ML20235Y567
| ML20235Y567 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 02/17/1989 |
| From: | Lawyer L, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20235Y562 | List: |
| References | |
| 50-395-88-26, GL-82-33, IEC-80-02, IEC-80-2, IEIN-88-086, IEIN-88-86, NUDOCS 8903140335 | |
| Download: ML20235Y567 (51) | |
See also: IR 05000395/1988026
Text
m
s
i
pm Ricoq'o
_
z UNITED STATES
_
4
NUCLEAR REGULATORY COMMISSION
j.'
'[
REGloN il
_ lt
,, j
101 MARIETTA STREET,N.W.
5
t
ATLANT A, GEORGI A 30323
D
% . . . . ./
y
1
l-
I
LReport No:- 50-395/88-26
~
Licensee: South' Carolina' Electric &' Gas Company
1
Columbia,'SC 29218
' Docket-No:
50-395-
-License No. NPF-12
Facility Name:
Virgil
C.'
Summer
~
Inspection Conduct
ov ber 14-18
ecember 5-9, and.' December 20-23, 1988-
,
/4
99
Inspectors:<
U-
M
_ _ _
Dite Signed
'
L. L.
_awyer, . TeampcTer1
Team Members:
K.'Brockman
C; Casto
<
P. Kellogg
W. Miller
,
,
T. O'Connor
'
R..Schin
f
-
D. Starkey
/_
,
.
ch//43/
'
'
'
Approved by:
~
T., A. Peebles, Chief
Date Signed
l
Operations Branch
<
l
Division of Reactor Saftey
SUMMARY"
Scope:
This was a special announced , Operational Safety Team Inspection -
(OSTI). The OSTI evaluated the11icensee's current. level of perform >
ance in the area of plant. operations'. - The inspection included an
evaluation of the effectiveness of- various iplant groups including -
Operations, Maintenance, Quality Assurance, Engineering,.and Training.
in the support of safe plant ~ operations. Plant-management awareness
of,-involvement in, and support of safe plant operation.were also
!
evaluated.
~
The inspection' was divided into four major areas' including . Opera-
tions, Maintenance _ Support .of Operations, Management. Controls,
and Emergency Operating. Procedures.
The team' placed emphasis on
j
numerous interviews of personnel-at all levels, observations:of plant.
activities and meetings, extended control room observations, - and
-
system . wal kdowns.
The ? inspectorsi also reviewed' plant - deviation
reports and LERs for the current Systematic Assessment of. Licensee-
_.
o ;fh4033,5 ggg, s
,
,
em
'
PL)
1
moca
,
+
,
ng
}
,
E
.
. -
o
..
m
2
Performance (SALP) evaluation period, and evaluated the effectiveness
of the licensee's root cause identification; short term and progra-
matic corrective actions; and repetitive failure trending and related
corrective actions.
Results:
The licensee's management organization exhibited a high degree of
professionalism and control and was well directed to support effec-
tive and efficient operations.
The team performed this inspection
during a four week period in which the licensee was conducting a
refueling outage and entering into Mode 4.
This afforded the team
the opportunity to observe the operations, maintenance and engineer-
ing departments performing activities that required a great deal
of coordination and organization during a period of potentially
,
high stress.
The . departments exhibited a calm demeanor and were
apparently in good control of the many diverse activities that were
being accomplished during this period of recovery from the refueling
outage.
Emergency Operating Procedures were found to be adequate to place
the plant in a safe, stable condition.
The team observed a number of noteworthy items which were considered
as contributors to the exhibition of proper command and control.
Among these were shift turnover forms which provided a vehicle
for continuity of plant status during shift changes, operations
department logs that were all legible and complete with off-normal
conditions clearly indicated, large status boards containing the
names and stations of watchstanders as well as the boron injection
flow path, the required reading was up-to-date providing the
operators with new information on plant safety, operator response
to abnormal conditions was prompt and thorough, control room access
was well controlled, operator access to locked spaces was well
organized,
and engineering department evaluation of potential
i
problems was aggressive. (Paragraph 2.a.)
Another noted strength was the use of a shift engineer throughout
the outage to coordinate with and resolve problems involving other
departments.
(Paragraph 2..c.)
The addition of licensed individuals to the maintenance scheduling
and planning section has provided operational expertise to the
process. The team considered this to be a strength in the scheduling
l
process.
(Paragraph 3.b.)
The NRC saw the scheduling section's preparation of a daily '" trip
package" which contained planned maintenance for unscheduled shut-
downs of short duration and the "sho.t duration outage package"
for an outage of less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as a strength. '(Paragraph 3.b.)
In addition, they considered the low backlog of maintenance work
requests that were older than three months to be a strength.
(Paragraph 3.f.)
l
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ _ _ _ _
- . _ _ . _ .
._
_;
_
_
_
_
_ _ _ - - - - - - - _ _
_ _ _ _ _ - . _ _ - - - - _ _ _ _ _ _ _ _ _ _ _
3
They also saw as a strength the engineering department's preparation
of design basis documents for the plant systems.' These provide a
living history of the systems from design through construction and to
present configuration.
(Paragraph 4.)
The team considered the independent safety engineering group's self
initiative of ' performing safety system functional inspections as a
strength.
(Paragraph 5.)
The team identified several areas which were considered to be weak-
nesses. Of these, inadequate procedures and inattention to procedure
adherence seemed to the team to be the most serious and resulted
in a violation.
(Paragraphs 3.c. and 3.1.1.)
The team considered the failure of the licensee to completely and
effectively respond to grounds on the dc bus and to previously detect
and correct a design problem in the ground detection circuit to be
problems of nearly equal seriousness.
(Paragraph 2.b.)
The licensee's lack of review thoroughness led to problems in the
areas of configuration control, drawing control, and procedural
control.
(Paragraph 2.d.,
e., and g.)
Inadequacies in 50.59 evaluations, which led to erroneous conclu-
sions were another weakness which resulted in a violation.
(Paragraph 2.j.)
The deficiency identification and correction process was considered
to be a weakness due to the fact that tagging is optional which
could result in not identifying known deficiencies.
(Paragraph 2.k.)
Lack of a formalized training program for maintenance planners was
a weakness.
(Paragraph 3.d.)
Blanket overtime authorization during outages was identified as
another area of weakness.
(Paragraph 3.f.)
l
i
l
l
t
i
r
i
!
I
-
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- 0. Bradham, Vice President Nuclear Operations
- W. Baehr, Manager Chemistry & Health Physics
- M. Browne, Manager, Systems & Performance Engineering
- C. Bowman, Manager, Scheduling & Modifications
- R. Campbell, Senior Engineer, ISEG
- R. Clary, Manager, Design Engineering
- H. Donnely, Senior Licensing Engineer
- W. Higgins, Supervisor, Regulatory Compliance
- S. Hunt, Manager, Quality Systems
- M. Garrett, Associate Manager, Quality Control
'
- A. Koon, Manager, Nuclear Licensing
- P. LaCoe, Assistant Manager, Facilities
- G. Moffatt, Manager, Maintenance Services
.
- D. Moore, General Manager, Engineering Services
I
- K. Nettles, General Manager, Nuclear Safety
- M. Quinton, General Manager, Station Support
- L. Shealy, Senior Engineer, Operating Experience
- J. Shepp, Associate Manager, Operations
- J. Skolds, General Manager, Nuclear Plant Operations
- A. Smith, Manager, Facilities & Administration
!
!
- G. Soult, General Manager, Operations & Maintenance
- G. Taylor, Manager, Operations
- G. Walker, Coordinator, Maintenance Services
- D. Warner, Manager, Core Engineering & Nuclear Computer Services
l
- M. Williams, General Manager, Nuclear Services
- W. Williams, Santee Cooper, Special Assistant, Nuclear Operations
- K. Woodward, Manager, Nuclear Operator Training
Other licensee employees contacted included Technicians, Operations
Personnel, Maintenance and Instrumentation personnel, Engineering person-
nel, and Office personnel.
NRC Representatives
- P. Hopkins, Resident Inspector
- E. Merschoff, Deputy Director, Division of Reactor Safety
,
- R. Prevatte, Senior Resident Inspector
1
'
- Attended Pre-exit interview on 12/09/88
- Attended exit interview
Acronyms used throughout this report are listed in Attachment 8.
l
_ _ _ _ _ _
_
_ - _ _ .
_- ._
_ _ _
_____- _ __
__ _ _ _
_,
.
_ _ _ _ _
- _ _ _ _ _ _
. _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
2
2.
Operations (41400,41707,42700,61700,71707,93802)
i
Many of the positive attributes of operational safety can be directly
l
observed in the Control Room. These attributes include such things as
adequate shift manning, delegation of Shift Supervisor (SS) non safety
l
related duties, Reactor Operator (RO) and Senior Reactor Operator (SRO)
system knowledge, relief turnover procedures, ' etc.
Adequate shift
manning assures that qualified plant personnel to man the operational
shifts are readily available . and that - excessive overtime need not be
. utilized;
delegation of nonsafety-related duties assures the SS
attention to the command function will not be diverted to nonsafety-
related duties;
accurate diagnosis and response. to plant transients,
minor and major, require detailed operator systems knowledge, etc.
Other operational safety attributes can be better assessed through
plant tours and system walkdowns. . These include material condition;
conformance to approved procedures; attentiveness to duties;
and return
I
to service of equipment important to safety, including correct system
alignments.
Finally, interviews with personnel holding a variety of positions on the
plant staff together with some review of= records is necessary to provide
indirect indicators of operational safety and to corroborate preliminary
assessments.
To assess the operational safety of the facility, the Nuclear Regulatory
Conaission (NRC) team performed extended observations of control room
activities, including back shifts, with the plant in mode 5.
Also, the
i
team conducted system walkdowns and plant tours.
In addition, they
I
interviewed operators during these observations, walkdowns, and tours,
observed shift turnovers, and reviewed operator logs.
The team also
reviewed records used for indication or control of plant status for
adequacy and vF:d operator awareness of their contents.
These
included the Ra n
and Restoration (R&R) Log, configuration control
records, Danger Tag Log, Caution Tag Log, and plant drawings.
The NRC monitored operator performance, control room decorum, awareness
of plant status, response to alarms, and use of procedures. The team
conducted interviews or plant tours with the General Manager 'of Nuclear
Plant Operations, General Manager of Operations and Maintenance, Manag-
of Operations, and Associate Manager of- Operations. 'The NRC team also
reviewed engineering evaluations, training, and maintenance as related to
questions that arose from observations in the plant.
t
/
E________
_ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _. _
_
_- _
l
l
3
a.
Summary of Observations
The NRC team made a number of observations of good operating
practices, which are summarized below:
All operators used shift turnover forms.
The forms included a
-
thorough checklist, and required operators to sign for reviewing
logs and plant status indicators. These forms helped to ensure
that oncoming watchstanders were knowledgeable of the safety
status of the plant.
Operator logs were all legible and complete. Off-normal condi-
-
tions were clearly indicated and explained. The team noted no-
recordkeeping errors.
These logs helped to provide auditable
records of plant conditions and to ensure operator awareness' of
the important ones.
The names of watchstanders and duty technicians were all clearly
-
visible on a large status board in the control room.
These
included fire brigade, duty chemist, duty H.P. specialist, and
shift engineer.
This board enhanced control room operator
awareness of who to contact for various operational needs. The
I
licensee's use of one watch position' on the board, the ~ shift
engineer, is considered a strength and is discussed later in
this report.
The boron injection flowpath that was to be maintained in an
-
operable condition by the operators was clen jy posted on
another large status board in the control room.
This board
enhanced operator awareness of equipment that was in standby
for emergency use.
The required reading book contained signatures of operators
-
I
which were up-to-date as required.
It included many types of
l
information, such as design changes, NRC Information Notices
'
(IEN), Licensee Event Reports (LERs), and Institute. Of Nuclear
Power Operations (INPO) Significant Operating Event Reports
(SOERs). The operators were keeping informed of new information
important to plant safety.
Operator response to an abnormal condition was prompt and
-
thorough.
The abnormal condition was that both source range
!
Nuclear Instruments (NIs) were inoperable at the same time.
'
This is discussed later in the report.
Prompt and thorough
'
operator response to abnormal conditions is important to plant
safety.
)
-
Control room access was well controlled, and watchstanders
maintained an appearance of proper decorum and professionalism.
.
A professional approach to plant operation enhances plant safety
l
by providing operators who are alert to off-normal conditions
l
and by providing a model for similar vigilance on the part of
plant workers coming into contact with them.
1
i___________________
__
-.
-
-
J
_ _ _ _ _ _ _ _ _ - - _
l
l
'
4
Key control for operator access to spaces and equipment was
-
provided -through a well organized key system and is discussed
later in this report.
Operator access to plant equipment in
emergencies is important to enable the accomplishment of
emergency actions.
-
The aggressive and thorough engineering evaluation of NRC
questions.during the inspection relating to direct current (de)
l
grounds was noteworthy,
prompt evaluation and correction of
potential safety problems is important in minimizing the risks
I
of plant operation.
The team also observed a number of areas in need of improvement:
The areas of Limiting Condition for Operation (LCO) control,
-
configuration control, drawing control, and procedure control
were in need of improvement and are each discussed later in
this report. Accurate control of safety-related plant systems
is important to overall plant safety.
l
-
The team considered the . failure to completely and effectively
l
respond to grounds on the dc bus and to previously detect and
correct a design problem with the ground detection circuit
as problems of nearly equal importance.
These problems are
.
discussed later in this report.
Inadequacies existed in a safety evaluation of a modification
-
to the fire protection system ' alignment, and are discussed -
later in this report. Complete and timely safety evaluation of
plant modifications is important, to minimize the potential of
introducing new conditions that may in some way reduce plant
safety.
-
The deficiency identification and correction process needs
improvement, and is discussed later in this report.
Timely
and thorough identification and correction of deficiencies -is
important, even though each individual deficiency may have
only minor safety significance.
Deficiencies can range from
the very serious, where safety significance is apparent, to
seemingly minor deficiencies.
Timely and thorough identifica-
tion and correction of even those which seem to have only minor
significance is important since two or more may, in combination,
be very significant.
t
r
__ ___________
_ _____ __
.
,
_ _ _ _ _ _ _ _ _ _ _ _
____
__
5
b.
Electrical Grounds on 125 Volt DC Systems
On entering the control room on the first day of the inspection
(during an outage), the NRC noticed that all three of the electrical
ground indicating systems indicated grounds.
Electrical grounds
existed on both of the vital 125 volt de busses and on the nonvital
125 volt de bus.
The team then inquired about:
Promptness and methods used in clearing grounds on vital 125
-
volt de systems.
Policy on magnitude of ground acceptable for plant operation.
-
'
-
Whether any safety evaluations had been done for the plant that
were dependent on an ungrounded de power supply.
Whether the licensee had reviewed NRC Information Notice 88-66,
-
issued October 21, 1988, on Operating with Multiple Grounds in
Direct Current Distribution Systems.
This notice identified
the potential for spurious actuation of equipment,
in response to these questions, the licensee's Operations Department
forwarded questions to the Engineering Department for evaluation and
response.
Included with 'the questions was the fact that existing
policy on operating with dc grounds required the maintenance -depart-
ment to locate and clear grounds of 5 volts or worse (positive or
negative leg to ground).
The 5 volt value represents a hard ground, on the order of 100 ohms
to ground.
With an existing ground of 100 ohms, the risk exists
that the occurrence of a second ground, of 0 ohms, could generate a
ground fault current of over 1 ampere. That amount of current could
cause a small 1-ampere fuse to blow and thus disable a piece of
safety equipment.
The plant manager stated that when grounds had. occurred while the
plant was operating, the operators. and Maintenance Department had
not always promptly cleared them. This was because the opening of
certain dc breakers with the plant operating would cause 'a reactor
trip or create unnecessary safety hazards.
The Engineering Department obtained a copy of IEN 88-66, then
responded aggressively to the questions. The IEN was already in the
licensee's system, having been received approximately one month
prior to this inspection.
Engineering determined that two safety
evaluations had been done based on an ungrounded vital 125-volt-dc
system.
The engineers also determined _ that one of the safety
evaluations, which involved -the effects of a steam break / Loss of
.
Coolant Accident (LOCA) event on solenoid actuated valves, was
)
adversely affected by the possibility of a ground on the de system.
l
l
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ .
_ _ _ _ _ _ _ _ _ _ _ _ _ . _
_ _ _ _ . - -
- - - - - -
-
-
,
i
!
6
i
i
l
With a ground on the positive leg of a vital 125-volt-dc bus, the
i
risk existed that a second ground, between the positive side of a
solenoid and its activation contact, could cause that solenoid ~ to
energize or remain energized inappropriately. This would occur since
!
the two grounds would be on opposite sides of the solenoid actuation
]
initiation contact, because there is no contact on the negative side
,
of the solenoid. A very small existing ground (approximately 4000
ohms) on the positive leg of the de bus, coupled with a hard ground
fault on the solenoid could thus prevent the solenoid from dropping
out or even pick it up, and cause a valve to spuriously operate. For
Automatic Switch Company (ASCO) solenoids, the dropout voltage was
about 20 volts and the pickup voltage was estimated to be about 40
volts, with required current in the range of milliamps.
Shown in Attachment 1 is a typical ASCO solenoid circuit, with a
ground fault on the positive side. Also shown is this licensee's
ground detection system, which includes 1000 ohm light bulbs in
series with 2000 ohm resistors, located in both the control room and
at the battery chargers.
A complete circuit through the solenoid
and the ground detector is shown.
The ground detector is discussed
later in this section.
This failure mode adversely affected the operation of approximately
90 solenoids. They in turn operated approximately 30 valves of
concern. The safety evaluation had assumed that these valves would
fail safe in the deenergized condition, and the valves had been
exempted from Environmental Qualification (EQ) sealing requirements.
The affected valve's included all pressurizer power operated relief
valves, main steam isolation valves, feedwater isolation valves,
reactor building cooling unit bypass dampers, reactor building purge
valves, and other containment isolation valves.
Based on this analysis, the licensee promptly modified the affected
solenoid circuits to provide environmental qualification by either:
-
Sealing the power supply conduit to the solenoid, or
Installing a contact on the negative side of the solenoid.
-
The licensee accomplished the modifications during an outage exten-
sion of approximately seven days.
The plant manager and engineers stated that the probability of- a
steam leak /LOCA event causing the dc busses to become grounded was
high, due to the many non-EQ loads on these busses. The probability
of a ground occurring on the positive side of a . solenoid, and not
simultaneously on the negative side, was not readily estimable. The
licensee believed that the potential for a solenoid to fail energized
in a harsh environment, with a grounded dc power supply, had never
been tested.
e
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
,
__
-_
_ _ - _ _ _ _ _ _ _ ___
___
7
The Engineering Department determined that the installed ground
detectors caused permanent grounds, of approximately 1500 ohms, on
both the positive and negative legs of the vital 125-volt-dc busses.
This magnitude of existing ground was sufficient to make the ASCO
solenoids susceptible to failing energized.
Based on this analysis, the licensee promptly disconnected the ground
detection circuits on both vital 125-volt-dc 'ousses by removing the
light bulbs.
In addition, the licensee wrote and implemented a
maintenance procedure for taking daily ground readings with portable
equipment.
This procedure required locating and removing grounds
(based on voltage and current readings) that were about 5000 ohms or
less.
,
The NRC asked if any other equipment, besides ASCO solenoids, existed
with circuitry and components such that it could similarly fail in an
energized condition. The licensee identified the Electro Hydraulic
Control (EHC) main turbine control as potentially susceptible to this
failure mode. The licensee plans to conduct further evaluations, and
to consider further modifications.
The licensee is pursuing the installation of a new ground detection
system that will not create a permanent ground of safety signifi-
cance.
Also, the licensee plans to purchase " state-of-the-art"
portable ground locating equipment.
The licensee stated that this
new equipment shculd enable locating dc grounds in the range of
1500 to 2000 ohms, without having to open breakers.
Better ground
locating equipment may well be a key to maintaining the de systems
ungrounded, since many dc breakers cannot be opened with the plant
at power without risking a trip of the plant.
The licensee's aggressive responsiveness to this issue was note-
worthy.
However, the team considered the past failures of the
licensee to always promptly clear de grounds while the plant
operated and to detect and correct a design problem in the ground
detection circuit as weaknesses.
c.
Shift Engineer
The licensee stated that the addition of a shift engineer during the
outage added to the effectiveness and safety of controlling outage
activities. The shift engineer is assigned to perform the required
Shif t Technical Advisor (STA) functions in modes 1-4, in addition to
many others. Qualification requirements for this position include
being a qualified STA, and in addition being a qualified SRO. A
shift engineer maintains an inactive SRO license. The shift engineer
duties are described in procedure SAP-421, Shift Engineer Conduct of
Operations, Rev. 3.
The position is filled during an outage in modes
5 and 6, as well as in modes 1-4.
A major function of the shift
engineer is to coordinate with and resolve problems involving the
engineering and maintenance departments.
The shift engineer also
performs engineering inspection and review functions, such as
conducting plant tours, investigating abnormal events, reviewing
__
_
_
.-- ------ _ -- _ _ _ _
8
jumper and lif ted lead requests, and monitoring cyclic and transient
events.
The shift engineer ' qualification requirements and use
during an outage are beyond minimum regulatory requirements and are
considered to be an area of strength.
d.
Configuration Control and Procedure Control
Gooo configuration control of safety systems can _ reduce the risk of
occurrence of situations that could result in or contribute to an
accident.
To assess the effectiveness of the licensee's procedures
for configuration control of safety related systems prior to' plant
startup, the team reviewed procedures, interviewed operators, and
walked down systems.
In this area of inspection, the team noted
several procedural points that needed improvement. These improve-
ments would increase the assurance of having safety systems aligned
and operable. For each point, the licensee had already initiated
changes or subsequently committed to make changes to the configura-
tion control program, as follows:
(1) The licensee revised all System Operating Procedure (50P)
alignment checklists for safety related systems during this
outage to include independent verification.
The licensee then
performed the independent verification on these systems prior
to plant start up.
The NRC verified this completion of inde-
pendent verification on a sample of 12 of the 45 systems.
(2) The licensee committed to write a procedure on independent
verification, describing how operators are to perform this
function.
(3) The licensee committed to revise procedure SAP-201, Danger
Tagging, Rev. 3 to require that when a tagout- is cleared,
independent verification on valves inside the tagout boundary
will be accomplished and recorded.
After the licensee had completed system SDP alignments, the team
walked down several systems with A0s.
During these walkdowns, the
team compared actual valve alignments with the SOP valve alignment
checklists and plant drawings. They also questioned operators about
the independent verification process. The NRC noted no deficiencies
with the knowledge n'
operators on how to perform independent
verification. The te m walked down all or portions of the following
systems:
-
.
-
Station and Backup Instrument Air
-
Process and Area Rad'ation Monitoring
-
Boron Thermal Regeneration
'
,
-
HVAC Chilled Water
,
_
_ _ _
_ . _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ - - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _
l*
l
l'
9
i
During the walkdowns, the NRC observed a number of equipment,
procedure, and drawing deficiencies.
The team identified these
deficiencies
to the licensee
for corrective
actions.-
The
deficiencies
are
summarized and discussed in the following
paragraphs.
In the Service Water system, one valve was open while it was required
to be closed by SOP-117, Service Water System, Rev. 13 and system
drawing D-302-222, Service Water, Rev. 24. This valve, XVG-3178-SW,
DG Air Start Aftercooler SW XConn Viv, was in a one-and-one-half-inch
pipe that cross connected the A and B diesel air start compressor
aftercoolers.
The open valve thus cross connected the two much
larger trains of service water.
The valve had become open when,
'
after completing the 50P valve lineup, the licensee performed
STP-123.001, Service Water System Valve Lineup Verification, Rev. 4.
This STP, which has been done monthly in Modes 1-4, has required
this valve to be open since January 3, 1984.
The licensee closed
the valve and changed the Surveillance Test Procedure (STP) to agree
with the SOP and the system drawing.
The team assessed the safety significance of operating . the -plant
with this cross connect valve open.
The valve was in nonsafety
piping, and was downstream of.a flow limiting orifice and check
valve in each of the A and B . train Service Water (SW) supply lines
to the respective' air compressors.
Also, the SW discharge side of
each air compressor aftercooler contained a check valve. With valve
,
XVG-3178-SW open and a . loss of one train of SW, the potential loss
of SW flow to the operating train would be negligible in comparison
to the design surplus in SW system flow. The error in valve position-
could not have caused a single failure (loss of one train or pipe -
break) to result in inoperability of both trains of SW.
Two Heating Ventilation & Air Conditioning (HVAC) chilled water
sample isolation valves, XVT-16364-VU and XVT-16373-VU were open
instead of closed as required by the SOP.
The licensee judged tnat
they were probably left open by Chemistry personnel .
The safety
significance of these valves being open was minimal.
The valves
were closed and the licensee stated that the following procedures
would be revised:
(1) SAP-105, Statement of Responsibilities, Chemistry and Health
Physics, Rev.
4, to include authorization for Chemistry to
operate sample valves.
i
!
(2) SAP-400, Chemistry Operations Manual, Rev.
5,
to include
I
authorization for chemists to operate sample valves.
l
(3) CP-902, Chemistry Sampling Point List, Rev. 5, to require that
3
after a sample is obtained, the sample valves be returned to
<
their normal position, per the SOP.
'
I
m
v:
q
I
l
10
!
{
The NRC team also observed a number of other discrepancies, which
!
are summarized below:
-
One Instrument Air System header isolation valve (XVA-72618)
3
was missing from the SOP and plant drawings.
j
1
Five Instrument Air System valves had incorrect positions
.
--
listed in the 50P.
Four Radiation Monitoring system valves were missing from the
-
~
l
50P.
These valves were in the correct position.
Identification numbers of several valves and flow instruments
-
were missing from system drawings.
A number of valves needed maintenance, including:
handwheels
-
broken or stripped, caps missing or loose, and packing leaks.
None of these deficiencies caused a system to be inoperable.
There were many errors in SOPS that did not affect valve
-
position,
such as " vent" vs. " drain" and " closed" vs.
" closed / capped."
-
There were a number of label plates with nomenclature or number
different from the SOP.
-
Many label plates were missing from valves.
Prior to plant start up, the NRC reviewed the completed SDP system
alignment records, to verify that the ' licensee had _ completed
independent verification on safety systems. The team verified that
the independent verification had been accomplished.
The team
observed that the licensee had made a number of temporary procedure
changes to the S0P valve lineup forms during the time that they were
,
performing the valve lineups.
Many of these temporary changes
J
involved changes in the required positions of valves.
For example,
1
in the completed SOP-101, Reactor Coolant System Valve Lineup, Rev.
l
17, the required position for three valves had temporary changes,
'
from open to closed or from closed to open, that the licensee had
inserted by pen and ink and the SS had approved. Operations started
this valve lineup on Nov. 11, made the temporary changes on Dec. 10,
and completed the lineup on Dec. 15, 1988.
The licensee had issued
and used the S0P with incorrect valve positions in it.
In SOP-112,
Safety Injection System, Rev.12, the required positions for four
valves contained similar pen and ink temporary changes.
The team
compared the previous revisions of these procedures to the revisions
j
in use, and confirmed that the temporary changes had been to correct
'
typographical errors that had been made in typing new procedure
revisions. The licensee had completely retyped the recent revisions
to S0P system lineup forms for all 45 systems important to safety,
due to a switch from one word processing system to .another ' This
retyping had introduced many errors that had not been corrected prior
_ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _
_.
_
,
_ _ _ -______
-
11
to issuing and using the revised procedures. The Auxiliary Operators
(A0s) and SSs were improperly depended upon to find and correct the
errors while using the procedures.
The use of incorrect procedures
could increase the risk of situations that could contribute to
accidents.
The issuance of these procedures without sufficient
review to insure adequacy is identified as an example of violation
295/88-26-03.
Overall, the areas of configuration control and procedure control
i
'
were considered to be weaknesses.
e.
Surveillance Test Procedure Errors
While conducting control room observations, the NRC witnessed the
performance of a part of STP-310.004, NIS Intermediate Range (N36)
Calibration, Rev. 6.
The TS require satisfactory completion of this
calibration procedure.
The team noted that the Instrumentation &
Control (I&C) technician performing this calibration made pen and
ink changes to Data Sheet 4 of the STP, changing acceptance
tolerances as follows:
-
plus or minus 0.010 milliamp dc was changed to 0.100
-
plus or minus 0.050 volts dc was changed to 0.150
The recorded data was acceptable using the new tolerances, but not
with the previous ones.
The NRC team inquired about the basis for making these changes, and
the technician informed them that the changes were made by verbal
authorization of the foreman, to correct typographical errors. The
pen and ink numbers were from the previous revision of the STP. The
inspector was told that the foreman had initiated a temporary change
form for the STP, which would be attached to the completed STP prior
to its approval. The licensee should not have to rely on technicians
to correct procedures while using them.
This increases the risk of
occurrences that could result in or contribute to accidents.
The issuance of this procedure revision with significant errors in
it is another example of violation 395/88-26-03.
f.
LCO Control
During the review of records used for indication and control of
plant status, the team identified a need for improvement in the
Removal and Restoration Log.
Procedure SAP-205, Status Control and
Removal and Restoration, Rev.
6,
describes the R&R Log.
The
licensee uses the R&R Log for tracking safety system status, and
uses three types of entries:
-
Action R&R:
The system is in a Technical Specification (TS)
LCO action statement.
The TS specifies time limits for
restoration of equipment or initiation of additional action.
_
-
_ _ - _ _ _ _
l
12
i
Tracking R&R:
The _ TS allows the LC0 action statament -to be
-
satisfied by compensatory action indefinitely, or LC0 require-
ments can be met by C train equipment.
Non-TS R&R: Used to limit and track the amount of time certain
-
non-TS items are restricted or removed from service.
In reviewing the index in th_e R&R Log on the af ternoon of Nov,15,
1988, the team noted that Action R&R 880788, on the Chemical and
Volume Control (CS) System, had an LC0 expiration time of.1800 on
Nov. 14, 1988 (the previous day). The TS required a portion of the
CS System to be operational at the time, to provide a boration flow
path with the plant in mode 5.
The LCO expiration information was
also on the log sheet for R&R 880788, with the reason given being an
The . inspector showed this log entry- to the SS.
The SS confirmed that,-based solely upon the log entries, the entire
CS system was inoperable 'due to exceeding a TS LCO action statement
the previous day.
He had not been aware of this problem, and
promptly began to look into the matter.
After further investigation with engineering personnel, the Associate
Manager of Operations determined that the inoperable snubber was
located on the CS letdown line' and did not _ affect the required
boration flow path.
There had actually been no violation of TS
i
requirements.
By reviewing shift schedules and watch station shift turnover sheets,
l
the team determined that a total of 12 different operators, on 3
1
different shifts, had signed for reviewing the R&R Log and had stood
l
watch during the time the log indicated that the CS system was
The licensee confirmed that all 12 had failed to detect
the indicated LCO expiration. The team felt that the SS, the STA,
and on watch operators should have been able to explain why the
required boration flow path was not adversely impacted by the
To prevent future operator failure to detect important. safety
information in the R&R Log, the licensee took the following actions:
i
-
Retrained operators in the importance of accurately reviewing
the R&R Log.
Made a commitment to revise procedure SAP-205, to provide a
-
better method of indexing the R&R Log so that Action R&Rs stand
out from all the less important entries. This is identified as
inspector followup item 395/88-26-04.
3
i
'
- _
_ - _ - _ _ _ _ _ _
_
_ _
-
l
l
13
l
g.
Control Room Drawings
Plant drawings are in the Control Room for operators to use in safely
controlling maintenance and abnormal conditions. During control room
observations and interviews, a licensed operator stated that improvement'.
i
l
in the legibility of control room drawings was needed. The team looked
at a sample of about 20 control room drawings, and observed that about
30% of one drawing was totally illegible, and portions of some others
l
were very difficult to read.
The grossly illegible drawing was safety
related drawing 0-302-222, Service Water Cooling, Rev. 24.
This drawing
was date stamped in red:
Copy #9, issued by Document Ccntrol Section,
Aug. 5, 1988.
,
'
Aside from the legibility problem, the NRC team observed that the
drawings were very accessible and easy to use.
)
l
In response to inquiry by the NRC, the licensee stated that the
j
l
Operations Department had identified the problem of illegible
!
drawings.
The Associate Manager of Operations gave the team a
!
copy of a - November 11, 1988 memo from the Operations Manager to
Engineering requesting enhancement or redrawing of 'a list of 10
'
illegible drawings, to ensure adequate quality for use by plant
operators.
The team observed that the problem of illegible drawings also
extended to reduced size drawings in use at the Auxiliary Building
Operator station.
Other than the legibility problem, the drawings
were a very useful aid to the A0s.
The licensee took the following corrective actions:
Conducted an audit of all drawings in the control room.
This
-
audit identified a total of 29 illegible safety-related
drawings.
All of these were reissued, in a legible condition,
prior to the end of this inspection.
The team verified the
legibility of these reissued drawings in the control room.
-
Committed to revise Document Control procedures to provide
better quality control of drawings that are issued.
-
Determined that the cause of most of the legibility problems
was multiple generation and reduction of drawings affected by
plant modifications.
Long term corrective actions will include
reviewing and modifying this process to minimize the degradation
in drawing quality.
I
l
The NRC team's assessment was that Document Control should not
!
issue illegible safety related material without specific management
approval, and the SS should have known of and rejected the illegible
l
,_
_
_ _ _ _ _ _ _ __
..
__
_
__
-
_ -
__
_.
_ _ _ _ _ _ _
14
drawings.
The licensee's issuance of a grossly . illegible Service
Water Cooling drawing and 28 other safety related illegible drawings
to the control room is identified as another example of' violation
395/88-26-03.
h,
Operator Response to Inoperability of Both Source Range NIs
While the NRC team was observing control room activities with the.
plant in mode 5 and the ~ Reactor Coolant System (RCS) partially
drained, a containment. evacuation alarm sounded.
This alarm was
caused by spiking of source range NI channel N31. At the time, the
second source range NI, channel N32, was labelled inoperable and so
recorded in the R&R Log due to previous spiking with undetermined
cause.
Immediately after the alarm, the operators confirmed both.
source ranges to be indicating steadily at about 10 counts per-
second, the same as they had previously indicated.
Also, reactor
vessel' water level indication remained steady.
The operators
energized spare. source range channel N33 and determined that it
was reading steady at ab'out 10 counts per-second.
There was. no
uncontrolled increase in ' reactor power.
The operators terminated
evacuation of the containment and were perusing the TSs as operations
department management personnel arrived in the control' room.
The operators stated that source range NI spiking had occurred many
times before due to welding activities. They initiated a search for
welding in the area or other cause of the N31 spiking. The operators
declared channel N31 inoperable, until it could subsequently be
proven operable, and initiated TS required action (calculation of
shutdown margin). In addition, they ordered an RCS sample for boron
to be taken. Shutdown margin, based on boron concentration, was well
above the minimum TS requirement.
The operators made an R&R log
entry on channel N31, which included contin 'ng TS required actions
and applicable mode restraints.
Subsequent (y,
operators declared
both channels N31 and N32 operable after the following were satis-
factorily performed:
physical walkdowns, . statistical reliability
checks, and source range analog operational tests.
Overall, the
operators' response to this abnormal condition was timely and
thorough.
i.
Key Control
A0s each carry a key ring containing keys for routine access to
administratively controlled areas. For emergency access to sensitive
!
'
radiological or security areas, secure key lockers are located in the
control room and out in the plant.
t
The security door system is supplied .with vital uninterruptible
electrical power.
Should the computerized system fail, security
doors would fail shut.
They could be manually opened to4 exit an
area. However, to enter vital security areas under these conditions,
)
.
use of a security door key would be required.
Through use of the
q
- - _ - - - - - -
_ _ _ , - _ _
_ _ _ .
. _ - _ _
_
- __ _
_. . _ _ _
15
secure key lockers, A0s him the ability to gain emergency access to
operationally important arris of the plant. Overall, the key control
system was well organized to provide plant access to operators, and
operaturs were knowledge >Ns of the system.
J.
Fire Protection System Vaives
While accompanying an Auxiliary Building Operator on rounds, the
NRC observed caution tags on closed fire protection system manual
isolation valves for deluge valves. The instructions on each tag
were to open only in the event of fire and at the direction of the
SS. The deluge valves were designed to be remotely. operated from the
,
control room.
The closing of these manual isolation valves thus
removed the control room operator's ability to initiate fire
protection water flow to the affected areas from the control room.
As listed in the Caution Tag Log, a total of 10 deluge sprinkler
i
systems were manually isolated.
The manual valves had been closed
for 15 to 24 months. A list of the valves, and the dates they were
closed, is in Attachment 2.
Six of the valves supply water to
ventilation charcoal filter units in the Control and Fuel Buildings.
These six are shown as normally open -in the Final Safety Analysis
Report (FSAR) and are in systems covered by TS.
.The other four
valves supply water to the charcoal filter units in the Auxiliary
~
and Reactor Buildings.
These four are also shown as normally open
in the FSAR and are in systems not covered by TS. The licensee had
closed the 10 fire. protection system deluge isolation valves to
prevent damage to the charcoal filters in the event of an unplanned
actuation of the deluge valves,
i
The team reviewed the affected control room annunciator response
i
procedure, and noted that procedure ARP-016-XCP-6210, Annunciator
Response Procedure (ARP) for the HVAC Board, Rev 0, did not indicate
the additional immediate action required in the event of a "Hi/Hi-Hi
Bed Temperature" alarm in the charcoal filter units. The procedure
requires activation from the control room of the deluge spray system
in each filter unit in the event of an actual Hi-Hi temperature. The
need to open the nanual isolation valve is not mentioned in the pro-
cedure.
Also, the procedure provided no such instructions for the
operator at the deluge valve control switches in the Control Room.
Further, the licensee had no record of having conducted formal
operator training on this subject.
The incomplete ARP could have
contributed to an inadequate operator response to an emergency
situation.
_ _ _ _ - - - _
_ _ _ _
v
1
1
16
I
The NRC team reviewed the licensee's safety evaluation for closure
of these valves. That safety evaluation covered only the T$ systems
and was dated July 15, 1987. The safety evaluation addressed only TS
operability concerns, and was incomplete in that it failed to specify
that closure of the valves-(in 1986 and 1987) would require changes
,
to- the control room alarm response procedures, plant drawings, and
i
the FSAR, and would require an associated 10CFR50.59 report to the
NRC. The failure to report this change to the NRC precluded an NRC
safety review of the change. The licensee had a second 10CFR50.59
safety evaluation on this change.
It was-dated November 18, 1988,
and properly required a revision to the FSAR. This latter evaluation
was dated almost two years after the first valve was closed and still
failed to require' changes to the control room alarm response proce-
dures and plant drawings.
The failure to perform adequate safety evaluations for the closure
of these fire protection system valves is identified as violation
395/88-26-02.
In reviewing this deficiency, the Control Room operators could not -
locate their assigned control copy of the Fire Protection Evaluation
Report (FPER).
The FPER is part of- the FSAR, and is .important
reference information for the operators, in that it describes the
approved design of plant systems.
The licensee determined that the
control room controlled copy had been lost for many months. The
clerk in an adjacent office was accumulating changes to be put in
that copy. The licensee pointed out that the fire protection office
located in the control room complex also has .a controlled copy of'
the FPER.
However, that copy was not in the fire protection office
on the date of this inspection, so was not readily available for use
by the control room. The licensee stated that a replacement copy of
i
the FPER would be issued to the control room.
k.
Deficiency Identification and Correction
]
During this inspection, the NRC team observed many minor equipment
deficiencies that had not been entered into the Maintenance Work
Request (MWR) system.
These included such items as broken valve
handwheels, leaking valves, and missing name tags.
Many system
]
leaks existed in the plant which had not been repaired during the
'
outage.
The team observed that many equipment deficiencies in the
plant did not have MWR tags attached and many did. The MWR procedure
implied that hanging a tag when initiating an MWR was optional. The
lack of MWR tags on equipment that has already had an MWR initiated
could be a deterrent to efficient operator initiation of needed MWRs.
i
The licensee stated that the MWR procedure would be revised to ,,
j
require that MWR tags be hung, with limited exceptions,
-
m _ _ ____ _ _ _ _ _ _ . _ _ _ _
_
-,
,
!
17
The team also observed many deficiencies in written procedures and
drawings. Most of the procedures with deficiencies had been in use
!
for years.
The accumulation of large numbers of deficiencies that
i
go uncorrected for months or years could have a resultant negative
I
safety impact on the operation of the facility. The' licensee needs
to improve the overall effectiveness of deficiency identification
q
and correction.
1
3.
Maintenance (62700, 62702, 92700, 92703,-71710)
a.
Licensee's Event Reports and Potential Reportable Events
The NRC Team observed the functioning of the licensee's program
for the evaluation of abnormal maintenance events to assess it's
efficiency in increasing equipment availability through correct
identification of root cause and by initiating the appropriate
corrective action.
The program was being applied to a number of
events (listed in Attachment 3) which were the scope of the team's
evaluation.
These events occurred between July 1987 and November
1988.
The licensee documents the evaluation of abnormal events in
off-normal occurrence (ONO) reports.
In addition, LERs report, to-
the NRC, events which meet the deportability criteria of 10 CFR 50.73.
Except for ONO Reports 870093 and 880004, the licensee had
determined the root cause of each event and had accomplished the-
1
appropriate corrective actions.
In the case of these latter two
ON0s, the licensee had taken the required corrective actions but had
not documented their completion.
The licensee promptly obtained
this information and made the necessary documentation changes.
b. Maintenance Scheduling and Planning
l
'
l
The MWR scheduling and planning ' process, when appropriately and
i
effectively applied, maximizes equipment availability by minimizing
'
its out-of-service time and optimizes plant safety by giving prefer-
,
ential treatment to those components most important to safety.
~l
The inspector observed the MWR scheduling and' planning process by
i
walking an active MWR through each step of the review process. An
j
operations scheduler, maintenance planner, maintenance engineer,
j
health physics scheduler, and quality control inspector reviews each
l
MWR, except emergency maintenance. A maintenance scheduler, during
this particular scenario, hand carried the MWR to each person noted
above. That permitted the inspector to briefly interview each person
!
in the review chain.
The assignment of a " Status Code", which
permits ready location of the document in the review cycle, normally
tracks each MWR through the review process. The licensee also enters
the MWR data into . Computerized History And Maintenance Planning
System (CHAMPS).
!
l
l
.
18
The team observed two strengths'in the maintenance. scheduling area.
Fi rst , three SR0s and one A0 staffed the Operations' Scheduling
.
Section.
Personnel fill these assignments on a temporary one year
i
rotating basis.
The. expertise of licensed personnel was a strong
1
d
point of the scheduling process.
Second, each day the Scheduling Section prepared a " Trip Package"
which contained planned maintenance activities requiring a duration
of less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to perform.
The Scheduling Section delivered
the " Trip Package" to the Shift supervisor at the end of each normal
werk day and picked it up the following morning. The " Trip Package"-
included only items that could be accomplished in Mode 3. - Addition-
ally, the scheduling section planned a "Short Duration Outage
Package" for those activities which could be completed in the event
,
plant trip recovery took longer than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> but less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
]
'{
The team noted one weakness in the scheduling area. Although each
1
'
maintenance planner had plant work experience ranging from apptentice
to foreman in his respective work speciality, there was no formal
qualification or training program for maintenance planners.
Some
planners had attended systems training and supervisory training but
i
this training was not routinely offered to all planners.
c.
Work Orders in Process
The maintenance planning and scheduling process above had priori-
tized, planned, and scheduled for implementation during the NRC
]
team's on-site assessment period those MWRs listed in Attachment 4.
4
Each MWR contained adequate procedures and instructions to ensure
that the maintenance craft personnel could accomplish the specified
1
work.
These procedures and instructions contained appropriate
~
Quality Control (QC) hold points.
The MWRs provided good interface
between the maintenance and operations staffs.
They also contained
appropriate radiation controls, spqcial housekeeping, scaffolding
controls, and burning and transient permits, except for MWR 8801131
which is discussed in the next paragraph.
During a plant tour the NRC inspection. team identified a total of 45
drums of charcoal, 200 pounds each, stored on the 463' level of the
auxiliary building.
Maintenance personnel performing the work
directed by MWR 8801131 had temporarily stored this charcoal in this
,
area preparatory to replacing the auxiliary building ventilation
1
system (XAA0040A) charcoal.
This charcoal storage resulted in an
increased fire load for which appropriate compensatory fire protec-
tion considerations had not been established.
Procedure SAP-601,
Application, Scheduling and Handling of Maintenance Activities
(Rev. 4) Section 7.2.15 requires transient combustible requirements
i
to be determined by the discipline planner.
Procedure FPP-003,
Control of Transient Combustibles, Sect-ion 3.1, 4.3 and 5.1, requires
i
h___
_ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . - . - - - . . _
v-
)
19
4
maintenance planners and job supervisors to generate a transient
1
combustible permit and specify the applicable fire protection
i
requirements for jobs which result in an increased fire. loading
within the plant. The NRC has identified this failure to perform an
appropriate transient combustible evaluation for MWR 8801131 as
another example of violation 395/88-26-01.
d.
Completed Maintenance Work Requests
The NRC team evaluated the recently completed maintenance work
requests listed in Attachment 4 for maintenance work in the mechan-
ical, electrical and I&C areas. The team concluded that completion
of 'these work requests contributed to better equipment availability.
'
This conclusion was based upon the team's consideration of several
l
licensee actions on ' each MWR:
adequate review and processing; post
l
maintenance testing; special housekeeping (as specified); independent
l
verification of lifted lead restoration and similar items; QC
l
inspector review of QC hold points; and technical evaluations of
.
i
inoperative systems or systems in need of repair to determine root
p
cause.
e.
Maintenance Overtime
The NRC has concluded that an individual's' detection of visual
signals deteriorates markedly with fatigue. Additionally the time
it takes for a person to make a decision increases and'more errors
are made.
For these reasons, the licensee should have a sound
policy covering working hours for the plant staff, such as' key
l
maintenance personnel, who perform safety related functions.
(IE
!
Circular 80-02)
The team reviewed the licensee's policy for control of outage
overtime.
The review included inspection of time and attendance
sheets for hourly paid maintenance personnel, interviews with
]
personnel from each maintenance discipline, and review of TS and
1
procedural guidelines concerning overtime.
The responsible department manager granted authorization to deviate
j
from established overtime guidelines prior to the outage and docu-
)
i
mented it on a properly executed " Authorization to Deviate From
I
Overtime Guidelines".
This authorization was for the entire depart-
'
ment for a 31/2 month time period encompassing the outage and post
outage start up.
Work hours during the current refueling outage
generally consisted of 6 consecutive 12-hour days followed by 1 day
off.
i
3
._-_---._.-_-_-_i_--_______-__-_--__-__-_-_
. _ _ - _ .
. _ _ _ _ _ _ _
_
_ _ -
_ _ _ _ - _ _ _ - _
20
Interviews with maintenance technicians, particularly in the I&C and
electrical groups, indicated - that personnel were discouraged from-
working more than 6 consecutive 12-hour. days without a day off.
However, in the mechanical maintenance area, the ' team noted several
instances of personnel working 12-hour days continuously, for 3 to 6
weeks, without a day off. While the team recognized that TS and
procedures may permit such extended work hours during a' refueling
. outage, they regarded this to be excessive use of overtime and
therefore not a good personnel managemant practice.
If not care-
fully monitored, blanket overtime authorization can lead to increased
error rate among key maintenance personnel while performing safety
related functions.
f.
Backlog Status of Maintenance Work Requests
It is'self evident that returning equipment to service in the order
of importance leads to optimization of availability of safety related
equipment.
Management controls on MWR backlog such as backlog
trending are necessary in order to ensure that the backlog of
important equipment requiring repair does not exceed the capability
of the maintenance group while working' within a sound overtime
policy. To measure these present and future equipment availability
indicators, the NRC' team reviewed the MWR backlog trend and manage-
ment controls on the MWR backlog.
They also covered the method of
work prioritization to ensure that equipment was returned to service
in order of importance.
Work priority was based on the importance that the work activity had
i
to the centrol of the plant. While "importance to control of the
plant" is not synonymous with "importance to safety", the team felt
they are so close that the difference will have a negligible effect
on safety.
The Summer staff assigns to all maintenance one of the
I
following priorities: emergency maintenance, priority 1,1S, 2, 25,
3, 4, or 5.
The SS determines those MWRs that require emergency
maintenance.
The SS also has the sole responsibility of assigning
Priority 1.
The Security Maintenance Supervisor may . assign priority
IS.
Af ter Maintenance has addressed all priority 1 work 'they can
then work Priority 2 and 2S MWRs.
The Operations Schedulers assign
the remaining classifications of priority. The licensee managed well
!
the prioritization of maintenance activities.
Scheduling generated a monthly report which listed all MWRs greater
than 3 months old. The Manager, Maintenance Services, then reviewed
the report and presented his findings to plant management.
For the
seven months preceding the current refueling outage, the percentage
of total corrective MWRs greater than 3 months old (MWRs greaters
than 3 months old/ total open MWRs) was approximately 47 percent which
is below the industry average of 52 percent.
The team considered
timely review of MWR oacklog and the relatively small number of MWRs
older than 3 months to be a strength.
'
l
__
-
.
21
g.
Calibration of Instrumentation
A good instrument calibration program ensures that those instruments
required by TS or associated with routine operator duties are
maintained within the required operating bands of the instrument.
The NRC Team reviewed the implementation of the calibration program
for permanently installed
instrumentation.
Procedure SAF-141,
Control and Calibration of Measuring and Test Equipment, Rev. 2,
establishes the calibration ' requirements.
The team verified that a
sample of-12 installed instruments used by the plant operators during
routine shift rounds to record plant data and 8 installed instruments
used by the plant staff to record data during surveillance testing
were included in the instrument calibration program and that they
had not exceeded their calibration due date. These instruments are
listed in Attachment 5.
The licensee's program for maintaining the
calibration of permanently installed instrumentation devices appeared
to be effective.
h.
Status of Maintenance Work Requests Older Than 6 Months
At the time of this inspection approximately 525 MWRs had been written
and approved for work.
Of this total approximately 110 work requests
were more than 6 months old.
The NRC Team reviewed these MWRs and-
.
found that the work had not been accomplished due to: maintenance work
assigned a low priority; repair parts had been ordered but had not been
received; or, the work had been scheduled to be accomplished at the
next available system / component shutdown.
This review indicated that
maintenance work which must be performed to preclude a possible major
load reduction, unit shutdown or meet an NRC requirement received a
'
high priority and appears to be accomplished.in a timely manner.
Based
upon this information, the .tean concluded that equipment availability
was enhanced by the timely review and small number of those MWRs greater
than 6 months old.
4
1
1.
Plant Observations
Plant housekeeping is indicative of plant management attention to
plant cleanliness, maintenance of equipment and structures, and
I
controlling the spread of contaminated material. There is a definite
i
relationship between plant material condition and proper' housekeeping'
l
practices.
'
1.
General Plant Housekeeping
The team conducted a housekeeping tour of the auxiliary, fuel
handling, and diesel generator buildings. Even though the unit
was in a refueling outage, the licensee was maintaining good
housekeeping practices. The licensee promptly corrected several
minor discrepancies which the team had pointed out.
The.
following two paragraphs discuss two of the more significant -
observations.
_ _ - _ _ _ _ _ _
_
._.
22'
The licensee needs to improve the labeling of components and
component room doors.
Room doors were identified only with an
alpha-numeric identification and did not- have a word description-
of the contents of the. room. Similarly, major componentsLlacked
prominent labeling with a word description of . the component.
The licensee is considering a label enhancement program that
would improve component tags and component room door'identifica-
tion.
This label enhancement program would result. in more
easily identified plant equipment which would be especially
beneficial ' during' emergency situations when time is of the
essence.
The team noted, during a walkdown of Diesel Generator Room "A",
that the local control panel ARP was missing from the panel.
The licensee stated that they had removed ARP-004-XCX-5201,
l
Annunciator Response Procedure .for "A" Diesel. Generator, Rev. 2 '
as required in SAP-139, Procedure Development,. Review, Approval'
and Control, Rev. 11, because it exceeded its 2 year review -
date on November 4, 1988.
SAP-139 requires that "No safety-
l
related/ quality related proceedure shall.be used beyond its-
'
two year review date".. However, SAP-139 also states that a
l
monthly print out shall be issued identifying procedures that-
l-
are due for a 2 year review in the next 3 months. Therefore,
i
the licensee should have'been cognizant of the expiration date
at least 3 months prior to reaching that date.
The licensee
placed the ARP on hold and removed.it from the panel on November.3,
1988, then subsequently reviewed and reissued-.it on' November 18,
1988.
No ARP was available for operator _use'in Diesel Generator
3
Room "A" during the 15-day interval .between removal and reissuance
'
of the ARP.
During that' time, the diesel.was in.an operable-
status. Absence of the ARP could have resulted in an untimely
or inappropriate response to a diesel alarm with'resulting damage
to safety-related equipment.
The failure.t'o follow procedure
concerning the required review of a safety-related procedure within
!
the 2 year time restraint and resultant failure to provide an.
]
approved procedure for operable safety related equipment during
1
l
a 15-day interval is identified as another. example of violation
,
395/88-26-01.
'
Overall plant housekeeping was very good.
l
2.
Scaffolding Controls
I
Procedure GMP-100.009, Scaffolding,-provides for the control of
erecting scaffolding within the plant.
It provides sufficient
controls to prevent damage to safety related components - from
>
scaffolding related accidents such as scaffolding collapse or
dropped equipment, and to provide for personnel safety.
The
L
procedure requires approval by the SS prior to scaffolding
'
being erected over or in~ the vicinity of safety-related equip -
ment.
However, at the beginning of the inspection, the . NRC
l
Inspection Team noted that scaffolding erected to work on
1
-
_ ___ _____-______--___- - - _ _--___ __ .________-- _-___ __
,
.__ ._ . _ _ _ _ _ - _ _ _ _ _ _
__
23
equipment and components installed above floor level did not
contain toeboards as required by the procedure.
The licensee
promptly initiated appropriate corrective action.
By the
conclusion of this inspection licensee personnel were providing
toeboards for all scaffolding, where required.
\\
3.
Radiation Controls
Each of the MWRs reviewed by the Team indicated the assigned
radiation work permit, if the work was to be accomplished within
the radiation controlled areas of the plant. The NRC Team did
not identify any noncompliance with the radiation protection
procedures during observation of personnel performing work in
radiation areas.
j.
Preventive and Predictive Maintenance Programs
The CHAMPS tracked all routinely performed preventive maintenance
tasks.
Three months prior to a Preventive Maintenance Task Sheet
(PMTS) due date, CHAMPS generated a PMTS which was routed through a
maintenance scheduler who forwarded it to the appropriate maintenance
discipline for review.
When feasible,
maintenance personnel
performed PMTS in conjunction with other scheduled maintenance
activities. When repetitive equipment failures occurred, the program
allowed increasing the frequency of the associated PMTS.
The
licensee performed PMTSs or lubrication tasks, unless specifically
identified to the contrary, within their scheduled due date +25% of
the PMTS interval.
For mandatory PMTS activities, i.e. , those required by regulatory or
engineering commitment, that could not be performed within their
required periodicity, Systems Engineering performed an evaluation of
the effect of the delay on the equipment.
Review of SAP-143 and
interviews with personnel indicated that the definition of " mandatory
activities"
was not clearly defined in SAP-143 nor adequately
understood by the Systems Engineers who have the responsibility of
determining whether a specific
PMTS i s mandatory.
The team was
informed by the Coordinator of Maintenance that the definition of
" mandatory activities" would be inserted into SAP-143.
l
In May 1988, Summer Nuclear Station Quality Assurance (QA) issued
I
finding #09-RMB-88-0-02 concerning an overdue PMTS on Service Water
Booster Pump
"A".
A recommendation of that finding was that
appropriate personnel perform a review of the PMTS program and
identify all overdue PMTSs.
On June 27, 1938, the Manager,
Scheduling and Modifications, in response to that finding, stated
that a large number of PMTSs were lost and/or overdue and that the
_
_
_
____. .__
.
. - . . _ _ _ _ _ _
_
__
_. _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _
_
24
initial corrective action would be to distribute to the responsible
supervisors monthly reports showing overdue or near overdue PMTSs.
QA stated in subsequent reviews that although the manager of
scheduling and modifications was generating monthly overdue reports,
that action was generating no progress in the reduction of the total
number of overdue PMTSs (Inter-Of fice Correspondence, CGSS-494-QA,
dated August 22, 1988).
Also, QA would continue the review of the
effectiveness of the program until it had established an ac eptable
trend.
Additionally, QA stated that the Manager, Scheduling and
Modifications failed to identify any safety-related PMTSs in the
monthly overdue report.
QA stated in Inter-Of fice Correspondence
CGSS-591-QA, dated September 20, 1988, that limited data received to
that date indicated a possible adverse trend in the area of overdue
PMTSs.
QA had scheduled for April 7,1989 a verification of the
implementation of the corrective action measures to reduce the
number of PMTSs.
The Manager Scheduling and Modifications did not issue overdue PMTS
monthly reports during the current refueling outage.
Due to the
lack of overdue PMTS data, the team could not determine the trend of
overdue PMTSs.
This item will be reviewed in a future NRC
inspection and is identified as IFI 395/88-26-05.
The team discussed with maintenance management the predictive
maintenance proomm.
They specifically discussed the chemistry
ferrography laooratory and the electrical maintenance vibration
trending programs. The team also toured the ferrography lab with a
chemistry supervisor.
The ferrography lab had been in existence for approximately 2 years,
l
while the vibration trending program was begun about 6 years ago.
'
Each program had regularly scheduled sampling and data collection
i
intervals for each major piece of equipment.
The lab was to trend
'
data using a computer program.
They closely monitored any unusual
trends and initiated corrective maintenance prior to predicted
equipment failure.
The ferrography and vibration trending programs
are functioning well and the licensee is considering expanding their
predictive maintenance efforts.
The team concluded that such
preventive and predictive maintenance programs have the capability
of identifying equipment problems prior to actual equipment failure.
Early identification of equipment deficiencies permits timely
maintenance response and the possible prevention of loss of safety-
related components.
t
.
_ . .
m
-
_
-- _
_ - - . - - - , - - - _ _ _ - - - - _ - - - -
!
25
i
4.
Engineering (37700,37828,42700,37702)
The safe operation of a nuclear power plant.is predicated on an adequate
design
This design incorporates various codes and standards governing
the construction and operations of the facility to ensure the. safe
.
operation. The design engineering function at the plant is carried on to
ensure this. design basis is maintained ' throughout- the -lifetime of the
facility and is not ~ abrogated by changes to- the structures, systems and
components or the manner in which they are operated.
.
The team reviewed the procedures used by the Design Engineering Department
to ensure that .the functions of the department would, if accurately
carried out, maintain the design basis. -The team also reviewed the
Modification Request Form (MRF) packages being installed during the
current outage and those previously installed as ~ noted in Attachment 4.
The team conducted this review to ensure that the packages contained
adequate procedures and instructions for installation, protective tagging,
housekeeping, QA/QC controls, and material procurement control. The team
walked through the MRF process noting especially .the initiation of the
,
MRFs by operations, the screening . process by which MRFs are prioritized
l
and scheduled.
The team reviewed completed MRF packages to verify
they contained the results of post maintenance testing; QA/QC review,
engineering technical review,and close-out procedures.
The team interviewed engineers, mechanics, and' electricians to ascertain
the procedural adequacy lof .the MRF packages received for installation,
the operations / maintenance interface on MRF installation, and ' problems /
concerns that should be addressed.
The team held discussions with members of the engineering services
department and the scheduling personnel to verify that MRFs are screened
for priority
and scheduling is done on the bases of importance to
s a fe ty .
I
The Engineering Services Department has started a program to establish a
l
design bases document (DBD) for plant systems. This document contains an
introductory section that describes the purpose and organization and
scope of the document.
It also contains a system description, a system
design basis, a component design basis, an accident analysis, a margin
summary, and a listing of reference documents.
DBDs have been prepared
for 14 plant systems and several more are in the process of being
,
prepared.
The team considered the preparation of these DBDs to be a
l
strength of the facility.
These DBDs will be a living document which
l
will enable the plant staff to maintain. a safe margin in plant operations
l
as well as document the design bases of the system and components.
l
No violations or deviations were identified.
l
I
1
l
E ----------------- ---
- - - - - - - - -
- - - - - - - -
-
b
_-_ _ ____--
26
5.
Independent Safety Engineering Group (ISEG)
'The ISEG functions to provide an independent review of plant operations,
operating experience feedback and operating characteristics of the plant
with a responsibility to ensure the plant activities are conducted.
correctly and that human errors'are reduced as much as practical.
The team reviewed the ISEG reports for safety system functional inspec-
tions (SSFI) the licensee had performed on the ac & dc distribution system
and the. service water system.
The ISEG has utilized contractors to
supplement their own expertise in performing these inspections.
The
inspection results reviewed by the team _ appeared to be of sufficient
depth and scope to provide the licensee with a valuable tool for evalu-
ating system performance.
The ISEG current goal is to perform two of
-
these SSFI inspections each year. The team considered the performance
of these inspections to be a strength.
No violations or deviations were identified.
6.
Quality Assurance
The Quality Assurance (QA) function is important to operations in that it
verifies that those activities affecting the quality of safety-related
components, systems, and structures are carried out' in accordance with
approved procedures and that the quality of those items affected is
maintained.
The QA Department accomplishes this function by. conducting
audits and surveillance
of safety-related functions accomplished by the
other departments of the plant organization.
The team reviewed the requirements of TS 6.5.2.8 on the scope and
frequency of audits in conjunction with the audit planning matrix and
schedule.
The team confirmed that the planning matrix and schedule
addressed all TS requirements.
The personnel of the QA department also
perform a number of surveillance type activities which encompass various
aspects of plant operation.
In discussions held with the team, the QA manager outlined the facility's
plans to correct what the manager perceived to be a a lack of commercial
nuclear power plant operational experience in the QA department.
Pending
completion of the present outage, a licensed operator will be transferred
into the QA department.
The QA manager also noted that individuals
with strong engineering, I&C, and maintenance backgrounds are also being
requested.
The acquisition of these individuals will greatly assist in
the completion of performance based audits with operationally constructive
findings. As a result of efforts thus far, personnel of other departments
perceive the QA department as becoming more creditable and constructive.1
'
,
_ _ _ _ _ _ _ _ _ _
,
_
_
_ _ . - . - _
_
. _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ - _ _ -
27
QA conducted an audit, Audit Report II-12-88-E, Control Room and Station
Operations, between July 6 and July 21, 1988, not only to meet the commit-
ments of TS and the operational quality assurance plan, but also to
assess performance in the area of operations. The. results of the audit
documented a large' number of compliance items with summations on 'the
thoroughness of processes and personnel activities. The team considers
incorporation of performance based audits into the realm of QA activities
as being extremely beneficial to the . facility's safe operation. As noted
by the QA manager, Audit Report II-12-88-E was the facility's first
performance oriented audit. The lessons learned from identified findings
and audit methodology, coupled with the incorporation of engineering,
maintenance and operational experience,
will serve to develop the QA
department into a significant tool in the safe operation of the facility.
,
No violations or deviationswere identified.
7.
Plant Status Meetings
Communications or the exchange of information among members of the plant
staff is important to safety.
Changes in plant status affect every
department of the staff and accurate information is vital to -the proper
i
functioning of the departments and thereby, to the safe operation of
the plant.
It is therefore important that communications be effective, .
efficient, and accurate.
Important information must be thoroughly
disseminated through the plant organization in a timely manner.
The team attended various plant status meetings to determine whether the
licensee adequately disseminated day-to-day plant activities and planned'
future activities to the applicable staff. Status meetings are conducted
by the General Manager of Operations and Maintenance.
Discussions of
particular ongoing' activities are provided by. the various department
I
managers. They also identify support that is needed from other depart-
ments. Overall, while members of the plant management staff are cognizant
of plant status, ongoing activities, and general problem areas, a sense
'
of heightened importance was lacking during the course of these meetings,
i
especially when viewed in light of the ongoing outage.
In particular,
)
discussions pertaining to the outage's critical path were absent from the
status meetings.
I
No' violations or deviations were identified.
8.
Plant Safety Review Committee (PSRC)
The PSRC is responsible to advise the Plant Manager on all matters
related to nuclear safety.
This group is the last collective body where
various interfaces are brought together below the Plant Manager level to
i
ensure that all disciplines are considered in the operation of the
facility and changes to that operation.
i
_ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ . _ _ _
__
_
._.
_
__
_
.___-____ __ _ _ _ _ __ - _-_ _
28
The team examined the activities of the PSRC to assess whether it was
functioning in a manner that optimizes safe plant operation by providing
adequate interface with various plant disciplines, and by performing
adequate safety reviews. This assessment encompassed an interview with
l
the PSRC chairman, a review of TS Section 6.5.1, a review of the governing
station administrative procedure sap-120, Plant Safety Review Committee,
.Rev. 4, observation of PSRC meetings and review of selected minutes of
PSRC meetings. The PSRC met regularly on Wednesdays and as required to
l
address urgent matters.
Prior to PSRC meetings, members were provided
I
with the meeting's agenda.
The agenda elaborated extensively on the
l-
subjects to be discussed thereby allowing the members to be better
prepared and to allow for a smooth flow of the meeting's business. The
team attended meetings during which the following areas were addressed:
TS changes; bypass authorization requests; and safety reviews associated
with modification requests and change notices, nonconformance notices,
and procedure changes and revisions.
Where appropriate, the PSRC was
assisted in its review of items by a representative of the department
responsible for the item. That facilitated communications and provided
real-time answers to questions raised.
No violations or deviations were identified.
9.
I&E Notices
l
Evaluation of information from outside sources is a valuable input to the
I
safe operation of a facility. Various sources provide information to the
plant staff for evaluation and incorporation if applicable. This informa-
tion is useful in avoiding mistakes made by others, as well as providing
for increased equipment availability.
The team selected four IENs from the past 18 months to determine the
adequacy of the licensee's review and their response.
Additionally,
IEN 88-86, Operating with Multiple Grounds in Direct Current Distribution
Systens, was examined because of recent industry problems and indications
in the control room of the presence of de grounds.
The licensee had, in all cases, reviewed the subject IENs in a timely
manner or were taking action on them. The Technical Oversight department '
coordinates the processing of IENs with input from various plant depart-
ments including the Engineering Services Group for technical evaluations
,
and the Nuclear Operations Education and Training department for training
j
requirements.
The evaluations reviewed, by the team, considered the
1
appropriate aspects of plant design, the FSAR, maintenance practices, and
i
plant operations. The thoroughness with which the IENs are evaluated, by
1
the plant staff, ensures that the licensee avoids similar problems experi-
i
I
enced by other facilities.
~.
No violations or deviations were identified.
l
l
>
L__________-___-_______-_______--______.-__
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
__
- - _
- - . . .
_
. _ _ _
_ - -__
_ - _ _ _ _ _ -
_ _ _ _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ - _ _ _ _
_
1
29
l
10.
Performance Monitoring Programs
The trending of.various performance parameters is important in order to
determine the availability of equipment in the plant and operations
expertise in operating the plant effectively. It also can be utilized to
predict, in a general way, future equipment operability status and .to
avoid unnecessary challenges to safety equipment.
The Operations Technical Assistants were compiling various monthly and
quarterly trending reports for Operations management'.
The documented
trends included Emergency Core Cooling System (ECCS) availability,
overall plant performance, fuel and gas consumptions, and administrative
errors. The trending reports were distributed to various members of the
l
'
plant management. The plant management was cognizant of the existence of
,
the various trend reports and believed that the reports were providing
I
information which assisted in safe plant operations.
No violations or deviations were' identified.
11.
Emergency Operating Procedures (25592)
a.
Background Information
V.C. Summer responded to Generic . Letter 82-33, " Supplement 1 to
NUREG-0737-Requirements for Emergency Response Capability," on
July 30, 1984 in a letter to the NRC submitting their Emergency
Operating Procedure (EOP) Generation Package. The E0Ps are based on
Westinghouse Owners Group Emergency Response Guidelines (ERGS),
Revision 1.
The licensee conducted a comparison of VC Summer to the
generic plant and submitted it to the NRC in the Procedure Generation
Package (PGP). Additionally,'the submittal included an E0P deviation
document, which outlined the specific. areas where SCE&G's E0Ps differ
from the ERGS, revision 1, and an Administrative Procedure (SAP-207)
which detailed the development of the E0Ps. 'The E0P Writers Guide
and validation program were designed using guidelines published by
,
the Institute of Nuclear Power Operations (INPO).
!
In June 1987, the NRC forwarded a Draft Safety Evaluation Report
(SER) to V.C. Summer, informing them that their PGP was not _ accept-
able as submitted.
Deficiencies of note included inadequate
documentation of deviations from and additions to the generic
guidelines, Writer's Guide deficiencies, inadequate guidance and
scope in the verification and validation process and lack of depth
and content in the operator training program.
,
I
i
V.C.
Summer had not obtained an approved PGP.
They had initiated
I
actions to resolve the discrepancies noted in the Draft SER.
Fore-
i
most'among these efforts were a new draft E0P Writer's Guide for use
j
in procedure generation, a revised SAP-207 which specified the
1
programmatic guidance and administrative requirements for the
]
development and maintenance 'of E0Ps, generation of a draft E0P
1
Setpoints Document to provide technical justification for process
j
I
i
_____
_ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ . _ _ _ .
._.
_
_
_ . _ _
v
.
30
'
-
.-
.
-variables and trigger .setpoints used in_ the E0Ps and the generation
'
of a draft E0P Plant Differences Document to identify and provide
justification for deviations and additions to the generic Westing-
house guidelines.
It 'was.. the licensee's intent ~ that. once these
~
documents are in place', an independent ;outside organization will
conduct an audit' to ensure that the intent of .the Westinghouse. ERGS
and NUREG-0899 are met.
Then a : major rewrite of all E0Ps will:
be initiated in 1989, with .all procedures in place and ' training
completed by the 4th' quarter of 1989.
b.
Review of the E0Ps by In-Plant and Control' Room Walkdowns
The team conducted in plant andi control' room ' walkdowns of the
emergency procedures listed in Attachment .6.
They . evaluated the
.
effectiveness of the E0Ps;by focusing on the current status of ..the
procedures and whether they can successfully mitigate' accidents given
the procedures as they.now exist. The team verified, that indicators,
annunciators, and controls.were accurately referenced in the EOPs,
that the steps in the E0Ps could physically be performed, considering
human factors conditions, and'that the' operators were confident in
the procedures' ability'to mitigate the consequences of an. accident.
The team has identified discrepancies in-labelling and human factors
concerns in Attachment 7.
The comments in Attachment 7 are identi-
fied as : .pector followup item 395/88-26-06.
Emergency Operating Procedures were found to be adequate to place the
plant in a safe, stable condition'.
While the procedures do ~ not
conform to the format required by the draft Writer's Guide, .the team
concluded that the procedures could ' physically.-be- performed as
q
written, with the exceptions noted .-in Attachment -7.... Generally, the
'
l
team found that setpoints are. not supported. by..a Setpoint Document.
l
The licensee has created a draft Setpoint Document 'that includes
allowances for potential cable degradation losses (I.R. ' Loss). Two
'~
licensed operators demonstrated the E0Ps during the walkdowns.
They were proficient in their use of the procedures and confident
that the procedures would mitigate the consequences of an accident.
c.
Simulator Exercise Observation-
1
The. team observed NRC-directed simulator exercises involving E0P
usage for an operating crew. The crew was briefed ahead of time on
the emergency procedures that would be utilized.
The team concen-
trated on the usability of the E0Ps, the operators' familiarity with
the E0Ps, the extent of physical interference and duplication of .
effort among the operators while performing the~ E0Ps, and the
efficiency and thoroughness of procedural transitions.
The . team,
utilized their observations - of the operators' ability to use :the
E0Ps, as well as postscenario discussions, - to determine whether-
l
procedural or training deficiencies existed.
Deficiencies or
j
observations not noted in the following paragraphs will be found in
Attachment 7.
'~
j
,
,
i
1
i
_ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _
_
_ . _ _ ~
l
..
m
31
The first simulator event consisted of a loss of'all alternating
current (AC) power, with subsequent recovery of one diesel generator,
complicated by a small break loss of coolant accident (SBLOCA).,
The simulator modeling of_ the characteristics and response of the
Seal Injection Flow Control Valve, HCV-186, were inadequate.
Its
throttling characteristics were incorrectly modeled.
This led to
negative training in that another locally operated. valve downstream
had to be operated to perform the important step of restering seal
injection flow in a controlled manner.
l
I
The second simulator event consisted of a loss of heat sink accident,
with the intent being to force the crew into a bleed' and feed
initiation until levels were recovered in the steam generators
"
( S/G s),.
at which time they would recover from the bleed and feed
situation. Again, the team noted simulator modeling problems which
provided an unrealistic plant response that would lead to negative
operator training.
The steam line power relief valves (PORVs)
provided little S/G' depressurization effect until they were almost
full open. Also, when these valves were closed, S/G pressure would
increase, even when there was very little mass in the S/Gs and the
only pressure source was a condensate booster pump with a discharge
pressure of less than 300 psig. Another modeling deficiency pre-
vented establishing a natural circulation condition once delta T
across the core had been raised above 60 degrees F by a " Loss of Heat
Sink" accident. Therefore, even with level restored in two S/Gs and
800 gpm bleed and feed flow cooling the core, cooldown could not be
established. This prevented the operators from continuing on into
the procedure to recover from bleed and feed operations.
The team
concluded that this was caused by the simulator model assuming
natural circulation flow was zero if delta T across the core was
greater than 60 degrees F.
Several procedural problems were noted. The most significant were:
1.
Step 4.h requires initiation of 100 gpm flow to the S/Gs though
the meters / recorders are calibrated in MPPH (mass pounds per
hour). The operator cannot adequately determine if 100 gpm is
I
established. The purpose of this step is to limit the potential
)
for thermal shock of the S/G tubes.
j
2.
Step 4.1 does not provide guidance with respect to the condi-
tions that must exist before the operator can start increasing
,
feed flow above the 100 gpm established in the preceding step.
l
This could either result in thermal shock of the tubes if done
i
l
too early, or delay the recovery of a S/G as a heat sink'if done
too late.
1
i
m
32
.
3.
Steps 19-25 do not have a hold point to keep the operator in the
loss of heat sink procedure (E0P-15.0), if the criteria in steps
19 a, b, and c are not met.
These criteria need to be met in
order to enter the subsequent procedure, E0P-1.2, Safety Injec-
tion (SI) Termination.
These E0P procedural problems are identified as inspector
followup item 395/88-26-07.
The third simulator event that was observed was a S/G tube rupture,
with 'a subsequen.t SBLOCA af ter the ruptured S/G was isolated.
The
team found it and the simulator response to be adequate,
d.
Independent Technical Adequacy Review of the E0Ps.
~
The team reviewed the E0P verification and validation documentation
for the procedures listed in Attachment 6.
The vendor recommended
step sequences were followed. The documentation for step deviations
were of borderline value to future E0P developers in that they
typically stated the reason for the deviation to be a " plant specific
requirement." The team found that the licensee had resolved comments
that had been made concerning procedural discrepancies and had
changed the procedure accordingly.
The validation process had
l
generated the comments.
l
The QA Department and ISEG did not actively participate in the
development and validation of the E0Ps.
The QA group conducted two
l
audits in 1986 and one audit in 1987.
Currently, QA has no open
items on the E0Ps, other than monitoring the program once per quarter
l
to ensure completion of the Procedure Generation Package. _ QA has
'
planned performance based inspections to begin with SAP-207 implemen-
tation. Through the performance of SSFIs, the ISEG has addressed the
E0P-Systems interface.
ISEG had four open items on the E0Ps.
The
team found that one of the four had been corrected, but had not been
closed out in the ISEG's records.
- pparently, the procedures group
use of the informal feedback program caused this error.
The team reviewed the E0P feedback program used. This program
4
l
receives procedure change requests from users and from the design
!
control process.
The team found that changes requested from the
operators were kept informally and no tracking or tickler systems
~
existed. Numerous feedback requests lacked the name of the requestor
or the date of the request
The licensee intends to implement a
,
formal operator feedback form with the issuance of the final SAP-207.
1
To assess the adequacy of the changes to the E0Ps resulting from,
t
design changes, the team reviewed all the Modification Request Forms
associated with the procedures listed in Attachment 6.
Plant
,
modifications which could have effected the E0Ps had been reviewed
and the procedures had been revised where necessary. Where modifi-
cation.s effected plant drawings used by the operators they"were
i
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _
~
.
33
updated by the use of interim drawings. The oldest' interim drawing
was dated August 1, 1986.
More timely incorporation into a permanent
plant drawing is appropriate.
This will aid the operators by reducing
the number of references they may have to use during an emergency. - The
team noted no other discrepancies in this area.
The team did note that the ECP procedure index was out of date with
regard to the revision number and the cate for numerous E0Ps.
However, the operators used controlled copies which are verified to
be current revisions without relying on the index.
The licensee
intends to delete the revision numbers and dates from the index to
avoid duplicating information found in the Master Control Copy.
12. Action on Previous Inspection Findings (92700, 92701, 92702)
(CLOSED) Inspector Follow Item 395/88-03-03, Completion of revisions to
natural circulation cooldown procedure.
This item involved several procedural deficiencies noted during the NRC
review of the natural circulation cooldown procedure.
The team reviewed
the revised procedure against the items listed in the inspection report
and concluded that all items identified in that report had been included
in the revised procedure. The actions taken to address this issue are
therefore considered satisfactory and this item is closed.
13.
Exit Interview (30703)
The inspection scope and findings were summarized on December 22,1988,
with those persons indicated in paragraph 1 above. The team described
the areas inspected and discussed in detail the inspection results listed
below.
,
Item Number
Status
Description / Reference Paragraph
j
395/88-26-01
OPEN
VIOLATION - Inadequate procedure or failure
to
follow procedures,
paragraphs
3.c.
1
and 3.1.1.
l
395/88-26-02
OPEN
VIOLATION - Inadequate 50.59 evaluation of
fire protection valves, paragraph 2.j.
395/88-26-03
OPEN
VIOLATION - Inadequate review of procedures
and drawings, paragraphs 2.d., 2.e. & 2.g.
395/88-26-04
OPEN
IFI - Revise R&R Log so Action LCOs stand
-
out, paragraph 2.f.
395/88-26-05
OPEN
IFI - The PMTS report of overdue preventive
maintenance items needs to be reviewed
following the outage, paragraph 3.J.
_ - ___ _ __ - ___
m-
34
395/88-26-06
OPEN
IFI - Correct E0P discrepancies, parag'raph
11.b.
395/88-26-07
OPEN
IFI - Correct E0P procedural problems,
paragraph 11.c.
395/88-03-03
CLOSED
IFI - Incorporation of comments into
natural
circulation
cooldown
procedure,
paragraph 12.
.
-
i
.
1
,
J
.-
r
1
- -
_ . - _ _ _ _ _ - - - _ - _ _ _ - - _ _ _ - _ - _ - _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ - -
_
_
-
- - _
,
c.
Attachment 1
.
DIAGR/N DESCRIPTION CF FAILU:E MODE
',
__
1
switch contact
l
ground indicating
for solenoid
(
C.__
light bulbs
4
i
resistors
"
'
125 v
.
1
e
ground fault
l
tfi tal
dc
-
battery
F
- installed
y'
ground
1
ASCO
y
jE
'
'
- """
solenoid
j
L
CR
,
i
!
)
L
Local
-
i
l
CR - Control P,oom
'
41 ASCO solenoid is shown, with a ground fault on the positive side of the
I
solenoid. TFe circuit for this solenoid contains one actuation switch
I
contact, on the positive side of the solenoid.
l
The installed ground detection system is also shown. This system consists of
two 1000 chn light bulbs plus plus 2000 ohm resistors, connecting each of the
positive and negative legs of tFe dc tx.is to ground. Net resistance to grcund
is 1500 chTrs on each of tFe positive and negative legs. Ground indication is
provided in the control room and at the battery charger.
A complete circuit through the solenoid, the ground fault, and the ground
detector is show) by dark lines.
l
l
l
l
lY
_ _ _ _ _ _ _ _ _ _ _ _ _
_
y
ATTACHMENT 2
FIRE PROTECTION VALVES CLOSED
DATE VALVE
VALVE NO.
PROTECTION AREA
CLOSED
XIG-4107
- Control Building Emergency Plenum "B"
08-18-87
- Control Building Emergency Plenum "A"
08-18-87
XVG-4111
- Control Building Exhaust Plenum
02-02-87
XVG-6751
Auxiliary Building Filter "A"
Plenum
02-02-87
l
XVG-6753
Auxiliary' Building Filter "B"; Plenum
02-02-87
XVG-6759
Reactor Building Purge Exhaust
02-02-87
l
XVG-6794
Reactor Building Sprinkler System
12-05-86
'
XVM-6786
- Fuel Building Plenum "C"
08-18-87
XVM-6788
- Fuel Building Plenum "B"
08-18-87
XVM-6790
- Fuel Building Plenum "A"
08-18-87
- SYSTEMS COVERE0 BY TECHNICAL SPECIFICATIONS
l
i
l
l
l
l
l
i
i
i
_
/
_ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _
- _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ -
_ _ .
-
J
)
ATTACHMENT 3
~
EVENT REPORTS
l
ON0/LER
TITLE
ONO 870083
Diesel Generator Building Preaction Check Valve
Failure
i
ONO 870093 &
Negative Rate Reactor Trip During Control Rod Drive
!
1
l
LER 870024
Cabinet Maintenance
ONO 870099 &
Reactor Trip on Power Loss To Panel 7008
LER 870027
l.
ONO 870102 &
Improper Light Bulb Application Cause Reactor LER
'
LER 870028
Trip
ONO 870108
Diesel Generator "A" Air Start Filter
Installation Error
ONO 870111
Diesel Generator Building Preaction Sprinkler
System Valve Failed to Operate
ONO 880004 &
Inverter Power Failure Led to Security Equipment
LER 880001
Malfunction
1
ONO 880017
Improper Installation of Jumper To Open Valves
]
on ORPI
ONO 880045
Ruptured Lube Oil Pressure Switch in the "A"
Main Feedwater Pump
ONO 880063
Isolation of RHR Train "A" During Performance
of Safeguard Test
i
..
l
l
.
- - - - - - _ - - _ - - _
i
'
.
I
ATTACHMENT 4
l
i
MAINTENANCE WORK ORDERS IN PROCESS
]
WORK REQUEST NO.
TITLE
88E0165
Repair
Valve
XVG03107A
for
Service
Water System.
88E0220
Perform Low Voltage Field Flash Test for
Diesel Generator XEG0001B.
8801688
Repair Valve XVB00002A to Radiation
Monitor RMA-004.
88E0253
Replace Diaphram Hose to Valve XVT08871 -
0-SI to Accumulators.
88D0082
Remove Diaphram from Reactor Make-up Water
Storage Tank XTK-39-MU.
8801131
Replace
Charcoal
Filter
in
Auxiliary
Building Ventilation system XAA0040A.
COMPLETED MAINTENANCE WORK REQUESTS
WORK REQUEST NO.
TITLE
8810504
Trouble Shoot and Repair or Replace as Required
Leak Detection Transmitter IL TO 1969
88T0158
Block Open and Unblock PCV 00445B To
Support ILRT
8810446
Replace NCH Card C01-542
l
8810348
Repair NLL Card in "C" Steam Generator
Pressure Cabinet
88 WOO 49
Investigate and Repair Steam Dump System
Valve IV02026-MB
88D0064
Open Check Valve XVC03135B-SW and Remove
<
Internals for. Engineering Inspection.
Replace after inspection.
88E0169
Remove Jumpers From TB 1 TB Prior to
Placing Inverter XIT 5908 In Service
i
(
8801632
Replace Blown Fuses FV2B in Panel XPN 5253
J
,
'
-
-__
_ _ _ _ _
_
\\
_ _ _ _
Attachment 4
2
DESIGN CHANGES REVIEWED
NUMBER
NAME
20726
20390
REACTOR COOLANT PUMP
21262
VANTAGE V FUEL TECH SPEC CHG.
31092
H2 RECOMBINERS
10131
INSTALL REACH RODS ECCS CK VLV
-20285
l
1
i
,
O
i
mi_________
___
_
l
,
f
ATTACHMENT 5
INSTRUMENT CALIBRATION
CALIBRATION
INSTRUMENT NO.
FUNCTION
DATE
.ITE-00604A
RHR Pump A Discharge Temperature
6-24-88
IPI-00601B
RHR Pump B Suction Pressure
6-14-88-
IPI-07377
RB Spray Pump B Discharge Pressure
9-26-88
IPI-04523
SW Booster Pump A Discharge Pressure
9-16-88
ILI-05420
D/G Fuel Oil Day Tank B Level
11-11-88
'
ITM-07052
CCW From CC Heat Exchange A Temperature
_10-06-88
-
IPI-00152A
Charging Pump B Suction Pressure
11-25-88
IPI-00152B
Charging Pump B Discharge Pressure
06-01-88-
IPI-04402
SW Pump A Discharge Pressure-
06-28-88
ILI-04418
SW Pond Level
01-30-88
ILI-01963
11-05-88
ILI-00991
RWST Level
-09-06-88
ILI-07433
Spent Fuel Pool Level
07-06-88
ILI-00926
Accumulator B Level
11-02-88
IPI-00927
Accumulator B Pressure
10-31-88
IPI-00163
Boric Acid Tank B Level
08-12-88
ILI-00461
Pressurizer Level
11-18-88
ITI-00432D
RCS Loop C Probe
10-16-88
ITI-09964
SW Building Room Temperature
07-22-88
IPI-15423B
D/G Starting Air Pressure
11-11-88
!
!
l
1
-
b
a
-
L_._______________
_
ATTACHMENT 6
E0P PROCEDURES REVIEWED
NUMBER
TITLE
E0P-2.0
Loss of Reactor or Secondary Coolant
E0P-2.1
POST-LOCA Cooldown and Depressurization
E0P-2.4
Loss of Residual Heat Removal System
E0P-2.5
LOCA Outside Containment
E0P-3.0
Faulted Steam Generator Isolation.
E0P-4.0
Steam Generator Tube Rupture
'
E0P-4.1
POST-SGTR Cooldown
E0P-4.2
SGTR with Loss of Reactor Coolant:Subcooled Recovery
E0P-6.0
Loss of all AC Power Recovery with Safety Injection
Required
E0P-6.2
Loss of all AC Power Recovery with Safety Injection
Not Required
,
l
E0P-7.0
Refueling Emergency
E0P-8.0
Control Room Evacuation
j
l
E0P-11.0
Emergency Boration
'
E0P-13.0
Response to Abnormal Nuclear Power Generation
l
E0P-15.0
Loss of Secondary Heat Sink (Feedwater)
i
E0P-15.3
Loss of Normal Steam Release Capabilities
l
E0P-18.2
Response to Voids in Reactor Vessel
!
l
l
!
l
"
l
!
ATTACHMENT 7
{
TECHNICAL REVIEW COMMENTS
The following are inspector comments as a result of reviews of the V.C. Summer
E0Ps.
1.
VCSNS E0P-2.0, Loss of Reactor or Secondary Coolant, Rev. 3; WOG E-1 Loss
of Reactor or Secondary Coolant
a.
Step 1.a does not check the alternate SI header flow as an
ALTERNATIVE ACTION.
With single failure criteria the normal SI
header may not have flow; the operator should then determine if
the alternate SI header is available or has flow established.
The team also noted this item in E0P-4.0 step 1.
b.
No criteria is provided for checking Reactor. Building Spray flow
in step AA.7.a.2 and 3.
Specific flow requirements are not provided
to the operator. The team found_ that the green' band labeled on the
Reactor Building Spray flow indicator is not based upon design basis
criteria.
The design basis flow is 2500 gpm while the indicated
green band range begins at 2000 gpm, therefore, less Qan design
basis flow could be present while the operator could have indication
that flow is adequate via the green band.
,
To preclude entering into a Critical Safety Function due to insuffi-
cient Reactor Building Spray flow, either the green band shouh. be
adjusted or a specific flow rate provided for the operator to verify
in this step.
c.
An inappropriate procedure is referenced.
In the event of a loss
of offsite power to one of the ESF buses, step 13 has the operator
attempt to restore power to the bus by using SOP-304, "7.2KV Switch-
gear." The team found that this procedure does not adequately guide
the operator in the restoration of offsite power to the ESF buses.
The step should have the operators use A0P-304.1 to restore offsite
power to a deenergized ESF bus.
Similarly, this item was noted by
the team in E0P-4.0, step 14.
2.
VCSNS E0P-2.1, POST-LOCA Cooldown and Depressurization, Rev. 2; WOG
ES-1.2, POST-LOCA Cooldown and Depressurization
a.
NOTE 15 provides the operator guidance that "The Charging Pumps
should be stopped on alternate Emergency Core Cooling System trains
when possible." This note is out of date with current plant opera-
tions and should be deleted,
b.
Step 32 provides guidance to the operator concerning ' actions to be
I
taken with the RHR System during certain RCS pressure and temperature
conditions.
The directions are not specific, in that there are
l
plausible conditions (e.g. Temperature = 300 Deg F and Pressure = 450
j
psig) when the guidance will not work.
The procedure needs to be
'
corrected to alleviate this problem.
~
-
l
L-______-_-_______.
..
Attachment 7
2
3.
VCSNS E0P-2.4, Loss of Residual Heat Removal System, Rev. 3; WOG ECA 1.1,
Loss of Emergene/ Coolant Recirculation
a.
Step A.3.b is constructed in a format inconsistent with the guidance
of the Owners' Group guidelines.
It is, in reality an ALTERNATIVE
ACTION (Response Not Obtained) action for Step 3.a, and should be
adjusted accordingly.
b.
At Step B.6, there is not a NOTE for supervisory personnel to remain
in the vicinity of the Reactor Building air locks to ensure that the
l
integrity check can be properly performed. This NOTE is included in
Part C of the procedure.
1
c.
There is no procedural reference provided the operator for installing
the Spent Fuel Pool Gate in Step B.11.
This activity is not fre-
quently performed and the proper procedure (FHP-611-5) should be
referenced for the operator.
d.
Insufficient guidance is provided the cperator in Step B.12.d
(ALTERNATIVE ACTION).
The "suppor ting equipment" for the " charging
train" is neither obvious, nor should it be memorized.
4.
VCSNS E0P-3.0, Faulted Steam Generator Isolation, Rev. 2; WOG E-2, Faulted
l
Steam Generator Isolation
a.
Inconsistent guidance is provided to the operator for filling the
Condensate Storage Tank with Demineralized Water in step 6.
This
evolution is performed at numerous points in the E0Ps and the guid-
,
ance is not always consistent. The licensee intends to standardize
the wording in upcoming revisions to the E0Ps.
b.
The Inspectors noted a typographical error in step 6.b for valve
XVG-668-CO.
Currently, the procedure has this valve listed as
XVG-643-CO.
5.
VCSNS E0P-4.0, Steam Generator Tube Rupture, Rev. 3; WOG E-3,
Steam
Generator Tube Rupture
a.
Contradicting information is given to the operator within one
Caution.
The operator is directed to depressurize the RCS using
normal spray at step 21. The team noted, however, that the operator
is also cautioned during the performance of step 21, that pressurizer
level may increase beyond indicator scale range (Caution 21 (2)).
Caution 21 (1) states that a steam bubble should be maintained in the
pressurizer. These two cautions provide contradicting information to
the operator. If a steam bubble is to be maintained then pressurizer
level should not increase beyond indicator scale range.
_ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ - -
.
.
Attachment 7
3
6.
VCSNS E0P-4.2, SGTR With Loss of Reactor Coolant: Subcooled Recovery,
Rev. 2; WOG ECA-3.1, SGTR With Loss of Reactor Coolant: Subcooled Recovery
a.
Incomplete guidance is provided to the operator for steam generator
sampling.
During performance of this procedure the ruptured steam
generator is isolated.
Step 8.b has the operator monitor blowdown
sample recorder for pH and conductivity.
This action cannot be
performed with the steam generator isolateo.
The operator is not
provided guidance on the proper restoration of sample flow.
7.
VCSNS E0P-6.0, Loss of All AC Power, Rev. 2; WOG ECA-0.0, Loss of All AC
Power, Rev. lA
a.
The procedure text does not reference the use of Attachment 2, "KW
l
Rating for Engineered Safeguard Features Equipment on Bus XSW1DA."
b.
The procedure does not instruct the. operator to attempt restoration
of offsite power. Step 5 directs the operator to restore ac power to
at least one ESF bus; however, the stated actions only refer to
restoration by using a Diesel Generator. The preferred source would
be offsite power using A0P-304.1, " Loss of One ESF Bus With the
Diesel Not Available." The licensee committed to changing this with
the next routine revision of E0P-6.
c.
Procedure steps used to reset ESF loading logic cannot be accom-
plished.
The operator is instructed to reset ESF loading logic in
step 27. The loading logic cannot be reset without first resetting
all Safety Injection signals.
If one ESF bus -is restored during
performance of steps 1-5, the operator is directed to step 26. At
this point the Safety Injection signal has not been reset; therefore,
step 27 can not be performed. Additionally, if the operators transi-
tion to E0P-6.2, " Loss of All AC Power Recovery With SI Required",
step 6 of that procedure cannot be accomplished either (establishing
i
'
RCP seal injection) since resetting Safety Injection i s 1al so a
prerequisite for establishing seal injection.
d.
The setpoint listed in step 35(a) for subcooling (2 degrees (22
degrees for adverse containment conditions)) is not supported by any
technical justification. The WOG recommended setpoint .is 0 degrees
subcooling.
8.
VCSNS E0P-6.2, Loss of All AC Power Recovery With SI Required, Rev. 2;
WOG ECA-0.2, Loss of All AC Power Recovery With SI Required
a.
The procedure text- does not reference the use of Attachment 1, "KW
Rating for Engineered Safeguard Features Equipment on Bus XSW1DB." ,
b.
Incorrect nomenclature is listed in step 5 (ALTERNATIVE ACTION)
a.1. for the MD EFP Reset Switch.
i
lL-.- ---
-
-
_. . - _ _ _ _
_
-
- _ _
Attachment 7
4
9.
VCSNS E0P-7.0, Refueling Emergency, Rev.2'
a.
Step A.6.f has the operator " Verify Fuel Handling Building sump
levels not increasing."
Accomplishment of this step is almost
impossible.
There are neither dip sticks, wall markings, level
.
indicators, or anything else that could assist the operator .in
trending the levels of the Fuel Handling Building sumps.
Some type
of indicating device is needed to allow accomplishment. of this
activity.
b.
Step 8.5 instructs the operator to take local actions to " Ensure
Reactor' Make-up System Valves closed." No notation is provided to
guide the operator to the location of these infrequently operated
,
valves.
10.
VCSNS E0P-13.0, Response to Abnormal Nuclear Power Generation, Rev. 2;
WOG FR-5.1, Response to Nuclear Power Generation /ATWS
a.
The SYMPTOMS for the procedure are not in compliance with the
guidance contained in the PGP.
Specifically, the only symptoms-
listed are entry form E0P-1.0 and E0P-12.0. The symptoms need to be
modified to be in compliance with the formatting defined in the
b.
Step 3.b (ALTERNATIVE ACTION) instructs the operator to take local
action to ". . manually open Steam Supply Valve to TD EFW Pump." No
notation is provided to guide the operator to the location of this
valve.
c.
Step 11.0 has the operator " Isolate each faulted SG."
This activity
is neither commonly performed
nor self-evident.
In E0P-3.0,
,
step-by step guidance is provided to the operator to accomplish this
task. Such guidance is needed in this procedure to ensure that the
actions are accomplished properly and expeditiously.
d.
Step 12.a.2 (ALTERNATIVE ACTION) instructs the operator to " Perform
actions of other procedures in effect which do not cooldown or other-
wise add positive reactivity to the core."
With the new fuel load
configuration in the Summer core, a positive moderator coefficient
.
is experienced during power operations.
This positive coefficient
l
is greater than any previously experienced positive coefficient and
will remain in effect for a significantly longer period of time
than any such previous occurrence. Analysis is needed to ascertain
whether this guidance is applicable with these new core conditions.
In effect, the operator is being given instructions to add rositive
reactivity to the core in an identified ATWS situation.
__-____--__ _ -
Attachment 7
5
11.
VCSNS E0P-15.0, Loss of Heat Sink; WOG FRP-H.1, Loss of Heat Sink
a.
The guidance in Step 2.e, " Verify EFW flow greater than 390 gpm to
at least one SG", is unclear to the operators.
Discussions with
four licensed operators of the plant staff resulted in two operators
stating that 390 gpm was needed to any one SG, while the other two
operators stated that a total EFW flow of 390 gpm was the requirement
and that it had to have a flow path to at least one SG.
This
inconsistency among the . operating staff concerning this procedural
step needs to be corrected.
b.
Guidance should be included prior to step 4.b, to state that pressure
must be below the P-11 setpoint in order to block the SI signals
listed,
c.
The alternative action in step 4.d.1 does not provide adequate
j
guidance on how rapidly the S/Gs should be depressurized,
d.
A caution warning operators of the potential loss of the condensate
pumps due to a high deaerating tank level should be inserted prior
to step 4.a.
This will make the operators aware of an impending
condition which could delay initiating feed water flow from the
condensate pumps in step 4.e.
e.
Step 9.b has the operator " Ensure PZR POWER RELIEF ISOL Valves
open." Power is normally available to at least one of these -valves.
However, since the plant is experiencing problems with " leakers",
power is not maintained to all of these valves.
Explicit guidance
concerning this anomoly, with the location of the breakers to be
reset is needed. The operators do not have these breaker locations
memorized and the only reference to their location is on the operator
aid on the control board, under the respective valve control
switches.
f.
The guidance in step 16(a) is unclear. Clarification should be made
so that the operators know that they are to continue in the loss of
heat sink procedure, vice transition to another procedure if auxil-
iary feed water flow is restored at this point in the procedure via
completion of step 2.
12.
VCSNS E0P-18.2, Response to Voids in Reactor Vessel, Rev. 1;
FR-I.3, Response to Voids in Reactor Vessel
a.
The SYMPTOMS for the procedure are not in compliance with the
guidance contained in the PGP.
b.
Step 7 does not have the operator check for hydrogen concentration,
as is required by the WOG.
No justification was in the technical
deviation documentation as to why this step was omitted from the
VCSNS E0P.
e
EE_____________._______
_ _ . . .
..
_ _ _ _
__ _ _ _ _ _ _ _ _ .
_
_ _ _ _ _ _ _ - _
_ _ _ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _
i
.i
Attachment 7
6
1
c.
Step 8 directs the operator to " Verify RCS pressure is at least 100
psi less than Technical Specification Cooldown limit and less than
1850 psig."
This guidance is confusing and did not result in
consistent interpretation by the operators.
The cooldown limit is
a "Deg F/ Hour" parameter, 'while RCS pressure is a "PSIG" parameter -
they are not compatable.
Both the intent of this step and the
specific way of performing it need to be addressed by the facility.
d.
Step 21.a directs the operator to " Unlock and close motor control
center breakers for the Reactor Head Vent Valves."
The operator
walking down the procedure had to call the control room to find out
where the breakers were. This was only obtainable from the operator
l
aid under the valve control switches on the Main Control Board.
'
'
Specific location.for these MCC breakers'needs to be included in the
procedure.
l
I
l
l
.
-
ATTACHMENT 8
- ALTERNATING CURRENT
A0
- AUXILIARY OPERATOR
- ALARM RESPONSE PROCEDURE
ASCO
- AUTOMATIC SWITCH COMPANY
CHAMPS - COMPUTERIZED HISTORY AND MAINTENANCE SCHEDULING
- CHEMICAL AND VOLUME CONTROL SYSTEM
.DBD
- DESIGN BASIS DOCUMENT
- DIRECT CURRENT
- EMERGENCY CORE COOLING SYSTEMS
- ELECTRO HYDRAULIC CONTROL
E0P
- EMERGENCY OPERATING PROCEDURE
- ENVIRONMENTAL QUALIFICATION
- EMERGENCY RESPONSE GUIDELINES
FPER
- FIRE PROTECTION EVALUATION REPORT
FSAR-
- FINAL SAFETY ANALYSIS REPORT
GPM
- GALLONS PER MINUTE
- HEATING VENTILATION &' AIR CONDITIONING
- INSTRUMENT & CONTROL
IEN
- NRC INFORMATION NOTICE
- INSTITUTE OF NUCLEAR POWER OPERATIONS
ISEG
- INDEPENDENT SAFETY ENGINEERING GROUP
LCO
- LIMITING CONDITION FOR OPERATION
LER
- LICENSEE EVENT REPORT
j
- LOSS OF COOLANT ACCIDENT
)
MPPH
- MILLONS POUNDS PER HOUR
1
'
MRF
- MODIFICATION REQUEST FORM
MWR
- MAINTENANCE WORK REQUEST
.
NI
- NUCLEAR INSTRUMENTATION
NRC
- NUCLEAR REGULATORY COMMISSION
ONO
- 0FF NORMAL OCCURRENCE
- PROCEDURE GENERATION PACKAGE
PMTS
- PREVENTIVE MAINTENANCE TASK SHEET
- POWER OPERATED RELIEF VALVE
- POUNDS PER SQUARE INCH GAGE
PSRC
- PLANT SAFETY REVIEW COMMITTEE
- QUALITY ASSURANCE
- QUALITY CONTROL
- REACTOR OPERATOR
R&R
- REMOVAL & RESTORATION
SBLOCA - SMALL BREAK LOSS OF COOLANT ACCIDENT
- SAFETY EVALUATION REPORT
S/G
- SAFETY INJECTION
- SIGNIFICANT OPERATING EVENT REPORT
- STANDARD OPERTING PROCEDURE
- SENIOR REACTOR OPERATOR
.
- SHIFT SUPERVISOR
- SURVEILLANCE TEST PROCEDURE
-
TS
- TECHNICAL SPECIFICATIONS
'
,
_________
-