ML14176A799
| ML14176A799 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 11/01/1989 |
| From: | Lawyer L, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14176A798 | List: |
| References | |
| 50-261-89-16, NUDOCS 8911200146 | |
| Download: ML14176A799 (72) | |
See also: IR 05000261/1989016
Text
pg REG~
UNITED STATES
o 0
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/89-16
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242
Docket No.: 50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Cond *ted: Septe
r 18 o 29, 1989.
Inspectors:
L. LawD r, Tam
nered
Team Members:
G. Bryan, Jr.
G. Galletti
L. Garner
G.. Salyers
R. Schin
A. Sutthoff
Approved By:
T. A. Peebles, Chief
Date Signed
Operations Branch
Division of Reactor Safety
SUMMARY
Scope:
This was a special announced Emergency Operating Procedure (EOP) team inspection.
Its purpose was to verify that the Robinson 2 EOPs were technically accurate,
and that their specified actions could be accomplished using existing equipment,
controls, and instrumentation.
The inspection. evaluated the adequacy of the
licensee's EOPs [including Abnormal Operating Procedures (AOPs)],
conformance
of these procedures
to the Westinghouse Owners'
Group Emergency Response
Guidelines
(ERGs),
and conformance to the approved writer's guide.
The
inspection included a.comparison of the EOPs to Westinghouse generic technical
guidelines, a technical adequacy review of the procedures, control room and in
plant walkthroughs, simulator evaluation of selected procedures, a review of
on-going control of these procedures, and interviews of operators who use the
procedures.
8911 200)1 46. 89110(:7
PDR, ADOCK
05C)C002
6 1
2
Results:
The overall assessment concluded that the EOPs adequately covered the broad range
of accidents ahd equipment failures necessary-for safe shutdown of the plant.
The team identified weaknesses in availability of equipment, paragraph 4; plant
design,
paragraph 4; level of detail in procedures,
paragraph 4; technical
documentation, paragraphs 2 and
4; conformance with the. writervs guide,
paragraphs 2, 3. and 4; and management control of the EOP program, paragraph 6.
The team reviewed the draft Safety Evaluation Report (SER)
on the licensee's
Procedures Generation Package (PGP)
commitments and determined that, when the
Inspector Followup Items (IFIs)
in this report are completed, all licensee
actions necessary in response to the SER will be completed.
Violations or
deviations were not identified in this report.
REPORT DETAILS
1. Persons contacted
Licensee employees
S. Allen, Manaqer-
License Training
J. Barry, Reactor Operator
- C. Baucom, Senior Specialist -
Regulatory Compliance
- D. Beith, Human Factors Specialist -
Human Factors Interfaces
- C. Bethea, Manager -
Training
D. Blakeney, Senior Engineer -
J. Boyd, Senior Specialist -
Simulator Support
T. Byron, Senior Specialist -
License Training
H. Carter, Senior Specialist -
License Training
D. Cook, Auxiliary Operator
J. Curley, Manager -
Environmental and Radiation Control
W. Cutright, Reactor Operator
- C. Dietz, Manager - Robinson Nuclear Project Department
W. Flanagan, Manager - Outage Modifications
S.-Griggs, Technical Aide -
Regulatory Compliance
J. Harding, Senior Control Operator
- E. Harris, Jr., Manager -
Onsi-te Nuclear Safety
T. Hodges, Administration
R. Ivey, Auxiliary Operator
- J. Kloosterman, Director -
Regulatory Compliance.
D. LaBelle, Project Engineer - Onsite Nuclear Safety
F. Legette, Senior Control Operator
B. McFeaters, Project Specialist - Corp. Emergency Planning
R. Moore, Shift Foreman
- R. Morgan, Plant General Manager
D. Neal, Senior Specialist -
License Training
- D. Quick, Manager -
Plant Support
D. Seagle, Shift Foreman
- J.
Sheppard, Manager -
Operations
- E. Shoemaker, Project Engineer - Operations
V. Smith, Senior Specialist -
License Training
- D. Stadler, Onsite Licensing-Engineer
R. Stebbins, Senior Specialist -
License Training
B. Stover, Senior Control Operator
T. White, Reactor Operator
- L. Williams, Supervisor - Emergency Planning & Security
- H. Young, Manager - Quality Assurance and Quality Control
Other licensee employees contacted included engineers,
technicians,
operators and office personnel.
0II
2
NRC Personnel
- R. Lo, Project Manager -
Robinson, NRR
.*W.
Regan, Chief
Human Factors Assessment Branch, NRR
NRC Resident Inspectors
K. Jury
- Attended exit interview-on September 29, 1989.
Procedures reviewed during this inspection are listed in Appendix A.
A list of abbreviations used in this report is contained in Appendix E.
2.
EOP/GTG Comparison
The team reviewed the development of the Robinson emergency operating
procedures (EOPs) as the basis for evaluating the relationship of the
EOPs to the plant specific technical guidelines (PSTG).
The Robinson Operations Department developed Revision 0 of the
Robinson EOPs directly from the emergency response guidelines (ERGs).
The EOPs were produced by application of the principles in the Robinson
writer's guide to the technical information in the ERG,
the Robinson
setpoint document
and other sources.
The licensee submitted an
Procedure Generation Package.(PGP), including a writer's guide, to the NRC
for review and approval in 1984.
The licensee conducted simulator validation of the EOPs on-the Shearon
Harris simulator in June 1983. Procedures that could not be validated on
the simulator were validated by control room walkthroughs during.July and
August of 1984.
No other plant walkthroughs were conducted as part of
the
EOP validation.
.The
licensee revalidated a limited number of the
EOPs on the Robinson plant specific simulator in 1987. Therefore,
not
all of the Robinson
had been validated on the plant specific
simulator.'
Robinson licensed operators conducted verification of the
EOPs in July 1984 through tabletop reviews.
The licensee conducted a
final technical
review of the
in August 1984.
The licensee
implemented Revision 0 of the EOPs on November 17, 1984.
In early 1985 the CP&L nuclear safety review group conducted a technical
review of the EOPs. Their major finding was the lack of a plant specific
technical document. Robinson QA conducted a review of the EOP program in
January of 1987 and issued a report in March 1987 with the major concern
that the transition documentation was incomplete.
In March 1988,
the
licensee issued an Emergency Operating Procedures Transition Document
(TD).
The purpose of the TD was to compare the Robinson plant to the
Westinghouse Owners Group -
Low Pressure Emergency Response Guidelines
(WOG-LP
ERG)
reference plant, document a step by step comparison of the
and the EOPs and justify step deviations between them,
and to
justify setpoints used in the EOPs.
3
The EOPs were developed without the use of an adequate PSTG in that the
TD was incomplete, and were revised over a period of more than three years
under the same conditions.
The team compared the EOPs to the Robinson TD and found that the TD was
not up-to-date. As a result, they found numerous deviations between the
current revision of the EOPs and -the EOP -supporting documentation in the
TD. The Team identified these deviations from the TD by the designation
"PSTG DEV" in appendix B.
In addition,
the TD was, incomplete.
The setpoint document was not
maintained to reflect procedure revisions including setpoint additions.
Although a number of setpoints referenced other sources for supporting
calculations, finding the appropriate documentation was often difficult.
The licensee could not trace at least one setpoint to the calculations
which established it. The team has addressed incomplete TO documentation
more fully in other sections of this report.
The team met with the licensee to discuss the development and
implementation of the as found PSTG. The licensee described this PSTG as
"the Robinson
PSTG consisted of the
.11 volume
TD plus Revision. 1A
WOG ERG-LP."
The licensee indicated that in this form,
the PSTG had
been difficult to maintain current and difficult to
use for the
development of the EOPs.
The inspection team indicated to the licensee
that a PSTG was required which could be maintained and used effectively
for the development and revision of the EOPs. The licensee committed to
develop a new
PSTG,
including an improved setpoint document and step
deviation document. The detailed description of this PSTG and schedule
for its development are to be addressed by the licensee in their response
to this inspection report.
Resolution of this issue was identified as
IFI 50-261/89-16-01.
The team compared the Robinson
EOPs to the ERGs and in general found
close agreement.
The
accident mitigation sequence. of the ERG was
generally followed in the EOPs and the EOPs were, adequate to cover the
broad range of accidents and equipment failures addressed in the ERG.
The team reviewed the role of the Robinson Quality Assurance Department
(QA)
in the development of the PSTG and upgraded EOPs.
Robinson QA
conducted technical comparisons of the EOPs against the ERGs in
November 1984. The documentation describing these reviews consisted of
approximately 19 pages; 5 pages bear no comments and the remaining pages
contained a limited description of the procedures reviewed
and
no
description of the review process.
The few issues raised in the reviews
were resolved prior to EOP implementation.
The team concluded that the
level of QA involvement in EOP development prior to implementation was
not adequate. However, the team found that other management controls, as
discussed above; were applied subsequent to implementation in lieu of a
more aggressive QA involvement.
4
Review of the
EOPs against the requirements of the writer' s guide
identified a number
of deviations.
These
deviations
suggested
inadequate verification of the procedures against the writer's guide.
The team found that. the format and wording of the abnormal operating
procedures (AOPs)
were substantially different from the other EOPs.
The
writer's guide. had not been applied to. the Robinson AOPs,
and this had
created for the operator a discontinuous and potentially confusing
interface with the EOPs. The AOPs and EOPs used different formats (one
column vs two column), different.action verbs, and different transition.
methods. In one example, if operators tranitioned from the A0P for loss
of CCW to the EOP for reactor trip by using an EOP method of transition,
they would not have continued concurrently with the AOP. This could have
resulted in immediate damage to all RCPs and CCW pumps. The licensee has
committed to developan AOP writer's guide. Resolution of this issue was
identified as IFI 50-261/89-16-02.
There were no violations or deviations noted in this area.
3.
Independent technical adequacy review of the EOPs
The team reviewed the procedures listed in Appendix A and found that
generally the vendor recommended accident mitigation strategy and action
sequence was followed.
The main entry into the
EOP network was via
Path-1 on a reactor trip or safety injection.
The only other EOPs that
were entered directly were EPP-1,
Loss of all AC power; EPP-5,
Natural
circulation cooldown;
EPP-21,
Energizing pressurizer heaters
from
emergency busses; and the AOPs.
The EOP procedure entry and transition
conditions closely followed the ERG.
Cautions and notes were often incorrect in application of the writer's
guide.
For example, cautions and notes were often found lacking
identification of the potential hazard to equipment or personnel as
required by the writer's' guide.
Both notes and cautions were written
containing action steps or conditional steps, which is also contrary to
the writer's guide.
Specific examples are delineated in Appendices B
and C.
Place keeping aids, such as pencil check marks or page markers, were not
addressed in the writer's guide and were not used during implementation
of the EOPs, with .the exception of the grease pencils used to traverse
the path procedures. Since most EOP steps were initiated without regard
to completion of prior steps and there were many transitions between
procedures, place keeping aids were important for keeping track of action
steps that had been initiated and steps that had been completed. Because
of the increased chance of operator error while transitioning within or
between procedures, there was a need for clearly established place keeping.
5
The EOP. procedures did not adequately reference nomographs, graphs, or
additional procedures required to carry out steps. This lack of adequate
reference
required the
operators to memorize
reference material
identifications or scan through manuals for the required information.
The quality of several operator. aids was
poor for determining the
information required to carry out specified actions.
For example, many
of the operator aids in the curve book. were not maintained to original
quality standards. Reproductions had lost their clarity due to excessive
photocopying.
The team also observed examples of poor contrast between
coordinate. values and background, and inappropriate scale to present the
full range of needed information.
The team inspected selected control room drawings to verify that EOP
specified components were accurately presented.
No discrepancies were
noted.
Operator action- setpoint values and justifications were contained in the
EOP/ERG setpoint study of the TO.
The team reviewed samples of these
values and found them to be adequately documented and justified, except
as listed in Appendix B.
The team found the degree of EOP adherence to the ERG to be generally
acceptable.
However,
the
TO was
not current and there were
many
differences between it
and the EOPs.
This was primarily due to the
licensee having made updates to the EOPs to reflect revision 1A to the ERG.
The licensee completed these EOP updates in early 1989 without updating
the TD. The existing, out of date,
TO could not perform its required
function of providing a basis for subsequent EOP revisions. The TO also
failed to provide adequate justification for many
EOP step deviations
from the ERG.
There were no violations or deviations noted in this area.
4. Review of the EOPs by inplant and control room walkthroughs
The NRC found the relationship of procedure nomenclature to the equipment
labeling to be difficult to compare because the procedures did not
reference exact equipment labels in most cases.
Because a precisely
defined method of referencing equipment nomenclature was not addressed in
the supporting EOP development documentation, the references to equipment
and controls used in the EOP procedures was not consistent. In addition,
steps requiri.ng lccal actions did not consistently reference equipment or
.,controller labels. The team conducted inplant and control room walkthroughs
of the emergency and abnormal procedures listed in Appendix A.
Where
required by the writer's guide, the EOP nomenclature appeared to be
generally consistent with installed equipment. The team enumerated noted
discrepancies in.
Appendix D. The licensee committed to review these and
make changes as appropriate. Resolution of this issue was identified as
IFI 50-261/89-16-03.
6
Indications, annunciators and controls referenced in the EOPs were found
to be available to the operators except as noted in Appendix B. Two sets
of emergency and abnormal procedures were maintained in the Control
Room
at. all times. These procedures were the latest revision.
While the results of the walkthroughs were generally acceptable, many
discrepancies in- the areas of technical adequacy, writer's guide
adherence,
and human factors were noted.
Technical and human factors
discrepancies are noted in Appendix B while writer's guide discrepancies
are noted in Appendix C. Appendix B.and C discrepancies were identified
as IFIs 50-261/89-16-04 and 05 respectively.
Important items noted by
the team during the walkthroughs included:
The availability and prestaging of needed equipment was weak
for some required actions; Appendix B, paragraphs VI.14.h & k
and III.1.n.
-P
Two procedural weaknesses in assuring compliance with technical
specifications were noted; Appendix B, paragraphs VI.27.d and
III.6.a.
o
Design weaknesses that inhibited the operator's ability to respond to
flooding in the service water pump pit and flooding in the
residual. heat removal pump pit were noted; Appendix B,
paragraphs VI.22.e and III-.9.1.
o
The level df detail in the EOPs was inadequate in some cases;
Appendix B, numerous examples.
Some plant modifications that impacted the usability of the
EOPs did not result in a proper EOP revision; Appendix B,
paragraphs VI.27.a & c, IJI.21.s, VII.2.b, and IV.4.c.
The HBR verification and validation program established in paragraph 5.6
of OMM-013, the writer's guide, did not apply to the AOPs or the alarm
response procedures but was limited to the PATHs,
EPPs,
V&V was required for all EOP revisions.
V&V did not require in plant
procedure walkdown. Either -one SRO or two ROs were required for the
verification process; for control room walkthrough validation, a minimum
of one shift licensed operator was required.
Of the two validation
options,
control
room and simulator,
the latter was defined as the
preferred method.
The NRC evaluated the V&V program requirements and sampled supporting
records for the initial EOP transition to the ERG Revision 0, the EOP
upgrade to ERG Revision 1, and the EOP upgrade to ERG revision 1A,
and
found the following:
Except for the absence of validation checklists, the procedure
review and approval packages inspected were complete to the
current program requirements.
O7
Simulator
validation
was conducted on all
possible EOPs
incident to the upgrade to
ERG Revision 1.
No
simulator
validation was conducted incident to the upgrades
to ERG
Revisions 0 or 1A.
o
Although V&V was applied during the upgrade to ERG revision -lA,
the latest revision, the process was insufficient in that it
failed to identify the fact that the transition documen't (set
points, deviations, generic to plant specific differences and
I&C task analysis) had not- been upgraded to ERG revision 1A.
Since the transition document was a principal constituent of
the HBR PSTG and was not upgraded,
the NRC concluded that the
HBR EOPs were not adequately based upon the PSTG and that the
V&V process fail&d to identify that shortcoming.,
The
licensee's
program did not require in plant
walkdowns.
During this inspection,
NRC walkdowns of EOPs
identified many procedure deficiencies.
o
These V&V deficiencies constituted a serious weakness in the
HBR V&V program.,
The licensee agreed with the V&V findings listed above.
Resolution of
this issue was identified as.IFI 50-261/89-16-06.
There were no violations or deviations noted in this area.
5. Simulator observation
The team observed a crew-performing the following five major scenario
categories on the HBR Simulator.
(1) Loss of all feedwater
(2) Intermediate size LOCA
(3) Steam line break inside containment
(4) Steam generator tube rupture with ATWS
(5) Loss of CCW
The simulator performed satisfactorily with one exception. The simulator
would -not model a loss of offsite power when grid voltage. was degraded.
The team looked closely at reactor vessel head voiding during natural
circulation, and the simulation was satisfactory.
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 duplicate operator
actions unless required.
The procedures did not cause the operators to physically interfere with
each other while performing the EOPs.
0
8
The simulator group utilizes a computer tracking system to track relavent
simulator modification requests (SMRs) which reflected modifications to the
control room. This tracking of the differences was used to maintain the
fidelity of the simulator. There were 56 open SMRs in varying degrees of
completion, some only requiring documentation to be completed for close
out. The simulator instructors felt obligated to inform the students of
15 of these SMRs,
due to the SMR's significance, prior to a simulator
session.
6. Management.control of EOPs
The team found that weaknesses.in management control of EOPs allowed them
to degrade over time.. Some of. these weaknesses were described in
previous paragraphs:
Failure to revise EOPs when a plant modification was performed,
paragraph 4.
o
Failure to provide adequate guidance to operators to help ensure
compliance with the TS, paragraph 4.
o
Failure to orovide justification for EOP step deviations from
the ERG and to keep the PSTG current, paragraph 2.
o
Deficiencies in .the V&V program, paragraph 4.
The team reviewed the quality assurance measures utilized to incorporate
operational and tr'aining experience into the EOPs.
Training instruction
909,
Simulator Conduct of Operations and Instructor Qualifications, was
issued in October 1988.
This TI required a "procedure
discrepancies"
book be made available to instructor and students. during simulator
training to collect any procedure problems identified in plant procedures.
These comments were reviewed by the training staff and then forwarded to
the Manager of-Operations for resolution.
Review of the comments indicated
that both the training staff and operators were actively participating in
the process. However, a potential weakness in the process was the lack
of feedback to the comment orginators. Failure to provide feedback could
eventually discourage participation in the process. The team verified that
some comments had been incorporated into the EOPs.
The process did not
solicit comments from classroom training sessions.
Revisions to the EOPs were prepared in accordance with OMM-013, Emergency
Operating Procedure Writer's Guide,
and approved in accordance with
AP-004,
Development,
Review and Approval of Procedures, Revisions, and
Temporary Changes. Section 5.6, verification and validation program of
OMM-013 required that the verification worksheet, Attachment 6..12,
be
completed prior to implementing the revision.
The worksheet steps were
general in nature
and lacked detail to ensure that the steps were
adequately addressed by the reviewer. This section also required that
validation be performed on EOP revisions.
The validation was to include
a simulator or control room walkthrough validation or both.
Interviews
with plant personnel revealed that this validation process had not yet
been implemented.
-9
7.
EOP user interviews
The team conducted interviews with twelve licensed operators.
The
operators felt that the EOPs had been improved with the recent revision.
Those interviewed expressed their belief that the level of detail in the
EOPs could be improved, but was adequate -for the level of knowledge of
the typical
operator.
Overall, the operators had confidence. in the
ability of the EOPs to perform their intended function although the level
of detail in the EOP was inadequate in some cases.
Section 5.1.4,
pages 7 and 8 of the. writer's guide, stated that Path
procedures relieve the operator
of the burden of memorization
of
immediate actions.
The
ERG background document for E-0 stated that
immediate actions "are those actions which the operator should be able to
perform before opening and reading his emergency procedures."
Whether
the procedure is in a two-column or flow chart format is immaterial. The
writer's guide must be clarified regarding the memorization of immediate
operator actions and their training adjusted accordingly.
If memorization is not required, this deviation should be technically
justified.
This
justification
should specifically
address
both
section 3.3.1 "Immediate action steps" and section 2 "Control
room usage
of guidelines" of the WOG ERG writer's guide.
Resolution of this issue
was identified on IFI 50-261/89-16-07.
The operators noted that the AOPs were not at the same useability level
as the other EOPs. 'Those
interviewed felt that an upgrade to the AOPs
similar to that which the other EOPs received would be beneficial.
There were no violations or deviations noted in this area.
8.
Exit Interview
The inspection scope and findings were summarized on September 29,
1989,
with those persons indicated in paragraph 1. The NRC described the areas
inspected and discussed in detail the inspection findings listed below.
No proprietary material is contained in this report.
No dissenting
comments were received from the licensee.
Item Number
Status
Description/Reference Paragraph
IFI 261/89-16-01
Open
Develop a new PSTG (paragraph 2).
IFI 26.1/89-16-02
Open
Develop an AOP writer's guide
(paragraph 2).
IFI-261/89-16-03
Open
Review each Appendix D item
(paragraph 4).
IFI 261/89-16-04
Open
Review each Appendix B item
(paragraph 4).
10
.
IFI 261/89-16-05
Open
Review each Appendix C item
(paragraph 4).
IFI 261/89-16-06
Open
Correct V&V deficiencies
(paragraph 4).
IFI 261/89-16-07
Open
Review memorization of operator
immediate actions.
(paragraph 7).
APPENDIX A
PROCEDURES REVIEWED
CFST - 1
Critical Safety Function Status Tree
REV 3
CFST - 2
Critical Safety Function Status Tree
REV 3
CFST - 3
Critical Safety Function Status Tree
REV 3
CFST - 4
Critical Safety Function Status Tree
REV 3
CFST - 5
Critical Safety Function Status Tree
REV 3
CFST - 6
Critical Safety Function Status Tree
REV 3
EPP-Foldouts
Foldouts
REV 6
EPP-SUPP.
Supplements'
REV 5
EPP-1
Loss of All AC Power
REV 5
EPP-2.
Loss of All AC Power Recovery without SI Required
REV 5
EPP-3
Loss of All AC Power Recovery with SI Required
REV 4
EPP-4
Reactor Trip Response
REV 4
EPP-5
Natural Circulation Cooldown
REV 3
EPP-6
Natural Circulation Cooldown with Steam Void in Vessel REV 2
EPP-7
SI Termination
REV 6
EPP-8
Post LOCA Cooldown and Depressurization
REV 4
EPP-9
Transfer to Cold Leg Recirculation
REV 6
EPP-10
Transfer to Hot Leg Recirculation
REV 3
EPP-11
Faulted Steam Generator Isolation
REV 2
EPP-12
Post-SGTR Cooldown Using Backfill
REV 3
EPP-13
Post-SGTR Cooldown Using Blotdown
REV 3
EPP-14
Post-SGTR Cooldown Using Steam Dump
REV 3
.
EPP-15
Loss of Emergency Coolant Recirculation
REV 3
EPP-16
Uncontrolled Depressurization of All Steam Generators REV 4
EPP-17
SGTR with Loss of Reactor Coolant:
Subcooled Recovery REV 4
EPP-18
SGTR with Loss of Reactor Coolant:
Saturated Recovery REV 4
EPP-19
SGTR without Pressurizer Pressure Control
REV 3
EPP-20
LOCA Outside Containment
REV 2
EPP-21
Energizing Pressurizer-Heaters from Emergency Busses
REV 3
EPP-22
Energizing Plant Equipment using the Dedicated
Shutdown Diesel Generator
REV 2
EPP-23
Restoration of Cooling Water Flow to Reactor
Coolant Pumps
REV 3
FRP-C.1
Response' to Inadequate Core.Cooling
REV 2
FRP-C.2
Response to Degraded Core Cooling
REV 2
FRP-C.3
Response to Saturated Core Cooling
REV 2
FRP-H.1
Response to Loss of Secondary Heat Sink
REV 2
FRP-H.2
Response to Steam Generator Overpressure
REV 2
FRP-H.3
Response to Steam Generator High Level
REV 3
FRP-H.4
Response to Loss of Normal Steam Release Capability
REV 2
FRP-H.5
Response to Steam Generator Low Level
REV 2
FRP-I.1
Response to High Pressurizer Level
REV 2
FRP-I.2
Response to Low Pressurizer Level
REV 2
FRP-I.3.
Response to Voids in Reactor Vessel.
-
REV 3
FRP-J.I
Response to High Containment Pressure
REV 2
FRP-J.2
Response to Containment Flooding
REV 1
FRP-J.3
Response to High Containment Radiation Level
REV 2
FRP-P.1
Response to Imminent Pressurized Thermal Shock
REV 2
FRP-P.2
Response to Anticipated Pressurized Thermal Shock
REV 2
FRP-S.1
.
Response to Nuclear Power Generation ATWS
REV 2
FRP-S.2
Response to Loss of Core Shutdown
REV 2
PATH-1
.
PATH-1
REV 5
PATH-2
PATH-2
REV 5
Malfunction of Reactor Control.System
REV 3
Emergency Boration
REV 2
Malfunction of Reactor Make-Up Control
REV 2
Control Room Inaccessibility
REV 2
- Radiation Monitoring System
REV 5
Turbine Vibration
REV.2
Turbine Trip without Reactor Trip Below P-7
REV 0
Accidental Release of Liquid Waste
REV 0
Accidental Release of Waste Gas
REV 0
Inadequate Feedwater Flow
REV 4
Loss of Circulating Water Pump
REV 0
Partial Loss of Condenser Vacuum
REV 4
Fuel Handling Accident
REV 2
Loss of Component Cooling Water
REV 0
Secondary Load Rejection
REV 1
Excessive Primary Plant Leakage
REV 5
Loss .of Instrument Air
REV 5
Reactor Coolant Pump Abnormal Conditions
REV 1
Malfunction of. RCS Pressure Control
REV 1
Loss of Residual Heat Removal (Shutdown Cooling)
REV 6
Seismic Disturbances
REV 3
Loss of Service Water
REV 2
Loss of Containment Intergrity
REV 3
Loss of Instrument Buss
REV 1
Low Frequency Operation
REV 0
.
Operation with Degraded System Voltage
REV 0
ISFSI Abnormal Events
REV 0
APPENDIX B
TECHNICAL AND HUMAN FACTORS COMMENTS
This appendix contains technical and human factors comments and observations.
Unless, specifically stated, these comments are not regulatory requirements.
However, the licensee -acknowledged that the factual content of each of these
comments was correct as stated.
The licensee further committed to evaluate
each comment, to take appropriate action and to document that action (proposed
or completed) in its answer to IR-89-16.
These items will be reviewed during
a future NRC inspection.
I. General comments:
1. Although the TD
intended to provide operator action setpoints
required by the HBR EOPs, there was no setpoint document to serve
AOP unique requirements.
2.
PSTG
DEV:
No deviations should have existed between'the PSTG and
the EOPs. Since the PSTG had been defined as a set of documentation
which included the GTG, all deviations between the GTG and the EOPs
became deviations between the PSTG and the EOPs,
by definition.
Although the EOPs were revised to conform to ERG rev.
1A,
the PSTG
.had not been (e.g. setpoint, deviation and plant comparison documents).
As a result, the Robinson revised EOPs were not adequately based upon
plant specific technical guidance. The NRC considered this a significant
weakness as documented in paragraph two.
3.
As stated in the writer's and user's guides, there were .no declared
immediate action steps in the EPPs and PATHs.
The NRC found that
elimination of immediate action steps and of the requirement that
operators commit these steps to memory was unacceptable and
constituted a weakness in the
program.
(see paragraph 7,
interviews).
4. HBR did not declare an NOUE based upon hurricane HUGO. The HBR EALs
did not conform to the guidance of NUREG-0654 Appendix I,
EAL 13 d,
to declare a NOUE given "Natural
phenomenon being experienced or
projected beyond usual
levels... any hurricane".
Hurricane
HUGO
passed
through
the area during the inspection.
The area was
declared a disaster area. Brunswick,. a sister CP&L plant, declared
a NOUE. HBR did not. HBR unit 2 was in cold shutdown; the control
.room
wind velocity instrumentation was inoperative; and hurricane
preparations were made.
The operators were aware that Brunswick had
declared a NOUE,
that the hurricane eye was projected. to pass
nearby, that it
was a category four hurricane. and that winds were
projected in excess of 135 mph when the hurricane came ashore near
Charleston.
As the local wind velocity increased, grid problems,
telephone .outages and on site wind damage were experienced. The HBR
applicable NOUE stated "Hurricane or tornado within site boundary".
The NRC concluded the hurricane impacted the site and that in the
absence
of wind velocity data,
the operators
were unable to
determine whether it
was or was not above hurricane velocity (e.g.
73 mph).
2
5. The licensee had organized neither the EPPs nor the AOPs such that
multiple local actions to accomplish a single goal were contained in
a procedure attachment which could be provided to the AO. Conversion
to this format would have, in many cases, relieved the control room
staff of a significant communications burden and would have enhanced
the successful completion of the step.
6.
provided. support in
EOP actions
(e.g.
jumper installation;
determination of NI undercompensation, etc.).
I&C did not provide
round the clock shift coverage nor were I&C personnel trained in the
performance of I&C responsible EOP steps.
Il
PATH comments:
NOTE:-
Since PATH
steps were not numbered,
step location is
specified belpw by grid location.
1. PATH-1
a. Grid D-16,
Paragraph 5.3.3 of the User's Guide required that
CSFST monitoring be initiated at a particular step in PATH-1 or
upon exit from PATH-P-.
Contrary to that requirement, the exit
to EPP-11 at grid D-16 was made without initiation of CSFST
monitoring nor was monitoring initiated within EPP-11.
b. Grid D-5,
CV fans:
The- GTG required that CV fan coolers be
verified running
in the emergency mode.
HBR required
verification that the fans were running since there was no
method of verifying that the intake dampers had shifted to the.
emergency position. No deviation existed.
c. Grid B-7 and elsewhere in the PATHs and EPPs,
RCS pressure
greater than or equal to 1520:
Recorder PR-444 and meters
PI-402 and 501
had scale increments of 50 psig.
Using the
half division rule, they could not be used to determine a
value of 1520.
d. The three AFW flow.controllers used in many places in the PATHs
and the EPPs (FIC-1425,
1426,
& 6416) were times 10 meters but
were not so labeled.
e. Grid C-10 and elsewhere in the PATHs
capacity to assume additional loads:
The process by which the
operator determined whether sufficient DG capacity existed to
bring on additional loads was cumbersome and in some cases
inadequate. Since DG KW was not available from the board meters,
to verify that sufficient capacity existed to bring on additional
load's the operator was required to read DG volts and amps and
calculate KW from a curve.
3
The operator aid then directed the operator to FSAR table
8.3.1-1 to determine the load bf the oncoming equipment.
If
the oncoming load was less
than remaining capacity, the
equipment could be loaded to the bus.
Some loads (e.g.
the
charging pumps) were not shown in FSAR table 8.3.1-1, the source
referenced on the operator aid.
f. Grid C-11, restart ES equipment:
This step was illustrative of
a aeneral problem which existed in the PATHs
and the EPPs;
insufficient definition.
g.
Radiation monitoring units, R-19 A/B/C:
Neither the recorder
nor the edge meters had engineering unit labels.
h. The CV water level meters did-not have engineering unit labels.
No instrument number labeling was provided.
There
was
no
standard
convention
for
steam
generator
designation. They were identified as units A, B or C; I, II or
III; or 1, 2, or 3
(e.g.
15 edge. meters on the RTGB and
annunciator panel APP-006 used the I, II or III convention;
most .RTGB
instruments used the A, B or C convention; plant
valves generally used 1, 2 or 3).
jI
,The .HBR standard abbreviation for pressurizer (PZR)
had not
been implemented universally.
PZR and PRZR were both used
(e.g. LI-459 meter vs. panel label).
1. Grid F-15'and elsewhere in the PATHs and EPPs,
emergency oil
pumps: This step did not clearly define which seal oil backup
pump was to be started.
During walkthroughs,
two operators
correctly started the air side DC seal oil backup pump; a third
started the AC pump adjacent to the emergency oil pump on the
RTGB.
m. Grid B-9 and elsewhere in other procedures:
The 300 gpm AFW
flow parameter for decay heat removal stemmed from-the setpoint
document generic footnotes attachment 1.0.
The GTG bases
document required allowances for normal channel accuracy. None
were included in the HBR setpoint calculation.
n. HBR setpoint document, generic footnotes, attachment 2.0:
Typo; paragraph 4.2 follows 2.1. Other typos; "valves" should
be "values" in paragraph 4.2; attachment 8.0 mid page, "syste".
o.
HBR. setpoint document,
attachment 1 pg.
2 and frequently
elsewhere:
the percent symbol was missing in the calculation
string (e.g. item 6, 0.5 of span).
4
III. EPP comments:
1. EPP-1
Loss of all ac power
a.
PSTG DEV, Step 3.0:
The ERG note that stated steps 1 - 4 were
immediate action steps has been deleted from this procedure.
The ERG required immediate action steps to be memorized by the
operators.
The TD attempted to justify this step deviation
based on
the use
of flow charts.
This was not adequate
justification for operators not to memorize these steps.
b. PSTG DEV, Step 3.1:
The word "check" in thi-sstep deviated from
'the word "verify" in the TD.
This same deviation appeared in
steps 2, 3, 4, 6a2, 6b, 8c, Se, 12b, 14, 15, 16, 17c and d, 18,
19, 20, 21, 22, 23, 24, 25, and 27.
c.
PSTG DEV, Step 3.1: The ERG required the operator to check rod
bottom lights and
RPIs to verify reactor trip, 'and these
actions were not included in this procedure.
The TD attempted
to justify this by stating that these indicators were not
powered from the batteries.
This justification was not
adequate to explain the fact that these indicators were not
powered in this instance.
d.
Step 3d:
The operator was unable to check some of these RCS
ventilation system valves closed, because the power to them was
deenergized and the position indicating lights were not lit.
e.
PSTG DEV,
Step 4a RNO:
The steam generator levels in this step
were different from those in the TD.
This
same deviation
appeared in steps 14 and 17.a.
f. PSTG DEV, Step 5d:
This item was not in the TD.
g. PSTG DEV, Step 7:
The charging pumps were included in the ERG
and were missing from this step.
The TD justification was not
adequate to explain the fact that the charging pumps were not
automatically started on safety injection.
h. Step 9: This step required operators to contact I&C to connect
steam line PORVs to nitrogen accumulators so they could be
operated.
personnel
were not always .available and
operators could do this step.
1.
PSTG DEV, Step 10:
Before this step, the TD included a step to
locally close valves to isolate
seals.
This step was
missing from the procedure,
due to use of the
DS diesel to
operate a charging pump.
5.
j.
PSTG DEV, Step 12, caution 2:
This caution in the.,procedure was
not in the TD.
k.
PSTG
DEV,
Step 13:
The
ERG. included condenser air ejector
radiation as a symptom of a. ruptured steam generator, but this
was not included in the procedure.
The TD justification that
this instrument was deenergized was not adequate to explain the
fact that it was deenergized.
1. Step
16
RNO:
The operator was required to switch to an
alternate AFW water supply,
but was given no -guidance- on
priority of alternate supply.
Interviews with operators
revealed.that not all would choose the same alternate supply.
m.
Step 16 RNO:
The operator was directed to align Unit 1 fire
main with unit 2 fire main, but was given no guidance on how or
where to do this. The location of these valves and the tool to
operate.them were not common knowledge among operators.
n. Step 16 RNO:
The operator was directed to fill the CST using
fire hoses, but no dedicated pipe fittings were provided. In
tact, a large flange fitting would have had to be manufactured.
The operators needed to have all tools and equipment required
to perform emergency actions to be readily available.
o. PSTG DEV, Step 17 caution 2:
This caution was not in the TD.
p.
Steps 20 and 21:
The arrangement of these lights on the RTGB
was poor.
Not all containment isolation phase-A lights were
grouped together.
Also, containment ventilation
isolation
lights were mixed with control room ventilation lights.
This
arrangement made it difficult for the operator to accurately
check status as required.
q. PSTG DEV, Step 22:
The TD included three items to check that
were not in the procedure.
r. PSTG DEV, Step 23: This step required the operator to check CV
radiation less than 1000 R/hr, while the TD used 100 R/hr.
s.
PSTG
DEV,
Step 24 RNO:
This step required the operator to
return.to the step 12 caution, while the TD required a return
to step 17.
t.
Step 25 caution: This cautioned the operator that loads placed
on the E-1 or E-2 emergency busses
should not exceed the
capacity of the power source, but did not provide a reference
to the information the operator would need to do this, such as
an emergency load list including KW.
6
u. Step 26a:
The
labeling of the
steam
generator PORV
controllers was inadequate. The demand signal was labeled from
0 to 100 percent, which represented a demanded setpoint of 1500
to 0 psig. The normal setpoint of 1035 psig was thus shown on
the indicator as 31 percent.
Operators had written "closed"
and "open" in pencil on the RTGB by the 0 and 100 percent. In
interviews, operators stated that better labeling was needed to
assist them in proper operation of these Valves.
v.
PSTG DEV, Step 27:
This step directed the.operator to check SW
booster pumps, which was not included in the TD.
W. Attachment A, page 4:
To. shed circuit 23 as directed, the
operator would need a 10 amp fuse puller, which was available
only in the control room.
Information needed by the operator
to get the correct tools for the job was not included in the
procedure where it could avoid unnecessary loss of time.
x. Attachment A, page 5:
The procedure did not adequately describe
loads to be shed. Breaker or circuit numbers were not specified
and load names did not match with labels on the panels. Operators
could not identify by using this list all of the correct loads
to shed.
2.
EPP-2 Loss of all ac power, recovery without SI required
a.
Step 17a RNO: This step required, the operator to observe the
caution statement prior to. step 18 and go to step 18.
There
was .no caution statement.prior to step 18.
b.
Step 18 RNO:
Increasing *feed flow and raising level to maximum
allowed would assist in reestablishing SCM.-
This alternative
was not included.
c.
Step 18:
The structure for natural circulation verification
steps differed between procedures.
This step consisted of a
check with an RNO to establish natural circulation.
EPP-16
step 29 RNO verified natural circulation.
Since the end result
is identical in both cases, the format should be standardized.
d.
Step 23a:
Backfeeding the aux transformer from offsite power
is a lengthy, complex and infrequent operation.
The backfeed
procedure in OP-603 was not cited.
e. Step 23a:
The alternative of shipping power from unit one was
described in some procedures as
"...IC
turbines or unit one
... "
and in others as "...
IC turbines and unit one '."
The
format was not standardized. (e.g.
EPP-16,
step 28 RNO and
elsewhere)
II7
.3. EPP-3
Loss of all ac power, recovery-with SI required
a. Step 3 RNO:
These procedural directions contained no verb.
b.
Step
6:
The verb used in this step was not defined in the
action verb list.
C.
PSTG DEV, Caution 9:
The key utility decision point contained
in the GTG caution 8 was missing from this procedure with the
result that the operator was not warned against establishing
component cooling water to the thermal barrier of an RCP which
has excessive seal leakage.
d.
Caution 2:
The ERG contained a caution prior to step 2 which
was not in EPP-3.
e. PSTG DEV, Step 4: In addition to other equipment, step 4 of the
TD required the operator to start the SW pumps and the SWB.
pumps. EPP-3 step 4 did not contain this requirement.
f.
PSTG
DEV,
Step 6:
The
TD step. 6 instructed the operator to
"rack in CV
spray pump breakers", but the corresponding EPP-3
step instructed the operator to "locally install control power
fuses for the CV spray pump breakers".
g.
PSTG DEV, Step 7:
Step 7 of EPP-3 stated "Check if CV spray is
required". The ERG and the TD did not contain a corresponding
step.
h.
Step 2a:
This step did not provide the operator a valve list
for guidance.in aligning SI valves for cold leg injection..
i.
Step 4b:
This step did not specify which RHR pumps to load.
j.
Step 4d:
This step did not specify which HVH units to load.
k. .
Step 5:
This step -instructed the operator to control AFW flow
and maintain S/G levels. It did not address control of the S/G
pressure or verification of natural circulation.
1. Step 6: *This step locally.,installed control power fuses for
the' CV Spray Pump Breaker.
There was not a preceding step
instructing the operator to "Reset
CV signal"; -such a step
would prevent the breaker from 'auto -closing if
a signal was
present when the operator was inside the open breaker cubical
installing fuses.
m. Step 7a:
The step did not specify the action to be taken if CV
pressure had "ever" increased to or was presently greater than
20 PSIG.
n. Step 7d RNOj:
This step required the operator to adjust the
fIowrate but did not specify a valve name or number. Adjusting
this flowrate is an infrequent operation.
4.
EPP-4
Reactor trip response
a.
Step 3 RNO:
The first asterisk does not specify how to dump
steam to the condenser.
b.
Step 4c RNO:
Parta of step'5 RNO did not specify the number
of pumps required for emergency boration.
c. Step 5, NOTE:
This note did not inform the operator that
letdown isolation could deenergize the PZR heaters. A level of
14.4 percent in the PZR will deenergize the heaters.
d.
Step 5a RNO:.
Part a of step 5 RNO did not specify. the number
of pumps required for emergency boration.
e. Step, 5b RNO:
This subpart was confusing as written and
contained more than two actions in each subpart.
f.
Step 5d RNO:
Part d of step 5 RNO had, as an option, "Open AUX,
4 '
PZR
SPRAY,
CVC
311".
This statement did not
inform the
operator of the maximum delta T limit of 320 degrees F between
the pressurizer temperature and the aux spray temperature.
g. Step 6a RNO:
Step 6.a.1 RNO did not contain the valve name or
number to be used to verify letdown isolation.
h. Step 6a RNO: Step 6.a.4 RNO was misleading in that it implied
that: the operator only "resets"
a particular bank. of
PZR
heaters "as
necessary" after clearing , a low level of 14.4
percent.
i.
Step 7a RNO:
This item did not specify how Safety Injection
was to be initiated.
j.
Step 7b RNO:,
Step 7b.2g RNO did 'not inform the operator which
RCP is associated with which spray valve. B PZR spray valve
was not associated with the B RCP.
k. Step 9 RNO:
Step 9 RNO was not clear. The step implied that
the operator was required to start and load the EDG's on the El
and E2 busses even if power to them had not been lost.
1. Step 9 RNO: Step 9 RNO instructed the operator to "Verify EDGs
have assumed the proper loads".
No guidance was provided to
4
the operator defining either "proper loads" or the KW rating of
the individual loads.
There was no
KW meter nor other
indication of EDG KW in the control room to aid the operator in
loading the EDG.
9
M. Step 9 RNO:
Step 9.c. There was no KW meter nor indication of
KW for the EDGs in.
the control room to aid the operator in
verifying adequate EDG capacity and loading the. instrument
air compressor(s)
and battery charger(s).
The step did not
give the operator the. KW rating of the instrument
air
compressor(s) nor that of the battery chargers.
n.
Step 10 RNO:
This step stated "start pumps". The step did not
specify which pumps to start. the starting priority of the
pumps nor the number of pumps.to be started.
o. Step 11
RNO:
This step did not define whether the operator
should dump steam to heat up,
cool
down,
or to maintain a
constant S/G pressure.
p.
Step 12 NOTE:
The note d.id not instruct the operator on which
RCP produced the most effective PZR spray.
q. PSTG DEV, Step 8:
Step 8 of EPP-4 which corresponds to step 6
of the ERG: "Check S/G levels" was not addressed by a deviation
in the TD.
r.
PSTG DEV, Caution 9:
The TD contained a CAUTION C-9 (EOP: TD
EPP-4 37) "On Natural Circulation, RTD bypass temperatures and
associated function will be inaccurate" is not in EPP-4.
S.
PSTG
DEV,
Step 13:
Step 13 of EPP-4 and step 10 of the ERG
"Check if Source Range detectors should be energized" is not
addressed in the T.D..
5.
EPP-5 Natural circulation cooldown
a..
Entry Condition:
The TD referred to pages 23,
16 and 27.
The
correct references are pages 24, 17 and 28.
b. Step 1, note 1:
This note required the RCPs to be run in order
of priority to provide PZR normal
spray.
The note did not
provide the preferred order.
C. Step 2a:
This step established conditions per OP-101 for
running an RCP.
The OP-101 sections contained actions which
are not essential to starting an RCP.
d..
Step 2b:
This step started RCP(s).
In other EOP steps, this
was combined with the previous step, thereby requiring the
RCP(s) to be started per OP-101.
e. Step 3, note:
This note stated that boron addition should be
based on total system volume.
The aids used by operators to
determine boron addition quantities are based on less than
total system volume.
10
Step 4, note 2:
This note. indicated sample results should
indicate an overborated condition to prevent dilution below
cold shutdown concentration if a PZR outsurge occurred.
During
walkthroughs, the operator did not know how much overboration
would be required.
There was ano specific guidance defining
"overborated condition".
g. Step Sc:
This step was not included in the TD.
.h. Step 7, caution:
This caution was a restatement of the AFW
supply switchover criteria in Foldout A.
Step 8:
This step required hot leg temperatures -to be less
than 540 degrees F. Step 7 of ERG ES-0.2 indicated less than
550 degrees F. The TD indicated 550 degrees F. Thus, the TD
did not provide justification for the difference.
- j.
Step 9, caution:
This caution warned that the SI initiation
circuits would automatically unblock if
PZR pressu'e increased
to greater than 2000 psig or Tavg increased to greater than 543
degrees F.
The caution in ERG-0..2 did not include the Tavg
criteria. The TD did not include the Tavg criteria. Thus, the
TD did not justify.the additional criteria..
Ak.
Step 10:
This step blocked safety injection due to PZR
Press/Hi stm line dp and Tavg.
require the Tavg function to be bypassed.
The TD did not
require the Tavg function to be bypassed. Thus, the TD did-not
justify the difference.
1 .
Step 27:
This step maintained required RCP seal injection
flow. There was no guidance defining "required ...
flow".
m. Step 29b:
This step was described in the TD as part of step 28.
6. EPP-6
Natural circulation cooldown with
steam void in vessel
(without RVLIS)
a. Step 4c:
This step required operators to maintain RCS
temperature and pressure within the limits of curve
3.4,
"Reactor coolant system pressure -
temperature limitations for
cooldown".
The curve
was
not labeled with all
of the
information needed to ensure compliance with it,
nor was this
information provided *in the procedure (eg.
which instrument
readings to
compare with which part of the curve).
In
interviews, two of six licensed operators (33
percent) could
not describe correctly how to comply with this curve.
Some of
these operators also did not know what the expected difference
should be between the hot leg and the cold leg temperatures
II
when on natural circulation cooling.
11
Curve 3.4 consisted of two parts:
TS
cooldown limits on
maximum pressure . allowed at any given cold leg temperature
(to protect
RCS integrity),
and
saturation limits on
minimum pressure allowed at any given core exit or hot leg
temperature (to maintain core cooling).
The operators needed
to be able to use this curve correctly.
7.
EPP-7
SI termination
a. Step 3:
This step contained multiple actions contrary to the
writer's guide.
b.
Step 3:
The alpha numeric listing rules of the-writer's guide
were
not followed in listing the sequence dependent steps
resetting
the reactor trip breakers and
resetting feed
i solation.
c. Step 4 RNO:
The procedure did not indicate this step as a
local action.
d.
Step 6:
This step directed "stop SI and RHR pumps". There was
no RNO. Therefore the substep bullets were superfluous.
e. Step 9: -The step.did not provide boration completion criteria.
The worth of the
most reactive rod
was
not promulgated
officially nor was it
documented in the control room.
Only
through training were the operators informed of the value and
then only once per cycle.
f.
Step 9 RNO:
Since the step was identical to components of
AOP-002, the step.would be simplified by referring to AOP-002.
g. Step
14:
This step checked whether
seal
flow should be
established.
Substep
f, establishing . seal
flow, was
inappropriate and should.stand as a separate step.
h.
Step 20 RNO c:
This step provided insufficient definition as
to which seal oil backup
pump
was to be started.
During
walkthroughs, two operators correctly started the air side DC
seal oil backup pump; a third started the AC pump adjacent to
the emergency oil pump switch on the RTGB.
i.
Step 20
RNO e:
Backfeeding the aux transformer from offsite
power . is a lengthy,
complex and infrequent operation.
The
backfeed procedure in OP-603 was not cited.
j.
Step 21
RNO a2 and elsewhere in other procedures:
This step
required trended values to verify natural circulation.- Other
equivalent
steps did not require trended values.
The
format is not standardized.
Some of the operators were unable
to expeditiously establish simultaneous trending on the three
values which were not on recorders.
This indicated a minor
ERFIS training problem since
ERFIS would support three,
simultaneous trends.
k. Step
21
RNO a2:
This step
neglected increasing feed flow
within established S/G level limits.
1. Step 25a:
The four manual
actuation zone switches on the
containment fire protection system panel did not have open or
closed position indication labels.
m.
Steps d, e. g and h:
These steps were not shown as local
actions.:
n. Step 28:
The substeps did not include a hold point at step b.
The plant operations staff decision is mandatory prior to
return to power, natural circ cooldown or forced flow cooldown.
8.
EPP-8 Post-LOCA cooldown and depressurization
a. Step 2:
Step 2 began on page 4 of 26 and ended on page 5 of
26.
The high level step number "2" was shown only on page 4.
Only the substep identifier was shown on page 5.
Therefore,
there was no complete identifier for the substeps on page 5.
b.
PSTG DEV, Step 2:
The verb "check" was used, rather than the
verb "verify," 'as in the PSTG.
c. Step 3, caution:
This caution
incorrectly contained a
conditional action -step.
d.
PSTG DEV,, Step 10b, RNO:
The words "Observe CAUTION and NOTE
prior to step 11 AND" was not included in the PSTG.
e. PSTG DEV, Step 11, cauti&n: This caution incorrectly contained
a conditional action step.
f.
Step 11:
Step 11 began on page 11 of 26 and ended on page 12
of' 26.
The high level step number "11"
was shown only on page
11.
Only the substep identifier was
shown
on
page
12.
Therefore, there was no complete identifier for the substeps on
page 12.
g.
PSTG DEV, Step 11c, RNO:
The words "Observe CAUTION prior to
step 10 AND" were not included in the PSTG.
h.
PSTG
DEV,
Step 11dl:
The words
"AND start one
RCP"
were
correctly shown in.the PSTG as a distinct substep.
i.
Step 12:
Step 12 began on page 13 of 26 and ended on page 14
of 26.
The high level step number "12"
was shown only on page
13.
Only the substep identifier was shown on page 14.
Therefore,
there was no complete identifier for the substeps on page 14.
j.
PSTG DEV, Step 12a:
This step was not included in the PSTG.
13
k. PSTG DEV,
Step
12a,
RNO:
This step was not included in the
PSTG.
1.
PSTG DEV,
Table, page 13:
The adverse containment value of 68
degrees F shown for required RCS subcooling when two or three
SI pumps are running
and
two or more charging- pumps
are
available was different from the PSTG value of 70 degrees F.
m.
Step 14:
Step 14 began on page 15 of 26 and ended on page 16
of 26.
The high level step number "14" was shown only on page.
15.
Only the substep identifier was shown on page 16.
Therefore, there was no complete identifier for the substeps on
page 16.
n. Step
14,
caution:
This caution incorrectly contained a
conditional action step.
o.
PSTG DEV, Step 14:. The PSTG included a caution prior to this
step that was missing in this procedure. The caution read "On
natural circulation,
bypass temperatures and associated
functions will be inaccurate."
p.
PSTG
DEV,
Step 14al,
RNO:
The words "start one RCP"
were a
separate substep in the PSTG.
q. PSTG DEV, Step 15b:
The words "turn on" were shown instead of
the verb "control" that was shown in the PSTG.
r.
PSTG
DEV,
Step 15c:
The expected response values for RCS
subcooling (35 degrees F; 55 degrees F for adverse containment)
differed from those shown in the PSTG (25 degrees F; 45 degrees
F for adverse containment).
s. PSTG
DEV,
Step 16:
The verb "check" differed from the verb
"verify" used in the PSTG.
t.
PSTG
DEV,
Step 17:
The verb "check" differed from the verb
"verify" used in the PSTG.
u. PSTG DEV, Step 17b, RNO:
The words "Observe CAUTION prior to
step 10 and" were not shown in the PSTG.
v. PSTG DEV, Step 18a:
See comment for step 15c above.
w.
PSTG DEV, Step 18a, RNO:
Only the words "go to step 19" were
shown in the PSTG. The setpoint of 370 degrees F differed from
the 400 degrees. F shown in the ERG.
x.
PSTG DEV, Step 18b: This step and its associated RNO step were
not shown in the PSTG.
The step "go to step 20"
shown in the
PSTG was not included in the procedure.
14
y.
PSTG DEV,
Step 20a, RNO 3:
The terms "EMERG OIL PUMP and SEAL
OIL BACKUP PUMP" differed from the terms used in the PSTG of
"DC lube oil and seal oil backup pumps."
z. PSTG DEV, Step 20a, RNO 4 and 5:
These steps did not appear in
the PSTG.
aa.
PSTG DEV., Step 20:
This step did not appear in the PSTG.
ab.
PSTG
DEV,
Step 21:
This step did not include the item "RCP
upper and lower bearing oil cooling -
NORMAL" that was shown in
the PSTG.
ac.
PSTG
DEV,
Step 21,
RNO:
The transition to EPP-23 was
not
included in the PSTG.
ad.
PSTG
DEV,
Step 22b:
The upper setpoint of 65 PSIG differed
from the value of 75 PSIG shown in the PSTG.
ae.
PSTG DEV, Step 22d:
This substep did not appear in the PSTG.
af.
PSTG.DEV., Step 27b:
This substep did not appear in the PSTG.
ag.
PSTG DEV, Step 17, RNOs a and b:
These steps did not appear in
the PSTG.
an.
PSTG DEV, Step 27cl: The 'word "locally" was not shown in the
PSTG.
ai.
PSTG DEV, Step 27c:
The PSTG also included substeps c3 and c4.
aj.
PSTG DEV, Step 28a and 28a, RNO:
These steps were not included
in the PSTG.
ak.
PSTG DEV, Step 30, RNO:
The words "observe caution prior to
step 5 and" were not included in the PSTG.
9. EPP-9 Transfer to cold leg recirculation
a. PSTG DEV, Step 1:
In the TO, there was a step 1 that required
the operator to open foldout B. That step was missing from the
procedure.
b.
PSTG DEV, Step 2:
This step, which required the operator to
reset containment spray, was not in the TD.
c. PSTG DEV, Step 4 caution: This caution was not in the TD.
d.
PSTG DEV, Step 4:
This step was in a different sequence than
the equivalent steps in the TD.
j~j.
15
e.
PSTG DEV
Steps 8b, c, and d:
These steps were in a different
sequence than the equivalent steps in the TD.
f. PSTG DEV, Step 9:
This step used the word "check" where the TD
used the word "verify".
This same deviation was in steps 10,
11, 14. 16, 22, 23, and 24.
g.
PSTG, DEV,
Step 10:
This step checked service water system
operation and was not in the TD.
h.
PSTG DEV, Step 12:
This step was not in the TD.
i.
PSTG DEV, Step 13 and caution: This caution and step were in a
different sequence than in the TD.
Step 18 caution:
This caution needed to be located prior to
the step to which it applied; step 20.
k. PSTG DEV, Step 24:
Three steps in the TD were missing from this
procedure prior to step 20:
close SI hot leg header valve,
open loop 3 and 2 hot leg injection valves, and open breakers
for RHR cold leg injection valves.
1. Attachment A, page
14:
The
inspectors observed design
deficiencies that would inhibit operator actions in responding
to flooding in the RHR pump pit.
These included:
pit level
alarms not supplied with vital power and not EQ, sump pumps not
supplied with vital power,
and expected high radiation levels
in the area of the isolation valves for CCW to the RHR pump pit
during the recirculation phase.
10.
EPP-10 Transfer to hot leg recirculation
a. Step 3, note:
This. note incorrectly contained a conditional
action step directing a transition to step 10.
b.
PSTG
DEV,
Step 3d,
RNO:
This step was not included in the
PSTG.
c. PSTG DEV, Step 4b:
The. phrase "as available" was not included
in the PSTG.
d.
PSTG DEV, Step 4c:
This step was not included in the PSTG.
e.
Step 5:
Flow indicator FI-605 used to determine flow rate did
not contain adequate resolution to precisely read desired flow
rate.
f.
Step 7a:
Step 7a did not adequately identify other available
isolation valves.addressed in the step (SI-878B & SI-888C).
16
g..
Step 9:
Step 9 began on page 8 of 10 and ended on page 10 of
10.
The high level step number "9'"
was shown only on page.8.
Only the substep identifier was shown
on. pages 9 an d 10.
Therefore, there was no complete identifier for the substeps on
page 9 and at the top of page 10.
h;
PSTG DEV, Step 9b2:
The expected response was not included in
the PSTG.
i.
PSTG .DEV, Step 9b6:
The words "aligned to" were not included
in the PSTG.
11.
EPP-11 Faulted steam generator isolation
a.
Entry Condition:
Entry was specified whenever a faulted steam
generator is identified or suspected. , The entry condition
stated in ERG E-2 did not address "or suspected".
The TD did
not address this addition.
b. Step 4, caution,:
This caution was an instruction on how-to
accomplish an item of step 4.
c..
Step 4:
This step 'closed the steam generator blowdown
isolation valves.
No preferred method to accomplish this task
was provided.
During walkthroughs, operators indicated that
placing the RM-19 in alarm or locally actuating the valves
would be possible ways to close the valves.
12.
EPP-12 Post SGTR cooldown using backfill
a.
Step 1, note:
This note incorrectly contained a conditional
action step containing transitions.
b.
PSTG
DEV,
Step 4:
The action verb "check" differed from the
verb "verify" used in the PSTG.
c. Step 5, caution:-
This caution
incorrectly contained a
conditional action step..
d.
Step 6, caution:
This caution was overly complex.
e.
PSTG
DEV,
Step 10b:
The valve-number "SI-869" differed from
that shown in the PSTG ("SI-889").
f.
PSTG
DEV,
Step 11b and 11b,
RNO:
These substeps were not
included in the PSTG.
g.
PSTG
DEV,
Step 11c,
substeps 1 and 2:
The word "locally" was
not included in the PSTG.
h
PSTG DEV, Step 11c:
The PSTG also contained substeps 11c3 and
11c4.
i. PSTG DEV, Step 12:
This step was not included in the PSTG.
j.
PSTG
DEV,
Step 13a:
The adverse containment value was not
included in the PSTG.
k.
PSTG DEV, Step 13b:
The adverse containment value of 320 PSIG
differed from that shown in the PSTG (345 PSIG).
13.
EPP-13 Post-SGTR cooldown using blowdown
a. Step 8b:
This step required "energize"
control
power for
selected valves. The .ECCS valve's control power defeat panel
switches were-labeled "normal" and "defeat".
b. Steps 16c & 17a:
Step 16c directed cooldown per GP-007.
.The
cooldown rate limits in paragraph 5.2.11.3 of GP-007 were more
restrictive than the "less than 100 degrees per hour listed in
step 17a.
14.
EPP-14
Post-SGTR cooldown using steam dump
a.
First caution before step 1: The NRC found that survival of the
control
room dose calculation. capability under accident
conditions was degraded because of
its dependency upon
establishment of a link between the control room console and
the Raleigh main frame computer.
b.
Step 8b:
This step required "energize"
control power for
selected valves.
The ECCS valve's control power defeat panel
switches were labeled "normal" and "defeat".
c. Steps 16c & 17a:
Step 16c directed cooldown per GP-007.
The
cooldown rate limits in paragraph 5.2.11.3 of GP-007 were more
restrictive than the "less than 100 degrees per hour listed in
step 17a.
15.
EPP-15
Loss of emergency coolant recirculation
a. Step la RNO: Step la RNO did not give the operator guidance on
what actions to take if a component had not functioned
properly.
If
an
failed to open,
it could have been
manually operated.
b.
Step 3:
Step 3 required that the operator "Initiate
Cooldown
to Cold Shutdown",
but did not give the operator
guidance on what S/G levels to maintain.
c.
Step 10, NOTE:
The note did not provide the operator with
priority guidance on which RCP. produced.the most effective PZR
spray.
d.
Step 10b RNO:
Step 10b.
the RNO had a typo. The
RNO was
labeled a. and should have been labeled b..
e. Step 10c:
Step 10c
did not
have
an RNO for operator
auidance if the RCP could not be started.
f.
Step 15b RNO:
Step 15b2 stated "Start CHARGING-PUMP(s)" and
did not give the operator guidance on the number of charging
pumps, or charging flow needed..
g.
Step 17a:
Step 17a instructed the operator to use PZR spray to
depressurize to decrease subcooling.
At this point only one
RCP was running.
The step did not give the operator
any
guidance on which spray valve was associated with which RCP,
ie. B spray valve goes to .C RCP.
h. Step 18a:
This step required the operator to take. actions
based on
RCS temperature.
The step did not specify which RCS
temperature to use. ie. Th, Tc, T/C.
i
.
Step 20b and 29b RNO: Venting an accumulator was an infrequent
operator action. - There was no guidance given to the operator
addressing required valve alignment.
j.
Step 22:
This step required the operator to take actions based
on RCS
temperature.
The step did not specify which
temperature to use. ie. Th, Tc, T/C.
k.
PSTG
DEV,
Steps 8 & 9:
EPP-15 action steps 8 & 9, and the
corresponding steps in the ERG were in the reverse order of the
way they appear in the TD.
1. PSTG DEV, Steps 11 thru 23:
Steps 11 thru 23 of EPP-15 were not
addressed in the TD.
EPP-15 was written against Rev 1A of the
'ERG and the TD was written to Rev. 1 of the ERG.
16.
EPP-16 Uncontrolled depressurization of all steam generators
a. PSTG DEV, Step 3:
The GTG bases for this procedure indicated
that the first of three major decisions was. the control room
decision regarding which generator to concentrate
their
isolation efforts on.
The assumption was that concentrating
on one generator might allow.early transfer from EPP-16 to
EPP-11. The procedure did not isolate one generator at a time
nor was there any caution or note concerning the need for that
decision.
19
b. Step 4 RNO
a:
Aux feed flow could not
be throttled to
individual generators from the control room; only total flow
throttling capability and individual S/G-feed valve open/closed
conditions were possible.
To maintain 25 gpm per S/G,
an AO
would have had to be dedicated to throttling local valves at a
time when AO talent was in short supply due to the isolations
in progress and rapidly decreasing CST inventory. Selection of
the conflicting alternatives of dedicating
an
AO to local
throttling or doing the best that can be done from the control
room to insure minimum constant flow to all three S/Gs was not
covered in the procedure.
c. Step 31 RNO a5:
The PZR heater transfer to the emergency bus
which was accomplished in step 31 RNO a4 was not restored to
normal after the substep 5 restoration of offsite power.
d.
Step 29, caution 1:
The GTG step description table for ECA-2.1
was incorrectly titled ES-1.1
on pages 66 and 67 of the LP
plant set.
e. Foldout B-F:
Item E of foldout D directed the user to go to
EPP-24 if an RHR pit level reached the limit level.
Since it
was important to continue EPP-16 actions concurrently, the "go
to" appeared to be in error; an instruction to refer to EPP-24
and continue concurrently in EPP-16 would
have been more
appropriate to the mitigation strategy.
f.
Step
24
RNO:
level
was one
inch per gradation.
The
scaling was inconsistent with a parameter value of 12.4.
17.
EPP-17 SGTR with loss of reactor coolant: subcooled recovery
a. Step 5 RNO and step 27a RNO:
This -RNO required an attempt to
restore offsite power.
No reference was provided for the
appropriate procedure to be used. During the walkthrough, the
operator indicated that he would use a procedure to perform
this task.
b. Step 5 RNO d and step 27a RNO 4: These RNO steps required
verification of adequate
DG capacity to load instrument air
compressors and battery chargers. These steps did not provide
the load that these components would require. No procedure was
referenced for loading the battery chargers.
c.
Step 5 RNO: Step 4 RNO of ERG ECA-3.1 required verification of
adequate DG capacity to load charging pumps and
shed non
essential loads if necessary. The TD did not justify why this
action was moved to step 9.
20
d. Step 6b
RNO:
This step directed that the CV spray pumps be
stopped when CV pressure is less than 4 psig.
Footnote 2 of
ERG ECA-3.1 required use of the CV . signal reset value.
The
setpoint document indicated that a value of 4 psig is used
instead of 20 psig.
the initiation setpoint (reset
value).
The justification indicated that using the value corresponding
to the adverse containment was more conservative.
The more
rapid depletion of the
supply was not addressed in the
justification.
e. Step
16:.
This step required PZR heaters to maintain
pressure and subcooling. Step 15 of ERG ECA-3.1 required the
heater switches to be turned off. The TD-did not address this
difference.
f. Step 18 and 21, notes:
These notes required RCP(s) to be run in
order of priority to provide PZR normal spray.
The order was
not specified.
g. Step 21a
RNO:
This RNO required that if natural circulation
was not verified, then increase dumping
steam
from intact
S/G(s).
The
RNO of step .20 of ERG ECA-3.1 did not limit
dumping steam to only the intact S/G(s). The TD did not address
this difference.
n. Step 22b:
This step required turning
on
PZR heaters as
necessary.
There
was
no
guidance defining "as
necessary".
During the walkthrough,
an operator thought that this was to
establish saturation temperature. in.
the PZR.
However, he was
unsure that this was the intent of the step.
i.
Step 23d:
This step required shutdown margin to be adequate.
There was no guidance defining "adequate".
j.
Step
33
RNO:
This
RNO required refilling the S/G(s).
No
precaution was provided to slowly refill the S/G(s) so that the
adverse conditions in the RNO might be avoided.
18.
EPP-18
SGTR with loss of reactor coolant: saturated recovery
a. This procedure contained many step deviations from the TD,
similar to those listed for other EPPs.
19.
EPP-19 SGTR without pressurizer pressure control
a. Step 4a RNO:
This RNO restored power to the PZR PORV valves.
There was no guidance on how to accomplish this task. During
the walkthrough,
it took the operator between 3 and 4 minutes
to determine which panels and circuits feed the valves.
- ~
21
Step 5 RNO:
This .RNO started a charging pump if
one was not
running.
No check was performed to see if the RCP seal supply
valves should be closed to prevent thermal damage to the RCP
seals. Such a check was contained in the step 10b RNO.
c.
Step
6, caution:
This caution was the
same
as the AFW
switchover criteria of Foldout G.
d.
Steo 10a RNO:
This RNO provided no guidance on how to attempt
to restore offsite power to the emergency busses.
During the
walkthrough, the operator indicated that he would not attempt,
this without a procedure.
e. Step .16a RNO 4: This RNO required verification of adequate DG
capacity to
load instrument air compressors
and battery
chargers.
The anticipated air compressor and battery charger
loads were not provided in the procedure., During the walkthrough,
an operator required between 3 and 4-minutes to locate the
information. Interview of another operator revealed that he
did not know where this information could be obtained.
Both
operators indicated that they would not load a battery charger
without a procedure.
No procedure reference for performing
this task was provided.
,f.
Step 22, note:
This note conditionally transferred to PATH-2,
Entry Point M. The ERG note of ECA-3.3 transferred to step 29
of E-3.
Entry Point M transferred to step 30 of E-3.
Entry
Point M transferred below the caution associated with step. 30.
Step 29 of E-3 was sequenced to be completed before step 30.
The transfer point difference was not justified in the TD.
g. Step 26, caution: This caution required pressures in the RCS
and the ruptured S/G be maintained less than the ruptured steam
line PORV setpoint. The procedure did not require the setpoint
to be adjusted to maximum. The caution did not provide a value
for what the.maximum allowed pressure should be.
h. Step 29 RNO: This RNO did not require the ruptured S/G to be
refilled at a specified slow rate.
The discussion on p. 82 of
ERG ECA-3.3 described that the refill should be slow to prevent
the adverse consequences listed in the.RNO.
i. Step 30, caution 1:
This caution stated that steam should not
be released from any ruptured S/G if water existed in its steam
line.
The method for determining if water existed in the steam
line was not specified.
Control
room instrumentation can be
offscale without water being in the steam lines.
22
j.
Step 30a:
This step provided three methods for depressurizing
the RCS and ruptured S/G(s). The third method, dump steam from
ruptured S/G(s),
could be accomplished by two means, dumping
steam to the condenser or- to the atmosphere.
Discussion
contained on p. 87 of ERG ECA-3.3 indicated that dumping steam
to the atmosphere was the least desirable alternative.
This
was not specified in the step.
k. Step'32d:
This step checked that shutdown margin was adequate.
inere was.no guidance defining "adequate".
20.
EPP-20
LOCA outside containment
a.
PSTG
DEV,
Step 1:
The verb "check" differed from the verb
"verify" used in the PSTG.
21.
EPP-21
Energizing pressurizer heaters from emergency busses
a. Step 1, RNO:
The verb used in this step could not'be used for
breakers as defined in the action verb list.
b. Step 1:
The abbreviations SERV, TRANS, HTR, KW, AUX, BLDG, MG,
TURB,
and GEN were not on the "Abbreviations used in the EOP
network" list.
c. Step
1:
The use of the verb "check" together with "removed"
(see page 5, bottom) is inconsistent and conflicting.
d.
Step 2:
The abbreviation EDG was not on the "Abbreviations
used in the EOP network" list.
e. Step 3:
The abbreviations BKR,
ARM,
PRESS,
HTR,
PNL,
EDG,
KW,
PRZR,
and RTGB were not on the "Abbreviations used in the EOP
network" list.
f.
Step 3:
This instruction contained no verb.
g. Step 3c:
The verbs used in this step were not defined in the
action verb list.
h. Step 3d:
The verb used in this step could not be used for
breakers as defined in the action verb list.
i.
Step 3f RNO:
The verbs used in this step were not defined in
the action verb list.
j. Step 4:
The verb used in this step was not defined in the
action verb list.
k.
Step 4c:
The verbs used in this step were not defined in the
action verb list.
23.
Steps 4c&d:
The abbreviations BKR,
ARM,
PRESS, HTR, and PNL
were not on the "Abbreviations used in the EOP network" list.
m. Step 4.f RNO:
The verbs used in this step were not defined in
the action verb list.
n. Step 4g:
This step required "Run. controller down to obtain
maximum output". This phraseology was confusing and- needs to
be reviewea.
o. Note 5:
The "multiple statements within this note" wer.e not
"separately identified by noting them with asterisks" as is
required by the writer's guide.
p. Step 5:
The wording of this step was
not definitive in
specifying the "as required" action.
q. Step 6:.
The verb used in this step was not defi'ned in the
action verb list.
r. Step 1:
One instruction stated "52/14C, Fuses Removed". There
was confusion on the part of the operator regarding what fuses
to remove.
s. Step 1:
Breakers 52/22B, Power supply to B SI Pp and breaker
52/29b Power supply to B SI
Pp were part of the B SI Pp
Modification and were no longer required to be on the list.
t. Step 3:
This step did not provide the operator with any
reference to Group A power supply.
u. Step 3a:
This step did not provide the operator with the
physical location of the disconnects for SST-2A and 2F.
During
the walkthrough of the procedure,
the operator was unable to
locate the disconnects without assistance.
v. Step 3b:
While performing the walkthrough of the procedure,
step 3b. could not be performed because the 480V bus E-1 Main
breaker tool could not be located.
w.
Step 3f 1, 2 & 3:
This step instructed the operator to
"monitor emergency bus response to prevent DG overload." There
was no indication 'of emergency bus current or voltage, but there
was an indication of EDG current and voltage.
x. Step 4:
This step did not provide the operator with any
reference to control heater power supply.
y.
Step 4f,
1, 2 & 3:
These steps instructed the operator to
'"monitor emergency bus response to prevent EDG overload. There
was no indication of emergency bus current or voltage, but there
was an indication of EDG current and voltage.
Step
4g:
This
step
was
inconsistent between controller
indication (process) and the procedure instruction. This was a
reverse acting controller.
22.
EPP-22
Energizing plant equipment using the' dedicated shutdown
diesel generator
a.
This procedure contained step deviations from the PSTG, similar
to those listed for other EOPs.
23.
EPP-23
Restoration of cooling water flow to reactor coolant pumps
a.
Step 4 RNO:
This 'RNO required emergency cooling water to be
established to the charging' pump oil cooler. The materials to
perform this task were not pre-staged.
b. Step 9a:
This step checked that the charging flow control
valve HCV-121 was open.
The only indication in the control
room was a demand signal on- the flow controller.
Actual valve
position determi'nation would have required local verification.
Because the step required HCV-121 to be checked open instead of
verified open,
the operator would have had- to perform the RNO
to open the HCV-121 bypass valve instead of attempting to open
HCV-121.
C.
Step 9b RNO:
This RNO opened the loop 1 hot leg charging valve
without trying to open the loop 2 cold leg charging valve
because step 9b stated "check" instead of "verify".
24.
EPP-24 Isolation of leakage in the RHR pump pit
a. Step 1:
This step required the use of a formula or graph to
find the
RHR pit level because .of
the use of the verb
"determine".
This was not the, proper verb for
this
application.
b. Step
1:
Substeps a and b were methods of accomplishing the
action of step 1,. unlike substep 1c which was an entirely
unrelated action.
c. Step 1c:
The verb used in this step was not defined in the
action verb list.
d. Step *2c:
This
substep could
not be started prior to
completion of substeps la and lb.
However,
this important
ordering of actions was not "specifically stated in- the step
containing the task nor in an associated note" as required by
the writer's guide.
e. Step 2c:
The verb used in this step was not defined in the
action verb list.
25
f. Step 2d:
The verb used in this step was not defined in the
action verb list.
g. Step 2d:
The abbreviations CV,
RECIRC,
HX,
and DISCH were not
on the "Abbreviations used in the EOP network" list.
h. Step 3 RNO: The three verbs used in this step were not defined
in.the action verb list.
i.
Step 3 RNO:
The abbreviations CV,
RECIRC,
HX,. and DISCH were,
not on the "Abbreviations used in the EOP network" list.
j Step Sc:
The verb used in this step was not defined in the
action- verb list.
k.
Step Sd:
The verb used in this step was not defined in the
action verb list.
1. Step 5d:
The abbreviations CV,
RECIRC,
HX,
and DISCH were not
on the Abbreviations used in the EOP network" list.
m.
Step 5d:
Some of these five valves were already in the
desired position and therefore the verb
"perform" was
inappropriate.
n.
Step 6 RNO:
The abbreviations CV,
RECIRC,
HX,
and DISCH were
not on the "Abbreviations used in the EOP network" list.
o.1
Step 7:
The verb used in this step was not defined in the
action verb list.
25.
EPP-Supplements
a.
No comment.
.26.
EPP-Foldouts
a.
Foldout A:
1.
Step b:
This step contained the SI actuation criteria.
During the walkthroughs,
an operator, when asked how he
would manually determine that RCS subcooling was less than
25 degrees F, indicated that he would use the cold leg
temperature Tc. In this application, Tc would not provide
the most limiting value.
2. Step b:
Generic footnote, attachment 9.0 of the setpoint
study addressed the error associated with the core exit
thermocouple/core cooling monitor system as the basis for
the selection of the 25 degree F setpoint value for the SI
actuation criteria.
The attachment did not address .
whether or not 25 degrees F bounded the errors if
the
value had to be determined manually from other process
instrumentation.
26
IV. FRP comments:
1. FRP-C.1
Response to inadequate core cooling
a. Step 1 RNO:
This step required the operator to "Align valves"
in response to an SI.
There was no list of valves provided.
b.
Steo 2c RNO:
This step required the operator to "Align valves"
in resoonse to an SI.
There was no list of valves provide.
.
C. Step 2d:
This step required the operator to take action based
on an RCS pressure of 170 psig. This pressure was based on the
maximum pressure at which RHR would inject into the RCS.
This
figure was
based
on suction pressure, pump Delta P and
instrument error. If the operator could not verify flow from
the RHR system,
he was to assume that there was a problem with
the RHR system,
and perform -a valve line 'up as a method of
investigating the loss of RHR flow. -The suction pressure from
the RWST was 13#, and the delta P across the pump ranged from
126 to 138 psig which would have produced the maximum pressure
of
151#
and the flow would have been zero.
From this it
appeared that instrument inaccuracies may have been applied in
the wrong direction.
d. Step 6a:
This step instructed the operator to obtain a
hydrogen concentration measurement
but provided no detailed
guidance.
e. Step 6b:
The operators did not know whether 'the containment
hydrogen concentration monitors
i.n
the control
room were
calibrated for varying containment humidity following a
degraded containment condition.
f.
Step 7a:
The main step stated "levels" and part a of the step
stated "level".
The
number of S/G levels needed to satisfy
step 7a was not specified.
g.
Step 7b:
This step was inconsistent with the rest of the EOPs
in referring to feed, flow.
Other EOPs referred to "total feed
flow" as meaning main
mean
strictly AFW flow.
h.
Step 9c:
The purpose of step 9 was to depressurize the S/G to
160 psig in order to depressurize the RCS to 160 psig and empty
the accumulators to a point just before the nitrogen was
introduced into the RCS.
Step 9c required that "at least two
hot leg temperatures less than 370 degrees F" be met before
depressurizing. If the core was in a degraded condition with
TCs greater than 1100 degrees F, the RTDs may have been in an
area that was voided. The 370 degree F criteria may have been
inappropriate in this case.
27
i. Step 10.:
The conditions for isolating an accumulator in step
10 "two
hot leg temperatures less than 370 degrees F" were
different than the equivalent step 18 "RHR pump flow indication"
in this procedure.
The comment on step 9c of this procedure
applied here also.
j.
Step 10b RNO:
Venting. an
was
an
infrequent
operator action. However,
there was. no guidance given to the
operator addressing required valve alignment.
k. Step 14b, .19a, and 21a: The 350 degree provision was a generic
Westinghouse number corresponding to a 1200 degrees F core exit
T/C temperature for inadequate core cooling. The 1200 degrees F
was changed for HBR to 1100 degrees F. The use of 350 degrees F
was not justified.
1.
Step
16
RNO:
This statement, "Start RCPs as necessary until
Core Exit T/Cs less than 1100 degrees F" was not clear.
There
was no operator guidance on the number of RCPs to be started or
the time or other conditions between RCP starts.
m.
Step 17:
in the statement, "Try to locally depressurize all
intact S/Gs to atmospheric pressure",
the word:
"locally"
needed clarification.
n. Step 20:
Step 20 instructed the operator to check for "SI
flow".
There was no guidance on what constituted an adequate
amount of SI flow.
2.
FRP-C.2 Response to degraded core cooling
a.
Step 1, caution:
This
caution
incorrectly contained a
conditional action step directing a transition.
b.
PSTG DEV, Steps 1 and 2:
The verb "check" differed from the
verb "verify" used in the PSTG.
c. Step 2b:
Step 2b required a pressure reading of 1520 PSIG.
The.. pressure indicators PI-402
and PI-501 did not exhibit
adequate resolution to precisely read.desired pressure.
d.
Step 3, caution:
This caution
incorrectly contained a
conditional action step.
e. Step 4, note:
This note incorrectly contained a conditional
action step.
f.
PSTG
DEV,
Step 8, caution:
This caution was not addressed in
the deviation document.
28
g. PSTG DEV, Step 10a:
The expected response value of 370 degrees
F differed from the value of 400 degrees F that was included in
the PSTG.
h.
PSTG DEV. Step 13:
The verb "check" differed from the verb
"verify" used in the PSTG.
3.
FRP-C.3
Response to saturated core cooling
a.
Step 2a:
This step checked SI and RHR pumps running.
The
associated
RNO started pumps.
No caution was provided to
prevent both RHR pumps from running greater than 9 minutes with
RCS pressure greater than 170 psig.
The vendor had indicated
that operation of both RHR pumps for greater than 9.3 minutes
under these conditions could result in pump damage. This was
included in applicable foldouts as an RHR Pump Trip Criteria.'
No Foldouts are applicable during execution of this procedure..
b.
Step 2c RNO:
This RNO aligned 'SI pump valves.
During
walkthroughs, the operators failed to identify that the hot leg
injection -path is available if
the cold leg path is not
available.
c. Step 3, caution: This caution contained an action step related
to the performance of Step 3a.
d.
Step 3a:
This step says to check PZR PORVs closed.
The ERG
Background document FR-6.3 indicates that PZR PORVs are closed
to preclude the possibility of an undetected stuck open valve.
Turning the control switch to close may be required to fully
close a PORV.
'Thus
checking position i.ndication may not be
sufficient.
e. Step 3c: This step required.other RCS vent paths to be closed.
The phrase "other RCS vent paths" was not defined.
4.
FRP-H.1
Response to loss of secondary heat sink
a. Step 1, caution:
The shift to RCS feed and bleed.with any S/G
wide range level greater than or equal to 60 percent appeared to
be premature since level in the other two units could have been
on scale, greater than or equal to 25 percent NR and immediately
recoverable (e.g. aux feed pump switching or feed flow increase).
The licensee was aware of this and was conducting a plant specific
analysis to determine the feasibility of relaxing the 60 percent
in any S/G criteria.
b.
Step 4, caution:
was
required
to
install
the
jumpers in case of a false high level
signal.
No jumper
installation
procedure
existed to
support
this
step.
Therefore,
valuable time would
have been lost chasing the
wiring diagrams and making up a temporary procedure.
The procedure did not reflect the plant modification which
shifted primary containment air to an external nitrogen supply,
backed up by internal N2 supplies and external instrument air.
(e.g. step 11 concentration on instrument air restoration while
N2 restoration was not-considered).
d.
Step 11:
Since step 11 was no longer critical due to the N2
modification, It
appeared- that the procedure
should be
reordered to
put instrument air restoration after feed and
bleea initiation.
e.
Step 21: This procedure placed the operator in a loop between
step
21 and
23.
The
ERG,
at this point is looping until
inventory addition can be terminated and normal charging and
letdown
established.
FRP-H.1. as written did not accomplish
this and the deviation document did not justify the difference.
5.
FRP-H.2
Response to steam generator overpressure
a.
PSTG
DEV,
Step
1:
The verb "check" differed from the verb
"verify'.' used in the PSTG. In addition, the item "FW isolation
vlvs" was included in the PSTG.
b. Step 4, caution:
This caution -incorrectly
contained a
conditional action step.
c. PSTG DEV, Step 7:
The RCS setpoint of 540 degrees F differed
from the value of 535 degrees F shown in the PSTG.
6.
FRP-H.3 Response to steam generator high level
a. This procedure contained step
deviations from the PSTG,
similar to those listed for other EOPs.
7.
FRP-H.4 Response to loss of normal steam release capability
a.
No comment.
8.
FRP-I.1 Response to high pressurizer level
-a. Step 2b: The procedure did not reflect the plant modification
which shifted' primary containment air to an external nitrogen
supply, backed. up by internal
N2 supplies and external
instrument air.
(e.g. instrument air restoration while N2
restoration was not considered).
9.
FRP-I.2 Response to low pressurizer level
a. Step 3c RNO:
This RNO did not specify a value for the amount
of charging flow required to cool letdown. Footnote 1 of ERG
FR-I.2 says to enter minimum indicated charging flow to provide
letdown cooling in the regenerative heat exchanger.
30
b. Step 6:
This step required turning on PZR heaters as necessary.
There was no guidance defining "as necessary".
The ERG Background
document FR-I.2 indicated that it was desirable to have stable
RCS pressure prior to returning to the guide and step in effect.
10.
FRP-1.3
Resoonse to voids in reactor vessel
a.
No comment.
11.
FRP-J.1
Response to high containment pressure
a. Step 2a: This step did not provide the operator clear guidance
concerning
proper containment ventilation isolation.
The
containment ventilation isolation panel
in the control
room
contained four windows that belong to other actuation signals.
b. Step 2a RNO:
The preferred method of "Alarming R-11 or R-12"
was not provided.
c. Step 3c and e RNO:
This step lacked sufficient detail
regarding proper valve alignment.
d. Step 6b: The step lacked detail regarding which valves were to
be isolated.
e..
Step 7a:
This step instructed the operator to obtain -a
hydrogen concentration measurement. Guidance was not provided
to the operator on where to obtain the sample or what methods
of indication were acceptable.
f. Step 7b: This step stated "LESS
THAN 0.5 percent IN DRY AIR".
The
operators did not iknow
if -the
containment )hydrogen
concentration monitors in control
room were calibrated for
varying containment
humidity following degraded containment
conditions.
12.
FRP-J.2
Response to containment flooding
a.
No comments.
13.
FRP-J.3 Response to high containment radiation level
a.
No comments.
14.
FRP-P.1 Response to imminent pressurized thermal shock
a.
Step le and
12e
RNO:
The three asterisked substeps gave
actions necessary to isolate the S/G, but did not specify "the
faulted S/G".
b.
Step le and
12e
RNO:
There was no guidance given to the
- operator addressing which feed valves needed to be shut to
isolate the S/G.
31
.
c. Guidance to the operator addressing what actions to take if the
level was less than 12.4 inches was lacking.
d. Step 20:
This step did not provide guidance
as to what
pressure to maintain or the desired condition of the primary
system.
e. Step 21:
This step was restrictive and did not provide the
operator with a tolerance band.
f. Step 22al:
There was no operator guidance on when the clock
started for the one hour timed soak.
g.
Step 23c1: . There were no defined pressure limits to be
maintained on ATTACHMENT A.
h. Step 23c2:
This step contained a typo. The 50 degrees F should
be 50 degrees F per/hr.
15.
FRP-P.2
Response to anticipated pressurized thermal shock
Entry Condition:
This statement indicated *that the entry
condition was YELLOW. Revision 1A of ERG FR-P.2 indicated that
the entry condition is ORANGE.
ERG *F-1.4, revision 1,
indicated that the critical safety function status tree for
enterina
FRP-P.2
is YELLOW.
The TD did
not provide
justification for selecting YELLOW as the entry condition.
The licensee confirmed with the NSSS vendor that "ORANGE"
in the ERG was in error.
b.
Step -1:
The
ERG step 1 was preceded by a note defining a
faulted S/G.
No note was included in FRP-P.2 step 1.
The TD
did not justify the omission of the note.
c. Step
3:
The, referenced curve,. reactor coolant system
pressure-temperature limitations for cooldown,
after 15 EFPY for 1/4 T as 282 degrees F and 3/4 T as- 139
degrees F.
TS
Figure 3.1-2.b listed these values as
290
degrees F and 149 degrees F, respectively.
d.
Step 4b:
This step provided
RCS cooldown restrictions by
referencing those of
curve 3.4, reactor coolant system
pressure-temperature limitations for cooldown and GP-007, Plant
cooldown from hot shutdown to cold shutdown.
The TD did not
provide technical
justification that these restrictions are.
appropriate.
16.
FRP-S.1
Response to nuclear power generation/ATWS
a. Step 1:
This procedure did not specify "Steps 1 through 4 are
IMMEDIATE ACTION" as provided in ERG FR-S.1, Step 1, note.
.
32
b.
Step 1 RNO:
This step required an operator to be dispatched to
locally trip the reactor trip breakers or rod drive motor
generator sets. Page 70 of the ERG background document FR-S.1
indicated that boration
had
to
be initiated before time
consuminq local actions to trio the reactor were taken.
Local
operator actions to trip the reactor were addressed in ERG
FR-S.1, Step 5 RNO.
No justification for inclusion- of local
actions in Step 1 RNO was documented in the TD.
C. Step 3a:
This step required checking whether the AFW or FW
pumps were running,
and if
not running,
then to start the
pumps...
Step 3 of ERG FR-S.,1 did not require FW pumps to. be
checked or.started. No justification for inclusion of the FW
pump in the procedure was documented in the TD.
d.
Step 3b:
This step required the SD AFW pump to be running if
necessary. There was no guidance defining'"if necessary".
e.
Step 4b RNO:
This RNO defined alternative pathways for
boration if the emergency boration path was unavailable.
This
step did not address use of the other boric acid transfer pump
if the one aligned to the system failed to start.
f. Step 4d:
This step required the loop 2 cold leg charging valve
to'be checked open. If closed, the RNO action was to open the
loop 1 hot leg charging valve.
Thus,
no attempt was made to
open the loop 2 cold leg charging valve.
g. Step 4f RNO:
This RNO required radiation monitor R-11 or R-12
to be alarmed if containment ventilation isolation valves were
not closed. During walkthroughs, operators indicated that they
would either pull the fuse or source check one of the monitors
to generate an isolation signal.
This RNO did not adequately
specify the intended operator action.
h.
Step 4e RNO:
This RNO did not include alignment of the normal
charging flow path if no charging flow to the RCS existed.
i.
Step 5b RNO: This RNO required the operator to close the MSIVs
and MSIV bypass valves if
the turbine did not trip.
This step
did not address other actions such as tripping the turbine at
the front standard or securing the EH oil pumps.
j.
Step
11 caution 2:
This caution was a conditional action
statement.
k.
Step 12 RNO: This step did not reference the procedure number
for
restarting
the
battery chargers.
During procedure
walkthroughs, operators indicated that they would not perform
this task without a procedure in hand.
- 33
Step 14, Note:
This note was identjfied as a caution in ERG
FR-S.1.
The
ERG caution read: "Boration
should continue to
obtain adequate
shutdown margin during subsequent actions".
This note read: "Boration should continue to obtain adequate
shutdown
maroin."
No justification for the differences was
addressed in the TD.
17.
FRP-S.2
Response. to loss of core shutdown
a. Step 1 RNO a:
Determination that an intermediate range NI
channel
was undercompensated' requi.red assessment by I&C
personnel. .I&C staff were not available .around
the clock.
This step did not clearly explain the operator actions when one
channel hangs up above 10E-10 while.the only other channel was
decreasing with negative SUR.
Two walkthrough operators
concluded that it
was appropriate to wait for I&C and not to
borate since undercompensation was unknown.
b.
Step 1 RNO,
last paragraph pg.
3:
There was uncertainty as to
the boration lineup during walkthroughs.
The operators were
uncertain whether normal or emergency boration was intended.
V.
CSFST comments:
1. Subcriticality
a.
No comments.
2. Core cooling
a..
No comments.
3. Heat sink
a.
No comments.
4.
Integrity
a.
No comments.
5. Containment
a.
No comments.
6.
Inventory
a.
CSFSTs 2 and 6. had been modified due -to the absence of RVLIS.
RVLIS had been installed for at least 17 months but was not yet
operational.
34
VI.
AOP comments:
1. AOP-001 Malfunction of reactor control system
a. Step 1.1.2.6:
The red pen on TR-408 was incorrectly labeled
"High Tav (Red)".
The instrument displayed median Tav as was
required by this step.
b.
Paragraph 4.3.2. step 11.
Three operators were unable to
perform this step; two were uncertain whether it
was an AO or
licensed operator step.
The external
cabinet doors were not
marked to reflect which
one of the three contained the
converter.
When
the converter was located, it had no
instrument label nor was it
identified in any fashion as the
P/A converter.
2. AOP-002 Emergency boration
a. Step 3.1.1.2:
CVC-358
was a local
valve; the others were
operated from the control room.
b. Step 3.2.10:
The procedure,did not refer to OP-301.
3. AOP-003 Malfunction of reactor make-up control
a. Step 3.1.1:
This step provided actions to secure potential
sources of water into the volume control tank. This step
secured the boric acid transfer pump but did not secure the
primary water pump.
4.
AOP-004 Control room inaccessibility
a. Step 3.2, caution:
This caution incorrectly contained a
conditional action step directing a transition.
b. Step 3.2.16.2:
This step did not provide the criteria
necessary to determine which containment fan coolers were to be
started.
C. The NRC observed several valves which did not follow the normal
convention of open counterclockwise, close clockwise.
This was
not indicated at the local operating station (e.g.
FCV-498C,
FCV-488B and FCV-478A).
5. AOP-005 Radiation monitoring system
a. Step 1.3.1.2,
substeps 3-5: The sequence incorrectly implied
that the paging system interrupted the evacuation alarm.
0I
35
b. Step 1.3.2.1.4:
This step referred to AOP-004 in the event of
a control room evacuation. A "go to" transfer appeared to be
more appropriate,
c.
Step 1.3.2.6:
No confirmation of sample station suction
ventilation was included in-the -step.
0
Meters RI-014 and Ri-018 on the unlabeled waste disposal boron
recycle panel both contained two scales and only one pointer.
There was no scale switching.
The scale ranges were 10EO-10E4
and 1OEO-10E6.
The operator was uncertain which scale was in
use and therefore was unable to read the instruments.
e. The
"green"
indicating lenses
on. the waste disposal boron
recycle panel ranged from green to washed out blue to almost
colorless.
f.
Step 2.3.2.4.2:
This step referred to service water flow but
only stated "check fan cooler flows and out-let temperatures".
6. AOP-006 Turbine vibration
a.
General:
The conclusion of the team was that the procedure as
written would not be an effective aid to the operator if needed
0 in handling an abnormal turbine vibration.
Two new recorders
have been installed in the control room,
and the procedure has
not been updated to reflect the new terminology.
7. AOP-007 Turbine trip without reactor trip below P-7
a. Step.3.2:8 This step instructed the operator to shut the MSIVs
and the MSIV bypasses if
the turbine start-up was going to be
delayed. more than one hour.
The purpose for shutting the
valves was not clear.
8t. AOP-008 Accidental release of liquid waste
a.
No comment.
9. AOP-009 Accidental release of waste gas
a. Step 3.2.3:
This step directed that fuel handling building
ventilation be shifted but did not specify the desired lineup.
b.
Step 3.2.5:
"...
REDUCE release rate
...".
This
step
neglected the option of increasing dilution flow.
-c. Step 3.2.7,
caution:
This step should be performed
under
the direction of RC personnel; E&C/RC personnel are not all HP
qualified..
36
10.
Inadequate feedwater flow
a.
Symptoms:
The following symptoms were duplications
1.1.5 High hotwell level (HOTWELL LEVEL Hi/Lo ALARM)
1.2.4 High hotwell level
1.1.6 Low feed pump suction pressure.
PRESSURE)
1.2.2 Low feed pump suction pressure
1.2.3 Low condensate pump discharge pressure
b.
Symptoms, 1.3.4:
This symptom was not appropriate as a control
room symptom.
There was
no indication for LCV-1530B in the
control room.
c.
Symptoms, 1.3.5:
Tavg and.Tc would increase on an inadequate
feedwater flow whereas the procedure did not address the
possibility of a feedwater control valve or bypass valve
failure.
d.
Step 3.0:
The procedure did, not address the possibility of a
feedwater control valve or bypass valve failure.
e. Step 3.1.1:
The priority for running the pumps was not given.
f. Step 3.1.2:
This step did not address the method or priority
of reducing turbine load.
g. Step
3.1.2:
The
maximum
power
for
the
different
feed/condensate pump combinations was not given.
h. Step 3.1.2:
There was no caution to the operator warning of a.
S/G level decrease due to shrink on load reduction.
i.
Step 3.2.1:
This step was superfluous and was extra material
the operator had to read through in a time critical situation.
j.
Step 3.2.3:
This -step did not specify that the only place
hotwell 'level could be read was locally.
k..
Step 3.2.4:
This step did not specify that the only place
drain tank level and feedwater heater level could be read was
locally.
1. Step 3.2.5: This step did not address the control rods as a
means of control.
Also the parameter the operator was.
controlling was Tavg/Tref and not equilibrium conditions.
m.
Step 3.2.6:
This step was superfluous and was extra material
the operator had to read through in a time .critical situation.
n. Step 3.22.:
This step was superfluous and was extra material
the operator had to read through in a time critical situation.
o. Step 3.2.8:
Reclosing HCV-1459 was not dependent upon starting
the heater drain pump.
p
Step 3.2.10:
This step was superfluous and was extra material
the operator had to read through in a time critical situation.
q. Step 3.2.11:
The step was superfluous and was extra material
the operator had to read through in a time critical situation.
11.
Loss of circulating water
a. Step 3.2.3:
This step failed to provide the criteria required
to determine adequate circulating water flow.
b.
Step 3.2.4:
This.step required local action without providing
adequate reference to location or pressure gauges required to
determine differential
pressure. The step failed to provide
the criteria required to determine high pressure.
c. Step 3.2.6:
This step failed to provide the the necessary
references required to take appropriate action.
12.
AOP-0 12-
Partial loss of condenser vacuum
a.
Step 3.2.3:
This step required local operator action without
providing adequate reference to the plant location.
This step
did not provide the criteria required to determine high DP nor
did it define high DP.
13.
Fuel handling accident
a.
No comments.
14. AOP-014
Loss of component cooling water
a.
Step 3.1.2.1: The name of valve DW-711 was missing from this
step.
b. Note 3.1.3:
This note stated that a plant cooldown should be
initiated, but did not tell the operators where to stop the
cooldown with- no
RHR available.
In this procedure,
the RHR
pumps have lost their CCW cooling water.
c. Step 3.1.3.1:
The
operator
needs to continue with this
procedure while concurrently using Path-1. Failure to continue
with this procedure could result in immediate damage to the CCW
pumps and the RCP shaft seals. This step did not clearly state
the requirement to continue with this procedure.
38
d.
Step 3.1.3.2:
This step did not state the size and location orf
the required fuse puller.
e. Step 3.1.3.3.b.
and c:
The operator could not monitor these
RCP temperature limits within two' minutes since the recorder
only printed approximately every five minutes.
RCP temperature
alarms were not included in this step as indicators to the
operator Tor stopping RCPs.
f.
Step 3.1.4:
The labeling on the charging flow-controller on
the
was inadequate.
The
demand
signal indicator was
labeled from 0 to 100 percent, with 100 percent indicating a
demanded valve position of closed.
Operators described it as a
"backwards"
indication.
The operators who were interviewed
stated that improved labeling, such as "OPEN" and "CLOSED", was
needed.
g.-
Step 3.1.4:
This step failed to direct the operator to run
only
one charging
pump at a- time.
A previous procedure
required two charging-pumps to -be- operated. After charging -and
letdown flow were isolated in this step, only one charging pump
was needed.
Since the -pumps were not being supplied with
cooling water,
running only one would avoid overheating two
charging pumps.
h.
Step 3.1.4:
With charging and
letdown flow isolated,
the
operators had lost the ability to control pressurizer level.
Thus pressurizer level would have slowly increased due to RCP
seal -water
flow.
This was revealed as a potential problem
during simulator exercises that the team observed.
This
procedure did not provide for prompt supply of alternate
cooling water to the charging pumps (see step 3.2.9.2 below).
It also did not provide a method to drain water from the RCS,
to.prevent excessive increase in pressurizer level.
1.
Step 3.2.1:
This temperature was required to be read locally,
a.fact that was not so indicated.
j.
Step 3.2.3:
The names of the valves in this step were not
included. Also, required local action was not indicated as
"local".
k. Step 3.2.9.2: The licensee had not provided dedicated fittings
to enable the operators to supply temporary cooling water to
the charging pumps,
safety injection pumps,
and residual heat
removal pumps. These fittings were not readily available, and
would have had to be manufactured.
In this procedure, all of
these pumps had lost their CCW cooling water,
reducing the
operators'
ability to maintain the
RCP seals intact and to
inject water i.nto the RCS. A number of design features of this
component cooling water system made it
more susceptible to
failure than similar systems in newer plants.
0
- 39
For these
reasons,
good procedures for handling a loss of
component cooling water were especially. important,
including
readily available ,dedi.cated pipe fittings.
1. Step 4.3:
This step was misleading,
in that it
stated "the
only possible way of losing all three CCW
pumps is by the
complete. loss of on and offsite power."
The team observed a
numoe r of potential ways of losing all CCW,
such' as a fire 'or
flooding in the CCW pump room, a pipe break in,
or a loss of service water to the CCW heat exchangers.
15.
AOP-015 Secondary load rejection'
a.
Symptoms 1.3: This symptom inappropriately read Unit "export"
load. It should have read Unit "output" load..
b.
Symptom
1.10:
This symptom- is no longer applicable.
The
actuation circuit has been removed..
c.
Step 2.8:
This step is no longer applicable.-
The actuation
circuit has been removed.
d. Step 2.9:
The step is no longer applicable.
The actuation
circuit has been removed.
16.
AOP-016 Excessive primary plant leakage
a.
No comments.
17.
Loss of instrument air
a.
No comments.
18.
AOP-018 Reactor coolant pump abnormal conditions
a. Step 1.3.1.2.2:
This step addressed actions associated with
loss of all CCW which were also contained in AOP-014,
Loss of
component cooling water.
It may have been better to exit to
AOP-014 than stay in AOP-018 under those conditions.
19.
AOP-019 Malfunction of RCS. pressure control
a.
No comments.
20.
AOP-020 Loss of RHR (shutdown cooling)
a.
No comment.
21.
AOP-021 Seismic disturbances
a.
Step 3.2.2:
The "Operating Supervisor" title has been changed
to "Operation Coordinator".
40
22.
AOP-022 Loss of service water
a.
Step 1.3.2.1:
This step required local action; that the action
was local was not indicated. This same comment applies to many
other steps in AOPs.
b.
Step 3.3.2.1:
The labeling for these valves was
on the
adjacent wall, and had been covered by wall mounts for seismic
supports, such that the label for SW-18 was totally unreadable.
c. Step 3.3.2.2.3: This valve was not commonly operated, and was
located in an out-of-the-way place,
so that it
was difficult
for some operators to find. The operators needed its location
to be stated in the step. This comment also applied to several
other valves in this procedure that were located among the
piping in the overhead of the auxiliary building, such as SW-52
and 53, SW-100, and SW-109.
The operator needed
enough
information in the procedure to allow placement of a portable
ladder in the right place the first time.
d.
Step 4.3.2.10:
Operators had no dedicated pipe fittings for
use with hose
to supply alternate emergency cooling water to
the safety injection pumps.
e. Step 6.1:
Operators
needed pit level alarms in order to
effectively respond to flooding in the service water pump pits.
All service water
pumps plus motor operated discharge and
cross-connect valves were located in these pits, and the pits
were all connected at about three feet above the floor level of
the pits. The plant was operated with the cross-connect valves
normally open.
As a result, flooding in one of these pits
could disable all of these valves by causing them to be under
water. A single pipe break could thus be unisolable by the
time is was discovered,
and could result in a loss of all
service water. No pit level alarms were installed, and the pit
sump pumps ware not supplied with vital power.
f. Step 6.3.3.3:
Valve FP-10 was located underground.
The steel
plate above this valve at ground level was not painted red or
labeled, making it very difficult for operators to find. Also,
the name and location of this valve were not included in the
step. In addition, the tool required to operate the valve was
not painted red or labeled, and its location was not stated in
the step.
Similarly, the names and locations of FP-4 and FP-5
were not in the procedure.
23.
AOP-23 Loss of containment integrity
a.
Step
1.5:
The
stated symptoms
were outside of the alarm
setpoints.
The control room alarm setpoints for containment
pressure were +0.9 psig and -0.4 psig.
This alarm was not
included as a symptom.
41
D.
Step 3.2:
Many of these subsequent actions were copied from
the TS, and the TS section was not referenced in the procedure.
In order to assure compli.ance with the TS,
the. situation
required the operator to look at the TS directly.
24.
Loss of instrument bus
a.
Ste
3..2: This step required local actions without providing
adequate reference to the. plant location.
25. AOP-026
Low frequency operation
a.
Step 3.1.1:
This step did not require the operator to verify
that the RCPs were tripped automatically by the underfrequency
-trip.'
b.
Step 3.1.2..1:
A caution was-missing prior to this step.
When
picking up additional generator load,
the operator needs to
ensure that generator reduced KVA limits are not exceeded.
c. Step 3.2.2:
The procedure told the operator to adjust
generator KVA,
but. not how to get a KVA number.
In interviews,
some operators did not know how to do this.
To get the
KVA
number, calculation by the operator was required. Calculations
by operators should not be required to accomplish steps in this
Drocedure.
d.
Step 3.2.3:
This step directed the operator to verify proper
voltage and frequency to the" emergency busses.
Verify meant
that if
it
was not so,
action was to' be taken to make it so.
The operator could not control voltage and frequency of the
grid,
and in this step was not instructed to place the
emergency busses on the diesel generators.
26.
AOP-027 Operation with degraded system voltage
a.
Step 1.1:
The 230 KV switchyard voltage had no indication or
alarm in the
control
room, as this had been
removed
approximately one year before. Therefore, this symptom was hot
valid.
b. Step 1.2:
The
115
KV switchyard voltage low alarm in the
control room was set at 112.4 KV.
However, during the.
simulator scenarios,
operators found that the setpoint was
required to be 110.4 KV for this alarm.
c.
Step 3.2.3:
This step required the operator to verify that the
E1-E2 tie bus was powered from the running emergency diesel.
Due to a plant modification that was done about one year ago,
this step was no longer applicable.
42
Step 3.2.8:
This step was not consistent with the intent of
the TS.
The step stated that if
a plant start-up was in
progress,
then continue with the start-up. At this point in
the procedure, the plant had both emergency diesel generators.
supplying power to the v ital busses, with nonvital busses being
supplied with degraded voltage
from offsite power.
Plant
start-up with such a degraded electrical system was not within
the intent of the TS.
e. Step 4.1:
This step stated that the procedure was required if
the plant was
shut down or at less that 5 percent power.
During simulator exercises, operators used this procedure when
the plant was at 100 percent power. Initial conditions
specifying when this procedure should be used needed to be better
defined.
27.
a.
Step 1.3.1.1.2:
This step required the use of a ladder to.
clear blockage from the outlets, however, there was no
dedicated ladder at the ISFSI.
b. Step 4.3.2.3:
The procedure required to perform this step was
not referenced (ERC-003).
VII.
Other document comments:
1. OMM-022 Emergency operating procedures user's guide
a. Paragraph 5.1.3:
This paragraph was in error; PATH-1 grid I-10
considered supplement D, not C.
b. Final paragraph of 5.3.4:
The discussion concerning heat sink
red path transfer to FRP-H.1 and hence to EPP-16 was in error.
c.
Final
paragraph of 5.3.4:
There was no EPP-16 caution
concerning
conditions
under
which
FRP-H.1
should
be
implemented.
2. Transition document, vol.1:
a. Table of contents:
In some instances, the page numbers listed
were incorrect.
b. Page 83,
pneumatic power:.
This section did not reflect the
plant .N2 CV modification.
APPENDIX C
WRITER'S GUIDE COMMENTS
This appendix contains writer's guide comments
and observations.
Unless
specifically stated, these comments were not regulatory requirements. However,
the licensee acknowledoed that the factual content of each of these comments
was correct as stated. The licensee further committed to evaluate each comment,
to take appropriate action and to document that action (proposed or completed)
in the response to IR-89-16. These items will be reviewed during a future NRC
inspection.
I. Deviations from the Writer's Guide
A sample of the EOPs was evaluated for deviations from the Robinson
writer's guide.
Types of deviations noted were characterized in this
section and accompanied by a list of examples of the specific deviations.
Note that some steps contained more than one example.
1. The following steps violated writer's guide directions for the
structure of logic steps or the use of logic terms:
EPP-8
Step 1, caution
Step 2d3 RNO
Step 3, caution
Step 4a RNO
Step 5, caution
Step 6, note
Step 6b
Step 11, caution
Step 12c RNO
Step 14, caution
EPP-10
Step Sa
Step 5b
Step 6c
Step 6d
Step 7
Step 8
Step 9
Step 9a3
Step 9a5
EPP-12
Step 1, note
Step 5, caution
Step Sa RNO
FRP-C.2
Step 1, caution
Step 3b RNO
Step 4, cote
Step 7, caution
FRP-H.2
Step 4, caution
PATH-1
A-5
B-3
B-11.
B-12
E-8
E-9
E- 10
E-11
F-2
H-7
H-9
H-10
PATH-2
A-10
B-2
B-9
B-12
B-13 (2 examples)
B-14
D-4 (2 examples)
0-12
G-9
G-12.
H-4
I-11 (2-examples)
2. The following steps violated writer's guide directions for the form
of transitions:
EPP-8
Step 2d3 RNO
Step 11d1
Step 14al RNO
Step 21 RNO
Step 28bi
EPP-12
Step 13c
FRP-C.2
Step 1, caution
Step 3, caution
PATH-1
H-6
PATH-2
A-10
H-5
1-12
FRP-C.2
Step 2c
Step 2e
Step 13
3. The following steps contained conditional actions within cautions or
notes, in violation of writer's guide direction.
EPP-8
Step 3, caution
Step 11, caution
EPP-12
Step 1, caution
Step 5, caution
FRP-C.2
Step 1, caution
Step 3, caution
Step 4, caution
FRP-C.3
Step 3, caution
FRP-H.2
Step 4, caution
FRP-S.1
-Step 11., caution
4. The
followina
steps violated writer's guide directions
for
referencing other procedures.
EPP-2
Step 23a
EPP-7
Step 20e RNO
EPP-17
Step 5 RNO
Step 27a RNO
II. Inadequacies in the Writer's Guide
The writer's guide did not thoroughly address each aspect of the procedures
nor did it define restrictively the methods designated for use in order to
assure consistency within and between
procedures
and to retain that
consistency over time and through personnel changes.
The Robinson writer's guide contained a number of areas where lack of
restrictive or thorough guidance had led to problems and inconsistencies in
the EOPs. These weaknesses were as follows:
1. Inclusion of contingent transitions was incorrectly allowed in
cautions by the writer's guide.
Because contingency steps and
transition steps required operator action, this contradicted other
writer's guide directions which specified that no actions would be
included in cautions.
Action steps by definition belong in the
numbered sequence of procedure steps.
2.
The writer's guide failed to provide directions for structure of
written steps, cautions, and notes in the path procedures.
3. Page 44 of 76 included a statement that proper logic statements were
to be used in foldout items.
That page also contained an example.
that included improper use of the logic term "if."
4.
The. wri.ter's guide failed to require special emphasis for the
transition terms
"go
to." - Because
transitions were
important
actions that could be difficult to perform,
special emphasis would
aid operators in their use of the procedures.
5. The writer's guide did not address nor require some method of
reminder to operators of steps that might be performed at some time
in the future (e.g., "WHEN condition, THEN action" sequences).
4
6. Attachment 6.8 of the wri.ter's guide, the abbreviation list, lacked
a number of acronyms commonly found in the EOPs. . For example:
F, SPDS, FW, SW, CV, EDG, PSID, GPM
7.
The writer's guide stated that. steps in the
RNO column would be
written in complete sentence format.
It failed to define complete
sentence format or to describe how it differed from the instruction
steps in the left hand column of the procedures.
8. The writer's guide failed to define a method for placekeeping.
9. The, writer's guide did not address the method for identifying
procedure steps when it was necessary to continue with that step on
the following page of a procedure.
10.
The writer's guide
allowed handwritten changes to- the path
procedures
and
CSFSTs.-
This method of revision contained the
potential for unreadable changes and was inappropriate.
11.
The writer's guide failed to define the type size, type style or
margins tobe used in the EOPs.
12.
The writer's guide failed to address the use of initial capitalization
in high level steps, although this method was applied in a number of
EOPs.
13.
The writer's guide allowed but did not require an alpha-numeric
border on path procedures.
14.
The writer's guide required line spacing in path procedures to be
"adequate".
No' objective criteria for determining
adequacy was
included.
15.
The writer's guide failed to define the use of parentheses or
quotation marks in the EOPs,
although these forms of punctuation
were used in the EOPs.
16.
The writer's
guide
stated that procedure designators used in
references in the path procedures must "positively and unambiguously
identify" the reference.
Specific directions and examples of
procedure designators were necessary but not provided to ensure
consistency.
17. Section 5.2.4.7,
page 12 of 76,
failed to provide criteria for'
editing the EOPs to meet the "expected minimum average level of
operator knowledge."
18.
The writer's guide
failed to describe a method for indicating
possible plural status.
For example,
as in the step "check faulted
S/Gs."
19.
The writer s guide failed to address certain action verbs used
throughout the
EOPs.
Examples included; running,
load,
faulted,
normal, contact, disconnect, and connect.
20.
The verbs "close" 'and "open"
were defined inconsistently in the
action verb list in that "close"
addressed both fluid flow and
electric current
whereas "open" addressed only fluid flow,
not
breaker ooeration.
This inconsistency led to undefined actions
.
Deing specified in the EOPs.
See for example EPP-21,
Energizing
pressurizer heaters from emergency busses, step 1 RNO.
21.
The writer's guide did not include a method for easily identifying
sections or subsections in the EOPs,
such as tabbing, in order to
facilitate rapid reliable movement within the EOP network.
22.
The writer's guide sections 5.3.4.6 and 5.3.4.7. provided guidance
for formatting tables and figures.
However,
it-
did not provide
examples of these formats to help procedure writers to prepare
consistently formatted tables and figures.
23.
The writer'-s guide section 5.3.4.14 provided guidance for labeling
of equipment or controls within the EOPs.
Clear criteria defining
"operator language" terms was not provided.
In addition, several,
examples
of
control
panel
equipment nomenclature and their
respective labels presented in the procedures were not provided.
III. AOPs
The AOPs were reviewed for application of human factors principles and
consistency with the presentation of information in the EOPs. Presentation
of information in ways that conflicted with the structure of the EOPs was
of concern because it required operators to cope with inconsistencies,
thereby increasing the burden on training and operator memory.
Specific
concerns were characterized below and accompanied by a list of examples.
Note that some steps contained more than one example.
.1.*
The following steps applied logic structure in a manner inconsistent
with that defined for use in the EOPs:
Step 3.2.5, note
Step 3.2.7.1
-
Step 3.2.8
Step 3.2.9.a
Step 3.2.10
Step 3.2.11, note
Step 3.2.12, note
Step 3.2.12
Step 3.2.14
Step 3.2.16
Step 3.2.16.2
Step 3.2.16.4
Step 3.2.19
6
Step 4 1
Step 4.2
Step 3.2.1
Step 3.2.2
Step 3.2.9
Step 3.2.11
Step 3.
2 15
Step 4.2
Step 1.3.1.1.1
Step 1.3.1.2.2
Step 1.3.2.10
Step 3.3.1.2.1
Step 3.3.1.3
Step. 3.3.1.6
Step 3.3.2.2
Step 3.3.2.2.3
Step 3.3.2.2.6
Step 3.3.2.3
Step 2.1
Step 2.2
Step 3.2.3
Step 3.2.4
Step 4.3
Step 4.4
Step 1.3.1.1.2
Step 1.3.1.1.3
Step 1.3.2.3
Step 1.3.2.4
Step 1.3.2.5
Step 1.4.1
Step 1.4.2
Step 1.4.3
Step 2.4.1
Step 3.3.2.3
Step 3.3.2.4
Step 3.3.2.6
Step 3.4.1
2. The following steps structured transition steps
in a manner
inconsistent with that defined for use in the EOPs:
Step,3.2.19
Step 1.3.2.1.4
Step 3.2.8
7
Step 3.2.14
Step 1.3.2.1
Step 3.3.2.2.6
AOP-'024
-Step 3.1.2
Step 1.3.2.5
'Step 2.4.1
Step 2.4.2
Step 3.3.2.4
Step 3.3.2.5
Step 3.3.2.6
3. The following steps were preceded by cautions or notes structured in
a manner inconsistent with that defined for use in the EOPs:
Step 3.2
Step 1.3.2.7
Step 3.2.1
4.
The following steps used past tense,
passive voice,
or were not
written as directives, in contrast with the present tense, active
voice, directives used in EOPs and the rest of the AOPs:
- Step 4.0
Step 3.1.1
Step 4.1
Step 4.2
Step 4.3
Step 1.4
Step 2.2.1
Step 2.4.1
Step 3.4.1
Step 4.0
Step 4.4
Step 1.4
Step 2.4
Step 3.4
5. The following steps included two actions,
in contrast to the
convention used in EOPs and the rest-of the AOPs:.
Step 3.2.4
Step 3.2.6
Step 1.3.2.4
Step 3.2.2
6. The following procedures used a typestyle that was different from
that used in EOPs and the majority .of AOPs:
A0 P-024
0
APPENDIX D
NOMENCLATURE
This appendix contains NRC observations of instances where Writer's Guide
apPlication to tne EOP would cause the reader to expect an exact nomenclature
match with component nomenclature, yet there was no identity. It also includes
instances where a complete match was neither required nor found and the mismatch
was sufficient-to cause concern. The licensee agreed in each case to evaluate
the difference and make the appropriate change. These items will be reviewed
during a future NRC inspection.
Procedure
Step/pg..
EOP nomenclature
Component nomfenclature
-
(ON
MCC9 & 9) STM
DRIVEN FWP ...
(ON
RTGB PHASE A ISOL.
STATUS PANEL) ACC NZ
SUPPLY VA 855 ...
EPP-1
16/4
CST Level.
Cond.
Storage Tank
Level
Attach. A/28
Control and Indication
?480 V Switchgear?
EPP-8
2.c RNO/4
SEAL OIL BACKUP PUMP
- TURNING GEAR AND SEAL
OIL
11.a/11
ALL STOPPED
OFF
-
19.b/19
ACCUMULATOR DISCHs
DISCH
SI-865A
DISCH
SI-865B
DISCH
SI-865C
26.c/23
SI-865A
V-865A
SI-865C
V-865C
EPP-10
2/3
STOPPED
status light OFF
3.a/4
CLOSED
status light SHUT
3.b/4
CLOSED
status light SHUT
9.b.1/9
HCV-121
HIC-121
9.b.4/9
CLOSED
status light SHUT
9.b.7/9
HCV-142
HIC-142
9.d/10
HCV-758
HIC-758
EPP-20
13
CLOSED
status light SHUT
EPP-21
1/5
52/11C Makeup water
MCC 20 Makeup water
Treatment
.
Treatment
EPP-21
1/6
52/22B, 480V Bus E-2
52/22B 480 Bus E-1
Tie Bus. Breaker
supply SI Pump .B
EPP-21
1/6
52/29B, 480V Bus E-2
52/29B 480 Bus E-2
Tie Bus Breaker
supply SI Pump B
EPP-21
3e/8
PRESS HTR PNL #1
Breaker 1, 2, & 3
No lables
EPP-21
4e/10
PRESS HTR PNL #3
Breaker 1, 2, & 3
No lables
EPP-SUPP
1.A/4
Injection Mode Valves
status lights SHUT
closed
1.B.6/5
IA-1716
PCV-1716
1.B.15-B.18/5 RC-516
VA-516
RC-519A
VA-519A
RC-519B
VA-519B
RC-553
VA-553
C-739
VA-739
S-855
VA-855
1.B.19/5
CC-739
VA-739
1.B.20/5
SI-855
VA-855
1.B.25-B.32/5 WD-1721
WDS:VA-1721
WD-1722
WDS:VA-1722
WD-1723
WDS:VA-1723
3
WD-1728
WDS:VA-1728
WD-1786
WDS:VA-1786
WD-1787
WDS:VA-1787
WD-1789
WDS:VA-1789
WD-1794
WDS:VA-1794
1.E/8
off
STOP
3.A.1/10
HCV-758
HIC-758
HCV-142
HIC-142
FRP-C.2
4.a/6
RUNNING
START
11/9
Stop
OFF
FRP-H.2
.2/3
FW RE.G(s)
FCV-478
A FEED REG VALVE
FCV-488
B FEED REG VALVE
FCV-498
C FEED REG VALVE
2/3
FCV-479 A S/G FEED REG
VALVE BYPASS
FCV-489 B S/G FEED REG
VALVE BYPASS
FCV-499 C S/G FEED REG
VALVE BYPASS
2/3
V2-6A
V2-6B
V2-6C
4/4
MSIV V-3A
BYP MS-353A
MSIV V-3B
BYP MS-353B
MSIV V-3C
BYP MS-353C
4
FRP-J.2
2 /4
CV
not in abbr list
3/4
not in abbr list
5/4
not in abbr list
1.1.2.6
...
MEDIAN ...
TR-408 HIGH Tav ...
3.2.4.3/4
START a Boric Acid
label.not on equipment
Transfer Pump
3.2.15.2/8
panel LP-28, circuit
circuit not labeled
No. 4
3.2.16.4/8
.
HVH-2
HUH-2
1.3.2.3.1
WASTE CONDENSATE
C WCT TO WASTE COND
RECIRCULATION PUMP
RECIRC PUMP
SUCTION VALVE
AOP-010-
1.1.2/3
FWP A/B FLOW LOW
1.1.5/3
HIGH HOTWELL LEVEL
HOTWELL LEVEL HI/LO
1.1.7/3
Low Feed Pump Seal
FWP SEAL WTR PUMP A/B
Water DP
TROUBLE
1.1.8/3
Electrical fault on FW
FWP A MOTOR
pump
FWP B MOTOR
1.1.9/3
FWP A LUBE OIL TROUBLE
FWP B LUBE OIL TROUBLE
1.2.1/3
Electrical fault on
COND PUMP A MOTOR
Condensate Pump
COND PUMP B MOTOR
1.3.4/4
Electrical fault on
HTR DR TANK PUMP A
Heater Drain Pump
MOTOR
HTR DR TANK PUMP B
MOTOR
3.2.3/4
S/G PORVs
handwritten labels on
-
equipment "open" and
"closed"
3.1.3/3
closed
SHUT
3.2.11/4
No. 2 LP guage
label not on equipment
1.2.1/4
stop HVE-15
OFF
C1
3 2.35
CLOSE
SHUT
3.1.2/4
PW MOV-832
Makeup CC-832
3.2.5/7
DW-711
CC-711
1.83
STEAM DUMP ACTUATION
STEAM DUMP ARMED
ADP-022
i.3.1.i.1/4
South Supply
eader
SW Pump Disch
Isolation Valve
1.3.1:1.2/4
SW Pump Discharge
SW Pump Disch
Header Cross-Connect
1.3.2.2/5
Chemical Injection
Hypochlorite/SW
Supply Lines
Isol
1.3.2.3/5
deep well supply
Potable water
3.3.2.2.3/18
IVSW,Tank .
seal water injection
tank
5.3.2.2.4/14
E. H. Oil Pump
Gov Fluid Pump
6.3.3.3/16
jockey pump
booster pump
1.5/3
Internal pressure
CV pressure
SII
APPENDIX E
Alternating Current
Auxiliary Operator
Abnormal Operating Procedure
Administrative Procedure
Anticipated Transient Without Scram
AUX
Auxiliary
BKR
Breaker
BLDG
Building
Component Cooling Water
Carolina Power and Light
Critical Safety Function Status Tree
Condensate Storage Tank
CV
Containment Vessel
CVS
Chemical and Volume Control
Direct Current
DEV
Deviation
Diesel Generator
DISCH
Discharge
DP
Differential Pressure
DS
Dedicated Shutdown
Demineralized Water
EAL.
Emergency Action Level
E&C/RC
Environmental and Chemistry/Radiation Control
Effective Full Power Year
EH
Electro-hydraulic
EMERG
Emergency
Emergency Operating Procedure
End Path Procedure
Environmental/Radiation Control
ERFIS
Emergency Response Facility Information System
Emergency Response Guidlines
F
Fahrenheit
Flow Control Valve
Flow Indicating Controller
Fire Protection
Functional Recovery Procedure
GEN
Generator
General Procedure
gpm
gallons per minute
GTG
Generic. Technical Guidelines
HBR
H. B. Robinson
Hand Control Valve
Hi
High
Health Physics
hr
hour
HTR
heater
HVH
Heating Ventilation Handling
Hx
Heat Exchanger
Instrumentation and Control
Internal Combustion
IFI
Inspector.Followup Item
IR
Inspection Report.
Independent Spent Fuel Storage Installation
KV
Kilovolt
KVA
Kilovolt Ampere
KW
Kilowatt
LCV,
Level Control Valve
Low
Loss of Coolant Accident
Low Pressure
Motor generator
Motor Operated Valve
Main Steamline Isolation Valve
mph
mile per hour
N2
Notice of Unusual Event
NR
Narrow Range
NRC
Nuclear Regulatory Commission
OMM
Operations Management Manual
OP.
Operating .Procedure
P
Premissive
P
Pressure
P -
Page
P/A
Public'Address
Pg
Page
Procedures Generation Package
Pressure Indication
PNL
Panel
Power Operated Relief Valve
Pp
Pump
PRESS
Pressure
PRZR
Pressurizer
PSID
Pressure Square Inch-differential
Pressure Square Inch-gage
PSTG
Plant Specific Technical Guidelines
PZR
Pressurizer
Quality Assurance
R.
Radiation
RC
Radiation Control
Reactor Coolant Pump
Reactor Coolant -System
RECIRC
Recirculation
R/hr
Roentgen/hour
RI
Radiation Indicator
Radiation Monitor
RNO
Response Not Obtained
Reactor Operator.
Rod Position Information System
Resistance Temperature Device
Reactor TurbineGenerator Board
Reference Nil-ductility Temperature
Reactor Vessel Level Information System
Reactor Water Storage Tank
SCM
Subcooling Margin
Safety Evaluation Report
SERV
Service
S/G
Steam Generator Tube Rupture
Safety Injection
Simulator Modification Request
SPDS,
Safety Parameter Display System
Senior Reactor Operator
Station Service Transformer
Steam
SUR .
Startup Rate
Service Water Booster
T
Temperature
T
Thickness
Tavg
Temperature-Average
Tc
Temperature-Cold
Thermocouple
TD
Transition Document
Th
Temperature-Hot
TI
Training Instruction
TR .
Trend Recorder
Tref
Temperature-Reference
TRANS
Transformer
TS
Technical Specifications
TURB
Turbine
V
Volt
Verification & Validation
VolumeControl Tank
V/V
Valve
WOG-
Westinghouse Owners' Group
III