ML17157C308
| ML17157C308 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 04/26/1993 |
| From: | Conte R, Florek D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157C307 | List: |
| References | |
| 50-387-93-06, 50-387-93-6, 50-388-93-06, 50-388-93-6, NUDOCS 9305070045 | |
| Download: ML17157C308 (23) | |
See also: IR 05000387/1993006
Text
U.S. NUCLEAR REGULATORY COMMISSION--
REGION
1
REPORT NO.
93-06
FACILITYDOCKET NOS.
50-387
50-388
LICENSEE NOS.
NPF-22
LICENSEE:
Pennsylvania Power & Light Company
2 North Ninth Street
Allentown, Pennsylvania
18101
INSPECTION AT:
INSPECTION DATES:
Susquehanna
Steam Electric Station, Units
1 & 2
April 5 - 8, 1993
'NSPECTOR:
g/p 6
Donald J. Florek,
r Operations Engineer
Dat
APPROVED BY'ich
. Conte, Chief, BWR Section
Operations Branch, Division of Reactor Safety
Date
SUMMARY:
outine announced
safet
in
tion com ined in
ection re o
5 -387/ 3-
~06
d
y
yy
D-y-yl,yyyy,y
y Iiyy
yy &
y
ie
y
Susquehanna
Steam Electric Station (SSES) EOPs to reflect the Revision 4 of the BWR
Owners Group Emergency Procedure Guidelines (BWROG EPGs) with some exceptions.
This inspection reviewed the current SSES EOPs for technical adequacy
and ability to be
implemented.
Nonlicensed operator training on an EOP task was observed.
Open items
from prior EOP inspections were also reviewed.
RESULTS:
The inspector concluded that the technical basis for the SSES EOPs is consistent
with the BWROG EPGs with exceptions.
Where the exceptions are taken, PP&L has
prepared
safety evaluations.
Several exceptions are significant and are being referred to the
NRC Headquarters
staff for further review in Rockville, MD. (Unresolved items 387/93-06-
Ol and 388/93-06-01).
The EOPs adequately implement the SSES EPGs.
Some
enhancements
can be made to reduce the potential for operator error when using the EOPs.
The SSES EOPs are able to be implemented.
However, some EOPs and methods for
actually carrying out your procedures in the field can be improved to assure more timely
completion of the tasks.
No violations were identified.
An unresolved item related to
secondary containment maximum normal radiation levels was identified (Unresolved items
387/93-06-02 and 388/93-06-02).
The observed nonlicensed operator training on an EOP
task was effective.
9305070045
930426
ADOCK 05000387
8
1.0
PERSONS CONTACTED
DETAILS
Pennsylvania Power and Light
4
- P. Bartel, Supervisor Operations Technical Support
- M. Chaiko,- Systems Analysis
M. Diltz, Licensed Operator
- A. Fitch, Supervisor Operations Training
- A: Gorin, NQA
- D. Kapuschinsky, Nuclear Plant Specialist - Operations Technical Support
- W. Lowthert, Manager Nuclear Training
- T. Markowski, Dayshift Supervisor
- H. Palmer, Manager Nuclear Operations
- G. Stanley, Superintendent of Plant
U. S. Nuclear Regulatory Commission
- D. Mannai, Resident Inspector
- Denotes those individuals present at the exit meeting on April 8, 1993
2.0
INSPECTION OBJECTIVE AND PURPOSE
Since the last Emergency Operating Procedure (EOP) inspection, the facility licensee (PP&L)
has revised the Susquehanna
Steam Electric Station (SSES) EOPs to reflect the Revision 4 of
the BWR'Owners Group Emergency Procedure Guidelines (BWROG EPGs).
NRC has
accepted Revision 4 of the BWROG EPGs for EOP development.
On December 31, 1992,
PP&L implemented the revised EOPs to reflect Revision 4 of the BWROG EPGs, with some
modification. This inspection reviewed the current SSES EOPs for technical adequacy
and
ability to be implemented.
Open items from prior EOP inspections were also reviewed..
3.0
TECHNICALADEQUACYREVIEW - BWROG EPG TO SSES EPG
COMPARISON
Scope
The documents in Attachment
1 were reviewed.
The SSES EPGs were compared to the
Where differences were noted, the justification for the differences were
assessed.
Calculations for the heat capacity temperature limit, heat capacity level limitand
pressure suppression
pressure were reviewed for consistency with the BWROG EPG
methodology.
Findings
The SSES EPGs contain some major exceptions to the BWROG EPGs.
Except for these
major exceptions,
the SSES EPGs are consistent with the BWROG EPGs and the NRC safety
evaluation report on the BWROG EPGs.
The SSES EPG major exceptions are listed in the
following discussion.
Any exception from the BWROG EPG is documented in a safety
evaluation prepared by the facility licensee.
The SSES major exceptions generally apply to strategies dealing with an anticipated transient
without scram (ATWS) situation.
The SSES EPGs require reactor pressure vessel (RPV) water level to be lowered to
between -80" and -110" for all ATWS events in which power is greater than 5%
independent of suppression
pool temperature.
reduction to between top of active fuel (-171") and 2.6 feet below top of active fuel
(minimum steam cooling RPV water level) when suppression
pool temperature is
above the boron injection initiation temperature.
independent of suppression pool temperature to uncover the feedwater spargers
so that
the subcooled makeup flow willbe heated by steam condensation
to reduce the
buildup of core inlet subcooling which can eventually lead to unstable reactor power
operation.
RPV water level is lowered to -110" to allow for increased
assurance of
maintaining clad integrity. PP&L calculations indicate difficultyin controlling RPV
water level at -171" with pressure perturbations
and reactor power fluctuations with
the possible development of clad perforations.
With water level between -171" and
2.6 feet below top of active fuel, PP&L calculations indicate a concern for adequate
two phase cooling of low power bundles.
PP&L calculations indicate that a higher
RPU water level assures
a better mixing of the sodium pentaborate for reactivity
control and assures
level indication on wide range instrumentation calibrated for a
pressurized
reactor, rather than the fuel zone indicator which is calibrated for a
depressurized
reactor.
2.
The SSES EPGs do not require rapid depressurization
when the suppression
pool heat
capacity temperature limit (HCTL), heat capacity level limit (HCLL), or pressure
suppression limit (PSL) are exceeded for ATWS events in which the core power is
greater than 5% at the time the limitis reached.
emergency depressurization
on the HCTL, HCLL, and PSL.
require rapid depressurization
because
the PP&L calculations indicate that, when
rapid depressurization
is performed with the reactor at powers greater than 5%, large
amplitude reactor power excursions willoccur which can lead to core damage.
3.
The SSES EPGs do not include the suppression
pool design temperature value in the
determination of the heat capacity temperature limitwhich differs from the BWROG
EPGs.
The basis for including the suppression
pool design temperature in the
determination of the heat capacity temperature limitis no longer valid based on the
PP&L assessments
of new analysis and experiments.
The new experiments indicate
that containment dynamic loads decrease
rather than increase
as steam discharges into
a hot suppression
pool.
The effect of not including the suppression
pool design
temperature in the determination of the heat capacity temperature limitis to increase
the lower bound of the limitfrom 165 F to 192'F.
The SSES EPGs allow use of high pressure coolant injection (HPCI) during RPV
rapid depressurization
in an ATWS situation in order to increase HPCI system
reliability at low pressure.
In the BWROG EPGs, HPCI must be terminated prior 'to
RPV emergency depressurization.
The SSES EPG ATWS strategy differs from the BWROG EPGs.
The PP&L calculations
'indicate that reactor power willstabilize at about 25% with RPV water level in the band of-
80" to -110".
As a result, the containment heat input willbe about three times higher with
the SSES EPG strategy than with the BWROG EPG strategy.
PP&L calculations indicate
that except for the case of a full ATWS with no manual rod insertion or SLC injection, the
SSES EPG strategy for the ATWS transient willnot result in reaching the primary
containment pressure limit. PP&L calculations indicate that, for the case of a full ATWS
from 100% power with no manual rod insertion or SLC injection, the primary containment
pressure limit will be reached in about 40-50 minutes and containment venting would be
initiated.
When containment venting is initiated, offsite releases
should not contain
substantial fission products because
the SSES EPG strategy prohibits operation in those
regimes that PP&L predicts fuel clad failure.
Since the SSES EPG ATWS strategy differs
substantially from the BWROG EPGs, these differences are being referred to NRC
Headquarters for further evaluation.
This item is considered
to be unresolved (387/93-06-01
and 388/93-06-01).
The inspector questioned
the facility licensee regarding restrictions on limiting rapid
depressurization
during ATWS situations other than identified in item 2 above.
For example,
should rapid depressurization
be permitted when reactor power is greater than 5% and there
is an unisolated primary system leak in secondary containment that exceeds maximum safe
levels in more than two areas?
Because of the clad failure potential when rapid
depressurization
is performed, it would appear that rapid depressurization
should be avoided.
The facility licensee individual plant evaluations indicated that there is a very small window
of time (2-3 minutes) that this would be a problem.
Nevertheless,
the facility licensee had
planned on performing additional analysis by the end of the year on the rapid
depressurization
desirability for all the conditions indicated in the SSES EPGs.
This was
acceptable to the inspector.
The HCTL and HCLL curves in the EOP flowcharts are consistent with the calculational
methods developed in the BWROG EPGs.
The HCTL calculation method was modified on
the basis of the SSES EPG deviation discussed
above.
Conclusion
The inspector concluded that the SSES technical basis for the SSES EOPs is consistent with
the BWR Owners Group Emergency Procedure Guidelines (BWROG EPGs), Revision 4,
with exceptions.
Where the exceptions are taken, PPkL has prepared safety evaluations.
Several exceptions are significant and are being referred to the NRC Headquarters
staff for
further review.
PP&L's future plans include additional analyses
to further improve the
EOPs.
4.0
EOP PROCEDURE REVIEW
Scope
The EOPs were reviewed to determine that the logic contained in the SSES EPGs was
properly translated in the EOPs.
The EOPs were also reviewed for consistent use of
transitions within and between EOPs.
Findings
The inspector concluded that EOP flowcharts (EO procedures)
were consistent and agreed
with the SSES EPG logic. The EOP flowcharts were consistent with the writers'uide for
transitions and presentation of logic statements.
Attachment 2 lists detailed comments
identified during review of the EOP flow charts.
Conclusion
The EOPs adequately implement the SSES EPGs.
Some enhancements
can be made to
reduce the potential for operator error when using the EOPs.
5.0
EOP IMPLEM<JACTATION
Scope
The inspector walked down the Unit 1 EOP support (ES) procedures identified in Attachment
1.
The inspector also reviewed selected EO procedures in the control room for terminology
and labeling consistency and whether the range of the control room instrumentation supported
the EO procedures.
The inspector selected a number of the ES procedures
to be walked
down in order to determine ifthe accident scenario described in section 3.0 which leads to
containment venting (100% power full ATWS with no manual control rod insertion or
normal standby liquid injection) could be mitigated with the alternate methods within the 40-
50 minutes before containment venting is initiated.
When containment venting is initiated,
the reactor building becomes
inaccessible.
The inspector considered the normal site staffing
levels.
The inspector assumed
that only the normal control room operators assigned
to Unit
1 were used, but assumed
that the Unit 1 and 2 nonlicensed operators were available to
support the ES procedures
that needed to be implemented in parallel.
As a result, 5
nonlicensed operators
and one licensed supervisor were available to support the out of control
room activities;
.Findings
The ES procedures
and plant labeling are easily used together.
The procedures clearly
identify specific equipment, panel location, right or left door, right side or left side of panel,
and relative location (i.e., waist high or head high). The field locations are uniquely
identified with a green indication.
During the walkdown, one location was incorrectly
identified in the procedure (left side vs right panel side) and was promptly fixed by the
facility licensee.
For the ATWS response,
the inspector determined that the licensee could lower and control
RPV water level, reset the generator lockout, control reactor pressure,
inhibit the automatic
depressurization
system (ADS), vent the residual heat removal (RHR) system, initiate
suppression pool cooling, spray the suppression
pool, perform the reactor protection system
(RPS) and alternate rod insertion (ARI) trip bypass,
reset the scram and rescram, perform
HPCI suction auto transfer bypass, transfer suction to the condensate
storage tank (CST), and
vent the suppression
chamber within 40-50 minutes utilizing the staffing levels assumed.
The
task to set up and inject boron using the reactor core isolation cooling (RCIC) system
requires a minimum of 2 persons
and falls in the range of 40-60 minutes.
While all tasks
were able to be performed, the inspector identified some inefficiencies in the procedures
and
administrative controls for performing some of the ES tasks that result in longer than
necessary
times to implement the procedures.
These include sequences of steps and the
obtaining of procedures, jumpers, keys, and directions in the control room.
(The
inefficiencies are identified in Attachment 2.)
Based on the facility individual plant
evaluation, the facility licensee has recognized that some of the ES tasks are better performed
by alternate means and is planning plant modifications to install bypass switches in the main
control room to bypass main steam isolation valve (MSIV) low level and containment
instrument gas in the next refueling outage and to bypass the rod sequence control system
(RSCS), HPCI suction auto transfer, and low pressure coolant injection (I.PCI) valve 5
minute timer in the subsequent
refueling outage.
These bypass switches willallow more
effective use of nonlicensed operators to support the EOPs.
In addition, the plant staff has
requested
a modification to the standby liquid control tank drain line to increase the
probability that the injection of boron using the RCIC can be accomplished in a timely
manner.
This modification should reduce the time to inject boron with RCIC.
No schedule
has been established
to install the modification.
Most control room labeling agreed with the EOPs.
There were some cases of computer
identification differences and control room labeling differences in the secondary containment
control EOP as described in Attachment 2.
e
Conclusion
The inspector concluded that the SSES EOPs are able to be implemented.
However, some
EOPs and methods for actually carrying out the procedures in the field can be improved to
assure more timely completion of the tasks.
PP&L has recognized many of these
improvements and has initiated design modifications and procedure changes.
6.0
TRAININGON EMERGENCY OPERATING PROCEDURES
During the inspection, the facility licensee engineering, operation, and training staffs were
comparing the new simulator response to ATWS scenarios with the PP&L calculations.
The
inspector observed portions of these activities.
This observation by the inspector was very
beneficial in understanding
the integrated effect of the SSES EPG strategy for ATWS
response.
The core model demonstrated
reactor power oscillations similar to those described
in the PP&L safety evaluations reviewed by the inspector.
The licensee's activities are an
ongoing process to have a certified simulator for which the reactor and containment simulator
models behave as the actual plant and its analyses.
The inspector reviewed the licensee plans to revise the facilityjob performance measure
(JPM) operator examination bank to reflect the revised EO and ES procedures.
The licensed
operators have been trained- in the classroom
on the new and revised procedures
{Inspection
Report 50-387/93-02; 50-388/93-02) but, as of yet, have not used revised JPMs.
Revised
JPMs are being developed to cover the ES procedures during the next two year
requalification cycle.
The nonlicensed operators willcover their JPMs over their next three
year cycle.
The new and revised ES procedures
have not identified any new tasks, but there
are different and/or new locations for existing tasks.
During the inspection, the facility licensee was conducting a training walkdown with the JPM
for ES-150-002 Boron Injection Using RCIC System for the nonlicensed operators.
The
inspector observed the adequacy of the training and determined the difficultyor ease of
accomplishing the task.
The instructor was knowledgeable of the task and the nonlicensed
operators were active participants in the training.
The inspector judged the training session
to be effective. It was clear to the inspector that several of the nonlicensed operators
had
received training on this task in the past.
Suggestions
were made by the nonlicensed
operators to make the job easier to perform.
Some commented that they had made
suggestions in the past, but they had not been implemented.
These 'suggestions
appeared
to
be related to the design modification to the SLC tank drain line. The nonlicensed operators
also had some suggestions for technique improvement in the unrolling of the hose from the
SLC tank to the RCIC turbine elevations (approx 100 feet).
The facility instructor indicated
that he would pass on these suggestions for procedure enhancement.
After the training
session,
the inspector asked the nonlicensed operator how long they thought the task would
take.
The responses
ranged from 30 - 45 minutes.
e,
e
8
7.0
LICENSEE ACTIONS ON PREVIOUS INSPECTION FINDINGS
1
nres Ived item
7
1-
-
1
nd
/ 1-
- 1.
These items related to the
technical adequacy of the SSES EPG RPV Pressure Control Guidelines.
Since inspection 91-
09 SSES has revised their EOP to reflect Revision 4 of the BWROG EPG.
The revised
EOPs contain the reactor pressure
strategy related to this unresolved item. This strategy is
consistent with the BWROG EPGs.
These items are closed.
l
ed
nr
lv
item
7
1-
- 2 and
8/ 1-
2.
These items are related to the
different SSES methodology for determining maximum normal and maximum safe radiation
The SSES EOPs have established
maximum normal radiation
levels for all secondary containment radiation levels at 200 mr/hr. This level is the highest
radiation level expected in areas normally accessed.
Allarea radiation monitors are set to
alarm at 200 mr/hr or below.
Maximum safe radiation levels for secondary containment
have been established
at 10 R/hr based on assuring no individual would receive 25 rem
whole body dose for the all emergency recovery actions expected to be performed and is well
below the environmental qualification radiation levels.
The licensee methodology is
'onsistent with the intent of the BWROG EPGs.
As a result, the original issue of these
unresolved items is closed.
However, foi the maximum normal levels, the facility licensee
has elected to establish 200 mr/hr as a single number to cover all radiation areas in
This radiation level is beyond the range of control room
instrumentation for elevations of 779'nd 670'nd is nonconservative for elevations 818',
779', and 670', since the maximum normal level is greater than a factor of 10 beyond the
area radiation monitor setpoints.
Therefore, a new unresolved item is established
to assess
whether using a single value for maximum normal radiation levels for areas in the secondary
containment is adequate
(Unresolved items 387/93-06-02 and 388/93-06).
l
nre olved items
7/ 1-
-0
and
1-
-
. These items are related to the
deletion of secondary containment water level control guideline.
In the implementation of
Revision 4 of the BWROG EPGs, SSES EOPs have added'
secondary containment water
level control guideline.
These items are closed.
I sed
Vi lati n
7
2-1
-
1 and
- 2-1 - 1. This violation resulted from three
instances in which reports pursuant to 10 CFR 55.25, licensed operator medical requirements
were issued in excess of the required 30 days.
Facility licensee letter, dated
September
18, 1992, provided the response to the violation.
Operations procedure OI-AD-
074, "Licensed Operator Medical Examination," Revision 2, dated August 28, 1992; OI-AD-
010, "Summary of,.Limitations and Restrictions Imposed on Licensed Personnel,"
dated
September 22, 1992; and PPBcL letter regarding licensed operators SOOR 1-92-234, dated
July 1, 1992, were reviewed.
PP&L implemented the corrective actions needed to prevent
occurrence,
as documented in facility licensee September
18, 1992, letter.
This violation is
closed.
<
8.0
EXITMEETING
An exit meeting was conducted on April 8, 1993, at the conclusion of the on-site inspection.
Those persons in attendance
are noted in section 1.0.
The results of the inspection were
presented
at the exit meeting.
No documentation was provided to the facility licensee.
The
facility licensee did not identify as proprietary any of the materials provided to or reviewed
by the inspector during the inspection.
Attachments:
I. Documents Reviewed
2,
Comments on EOPs
10
ATTACHMENT1
DOCUMENTS REVIEWED
Susquehanna
Steam Electric Station Emergency Procedure Guideline, Revision 4, dated
December 29, 1992
AD-QA-330
"Symptom-Oriented EOP Program and Writer's Guide," Revision 7, dated
November 3, 1992
EO-100-102
"RPV Control," Revision 4
EO-100-103
"Primary Containment Control," Shts
1 & 2, Revision 4
EO-100-104
"Secondary Containment Control," Revision 4
EO-100-105
"Radiation Release Control," Revision 4
EO-100-112
"Rapid Depressurization,"
Revision 3
EO-100-113
"Level/Power Control," Shts
1 & 2, Revision 4
EO-100-114
"RPV Flooding," Revision 4
Safety Evaluation for EO-100/200-103, dated September
3, 1992
Safety Evaluation for EO-100/200-103,
dated September 3, 1992
Safety Evaluation for EO-100/200-103,
dated September
3, 1992
Safety Evaluation for EO-100/200-103,
dated December
15, 1992
NL-92-021
Safety Evaluation for EO-100/200-113,
dated November 9, 1992
Safety Evaluation for EO-100/200-112 & 113, dated October 28, 1992
Safety Evaluation for EO-100/200-114,
dated November 17, 1992
Safety Evaluation for EO-100/200-115,
dated December
17, 1992
HP-TP-441
"ARMAlarm Response
and Setpoint Adjustment Requests,"
Revision 0, dated
February 7, 1992
PLIS-39327
SSES Secondary Containment Radiation Levels, dated April21, 1992
Attachment
1
11
NPE-91-001
"SSES Individual Plant Evaluation Volume 1," dated December
1991
SE-BNA-117 Suppression
Pool Heat Capacity Temperature
and Level Limit Calculation,
dated February 2, 1992
SE-BNA-125 Pressure
Suppression
Pressure
Calculation, dated August 30, 1992
"Boron Injection Using RCIC System," Revision 7, dated March 29, 1993
"HPCI Suction Auto Transfer Bypass," Revision 3, dated June 29, 1992
"Bypassing RSCS Rod Blocks," Revision 2, dated September 30, 1991
"RPS and ARI Trip Bypass," Revision 0, dated December 28, 1992
"Venting Suppression
Chamber Irrespective of Offsite Release Rates,"
Revision 0, dated December 28, 1992
"Bypassing MSIV and CIG Interlocks," dated December 31, 1992
"Rapid Depressurization
or RPV Venting Bypassing MSIV Isolations,"
Revision 0, dated December 28, 1992
12
ATTACHM<WT2
COM1VKNTS ON EOPS
EO-100-102 RPV Control
Item 1.
The SPDS display for RHR vortex limits is not functional due to lack of a data
input.
EO-100-103 Primary Containment Control
PC/P-8
This step refers to the Pressure
Suppression Limitcurve using the word
"within." Due to the shape of the curve "within," can have multiple
meanings.
PC/P-10
This step refers to the Primary Containment Pressure Limitcurve using the
word "below." Due to the shape of the curve "below," can have multiple
meanings.
SP/L-5
This step refers to the Primary Containment Water Level Limitusing the word
"below." Due to the shape of the curve "below," can have multiple meanings.
PC/H-12
The logic provides no action when drywell oxygen concentration "= 5%."
SP/T-l
The procedure for placing suppression
pool cooling in service requires in-plant
operators to filland vent the system.
This may add unnecessary
time during
an emergency situation and may not be necessary
in all cases.
EO-100-104 Secondary Containment Control
Table 8
The secondary containment temperature indications in the table do not agree
with all the labels in the control room for all areas.
The RWCU heat
exchanger room is not indicated on the table.
The table indicates RHR pipe
routing whereas the instrumentation is labeled RHR equipment area.
The table
indicated RHR pump room A 8c B; whereas,
the instrumentation is labeled
RHR pump room
1 & 2.
Table 9
The maximum safe PMS in the table is in R/hr; whereas,
the instrumentation
in the control room is in mr/hr. The upper range of the area radiation monitor
(ARM) for elevation 779's 100 mr, which is below the identified maximum
normal value.
The PMS column for Max Safe for elevations 779'nd
670'hould
be NA, since there is no PMS instrument in those areas for Max Safe
(more comments regarding maximum normal radiation values are included in
section 6.0.
0-
Attachment 2
i
13
The computer identification of the high range ARMs does not agree with the
terminology in the table.
The identification should agree with the EOs,
computer and high range monitors in the upper relay room.
The computer
identification needs to agree with the table, 'since the computer output is the
only information available in the control room.
EO-100-113 Sht 2 Control Rod Insertion
CR-12
ES-158-002 does not "reset" ARI; it only bypasses
logic.
CR-13
.CR-18
ES-158-002 does not "reset" a scram; it only bypasses
logic.
The phrase,
"partially drain," is not sufficiently specific to provide direction to
the operator.
Logic that relies on either elapsed time and clearing of the SDV
not drained annunciator or SDV level information in the relay room is more
easily used by the operator.
CR-8
Closing the charging water isolation valve can be performed in parallel with
bypassing the RSCS ifpersonnel are available in order to reduce the time
necessary
to manually drive rods.
EO-100-114 RPV Flooding
RF-2
This step refers to the Primary Containment Water Level Limit using the word
"below." Due to the shape of the curve "below," can have multiple meanings.
ES-150-002 Boron Injection Using the RCIC System
Item 1.
To perform this procedure,
the nonlicensed operator has to go to the control
room to get the procedure and key for the local tool and equipment box.
This
adds unnecessary
time to accomplish the task.
Item 2.
There is a second lock on the Unit 1 two foot pipe extension which uses a
different key than the one on the local tool and equipment box.
This adds
unnecessary
equipment, confusion and time in performance of the task.
Item 3.
The hose clamps in the equipment box require two persons to install due to the
snug fitof the clamps.
Slightly larger clamps would permit the job to be
performed by one individual, allowing the other individual to do other
activities.
Item 4.
Access to install the 2 foot section of 1 inch pipe into the pipe elbow
downstream of SLC drain valve and to connect the noncollapsible hose is
limited, but sufficient.
The current design modification requested by
Attachment 2
14
operations to extend the drain line to the walkway would reduce the time to
connect the noncollapsible hose.
4.2.1.e
The procedure does not provide guidance on how to unreel and secure the hose
to have the appropriate length lowered to elevation 64S'nd have enough left
over on elevation 749'.
4.2.2
A precaution reminding the operator to take a wrench and equipment needed to
be installed when going to the 64S'levation could avoid the delay which
would ensue ifthe operator forgets to take the wrench and equipment.
4.3.2
Performing the bypass of RCIC turbine isolations and trip at this time adds
unnecessary
delay in injection.
This task can be performed in parallel with
installing the hose.
ES-173-003 Venting Suppression Chamber Irrespective of Offsite Release Limits
4.2,3.a
This step as written unnecessarily
secures pumps needed for suppression
pool
cooling.
The intent of this step was to perform RHRSW crosstie lineups
insofar as possible, but not to secure pumps, as was implemented.
4.2,3.e
~
~
The step to notify maintenance
to rotate the spectacle flange adds unnecessary
delay to the completion of the task.
The task involves independent individuals
who could perform this activity in parallel with other steps in the procedure.
Consideration should be given to how this step should be accomplished in the
time frame necessary
when maintenance
personnel are on-call and not on shift,
This step refers to OP-118-001 to obtain the instruction to open one valve.
The time necessary
to obtain the procedure and then open the valve adds
unnecessary
time to implement the procedure.
ES-184-001 Bypassing MSIV and CIG Interlocks
Item 1.
The travel sequence for section 4.2 is upper relay room to lower relay room.
The travel sequence for section 4.3 is upper relay room to lower relay room.
Since section 4.3 is always performed when section 4.2 is performed, starting
section 4.3 in the upper relay room unnecessarily
adds travel time to
accomplish the task.
Revising the. steps in section 4.3 to start in the lower
relay room and finish in the upper relay room results in the same end point but
reduced time to perform the tasks,
Attachment 2
15
i
'I
ES-184-.002 Rapid RPV Depressurization or RPV Venting Bypassing MSIV Isolations
Item 1.
The procedure combines rapid RPV depressurization
and RPV venting into one
procedure.
Each of these activities is entered from different EO procedures.
Each activity requires different sections of the procedure.
For one activity,
section 4.1, 4.2, 4.3, and 4.7 may be used; and, for the other activity section,
4.1, 4.2, 4.4, 4.5, 4.6, and 4.8 may be used.
The format of the procedure is
cumbersome
to be used as written.
Item 2.
The procedure indicates that timeliness is critical to the performance of this
procedure.
Timeliness is important in the rapid RPV depressurization
portion,
but less important for the RPV venting.