RV 2NC34 Operation on November 15, 1986.
(5) Unit 2 NC He'atup on November 16, 1986.
The matter was discussed with the Reactor Engineering group in an
effort to determine the status of the missing reports.
In a
memorandum dated May 8, the Reactor Engineering group stated that
reports for transients 2,4 and 5, listed above, had been located on
one of the desks in their office area, but that they had not been
approved or filed. Transient 3 had been identified at the time of
the occurrence, but the report had not been completed, and
_ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _
.
.
4
~
4
.
transient I had not been identified and had apparently been
overlooked in their review of the reactor operators' log books.
As discussed in.Section 5.2.1.5 of the McGuire Final Safety Analysis
-
Report, five ASME (American Society of Mechanical
Engineers)
. operating conditions were considered in the design of the NC System:
normal,
upset, emergency,
faulted,
and testing.
The design
transients selected for monitoring are representative of operating
conditions which could be of possible significance in component
cyclic behavior and equipment fatigue evaluation. The fact that the
Unit 1 operating transient of August 27, 1986, was overlooked is
exacerbated by the apparent lack of discipline evident in the
completion of several other operating transients on both units and is
an apparent violation of the plants' procedures and the Technical
i
Specifications.
In a related effort, _the inspector requested the Licensing and
Compliance group at the plant to confirm that the Special Reports
required by TS 3.4.9.3 had been submitted. Action Statement (c) of
that Specification directs that a Special Report be prepared and
submitted to the Commission pursuant to Specification 6.9.2 within 30
days in the event the PORVs are used to mitigate a RCS pressure
transient. On May 19, the inspector was informed that the required
Special Reports had not been prepared for transients 1 and 4 listed
above. These failures to comply with the requirements of TS 3.4.9.3,
together with the related non-compliance discussed in the previous
paragraph, collectively constitute Violation (50-369,370/87-14-01).
Unit 2 remained in Mode 5 until 11:20 p.m. on May 9, when the first
reactor pressure vessel (RPV) head closure stud was detensioned and
Mode 6 (refueling) operation commenced. The RPV head was removed on
May 17, and core alterations were begun on May 18. At the close of
the report period core off load continued.
5.
Technical Specification Action Item Logbook (TSAIL) (71707)
Operations Management Procedure (OMP)
provides
instructions
for
documenting operations in a degraded condition as permitted by a Technical
Specification (1S) action statement for the existing mode.
The following
deficiencies in maintaining the Unit I and 2 TSAILs were detected by the
inspectors while performing routine log review during the inspection
period,
a.
As permitted by TS 3.4.4. , Unit 2 had operated from November 17,
1986, until the unit was shut down for the outage with one
pressurizer power operated relief (PORV) block valve isolated and
deenergized. This action was documented in the Unit 2 TSAIL (entry
- 12279) as required by OMP 2-5.
The isolated PORV (2 NC 32) is one
of two valves required to be operable for overpressure protection,
per TS 3.4.9.3. , when any reactor coolant system (RCS) cold leg
- . .
__ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
!
l:
"
.
i
5
temperature is less than, or equal to, 300 degrees Fahrenheit in -
,
'
Mode 4, and during Mode 5 and 6 operations (with the vessel head on).
Action Statement (a) of TS 3.4.9.3 requires that, with one PORV
. inoperable, it must be restored to 'an operable status within seven
days, or the RCS must be depressurized and vented through a vent of
at least 4.5 square inches within the next eight hours. This action
statement was entered sometime prior to 11:52 a.m. , on May 2,- 1987,
the time when Mode 5 (average RCS temperature at or below 200
degrees F) operation was commenced. However, the TSAIL entry made to
document the degraded condition indicated the start time for the
seven-day clock as 20:40 on May 2.
This erroneous entry was brought
to the attention of the Unit Coordinator, who later resolved the
discrepancy with the Shift Supervisor on duty at the time and
corrected the problem. The actual time was 10:40 a.m., May 2.
b.
Technical Specification 3.7.6 requires that two independent control
area ventilation systems (VC/YC) be operable in all operating Modes.
Train "A" of VC/YC is normally powered from Unit 1 and train."B" from
'
Unit 2, however, both trains are capable of being powered from the
same unit. The power supply transfer requires that both sources of
power to the train being swapped be deenergized and danger tagged,
thereby making the train inoperable and requiring a TSAIL entry per
OMP 2-5.
On May 4,1987, train "A" was transferred from Unit 1 to
Unit 2 to support engineered safety features testing requirements;
TSAIL entry Nos. 12898/13146 apply.
While reviewing the shift
,
i
turnover documentation on May 6, the inspector noted that train
"A"
had been transferred back to its normal Unit 1 supply, but that no
'
TSAIL entry had been made to document the degraded condition. This
was brought to the attention of the Unit Coordinator and late entries
(Nos. 12912/13180) were made to cover the event.
!
!
c.
A review of Shift turnover documentation on May 7,1987, revealed
that train "B" of VC/YC had been transferred to Unit 1 during the
l
night, but, once again, the degraded condition was not logged in
'
either Unit's TSAIL as required by OMP 2-5.
d.
On March 30, 1987, at 11:29 a.m.,
while Operations (OPS) personnel
'
were attempting to perform a routine diesel generator operability
l
test, Diesel Generator 2B (D/G 28) experienced a trip following a
normal start. It was determined that periodic maintenance (PM) was
being performed by Instrumentation and Electrical (IAE) personnel on
a pressure switch which trips the diesel when in the manual start /run
l -
mode if the cooling water pressure is below the setpoint. Due to a
i
breakdown in communications, the operators were unaware that the
pressure switch was isolated and removed when they started D/G 28.
The pressure switch was replaced and a successful diesel generator
operability test was performed.
Unit 2 was in Mode 1, power Operation, at 100% power, at the time of
this incident.
L
..
. _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
.
.
,
6
Analysis of the circumstances surrounding this event indicate IAE
personnel began a series of PMs on D/G 2B'on March 30, 1987, at
approximately 0830 a.m.
By approximately 0900
a.m.,
they were
preparing to calibrate . diesel cooling water pressure switch . KDPS
5051, and contacted the Shif t Supervisor to advise him that the
manual start circuits for the diesel would be inoperable for
approximately one hour. The IAE personnel, were cleared to begin
work by the Shift Supervisor.
Work on the Voltage Regulator was also in progress by a different IAE
crew. This PM disabled the D/G 2B emergency start /run circuit.
Log
entries had been made by OPS personnel to document this and declare
D/G 2B inoperable in preparation for the PM work.
The work on the
Voltage Regulator was finished by approximately 10:30 a.m. and IAE
contacted the Control Room to arrange for the post maintenance diesel
test.
Control Room personnel contacted the Operations Periodic Test Group,
to have the operability test run.
Two operators responded:
one to
the Control Room and one to the D/G Room.
The two operators were
unaware of either maintenance activity. At about this same time the
IAE crew working on the pressure switch discovered a frayed wire,
isolated the instrument line, removed the' component and took it to
the IAE shop for further evaluation. They were not in the D/G room
when the operator arrived to conduct the test.
At 11:29 a.m.
the D/G was manually started.
20 seconds later it
tripped on a low cooling water pressure signal.
The cause was, at
that time, recognized by the Shift Supervisor and was confirmed by
the operator in the D/G Room. The IAE crew working on the pressure
switch was contacted and then reinstalled the pressure switch. At
approximately 12:02 p.m.,
D/G 2B was again started and the
operability test was successfully completed.
Operations Management Procedure 2-5, Technical Specifications Action
Items Logbook, Section 7.0 (P) requires that any system or component
which is made inoperable by taking one of its support systems
(instrumentation, controls, electrical power, cooling or seal water,
lubrication or other required auxiliary equipment) out of service
shall be logged.
Furthermore, the definition of operability as specified in McGuire
Technical Specification 1.18 states that a system, subsystem, train,
component or device is OPERABLE when it is capable of performing its
specified
function (s),
and
when
all
necessary
attendant
instrumentation, controls, electrical power, cooling or seal water,
lubrication or other auxiliary equipment that are required for the
system, subsystem, train, component, or device to perform its
function (s) are also capable of performing their related support
function (s).
.
. .
. ..
.. .
.
..
.- .
._
_ _ _ _ _
. _ _ .
-
.
.
7
The specified functions of the. emergency diesel generators include.
manual operation from the control room (Reference The Emergency
Diesel Generator and Related Systems, MCSD-0120-00.01 Rev.3, 7/16/85
and applicable Emergency Procedures).
A controversy exists over whether or not the D/G was inoperable with
the manual start /run feature inoperable and whether logging the
pressure switch would have made any difference in the outcome of this
event.
In that vien, this specific event will be carried as on
Unresolved Item (50-370/87-14-02).
The whole point of this scenario being the inadequate implementation
of an administrative vehicle designed to aid the operating staff in
maintaining cognizance of plant status.
Although
all
four events are valid examples of deficient
implementation of OMP-2-5, items two and three collectively are being
identified as an apparent violation of TS 6.8.1
(50-369,
370/87-14-03).
6.
Surveillance Testing (61726)
Selected surveillance tests were analyzed and/or witnessed by the
inspector to ascertain procedural and performance adequacy and conformance
with applicable Technical Specifications.
Selected tests were witnessed to ascertain that current written approved
procedures were available and in use, that test equipment in use was
calibrated, that test prerequisites were met, that system restoration was
completed and test results were adequate.
Detailed below are selected tests which were either reviewed and/or
witnessed:
PT/0/A/4600/140
-
Nuclear Instrumentation System Power Range N-41
Analog Channel Operational Test
PT/2/A/4150/14
-
PORV Channel Functional Test
Reactor Protection System Response Time Test
IP/0/A/3010/06
-
PT/0/A/4601/008A
-
Solid State Protection System (SSPS) Train "A"
Periodic Test Above NC System Pressure of 1955
Engineered
Safety
Features
(ESF) Actuation
PT/2/A/4200/09A
-
Periodic Test
Auxiliary Feedwater System Performance Test
PT/1/A/4252/07
-
,.
-
..
-_
_.
.
8
Identified below is an opporant surveillance testing inadequacy with
auxiliary feedwater suction valves.
f
7.
-Auxiliary Feedwater Pressure Switch Calibration (62703)
Each McGuire unit is equipped with three auxiliary feedwater (CA) pumps,
two motor and one turbine-driven, to provide makeup to ~ the steam
generators for decay heat removal capability when the main-feedwater pumps
are unavailable. The normal, preferred source of suction to the CA pumps
comes from either the upper surge tank, the CA condensate storage tank or
the condenser hotwell.
The assured source of water, while not preferred
because of low purity, comes from the nuclear service water (RN) system.
The RN supply to each CA pump is normally isolated by two valves in
series, one in the CA system and a second in the RN system. Each of these
valves is designed to open automatically upon receipt of a low pressure
signal from single pressure switches, which sense the suction pressure for
their associated CA pump,
s
On May 9, 1987, Instrumentation and Electrical (IAE) personnel determined
that the pressure switch (ICAPS 5002) which controls the automatic
repositioning of valve ICA15 to supply RN to the,1A motor-driven CA pump
was miscalibrated.
They found that the pressure switch had been
previou;1y calibrated without taking into account the static leg of
r
approximately 11 feet of water always present in the instrument line. The'
1A CA_ pump was declared inoperable until the pressure switch was correctly
calibrated.
The calibration records for the other CA pump suction
pressure switches were checked to verify proper ~ calibration; no other
problems were detected.
The inspectors requested the licensee to make a determination whether the
1A CA pump suction would ever have transferred to the RN system as
designed and to research the equipment history for ICAPS 5002 to find out
how long it had been out of calibration. In a preliminary evaluation of
the incident, the licensee has concluded that, since the pressure exerted
by the instrument's reference leg exceeded the switch's setpoint, the
switch would never have actuated.
They consider that the incident is
reportable under 10 CFR 50.73 and that CA train 1A was inoperable prior to
recalibration of the pressure switch on May 9.
Preliminary indications are that ICAPS 5002 had been out of calibratien'in
excess of one year; a more precise determination will be made during the
Incident / Problem Investigation (PIR No. 1-M87-0083).
Technical Specification 3.7.1.2 requires at least three independent steam
generator CA pumps and associated flow paths to be operable in Modes 1,2
and 3.
Surveillance requirement 4.7.1.2.b.3 verifies that the valve in
the suction line of each CA pump from the RN system automatically actuates
~,
to its full open position within less than, or equal to,13 seconds on a
low suction pressure test signal.
This surveillance requirement,
implemented by PT/1/A/4252/07, was last successfully performed on
1
!
.
.
9
March 20, 1986, but it does not challenge the system with an actual low
pressure condition in the pump's suction:line.
Pending the completion of the licensee's PIR and further review of the
surveillance testing pursuant to TS 4.7.1.2.b.3, this issue will remain
unresolved (50-369/87-14-04).
8.
ESF Actuation Testing (61726)
During the report period the inspectors witnessed Unit 2 ESF Actuation
testing.
The test is run on both trains, one train at a time and is
'
designed to:
-
To demonstrate the diesel generator's ability to restart and load in
response to a manually initiated safety injection, Phase A Isolation,
Phase B Isolation and Blackout after having been run or 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and
shutdown.
-
To demonstrate that when the D/G paralleled with offsite power, a
safety injection returns the D/G to standby status and the emergency
loads are sequenced onto the offsite power supply.
-
To demonstrate D/G starting load shedding and emergency load
sequencing in response to a blackout.
.
To document the correct movement of valves in response to a safety
injection, Phase A Isolation, and Phase B Isolation which are
operated pursurant to above.
The D/G is operated at 110% rated load for two hours, followed by at
least 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> at 100% rated load and then shutdown. Within five
minutes a SI, Phase A and Phase B Isolation and blackout are manually
initiated with the D/G subsequently starting, accepting and operating
the emergency laod for at least five minutes.
Power is restored to
the 4Kv transformer, the D/G synchronized, and the load transferred,
with the D/G being returned to standby status. The D/G is paralled
with offsite power and a SI manually initiated. The D/G nreaker is
auto tripped with the D/G returning to standby status as the
sequencing of loads onto offsite power progresses.
D/G parameters,
system response times, and correct valve movement are recorded.
To test ESF response to a train blackout the 7KV feeder to 7/4KV
transformer is tripped initiating a B/0.
The D/G auto starts, load
shed occurs, sequencing for B/0 progresses and the D/G carries the
B/0 loads for at least five minutes. The sequencer is reset and the
D/G us manually tripped with load shedding, D/G restarting and load
sequencing reinitiated.
D/G paragmeters, corrrect valve movements,
response times, and system responses are recorded.
i
'<j
f
.
.
10
- At the - end of the report period, the inspectors review of the ESF
tests was not complete. -This item will be carried as an Inspector
Followup Item. (50-370/87-14-05)
9.
Maintenance Observations (62703)
~ Routine maintenance activities were reviewed and/or witnessed by the
resident inspection staff to ascertain procedural and performance adequacy
and conformance with applicable. Technical Specifications.
The selected activities witnessed were examined to ascertain that, where
applicable, current written approved procedures were available and in use,
that prerequisites were met, that equipment restoration was completed and
maintenance results were adequate.
An Unresolved Item (50-369,370/87-08-02), regarding the maintenance and
testing of ' valve INM-26 as documented in a previous Inspection Report, has
been resolved as a Licensee' Identified Violation. This issue is discussed.
in detail later in this report.
10. Unit 2 Refueling (60705, 60710)
As discussed earlier in this . report, Unit 2 commenced a refueling outage
on May 1, 1987.
In preparation for refueling, the inspector reviewed a
number of licensee procedures for the -conduct of refueling operations to
ascertain their adequacy.
The following procedures were reviewed:
OP/2/A/6100/02 - Controlling Procedure for Unit Shutdown
OP/2/A/6150/06 - Draining the RCS
OP/0/A/6550/04 - Fuel and Component Handling
MP/2/A/7150/057 - Reactor Head Removal and Replacement
PT/2/A/4550/022 - Total Core Unloading
PT/0/A/4550/024 - Fuel Assembly Examination
OP/0/A/6550/01 - Receipt, Inspection and Storage of New Fuel
PT/2/A/4550/21 - Inspection and Storage of New Fuel
0P/0/A/6550/11 - Internal Trsosfer of Fuel Assemblies / Inserts
Enclosure 4.6, "NC Level InctOamer ation Overlap", was noted to be missing
from.the Master File cop'
~ 0F
'A/6150/06.
The Operations Procedure
t
Group was informed of the . l se
,ncy and verified that the Control Copy
of the OP maintained in the Control Room did have the necessary enclosure.
The licensee, took prompt action to correct the deficient Master File
procedure.
PT/2/A/4550/01 was noted to have been recently revised to incorporate
documentation for the removal of the curbs which protect the containment
air return (VX) fans from the in' flux of excessive amounts of water during
containment spray system operation. The failure to control the removal
and reinstallation of the VX curbing was the subject of recent enforcement
action against Duke Power.
\\
m
te
-
.:
.
.
11
'
. Pre-refueling and refueling activities were observed and monitored to.
ascertain whether Technical Specification requirements were satisfied and
. activities _were conducted in accordance with approved procedures.
-
On:May 5,.1987, while the reactor ~ coolant (NC) System was being drained,
in accordance with OP/2/A/6150/06, inconsistencies were. noted between the
various RPV level instruments (i.e., installed -wide and narrow range
meters, sight glass and tygon tube).
In light- of recent incidents' at
other'similar facilities during mid-loop operations, and as required by.
their procedures, the licensee proceeded very cautiously to ensure that
adequate residual : heat- removal ~ system suction was maintained. .The
licensee is taking a pro-active approach to the_ issue and has-initiated an
e
Incident' Investigation (Report No. M87-031-2) to determine the cause ' of
.
the instrument inaccuracies and to propose corrective actions to preclude -
recurrence. This . investigation will be reviewed by. the inspectors when
complete.
- No violations or deviations were identified.
Ell. Auxiliary. Feedwater Pump Halon Fire. Suppression System
The- Unit 1 and 2 auxiliary feedwater (CA) systems at McGuire consist of
two motor-driven pumps and one ' turbine-driven pump.
The turbine-driven
- pump rooms are' protected from fire by. halon 1301 fire extinguishing
systems consisting of two halon cylinders each (one main and one reserve),
located in'the basements of the unit turbine buildings.
Subsequent to ' the maintenance problems _ encountered -.with the diesel:
generator halon fire suppression' systems, as documented in NRC Inspection
Report Nos. 50-369,370/87-12, the inspector examined the CA halon systems
to determine- whether they were susceptible toi similar' problems.
During
the inspection, it was noted that the Unit 2 halon cylinders were mounted
to the turbine building wall in a manner which would prevent their
becoming a missile hazard.
In comparing the Unit 1 cylinder support with
that.on Unit 2, it was noted that the only support afforded to the Unit 1
CA halon cylinders wa's that provided by the discharge pipe. The inspector
informed the Unit Coordinator of the apparent deficiency and later
verified that the cylinders had been temporarily restrained with a chain.
Further research and discussions with licensee personnel revealed the
following:
,
-
_The McGuire Nuclear Station Final Safety Analysis Report (FSAR),
i
Section 9.5.1.2.1, states that the Fire Protection System is designed
to meet the standards developed by the National Fire Protection
Association (NFPA) where practicable.
It further states that halon
1301 fire protection systems are provided for the turbine-driven CA
pump oil hazards _in the auxiliary building.
-r
.
.
12
-
NFPA Standard 12A, "Halon 1301 Fire Extinguishing Systems", Section
1-9.4.6, states that, when manifolded, containers shall be adequately
mounted and suitably supported in a rack...".
-
The ' Duke Power Company Administrative Policy Manual for Nuclear
= Stations, Section 3.11.3.4, states that the halon 1301 systems shall
be tested, maintained, and inspected in accordance with NFPA Standard
12A.
-
The McGuire Nuclear Station Fire Protection . Review Manual responded
to positions presented in Appendix A to Branch Technical Position
APCSB 9.5-1.
Position E.4, "Halon-Suppression Systems," states that
the use of halon fire extinguishing agents should, as a minimum,
comply with the requirements of NFPA 12A. The licensee's response to
Position E.4 stated that approved halon 1301 systems were available
for the CA steam-driven pumps and did not take exception to the
Branch Technical Position.
-
Drawing MCM 1206.07-30, Sheet 3 illustrates the Unit 1 CA halon 1301
system as being rack mounted to provide suitable support.
The licensee's design engineering staff has acknowledged that the as
built Unit 1 CA halon 1301 system does not conform with the
applicable standards and has informed the inspector that action has
been initiated to correct the deficiency. This design deficiency is
classified as an apparent deviation from commitments made to the NRC
-(50-369/87-14-06).
12.
I.E. Bulletin Closeout
(Closed) 369,370/86-BU-03, Potential Failure of multiple ECCS pumps due to
single failure of air operated valve in minimum flow recirculation line.
The licensee responded to IEB 86-03 in a letter dated November 10, 1986.
In their response the licensee stated the concern was previously
investigated as a followup to IEN 85-94.
From this review, the licensee
determined that the ECCS minimum flow lines were adequately designed to
protect the pumps.
In addition, the licensee stated the issue of single
failures and deadheading ECCS pumps was discussed extensively with the
NRC staff during the license review for Catawba, whose design is
essentially the same as McGuire. As a result of the reviews, the licensee
has concluded that McGuire does not have the potential for a single
failure causing the failure of more than one ECCS train. This item is
closed.
13.
Inadequate Post Maintenance Procedure
As was previously reported (369/87-08), on February 24, 1987, valve
INM-26B, Reactor Coolant (NC) Hot leg Sample Header Outside Containment
Isolation, failed to operate correctly during a slave relay test.
,
.
- _.
___
. _ _ - _ _ _ _ _ _ _ _ _
'
V
>
c
.
,
,
- -
,
' 13 '
.
A more: detailed review of the circumstances surrounding the event revealed
~
that Eon JJanuary -15, 1987, - valve : 1NM-268 : failed a - r'outine valve 1 stroke
- timing' test. iThe 'cause of. the problem was determined to be an inoperable.
=
actuator motor- on :the valve. -The ' actuator was replaced on .Febr~ ary. 9,
u
.1987.
The valve owith the new ' actuator passed functional : testing and
operatedDsatisfactorily. until February 24, 1987.
On1this date,? performance (PRF) personnel performed a routine test of.the
SSPS slave relays. During_a portion.of the test valve.1NM-268 should have
closed and remained closed. ' Instead, the valve ' cycled continuously, as
along as the output relay was energized from the slave relay test -device.
With the output relay deenergized ~(normal), valve 1NM-268 - operated -
correctly with the control. board switch._ In other words, the valve would
not-have' isolated on an automatic ESF. signal.
-
IAE personnel investigated the problem with valve INM-268 on February 25,
~
1987. When the IAE technician removed the cover from the terminal block,
he detected what' appeared to be a metal to metal contact between
= termination ~ point'24 and. termination point 15. He bent the neckoof the
. ring' terminal on point 24 so that contact.was no longer made,
PRF personnel retested valve INM-26B which closed and remained closedJas
required.and operated satisfactorily with the control board switch.
Examination revealed a nick in the insulation. covering the metal sleeve of.
ring ~ terminal 24 which allowed the - metal to directly contact the barrel
nut below it.
The~ normal orientation when installing a single ring terminal is to
position -the metal sleeve facing away' from the terminal block. When the
= actuator for-valve INM-268 was replaced in February 1987, ring terminal 24
was installed with the metal sleeve facing 'the terminal. block.
Upside-
down -if you will, increasing the possibility of creating a short circuit.
The short circuit. was most likely caused by the positioning of ring
-terminal 24 by the IAE technician during the most recent installation. A
review of applicable procedures revealed that this 'did not address- the
' positioning of ring terminals, nor precautions to take to avoid shor+.
circuits.
Discussions with licensee and a review of McGuire Incident Investigation
Reports did not reveal any valve malfunctions due to similar problems.
In report 369/87-08, the subject of post maintenance testing was opened as
an Unresolved Item. In as much as the licensee has determined that normal-
- functional testing after valve repairs will still not include a test of
function when as SSPS signal is applied, the issue Item will remain
unresolved, pending further review.
(50-369,370/87-14-08)
'
I
It appears that the root cause of this event was the inadequacy of the
applicable procedures.
More specifically, Procedure IP/0/A/3066/02A,
I.
I
l
q.
-
~
'
,
"
[
w
.
-14'
i
-
Installation, Removal ~, and Set-up of Rotork Actuators,_the procedure.which
delineates = thef directions for: rewiring -Rotork : actuators, contained .no
instructions for positioning'of ring terminals nor= precautions to take to
avoid short circuits. However, 'in' as much as' the problem was identified,
and corrected by the licensee, the event-contributes a Licensee Identified
- Violation. l(50-369/87-14-07)
-14. ._ Design,'De' sign Changes, and Modifications (37700)
_ Selected _ design ' changes and modifications that were d'etermined 'by the
licensee to :not-- require'. approval by the NRC were reviewed to ascertain
conformance with the requirements oflthe plant's Technical Specifications
and 10 CFR4 50.59.
Specifically, ' the following Nuclear Station Modifications (NSMs) and
associated work requests (WRs) were~ evaluated:
~
NSM MG-1-1930/MG-2-0700 -
Move selected safety, injection,
-
WRs 94621, 94623'
chemical volume and control, and: CA
System valve actuator - torque bypass
switches to' the actuator add-on. pack.
Reset torque bypass switches to 50*.' and
replace all jumpers' with qualified
wire.
NSM MG-2-0089,IRev. 1
-
Modify the-control rod gripper
-
on the reactor building rod control
cluster change fixture.
No violations or deviations were identiified.
15.
LER Followup-
The Licensee Event Reports detailed below were reviewed in order to
determine if the licensee's review, corrective action and report of the
~
identified event and associated conditions are adequate and in conformance
with
regulatory
requirements, ' Technical
Specifications,
licensee-
conditions and licensee procedures and controls.
-The review, consisting of record review, direct observation or discussion
with licensee personnel was directed primarily at verifying that:
corrective action is appropriate to correct the cause of the event.
-
corrective action has been or is being caken.
-
,
for corrective action not yet complete, that responsibility has been
L
-
,
assigned for' assuring completion thereof.
-
generic implications i f identified were incorporated in corrective
L
action.
.
is
,-
p4.,
--
-c,e,
, w
a--m es, e
,,y,w.
um.,
+---.w.
w-~-t-~t-r.,
.w
mwy*
y,.p
w v v-y
-ww,..e
9 f T
'r'
, y- r y- e v, e-wn 't-* * w w
e- w w - ar -- - --
m
.
15
'
Unit 1
Unit 2
-LER 86-04
LER 86-04
LER 86-06
LER 86-05
LER 86-07
LER 86-07
LER 86-08
LER 86-11
LER 86-09
LER 86-12
LER 86-13
LER 86-15
LER 86-18
LER 86-17
LER 86-02
LER 86-21
LER 87-01
LER 87-03'
LER 87-06
LER 87-05
No Violations or Deviations were identified.