ML16161A988
| ML16161A988 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/07/1988 |
| From: | Julian C, Lawyer L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16161A987 | List: |
| References | |
| 50-269-88-11, 50-270-88-11, 50-287-88-11, NUDOCS 8807120257 | |
| Download: ML16161A988 (25) | |
See also: IR 05000269/1988011
Text
NUCLEA
EULATRS COMMSO
REGION if
0 VASTTA STREET, N .V
1
TLANTA, GEORGIA 30E23
Licensee:
Duke Power Company
422 South Church Street
Charlotte NC 28242
Docket Nos.:
50-269, 50-270, 50-287
License Nos.:
Facility Name:
Oconee Nuclear Station
Inspection Conducted: April Z2-
May 5, 19,8&.
Inspection Team Leader:
LA3
.
t--
f
A
L. Lawyer
Date Signed
Inspection Team Members: M. Archer
M. .DeGraff
P. Kellogg
G. Bryan
P. Skinner
Approved By:
!
C. A. Julia ,/}Chief
Date Signed
Operations Branch
Division of Reactor Safety
SUMMARY
Scope:
This special, announced inspection was conducted in the area of review
of the adequacy of Emergency Operation Procedures.
Results:
No violations or deviations were identified.
807120:257 880628
ADOCK050006
P DC
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- R. Bugert, Manager Operations Training
- M. Carter, Design Engineer
- D. Deatherage, Operating Engineer
- C. Harlin, Compliance Engineer
- R. Ledford, QA Surveillance Supervisor
- R. Lingle, Operations Engineer
- R. Morgan, Production Engineer
- F. Owens, Shift Supervisor
- M. Patrick, Operations Engineer
- P. Stovall, Lead Simulator Instructor
- R. Swiegart, Superintendent Operations
- M. Tuckman, Station Manager
Other licensee employees contacted included engineers, technicians,
operators and office personnel.
NRR Attendees
- W. Regan, Chief, Human Factors Assessment Branch
- H. Pastis, Project Manager
NRC Resident Inspectors
- P. Skinner, Senior Resident Inspector.
- L. Wert, Resident Inspector
- Attended exit interview on May 5, 1988.
2.
Exit Interview
The inspection scope and findings were summarized on May 5, 1988, with
those persons indicated in paragraph 1.
The
NRC described the areas
inspected and discussed in detail the inspection findings listed below.
Although proprietary material was reviewed during this inspection,
no
proprietary material is contained in this report.
Those items on which
dissenting comments were received from the licensee are identified by a
marginal asterisk in the detailed discussion which follows.
Note: A list of abbreviations used in this report is contained in
Appendix E.
2
Item Number Status
Description/Reference Paragraph
IFI 269,270,287/88-11-01
Open
Resolution of QA review
effectiveness (paragraph 4)
IFI 269,270,287/88-11-02
Open
Resolution of OP references in the EP
(paragraph 5)
IFI 269,270,287/88-11-03
Open
Correction of labeling discrepancies
between EOPs and panel indication as
outlined in Appendix D (paragraph 6)
IFI 269,270,287/88-11-04
Open
Correction of technical discrepancies
contained in the EOPs as outlined in
Appendix B (paragraph 6)
IFI 269,270,287/88-11-05
Open
Correction of human factors discrep
ancies contained in EOPs as outlined
in Appendix C (paragraph 6)
IFI 269,270,287/88-11-06
Open
Review Natural Circulation Cooldown
with vents open (paragraph 6)
IFI 269,270,287/88-11-07
Open
Review simulator
effectiveness
in
training on EOPs (paragraph 7)
IFI 269,270,287/88-11-08
Open
Review writer's guide training to
increase operator awareness of terms
(paragraph 8)
3.
Background Information
Following the TMI accident, the Office of Nuclear Reactor Regulation
developed the "TMI Action Plan" (NUREG-0660 and NUREG-0737) which required
licensees of operating reactors to reanalyze transients and accidents and
to upgrade Emergency Operating Procedures (EOPs) (Item I.C.1).
The plan
also required the NRC staff to develop a long-term plan that integrated
and expanded efforts in the writing, reviewing, and monitoring of plant
procedures (Item I.C.9).
NUREG-0899, "Guidelines for the Preparation of
Emergency Operating Procedures," represents the NRC staff's long-term
program for upgrading EOPs, and describes the use of a "Procedures
Generation Package" to prepare EOPs.
The licensees formed four vendor
type owner groups corresponding to the four major reactor types in the
United States; Westinghouse, General Electric, Babcock & Wilcox, and
Combustion Engineering.
Working with the vendor company and the NRC,
these owner groups developed Generic Technical Guidelines (GTGs) which
are generic procedures that set forth the desired accident mitigation
3
strategy. These GTGs were to be used by the licensee in developing their
PGPs.
Submittal of the PGP was made a requirement by Confirmatory Order
dated July 6, 1984. Generic Letter 82-33,
"Supplement 1 to NUREG-0737
Requirement for Emergency Response Capability," requires each licensee to
submit to the NRC a PGP which includes:
a.
Plant-specific technical guidelines with justification for differ
ences from the GTG
b.
A writer's guide
c.
A description of the program to be used for the validation of EOPs
d.
A description of the training program for the upgraded EOPs.
From this PGP, plant specific EOPs were to have been developed that would
provide the operator with directions to mitigate the consequences of a
broad range of accidents and multiple equipment failures.
Due to various circumstances,
there were long delays in achieving NRC
approval of many of the PGPs.
Nevertheless,
the licensees have all
implemented their EOPs.
To determine the success of the implementation, a
series of NRC inspections are being performed to examine the final product
of the program; the EOPs. The objective is to perform table top reviews,
simulator exercises where possible,
and in-plant walk-throughs of the
EOPs with licensed operators to verify their adequacy.
The
EOPs are
considered to be adequate for use if they can be understood and performed
successfully by the operators and they incorporate the accident mitigation
strategy developed by the appropriate vendor specific owner groups.
This inspection report represents findings, observations, and conclusions
regarding the adequacy of the EOPs.
It
did not,
as a matter of intent,
review whether the EOPs thus prepared conformed to the NRC staff's long
term program for upgrading EOPs and whether those EOPs had been properly
prepared using a PGP.
The success level of licensees in following the
PGP submitted to NRC
is a regulatory issue that will be dealt with on a case-by-case basis.
Although some licensees'
EOPs strayed far from their PGP,
that issue is
of secondary importance to this inspection effort.
The purpose of this
inspection is to verify adequacy of the EOPs for continued safe operation
of the facility.
4.
EOP/GTG Comparison
The NRC reviewed the relationship between the Oconee EOPs and the plant
specific EPGs. The approved Oconee ATOG and the B&W owners' group TBD are
generic technical guidelines that form the basis for the Oconee plant
specific technical guidelines detailed in the EPG document (Figure 1).
An
"EPG
-
TBD Deviations Document"
(2/12/88)
details specific deviations
between the EPG document and the TBD.
4
Figure 1
Development of the Oconee EOPs
Generic Technical
l
Plant Specific
l
Emergency Operating
Guidelines
l
Technical Guidelines I
Procedures
(ATOG +
TBD)
=>
Oconee EPGs
=>
(Deviation Document)
The EPG document serves as the plant specific technical guideline from
which Oconee EOPs and their changes are developed.
The Oconee emergency
procedure (EP/1/A/1800/01)
very closely parallels the EPG document, but,
as appropriate, provides greater operational detail.
The licensee uses
plant specific APs to supplement the EP.
The Oconee EP and APs together
compose the licensee's emergency operating procedures.
The NRC reviewed emergencies and other significant events covered by the
Oconee
and APs.
Taken together the EP and AP procedures cover the
broad range of emergencies and other significant events listed in RG 1.33,
section 6. At Oconee the EP and AP procedures together constitute the
EOPs.
A Quality Assurance department individual was interviewed and selected
records were reviewed to verify that QA had been properly involved in the
initial preparation
of the
and
APs.
audit NP-87-14(ON)
was
conducted on operations activities from 8/24/87 to 9/18/87.
This audit
encompassed the EP and APs. There were no deficiencies noted by that QA
audit.
A review of the EP and APs was conducted by QA during the procedure
preparation phase.
While the purpose of this review was
to verify
adherence to the writer's guide,
findings produced by this review were
minimal and many failures to conform to the writer's guide were missed
(see Appendix C). Three specific examples of this were AP/1/A/1700/7, Loss
of Low Pressure Injection System, AP/1/A/1700/22, Loss of Instrument Air,
and AP/1/A/1700/23, Loss Of 1KI (NNI).
The QA review of these had listed
only a small fraction of the writer's guide deficiencies such as unapproved
abbreviations, incorrect
spelling
and capitalizations
which
were
identified in a spot check
by the
NRC.
A licensee representative
5
committed to review the effectiveness of this QA
review and take
appropriate corrective action.
Resolution of this
issue will
be
identified as IFI 50-269, 270, 287/88-11-01.
No violations or deviations were noted in this area.
5.
Independent technical adequacy review of the EOPs.
- The NRC determined by review of the procedures listed in Appendix A that
generally the vendor recommended step sequence was followed except where
deviations were documented in the EPG-TBD Deviations Document.
Review of
the EOPs established that the ATOG guidance was contained within the EOPs
whenever applicable. The general priority of treatment and order of steps
was maintained in the procedures. However, in order to reduce the bulk of
the EOP,
on occasion the operator was referred to an entire operating
procedure, of which only a small portion was applicable (e.g.,
Appendix
C, item la,
1c1,
1c2,
1d,
etc.).
The licensee should review the OP
references to determine if
the applicable portions of the OPs could be
included as steps within the EP or as a separate enclosure.
Resolution
of this issue will be identified as IFI 50-269,270,287/88-11-02
Placekeeping deficiencies were identified during simulator and control
room walk-throughs of the EOPs and are documented in Appendix C. These
include:
- a.
Portions of the
EP and APs were removed from their binders to
hand to other operations personnel.
This caused several delays in
the completion of procedures. An additional copy of the APs should
be provided in the control room or other steps should be taken to
avoid the need for doing this.
b.
Many operators inappropriately made use of random objects
(fingers,
pencils,
and a stapler) as placekeeping aids.
However,
one
employed an appropriate solution to this problem.
He used yellow
stick-ups to mark
WHEN
statements to remind himself of future
actions. This placekeeping technique worked successfully and should
be encouraged.
The inspectors verified that entry conditions to the procedures were
generally clear.
The
scenarios postulated during
the procedure
walk-throughs resulted in multiple transfers and instances of simultaneous
use of the EOPs; no significant errors were identified.
Cautions and notes were generally clear and properly placed within the
EOPs. The priority of accident mitigation appeared to be maintained in the
Oconee EOPs.
The degree of adherence to the B&W guidance available in the ATOG and the
TBD was found to be appropriate.
The licensee has identified major
deviations as required between the ATOG/TBD and the EPG in the Emergency
Procedure Guidelines Technical Basis Document Deviations Document.
The
6
inspectors were unable to confirm that safety significant deviations were
reported to the NRC due to time constraints.
ONS unique operator action parameter values were established in the ONS
setpoint document and were used in the EOPs except for the infrequent
occasions noted in the appendices.
Control room drawings were inspected to verify that management controls
were effective and that plant changes were reflected in interim and final
drawings in a timely manner.
The inspectors found that the number of
outstanding NSMs requiring drawing changes did not appear to be excessive,
and the number appeared to be decreasing.
There were no violations or deviations noted in this area.
6.
Review of the EOPs by In-Plant and Control Room Walk-throughs
In-plant and control
room walk-throughs of the emergency and abnormal
procedures listed -in
Appendix A were conducted.
Generally,
the
nomenclature appears to be consistent between the instrumentation and
control labeling on the control board and the procedures.
Those few
discrepancies noted are enumerated in Appendix D. The licensee committed
to review these and make changes as appropriate. Resolution of this issue
is identified as IFI 50-269,270,287/88-11-03.
Indicators, annunciators and controls referenced in the EOPs were found to
be available to the operators. There is one set of emergency and abnormal
procedures maintained in the control room at all times for each unit.
These procedures were verified to be of the latest revision and free of
any handwritten changes.
While the result of these walk-throughs was generally positive, a few
discrepancies in the areas of technical adequacy, writer's guide adherence
and human factors were noted.
Technical discrepancies are identified in
Appendix B, while writer's guide and human factors discrepancies are noted
in Appendix C. The licensee has committed to correct the discrepancies
identified in the aforementioned appendices except where specifically
excepted by marginal asterisk.
Appendix B discrepancies will be identi
fied as IFI 50-269,270,287/88-11-04, and Appendix C discrepancies will -be
identified as IFI 50-269,270,287/88-11-05.
In response to Generic Letter 81-21, the licensee committed to perform a
natural circulation cooldown without forming a void in the reactor vessel
head. The licensee's method of accomplishing this is to open the reactor
vessel head vent prior to initiating the cooldown. While this will help to
prevent void formation this will also open the reactor coolant system to
the reactor building. This could result in excessive contamination of the
reactor building and possibly limit access for some time.
7
It
should be noted that at the time Generic Letter 81-21 was issued,
procedures for natural circulation cooldown with upper head voids were not
generally available.
The
NRC staff's technical position on upper head
voiding has changed accordingly. Controlled voiding into the reactor
vessel upper head is
now an acceptable strategy provided that it
can be
done using all safety grade equipment with NRC approved procedures and
licensed operators trained in the use of these procedures.
The licensee
committed to review the use of head vents in light of this position and
request a change to allow cooldown with the head vents closed. Resolution
of this issue will be identified as IFI 50-269,270,287/88-11-06.
Due to time constraints many of the aspects of the validation and
verification program that were applied to the development of the EP and
APs were not inspected in depth.
Some deficiencies are identified in
connection with the licensee's ongoing evaluation of EOPs in paragraph 8.
There were no violations or deviations noted in this area.
7.
Simulator Observations
The
NRC
observed
two different crews performing
the following six
scenarios on the Oconee simulator:
a.
Loss of Electrical Power
b.
Overcooling
c.
Loss of HPI and RCP Seal Failure
d.
Loss of all Feedwater
e.
Steam Line Break with SG Tube Rupture
f.
Small Break LOCA
The procedures provided operators with sufficient guidance to fulfill
their responsibilities and required actions during the emergencies, both
individually and as a team.
The procedures did not cause the operators -to physically interfere with
each other while performing
the
and APs.
However,
the operator
concurrently performing APs and OPs was loaded with tasks.
The procedures did not duplicate operator actions unless required (e.g.,
for independent verification).
When a transition from one
EOP to another EOP or other procedure was.
required,
precautions were taken to ensure that all necessary steps,
prerequisites, initial conditions, etc. were met. Operators were found to
be knowledgeable about where to enter and exit the procedures.
However,
there were a number of problems related to placekeeping in the procedures
(see Appendix C, Writer's Guide and Human Factors discrepancies).
8
Activities that should occur outside the control room were initiated by
the operators and proper confirmation of their completion was given.
These actions were
inspected during
in-plant walk-throughs
of the
procedures.
The EOP lesson plans cover both the technical basis behind the procedures
and their structure and format. The training scenarios provide sufficient
coverage of the EOPs (with the exceptions noted below), including multiple
malfunctions.
In addition, operators were
trained on
significant
revisions of the EOPs prior to their implementation.
The training simulations should duplicate actual plant operations whenever
possible.
The extent of simulation should be such that the operator is
required to take the same action on the simulator to conduct an evolution
as on the reference plant using the same procedure. Three deficiencies in
this aspect of EOP training program were noted:
a.
Operators are encouraged in training not to check the placekeeping
check-off spaces in the EP,
while they are expected to do so in an
actual emergency.
- b.
The PORV operating switch (1RC-66)
in the simulator is not a spring
return to auto switch as it is in the plant.
Because of this, the
simulator does not accurately simulate plant procedures involving
opening the PORV.
c.
The simulator cannot model the use of the diesel air compressor as
an emergency supply of instrument air.
Simulator training in EOP usage should model the reference plant as nearly
as possible. The licensee should review EP and AP simulator training and
retraining, and assure that discrepancies such as these are eliminated.
Resolution of, this item will be identified as IFI 50-269,270,287/88-11-07.
No violations or deviations were noted in this area.
8.
Ongoing Evaluation of the EOPs
Administrative controls were reviewed to determine if
the licensee has
an acceptable program in place for a continuing evaluation of the EOPs.
These were OMP 4-2, The Validation Process; APM Section 4.2, Administra
tive Instructions for Permanent Station Procedures; and procedure MNSA-103,
Workplace
Procedure for Technical Review and Verification of Nuclear
Station Emergency Procedure and Guidelines. While these procedures were
used to verify the EP, only selected APs received full V&V. Since the NRC
did not consider the number of discrepancies listed in Appendices B, C,
and D to be indicative of a serious V&V problem,
no corrective action is
proposed for existing EOP revisions. However, the licensee has committed
to apply V&V to future revisions of the EOP.
9
There were no violations or deviations noted in this area..
9.
EOP User Interviews
Ten interviews were conducted by the NRC inspection team and it
was
determined that the current EOPs satisfy the needs of the operational
personnel.
The operators felt the EOPs were adequate and compatible with
the level of knowledge of the typical operator,
and the operations staff
were confident that the EOPs would function effectively during an actual
event.
One discrepancy that was noted during these interviews was that
confusion appeared to exist among the operators interviewed as to the true
meanings of the terms "available","excessive", "go to",
"refer to" and
"complete".
These inconsistencies indicate a need for further operator
training in the terminology used in the EOPs and/or definitions contained
in the Writer's Guide. The licensee should review this area and provide
retraining as necessary. Resolution of this issue will be identified as
IFI 50-269,270,287/88-11-08.
There were no violations or deviations noted in this area.
APPENDIX A
PROCEDURES REVIEWED
NUMBER
TITLE
EP/1/A/1800/01
EMERGENCY OPERATING PROCEDURE
04/08/88
AP/1/A/1700/01
LOAD REJECTION
04/08/88
AP/1/A/1700/02
EXCESSIVE RCS LEAKAGE
04/08/88
AP/1/A/1700/03
BORON DILUTION
04/08/88
AP/1/A/1700/05
04/08/88
AP/1/A/1700/06
NATURAL DISASTER
04/08/88
AP/1/A/1700/07
LOSS OF LOW PRESSURE INJECTION SYSTEM
AP/1/A/1700/08
LOSS OF CONTROL ROOM
04/07/88
AP/1/A/1700/09
SPENT FUEL DAMAGE
04/07/88
AP/1/A/1700/10
UNCONTROLLABLE FLOODING OF TURBINE BUILDING 04/08/88
AP/1/A/1700/11
LOSS OF POWER
01/29/88
AP/1/A/1700/12
LOOSE PARTS IN REACTOR COOLANT SYSTEM
04/07/88
AP/1/A/1700/13
LOSS OF CONDENSER CIRCULATING WATER INTAKE 04/07/88
CANAL/DAM FAILURE
AP/1/A/1700/14
LOSS OF NORMAL MAKEUP OR LETDOWN
AP/1/A/1700/15
DROPPED CONTROL RODS
AP/1/A/1700/17
LOSS OF CONTAINMENT INTEGRITY
04/13/88
AP/1/A/1700/18
ABNORMAL RELEASE OF RADIOACTIVITY
04/22/88
AP/1/A/1700/19
LOSS OF MAIN FEEDWATER
02/29/88
AP/1/A/1700/20
LOSS OF COMPONENT COOLING
04/12/88
AP/1/A/1700/21
HIGH ACTIVITY IN RC SYSTEM
04/25/88
AP/1/A/1700/22
LOSS OF INSTRUMENT AIR
03/31/88
AP/1/A/1700/23
LOSS OF 1KI (NNI)
04/14/88
AP/1/A/1700/24
LOSS OF LPSW
PROCEDURES REFERRED TO BY EP OR APs THAT WERE REVIEWED (IN FULL OR IN PART)
CP/1&2/2002/05
POST ACCIDENT CAUSTIC INJ INTO LPI
03/14/88
.OP/0/A/1102/22
10/03/85
OP/O/A/1102/23
OPERATION OF CONTAINMENT HYDROGEN RECOMBINER 03/01/87
OP/O/A/1102/25
SHUTDOWN FOLLOWING A FIRE
10/20/87
OP/O/A/1103/05
PRESSURIZER OPERATION
08/16/84
OP/O/A/1106/31
CONTROL OF SECONDARY CONTAMINATION
01/22/87
OP/O/A/1600/11
SSF EMERGENCY OPERATING PROCEDURES
12/10/87
OP/1/A/1102/04
OPERATION AT POWER
02/03/88
OP/1/A/1102/10
CONTROLLING PROCEDURE FOR UNIT SHUTDOWN
11/24/87
OP/1/A/1103/06
RCP OPERATION
04/13/87
OP/1/A/1104/04
LPI SYSTEM
10/21/87
OP/1/A/1106/01
TURBINE GENERATOR
01/18/88
Appendix A
2
PT/1/A/1103/15
REACTIVITY BALANCE
10/09/87
- Procedures are in the review process and have not yet been approved
for use.
-APPENDIX B
TECHNICAL COMMENTS.
This appendix contains technical comments, observations and suggestions for EOP
improvements made by the NRC.
Unless specifically stated, these comments are
not regulatory requirements. However,
the licensee agreed in each case to
evaluate the comment and take appropriate action. These items will be reviewed
during a future NRC inspection as noted in paragraph 6.
1. EP/1/A/1800/01 Section 504,
SG Tube Leak
a. Step 9.1 has the operator open 1RC-159 and 1RC-160, but does not
inform the operator that SKL Breaker 8 in the Cable Room must be
closed to open these valves.
The breaker is normally kept open
during operation. A number of operators were not aware of this. The
need to close the breaker should be noted in the EP or a warning
label placed next to the valve switches on the control panel.
b. Step 11.2 The order of the items is important, but they are not
numbered as required by the writer's guide.
2.
EP/1/A/1800/01 Section CP-603, HPI Cooling Cooldown
a. step 5.0; In order to open either the high point vents or the
reactor head vent the local breaker must be closed and then the
"power on" button must be depressed on the main control board.
This
required action is not addressed in the procedure.
The licensee
should revise the procedure accordingly.
b. step 26; A note should be included in the step to feed only the
unaffected generator unless the affected steam generator is required
for heat transfer.
3.
AP/1/A/1700/03, Boron Dilution
The licensee should consider revising the AP and supporting
OP/1/A/1103/04 to recognize those AP cases and symptoms which are
severe enough to warrant immediate boron injection without waiting
for chemistry sample results. As written, the procedures currently
follow a process of:
AP entry to a particular case,
chemistry
sampling, exit to the OP,
await sample results, determine desired
concentration, compute, lineup, and then add boron.
An example of a case that warrants immediate boron injection is AP
case D. With the reactor critical at power and control rod insertion
to a position to the left of the safety limit curve,
the procedure
Appendix B
2
should add boron immediately. When rod position has been restored to
at least the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO region, a final predetermined addition can be
made in the normal manner.
The
NRC concluded that immediate boration was applicable in other
cases such as AP case A,B and C.
4.
AP/1/A/1700/13,
Loss of Condenser Circulating Water Intake
Canal/Dam Failure.
a. Pg. 3, step 5.4;
This step waits until secondary heat removal
systems are "exhausted" before sending personnel to the SSF.
The procedure should be revised to man the SSF prior to exhaustion.
b. Pg 7, step 4.4; The licensee should consider adding a note
following 4.4 explaining that if all four CCW pumps were running,
CCW 10-13 would be open. To reestablish pump flow, an NLO must
close one discharge valve prior to start of that pump in step 4.5.
5.
OP/1/A/1103/06, Reactor Coolant Pump Operation
Enclosure 4.3, section 2.5; This section requires "start RCPs using
enclosure 4.1." If
enclosure 4.1 was used in strict conformance to
this step, i.e. establish the seal injection prior to the start of
the pump, the intent of this section would not be met. The intent is
to start the pump without seal injection and gradually bring seal
injection into operation.
Appendix C.
WRITER'S GUIDE AND HUMAN FACTORS DISCREPANCIES
This appendix contains comments, observations and suggestions for EOP improve
ments made by the
NRC.
Unless specifically stated,
these comments are not
regulatory requirements.
However, the licensee agreed in each
case to
evaluate the comment and take appropriate action. These items will be reviewed
during a future NRC inspection as noted in paragraph 6.
1. EP/1/A/1800/01, Emergency Operating Procedure
a.
Section
502,
Loss
of
Heat Transfer;
The
reference to
OP/O/A/1102/25, Shutdown Following a Fire, for operation of the
atmospheric dump valves is inappropriate. The EP should specify
which section of the enclosure to use or the specific steps
should be put into the EP from the OP.
b.
Section 503,
Excessive Heat Transfer; Step 2 refers to a SG
level of greater then 92%. The
EPG references a 95% setpoint
for this condition.
The licensee should resolve this conflict
to reflect the actual plant value.
c.
Section 504, SG Tube Leak
(1) Step 5.0 refers the operator to OP/1/A/1102/4,
OPERATION
AT
POWER,
but does not specify a step number.
The only
applicable step is 3.4. This should be referenced in the
EP.
(2) Step
6.1
refers
the
operator
to
OP/1/A/1102/10,
CONTROLLING
PROCEDURE
FOR
UNIT
SHUTDOWN,
but does
not
specify a step number.
The only applicable step is 3.2
(Turbine Generator Shutdown).
This step number should be
referenced in the EP.
(3) Steps 11.0 and 26 contain a list of valves to be closed to
isolate the SG. There is no action statement to inform the
operator that he should close the valves. This step should
be rewritten to conform with the writer's guide.
(4) Page 83.
In the Unit Status Summary "using on
SG with
forced circulation" appears to be a typographical error.
d.
Section 507, Inadequate Core Cooling; In step 14 the intentions
are to start a Reactor Coolant Pump.
The caution and first
bullet reference support systems and the operating procedure.
The initial conditions of the operating
procedure
may
be
contradictory to the current plant condition at the time this
step is
being
implemented
and could
be confusing
to the
operator. This step should be modified to clearly state which
section of the OP would be applicable.
Appendix C
2
e.
Section CP-601, Cooldown Following a Large LOCA
(1) Step
2.4.2;
This
step
refers
the
operator
to
OP/0/A/1102/25,
Shutdown
Following a Fire,
to provide
direction on the use of the atmospheric dump valves. From a
review of this procedure it
appears that only one step in
this OP is applicable to the operation of the atmospheric
dump valves. The licensee should revise the EP to include
the applicable information from the OP.
(2) Step 8.1; This step requires the operator to verify RB
isolation but the step provides no guidance on which valves
need to verified closed nor does the step address any
specific valve line-ups. The licensee should provide
additional guidance denoting valves which
need to
be
verified.
(3) Step 8.1; This step is lacking in two other respects.
Step 12 of the same procedure requires,. when initiating
make-up
to the
BWST,
that the boron concentration be
greater than T.S. values. Additionally, step 12 references
OP/1/A/1104/04, Low Pressure Injection System for the
correct make-up
procedure
given
the
current
plant
configuration. Step 8.1 contains neither the concentration
requirement nor the reference.
The licensee should revise
step 8.1 to be consistent with other steps completing the
same action.
(4) Step 9.0; Within this step there are two separate actions.
The first action requires chemistry to sample the RB
emergency sump for boron concentration.
The second action
(if
necessary)
requires operations to isolate possible
sources of sump dilution. The licensee should revise the
procedure to separately state these group responsibilities.
f. Section CP-602, SG Cooldown With Saturated RCS
(1) Step
17 includes a list of valves to close.
One line
lists the RCP seal return valves, the next states "(If RCPs
NOT operating)," and the following line lists the Quench
Tank Vents. This use of a conditional is unclear, and not
in accordance with the Writer's Guide. This step should be
rewritten to clarify the meaning of the conditional
and
conform to the writer's guide.
(2) Step
39; This step includes a list of "bullets"
for
alternative methods to be used to reduce
RCS pressure.
This list is intended to provide alternative actions to be
taken in order of preference, not an indication that the
operator should
always perform all the actions (the
Appendix C
3
meaning of bullets is described in the writer's guide).
This step should be rewritten to clarify the meaning of
these bullets and to conform to the writer's guide.
g.
Section CP-603, HPI Cooling Cooldown
(1) Step 2.0 requires that when subcooling margin is greater
than
50 degrees F and CETCs are decreasing,
RCS P/T be
maintained in the proper region of enclosure 7.1.
To be
consistent with other steps referencing the same action the
licensee should include a statement to throttle HPI.
(2) Step 16; Same comment as CP-601, step 9, above.
h.
Section CP-604, Solid Plant Cooldown
(1) Step 4.0;
To
be
consistent with other
steps which
reference maintaining RCS P/T within the proper region of
enclosure 7.1, the licensee should include a statement to
throttle HPI when subcooling margin is greater than 50
degrees F.
(2) Step 11; Under verify RB isolation the phrase "if RCPs are
not operating" appears. It is unclear
as
to
the
applicability of this statement. The licensee should revise
the procedure to clearly identify which valves need to be
verified closed if the RCPs are not operating.
2. AP/1/A/1700/01, Load Rejection
a.
Step 3.0;
Main steam relief valve position indication is not
available in the control room. The procedure should be revised
to indicate that confirmation of valve position is required from
external observation.
b.
Step 5.3;
396" is near the upper range limit of the instrument
(400")
and is too precise to be read from the installed meter.
If this value is correct (see comment below) and the precision
is required, the step should be revised to direct the operator
to verify level from a computer point.
c.
Step 5.3;
Change 396" to be consistent with other documents.
This
step
reacts
to pressurizer solid conditions.
Both
EP/1/A/1800/01
(step
5.17.4)
and the
EPG Setpoint
Document
(pg.9)
use 375" as the licensee's definition of pressurizer
solid.
396" does not appear in the setpoint document.
Appendix C
4
3. AP/1/A/1700/02, Excessive RCS Leakage
Step 5.6.1; This step refers to any subcooling margin " less than or
equal to zero."
To be consistent with other steps the reference to
subcooling margin should be changed to " equals zero."
4. AP/1/A/1700/03, Boron Dilution
Step 5.1 of Case A, B, C, & D; In this step, the reader is directed
to "Refer to the Emergency Plan."
Where appearing, this should be
changed to "Refer to AP/O/B/1000/01, Classification of Emergencies."
The decision to implement the EP plan is made from that procedure.
5. AP/1/A/1700/07, Loss of Low Pressure Injection
a.
Steps 5.2, 5.5 and 5.5.4 case B; All these steps address
make-up to the RCS; however, they are not consistent with each
other. The licensee should revise these steps such that make-up
to the RCS is done the same way each time.
b.
Step 5.5.4.2; There is a typographical error. The licensee
needs to change "fo" to "to".
6.
AP/1/A/1700/08,
Loss of Control Room
Case A; In Step 4.8, an operator is sent to the Unit 1 and 2 WDP with
directions to establish communications with the Auxiliary Shutdown
Panel as soon as possible. Although there is a telephone at the WDP,
no phone number is listed in the procedure,
posted by the telephone
or otherwise quickly available to allow the operator to establish
this communication.
7. AP/1/A/1700/11, Loss of Power
a.
Step 6.1, THEN statement. Add a reference to OP/1/A/1104/12.
b.
Step 11.0.
Add "Verify" to the last 4 bullets of the IF
statement.
c.
Step 4.2;
Position a copy of OP/O/A/1106/27 at the diesel air
compressor. Currently,
an in plant NLO tasked to start the
compressor must go to the Control
Room for a copy of the OP,
then to the diesel compressor.
On a loss of instrument air,
time is too precious to accept the lost time involved in pulling
a copy of the procedure from the control room before proceeding
to the diesel.
d.
Step 5.3.1;
Valve label plate is missing on 1CCW- 79 and
should be replaced.
Appendix C
5
e.
Enclosure 6.2, step 1.0;
This step involves high voltage
hazards and should be done by experienced I&E personnel.
At
present there is no procedural requirement for I&E staffing on
back shifts.
The licensee should consider establishing a
minimum I&E manning level in plant procedures.
f.
Step 8.0;
1HP-26 is an infrequently operated valve. The
procedure should be revised to include the physical location of
the valve.
g.
Step 3.0;
Provide a racking tool at or near the auxiliary
service water switchgear.
h.
Step 3.6;
ASW 600V Load Center label plate is missing and
should be replaced.
8. AP/1/A/1700/13, Loss of Condenser Circulating Water Intake Canal/Dam
Failure
a.
Case A & B, Step 2.0;
The same parameter value should apply in
both lake level bullets (now shown as -775' and decreasing less
than 775' respectively).
b.
Case B, Step 4.1.1.
Delete the last bullet. "Continue
concurrently with ...
" is redundant to "REFER TO."
c.
Case B, Step 4.3; The procedure should be revised to direct the
operator to obtain 1CCW-20 through 25 valve positions from the
control room computer point readout or by local verification.
d.
Case B, Step 4.6;
The last bullet states security will
energize the lock. Operators indicate that normal practice is
to send a guard directly to the gate and that some problems have
arisen when
guards did not know-where
to go.
Additional
training and possible procedure changes should be considered.
e.
Enclosure 6.1, Step 1.0;
Install a chain on LPSW-139 or
provide a nearby ladder.
The nearest ladder is -150'
away
through a dimly lighted area,
an area which may be flooded if
this procedure is operative.
f.
Enclosure 6.1, Pg 12;
After step 4.0, direct the reader back
to pg. 9 to continue with step 5.6.2 of Case B.
9. AP/1/A/1700/23 -
Loss of IKI Bus (NNI)
Step 5.7 instructs an operator to proceed to the equipment room to
bypass the 1KI inverter by changing switch positions. These switches
are located above the KI panel so that a ladder would be required to
safely operate these switches.
A ladder should be
staged in the
room.
Appendix C
6
10. AP/1/A/1700/20, Loss of Component Cooling
Step 4.4 requires that all heat exchangers be checked for temperature
increase. The licensee should revise this step to include the maximum
values to assist the operators in determining when a limit is being
approached.
11. AP/1/A/1700/22, Loss of Instrument Air
a.
Section 2.0, symptoms; The statalarm location, (2SA-4 D-5)
should be (2SA-4 C-5). Typographical error.
b.
Step 5.3.1; The second bullet requires the operator to remain
in the
area
of
1CC-8. Radiation
levels
need
further
consideration. The present stationing of an operator in this
area would be unacceptable under certain accident conditions.
The licensee should revise the procedure to include a caution
statement as to the presence of high radiation levels under
certain accident conditions when manual operation of 1CC-8 is
required.
c.
Step 5.5; The labels attached to 1FDW-315 and 1FDW-316 are
color coded incorrectly, i.e. red versus black.
12.
OP/1/A/1103/06, Reactor Coolant Pump Operation
a.
Step 2.7; Several sub steps reference seal leakage flow rates
of 8.5 gpm or greater. The maximum flow rate that can be read on
the instrumentation provided to the operators is read on a chart
recorder that can only read a maximum of 6 gpm.
b.
Step 2.7.5; Where the term " seal return valve " is used, the
actual valve designators should be used.
c.
Enclosure 4.1, step 2.1; A tolerance should be provided to the
operator to provide practical adjustment of the flow to an RCP.
d.
Enclosure 4.1, step 2.4; Locations should be provided for
1HP-277 and gage 1PG-102. In addition, labels should be attached
to the gage.
e.
Enclosure 4.3, section 2.2; This section requires the operator
to slowly reestablish component cooling flow to all reactor
coolant pump thermal barriers. This section should be clarified
to provide details on how this action is to be accomplished.
APPENDIX D
NOMENCLATURE DISCREPANCIES IDENTIFIED
BY
NRC EOP INSPECTION TEAM
Step/
Procedure
Page
Procedure Nomenclature
Label on Equipment
EP/1/A/1800/01
3.0
SU Block Vlv
SU FDW Block Vlv
SU Control Vlv
SU FDW Control Vlv
MS to SSRH
MS to 2A1 & 2B2
TD EFDWP Disch Vlv
To 2A/2B OTSG Blk
6.1
1 HP-25
Suction)
6.1
1 HP-27
7.3.1
Reference to SG
OTSG on Board
Section 504
3.3.1
'lB' HPI BWST Suction
No Name on Label
3.3.3
'lB' HP Injection
No Name on Label
8.1
Subcooling Margin
Saturation Margin
11&26.0
Main FDW Control Vlv
Main FDW Control
SU Control Vlv
Startup FDW Ctl
MD EFDWP Disch Vlv
No Name on Label
TD EFDWP Disch Vlv
TDEFDWP Disch to
1A(1B) OTS 6 Blk
13.7.3
Emerg HP Inj Flow
19.2.1
"High"
HI
19.2.2
"OFF"
Stop
27.7.7
RBNS Isol
28
SG Secondary Pressure
Main Steam Prss.
Section 505
1.1
Emerg HP Inj'Flow
Appendix D
2
2.2
DH Removal Flow
2.3
LPSW Flow
LPSW to Decay Hx
3.1
LPSW Flow
Reactor Bld, Vent
4.0
RB Spray Flow
RBS Flow
Section 602
1
Emerg HPI Ind Flow
36
DH Removal Flow
OP/O/A/1600/11 2.3
Diesel Engine Service
Diesel Engine
Water Flow
Service Pump
Discharge Flow
2.13
PORV Block Vlv
PORV Block
2.13
Pzr Water Space Sample
Pzr Water Sample
2.13
RC Pumps Seal Return
RCP Seal Return
2.21
TH-103 (SSF ASW Suction
No Label on
Temperature)
Component
2.21
No Descriptive
Label
AP/1/A/1700/01
1/3.0
Turbine Master
Turbine Header
Pressure
AP/1/A/1700/02 5.5
Pilot Valve)
AP/1/A/1700/03 4/5.6.1
Channel 6 Label
Supply)
Plate Missing
AP/1/A/1700/05 5.5
Red Phone Notification
No Procedure So
Procedure
Designated
AP/1/A/1700/11
4/2.0
...
channel A &
Bus 1 and Bus 2
channel B ...
7/4.1
SLI LEE STBY BUS
Transformer CT5
1 FDR
Bus No. 1
7/4.1
SL2 LEE STBY BUS
Transformer CT5
2 FDR
Bus No. 2
7/4.2
SK1 KEOWEE STBY
Transformer CT4
BUS 1 FOR
STBY BUS No. 1
Appendix D
3
7/4.2
SK2 KEOWEE STBY
Transformer CT4
BUS 2 FDR
BUS No. 2
8/5.2
SL1 LEE STBY BUS
Transformer CT5
1 FDR
STBY Bus 1.
8/5.2
SL2 LEE STBY BUS
Transformer CT5
2 FDR
Bus 2.
8/5.3
LEE BUS BKR
CT5 Bus 1 Auto/
Xfer SWs
Manual; ...
Bus 2
8/5.3
SL1 ....
(w/o SL1)
8/5.3
SL2 ....
(w/o SL2)
11/4.2
RCP Seal Injection Flow
Seal Inlet Header
14/7.3
(HWPs ....
)
Hotwell Pump
14/7.4
Cond Booster Pump
14/7.6
CSAE
Eject A (or B or C)
14/8.1.4
CC Total Flow
Comp Cool Header
Flow
29/3.6
SF Priming Pump
Ul & U2 Emerg.
Cooling Water
Priming Pump
AP/1/A/1700/13
1/2.0
Lake Level
Forebay Level (w
700' Correction)
3/5.2
1LPSW-138 (TD EFDWP
1LPSW-138 & 184 to
Cooling Bypass Valve)
EFWP Pump Cooling
Bypass
3/5.3.1
ESWT
Storage Tank Level
11/1.0
2CCW-70 Service
Unit 3 .....
)
Water Return to
Unit 3 .....
11/1.0
2CCW-71 Service
to .....
Water .....
11/2.0
1LPSW-19 (lB RBCU
1LPSW-19 lB RBCU &
Inlet)
Aux Fan CLR Inlet
Appendix D
4
11/2.0
2LPSW-19 (2B RBCU
2LPSW-19 2B RBCU &
inlet)
Aux Fan CLR Inlet
AP/1/A/1700/20
5.2
CC Surge Tank
Comp. Cool. Surge
Tank Level
AP/1/A/1700/24 --
LPSW Pump Discharge
LPSW Serv H20 Hdr
Note:
1. Specific discrepancies between procedure and equipment nomenclature
may occur more than once in the same procedure. To avoid repetition,
they are only identified once.
2.
This appendix lists identified nomenclature differences between
procedures and installed equipment.
Nomenclature requirements for
the EP and APs are stated in the writer's guide; for OPs they are
stated in APM section 4.2.3.4.
APPENDIX E
LIST OF ABBREVIATIONS
Abnormal Procedure
ASW
Auxiliary Service Water
ATOG
Abnormal Transient Operating Guidelines
Babcock & Wilcox
BWST
Borated Water Storage Tank
Condenser Circulating Water
Emergency Operating Procedure
Emergency Operating Procedure
Emergency Procedure Guidelines
GTG
Generic Technical Guidelines
High Pressure Injection
I&E
Instrument & Electrical
LCO
Limiting Condition of Operation
Loss of Coolant Accident
Non-licensed Operator
NRC
Nuclear Regulatory Commission
NSM
Nuclear Station Modification
Owners Group
Oconee Nuclear Station
OP
Operating Procedure
Procedure Generation Package
Power Operated Relief Valve
P/T
Pressure/Temperature
Quality Assurance
Reactor Building
Reactor Coolant Pump
Regulatory Guideline
Senior Reactor Operator
Shift Supervisor
SSF
Safe Shutdown Facility
Technical Basis Document
Three Mile Island
Validation and Verification
WDP
Waste Disposal Panel