ML20151K334
| ML20151K334 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 07/05/1988 |
| From: | Julian C, Lawyer L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20151K317 | List: |
| References | |
| 50-313-88-17, GL-81-21, NUDOCS 8808030166 | |
| Download: ML20151K334 (38) | |
See also: IR 05000313/1988017
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UNITED ST ATES
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g , 'c, NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET.N W.
ATLANTA, GEORGI A 30323
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Licensee: Arkansas Power and Light Company
P. O. Box 551
Little Rock, Arkansas 72203
Docket No.: 50-313 License No.: DPR-51
Facility Name: Arkansas Nuclear One, Unit 1
Inspection Conducted: May - June 10, 1 8
Inspection Team Leader: e iN
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S "Je ff
'L. Lawyer (/ Date 31gned
Inspection Team Members: J. DeBor
M. DeGraff
P. Kellogg
G. Bryan
W. Johnson
Approved by: CA W
C. A. JulIaft,sChief
Operations Branch
7/5/8W
Date Signed
Division of Reactor Safety
SUMMARY
Scope: This special, announced inspection was conducted in the area of review
of the adequacy of Emergency Operating Procedures for Unit 1. No inspection of
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Unit 2 was conducted.
Results: No violations or deviations were identified. Although numerous
technical and human factor deficiencies were identified, the Emergency
Operating Procedures were found to be adequate for continued operation of the
facility. The licensee coramitted to review the deficiencies and take prompt
corrective action to resolve them.
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8808030166 880785
PDR ADOCK 05000313
Q PDC
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REPORT DETAILS ,
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1. Persons Contacted
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- W. Converse, Operations Assessment Superintendent
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M. Cooper, Nuclear Quality Specialist
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- E. Ewing, General Manager Plant Support
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B. Garrison, Operations Technical Support
H. Green, Quality Assurance Superintendent
- D. Howard, Licensing Manager
- L. Humphrey, General Manager Nuclear Quality ;
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- R. Lane, Manager Engineering
- J. Levine, Executive Director Nuclear Operations ;
- D. Lomax, Licensing Supervisor :
- P. Michalk, Nuclear Safety and Licensing Specialist
D. Provencher, Quality Engineering Supervisor
- S. Quennoz, Plant General Manager
- J. Vandergrift, Operations Manager i
- D. Williams, Senior Engineer !
- C Zimerman, Supervisor Technical Operations
Other licensee employees contacted included engineers, technicians, l
- operators, and office personnel.
NRR Attendees
- C, Harbuck, Project Manager, NRR
- G. Lapinsky, NRR
NRC Region IV Attendees
. *J. Gagliardo, Section Chief
- A. Howell, Project Engineer
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! * Denotes those persons attending the exit interview.
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l 2. Exit Interview
1
The inspection scope and findings were sumarized on June 9 and 10,1988,
with those persons indicated in paragraph 1. The NRC described the areas !
4 inspected and discussed in detcil-the inspection findings listed below. )
j Licensee representatives agreed to review and resolve the open i', ems which
i are documented in paragraphs 6, 7, 8, and 9 of this report. Although
j proprietary material was reviewed during this inspection, no proprietary
j material is contained in this report. Those items on which dissenting
- comments were received from the licensee are identified by a marginal
,
! asterisk in the detailed discussion which follows. !
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NOTE: A list of abbreviations used in this report is contained in
Appendix E.
Item Number Status Description / Reference Paragraph
IFI 50-313/88-17-01 Open Correction of labeling
discrepancies between E0Ps and
panel indication as outlined in
Appendix D (paragraph 6)
IFI 50-313/88-17-02 Open Correction of technical
discrepancies contained in the
E0Ps as outlined in Appendix B
(paragraph 6)
IFI 50-313/88-17-03 Open Correction of human factors
discrepancies contained in E0Ps as
outlined in Appendix C (paragraph ;
6)
IFI 50-313/88-17-04 Open Review natural circulation i
cooldown with vents open
(paragraph 6)
IFI 50-313/88-17-05 Open Review simulator effectiveness in
training on E0Ps (paragraph 7)
IFI 50-313/88-17-06 Open Resolution of QA review
- efficacy (paragraph 8)
"
IFI 50-313/88-17-07 Open Review writers guide training to
increase operator awareness of
terms (paragraph 9)
- 3. Background Information
Following the TMI accident, the Office of Nuclear Reactor Regulation
developed the "TMI Action Plan" (NUREG-0660 and NUREG-0737) which required
licensees of operating reactors to reanalyze transients and accidents and
, to upgrade E0Ps (Item I.C.1). The plan also required the NRC staff to
develop a long-tern plan that integrated and expanded efforts in the
writing, reviewing, and monitor.ng of plant procedures (Item I.C.9). i
NUREG-0899, "Guidelines for the Preparation of Emergency Operating
Procedures," represents the NRC staff's long-term program for upgrading
E0Ps, and describes the use of a "Procedures Generation Package" to
prepare E0Ps. The licensees formed four vendor type owner groups
corresponding to the four major reactor types in the United States;
- Westinghouse, General Electric, Babcock & Wilcox, and Combustion
, Engineering. Working with the vendor company and the NRC, these owner
- groups developed GTGs which set forth the desired accident mitigation
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strategy. These GTGs were to be used by the licensee in developing their
PGPs. Submittal of the PGP was made a requirement by Confirmatory Order
dated June 14, 1984. Generic Letter 82-33. "Supplement 1 to NUREG-0737 -
Requirement for Emergency Response Capability" requires each licensee to
submit to the NRC a PGP which includes: -
(i) Plant-specific technical guidelines with justification for
differences from the GTG.
(ii) A writer's guide.
(iii) A description of the program to be used for the validation and
verification of E0Ps.
(iv) A description of the training program for the upgraded E0Ps.
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From this PGP, plant specific E0Ps were to have been developed that would
provide the operator with directions to mitigate the consequences of a
broad range of accidents and multiple equipment failures.
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Due to various circumstances, there were long delays in achieving NRC
approval of many of the PGPs. Nevertheless, the licensees have all :
implemented their E0Ps. To determine the success of the implementation, a
series of NRC inspections are being performed to examine the final product
of the program, the E0Ps. The objective is to perform table top reviews,
simulator exercises where possible, and inplant walkthroughs of the E0Ps ;
, with licensed operators to verify their adequacy. The E0Ps are considered
to be adequate for use if they can be understood and performed
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successfully by the operators and they incorporate the accident mitigation ,
j strategy developed by the appropriate vendor specific owner group.
This inspection report represents findings, observations, and conclusions
regarding the adequacy of the E0Ps. It did not, as a matter of intent,
review whether the E0Ps thus prepared conformed to the NRC staff's
long-term program for upgrading E0Ps and whether those E0Ps had been
properly prepared using a PGP.
The success level of licensees in following the PGP submitted to NRC is a
regulatory issue that will be dealt with on a case-by-case basis.
Although some licensee's E0Ps strayed far from their PGP, that issue is of
secondary importance to this inspection effort. The purpose of this
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inspection is to verify adequacy of the E0Ps for continued safe operation
l of the facility.
4. E0P/GTG Comparison
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The NRC reviewed the relationship between the ANO-1 E0Ps and the plant
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specific ATOG Parts 1 and 2. Part 1 of the ATOG, including a sample set
of E0Ps, was rejected by the licensee as inappropriate for ANO-1. However,
a the ANO-1 based AT0G Part 2 was used to develop the plant specific
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technical guidelines. Deviations between the NRC approved Oconee ATOG and
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the ANO-1 plant specific ATOG were identified, justified and documented by
AP&L. !
The ANO-1 ATOG document serves as the plant specific technical guidelines
from which the AEL-1 E0Ps and their changes are developed. The ANO-1
emergency procedure 1202.01 very closely parallels the ANO-1 ATOG Part 2,
but as appropriate, provides greater operational detail. The licensee i
uses plant specific A0Ps (1203 series) to supplement the 1202.01 E0P. The
ANO-1 E0Ps and A0Ps together compose the licensee's emergency operating
procedures.
The NRC reviewed the emergencies and other significant events covered by
the ANO-1 E0Ps and A0Ps. Taken together the E0P (1202.01) and A0P
nrocedures cover the broad range of emergencies and other significant
events listed in Regulatory Guideline 1.33, Section 6. ;
With respect to QA involvement in E0P development, QA audits of plant '
operations performed in 1986 and 1987 were reviewed. The scope of these
andita did not include the E0P or any A0Ps. The NRC expressed concern
that routine QA audits have not covered E0Ps and AOPs. Past involvement
of the QA organization with the E0Ps has been limited to membership of the
QA superintendent on the plant safety committee and performance of a
review in 1986 to verify that E0P discrepancies identified by INP0 had
been corrected. There was inadequate QA involvement in the development
process. However, it was determined that adequate management controls
were applied to the E0P development process as indicated by internal
letters, correspondence to the NRC, and site safety committee activities.
5. Independent Technical Adequacy Review of the E0P
The ANO specific guidelines were submitted to the NRC on April 15, 1983,
5 months before issuance of the lead plant SER.
As a result and as noted in Section 4 above, ANO had no NRC approved l
document to serve as a bases for development of the ANO specific
guidelines. For this reason, ANO has consistently defined their r
applicable technical guidelines as Part II, Volumes 1 and 2 of the ANO
ATOG. ,
The NRC inspectors used the ANO ATOG Part II and ANO E0P Bases Document as
the ANO +.echnical guidelines and made no effort to trace back to the lead
plant guidelines during this inspection except as noted in paragraph 4
above, s
The NRC inspectors determined by review of the procedures listed in
Appendix A that technical guideline step sequence and placekeeping
requirements were met and that entry and exit points were correct except
as noted. Since the E0P itself is almost self contained, there is little
external transfer. Transfers within the E0P were few and were well
defined and appropriate except as noted in the appendices. The general
priority of treatment and order of steps was maintained.
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Because of the self contained nature of the E0P and the presence of two
copies in " m ntrol room as well as one copy of the A0Ps, ic was not
necessarv e operators to remove pages. For these reasons,
placeks . not a significant problem. The inspectors verified that
entry s nto the procedures were properly and clearly identified
and cou. y followed by the operators.
The lice, se of notes, cautions, and transfer instructions was
generally J. . except as noted in the appendices.
Two deviations (procedural differences) between the E0P and the AN0 AT0G
Part II were previously documented by the licensee in an internal audit.
There were no violations or deviations noted in this area.
6. Review of the E0Ps by Inplant and Control Room Walkthroughs
Inplant and control room walkthroughs of the emergency and abnormal
procedures listed in Appendix A were conducted. The emergency procedures
appear to be consistent between the instrumentation and control labeling
on the control board and the nomenclature used in the procedures. Those
few discrepancies noted are enumerated in Appendix D. The majority of the
discrepancies noted in Appendix 0 originated from the abnormal procedures
which have not yet been subject to the PWG review. The licensee
committed to review these Appendix D discrepancies and make changes as
appropriate. Resolution of this issue is identified as Open Item
50-313/88-17-01. Conversation with the licensee indicated that completion
of the PWG review for all remaining A0Ps and ops is scheduled for February
1990. The NRC recommends that the licensee ensure that the PWG review for
the A0Ps and most significant ops is completed first. The licensee stated
that this would be done.
Indicators, annunciators and controls referenced in the E0Ps were found to
be available to the operators. There are two sets of emergency and one
set of abnormal procedures maintained in the control room at all times.
These procedures were verified to be of the latest revision and free of
any handwritten changes.
While the result of these walkthroughs was generally positive, several
discrepancies in the areas of technical content, writer's guide adherence, l
and human factors were noted. Technical discrepancies are identified in 1
Appendix B, while writer's guide and human factors discrepancies are noted i
in Appendix C. The licensee has committed to review and resolve the
discrepancies identified in the aforementioned appendices. Appendix B
discrepancies will be identified as Open Item 50-313/88-17-02 and
Appendix C discrepancies will be identified as Open Item 50-313/88-17-03.
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In response to Generic Letter 81-21, the licensee comitted to perform a )
natural circulation cooldown without forming a void in the reactor vessel
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head. The licensee's method of accomplishing this is to open the reactor ,
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vessel head vent prior to initiating the cooldown. While this will help
to prevent void formation this will also open the reactor coolant system
to the reactor building. This could result in excessive contamination of
the reactor building and possibly limit access for some time.
It should be noted that at the time Generic Letter 81-21 was issued,
procedures for natural circulation cooldown with upper head voids were not
generally available. The NRC staff's technical position on upper head
voiding has changed accordingly. Controlled voiding in the reactor vessel
upper head is now an acceptable strategy provided that it can be done
using all safety grade equipment with NRC approved procedures and licensed
operators trained in the use of these procedures. The licensee should
review the use of head vents in light of this position and request a
change to allow cooldown with the head vents closed. Resolution of this
issue will be identified as Open Item 50-313/88-17-04.
During inplant walkthroughs, the NRC expressed a concern that following an
accident with fuel damage the EDG rooms would be inaccessible due to their
proximity to the makeup tank. The licensee had previously identified this
concern in a design review of plant shielding and sampling capabilities in
response to NUREG-0578 completed in December of 1979. Initially, the
licensee's response was to provide for alternate access routes to the
equipment. Since then, the licensee has revised AP 1203.19, High
Reactivity in Reactor Coolant to include step 3.6. Step 3.6 requires that
if the failed fuel monitor reaches a set value and the area monitor
exceeds 100 mr/hr, letdown be isolated and seal return be diverted to the
quench tank. This prevents high radiation levels in the makeup and
purification system from restricting access to vital areas. Currently the
EP does not reference this AP and the possibility exists that following a
reactor trip letdown can be reestablished. The licensee has committed to
evaluate the need to reference this AP in the EP. -
During this inspection, the aspects of the validation and verification
program that were applied to the development of the E0P and A0Ps were not
inspected in depth. Some deficiencies were identified in connection with
the licensee's ongoing evaluation of E0Ps.
There were no violations or deviations noted in this area.
7. Simulator Observations
The NRC observed an operating crew performing the following eight
scenarios on the AN0-1 simulator:
a. Loss of Offsite Power with One EDG Inoperative
b. RCS Leak causing ESAS Actuation
c. Loss of all Feedwater
d Steam Line Break Outside Containment /Inside the MSIV
e. SG Tube Rupture with Steam Leak
f. Station Blackout
g. Overcooling
h. Loss of ICS Power
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The procedures provided operators with sufficient guidance to fulfill
their responsibilities and required actions during the emergencies, both
individually and as a team.
The procedures did not cause the operators to physically interfere with
each other while performing the E0P and A0Ps.
The procedures did not duplicate operator actions unless required (e.g.
for independent verification).
When a transition from the E0P to an A0P or other procedure was required,
precautions were taken to ensure that all necessary steps, prerequisites,
initial conditions, etc. were met. Operators were found to be
knowledgeable about where to enter and exit the procedures.
Activities that should occur outside the control room were initiated by
the operators and proper confirmation of their completion was given.
These actions were inspected during inplant walkthroughs of the
procedures.
The E0P lesson plans cover both the technical basis behind the procedures
and their structure and format. The training scenarios provide sufficient
coverage of the E0Ps (with the exceptions noted below), including multiple
malfunctions. In addition, operators were trained on significant
revisions of the E0Ps prior to their implementation.
The training simulations should duplicate actual plant operations whenever
possible. The extent of simulation should be such that the operator is
required to take the same action on the simulator to conduct an evolution
as on the reference plant using the same procedure. Six deficiencies in
this aspect of E0P training program were noted and are listed at the end
of Appendix B. The licensee should review E0P and AOP simulator training
and retraining, and assure that discrepancies such as these are
eliminated. Resolution of these concerns will be identified as Open Item
50-313/88-17-05.
No violations or deviations were noted in this area.
8. Ongoing Evaluation of the E0Ps
Procedures and records were reviewed and licensee personnel were inter-
viewed to determine whether the licensee has an acceptable program in
place for continuing evaluation of the E0Ps. The NRC found that
Operations Administrative Procedure 1015.11 provided administrative
guidelines for preparation and review of revisions to the 20Ps. It was
found that operations or training department personnel document E0P
problems identified during individual study, classroom training, simulator
exercises, or control room walkthroughs. In addition, comments are
generated and resolved during the verification and validation activities
for the various revisions to the E0P. Unit I transient reports identify
the procedures (including the E0P and A0Ps) used during unit transients
and contain an evaluation of the adequacy of the procedures. Industry
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experience is evaluated by the operations assessment group. When this
evaluation determines that E0P revisions are prudent, action assignments
are made by management. The NRC determined that the licensee has an
acceptable program for continuing evaluation of the E0Ps. The NRC
determined as noted in section 4 that QA involvement in the development of
the E0Ps was not adequate, although adequate management controls were
applied. Concerning the ongoing E0P development program QA personnel
showed the NRC a draft of a revised audit procedure for plant operations.
The revised procedure will include E0Ps and is scheduled to be implemented
in September 1988. In addition, a new audit procedure is being developed
for records and document control. This procedure is scheduled to be
implemented in 1989. The draft of this audit procedure indicates that it
will include E0Ps. At the time of this inspection, the QA organization
had one staff member who held an operator license for Unit 1. A person
holding a senior operator license for Unit 2 is scheduled to join the QA
i staff in August 1988. This addition is expected by licensee personnel to
j enhance the QA organization's ability to perform meaningful audits of the
E0Ps. Implementation of the~ revised audit procedure will be identified as
l Open Item 50-313/88-17-06.
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There were n'o violations or deviations noted in this area.
9. E0P User Interviews
Ten interviews were conducted by the NRC inspection team, and it was
determined that the current E0Ps satisfy the needs of the operational
personnel. The operators felt the E0Ps were adequate and compatible with
the level of knowledge of the typical operator and the operations staff
was confident that the E0Ps would function effectively during an actual
event. One discrepancy that was noted during these interviews was that
confusion appeared to exist among the operators interviewed as to the true
meanings of the terms "available," "verify," "secure," "check," and "go
to." These inconsistencies indicate a need for further operator training
in the terminology used in the E0Ps and/or definitions contained in the
Writer's Guide. The licensee should review this area and provide
retraining as necessary. Resolution of this issue will be identified as
Open Item 50-313/88-17-07.
There were no violations or deviations noted in this area.
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APPENDIX A.
PROCEDURES REVIEWED
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NUMBER TITLE REV
OP 1202.01 EMERGENCY OPERATING PROCEDURE 11 ,
OP 1203.01 ICS ABNORMAL OPERATING 2 l
OP 1203.02 ALTERNATE SHUTDOWN 5 i
OP 1203.03 CONTROL R0D DRIVE MALFUNCTION ACTION 9 !
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OP 1203.04 REACTOR HIGH START UP RATE- 4
OP 1203.05 LOSS OF REACTOR BUILDING INTEGRITY 4
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OP 1203.06 WASTE GAS DISCHARGE LINE RADIATION HIGH 4 1
OP 1203.07 LIQUID WASTE DISCHARGE LINE HIGH 4
RADIATION ALARM ;
OP 1203.08 EXCEEDING THERMAL LIMITS ON CONDENSER 3 1
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DISCHARGE WATER
OP 1203.10 AB0VE NORMAL H2/02 CONCENTRATION 3
OP 1203.13 NATURAL CIRCULATION C00LD0WN 7
OP 1203.14 CONTROL OF SECONDARY SYSTEM 3
CONTAMINATION i
OP 1203.15 PRES $URIZER SYSTEMS FAILURE 4 l
OP 1203.16 LOSS OF CONDENSER VACUUM 3
OP 1203.17 MODERATOR DILUTION 2
OP 1203.16 TURBINE TRIP BELOW 43 PERCENT POWER 4
OP 1203.19 HIGH ACTIVITY IN REACTOR COOLANT 3
OP 1203.20 LOAD REJECTION 3
OP 1203.21 LOSS NEUTRON FLUX IND 2
OP 1203.22 LOSS RC FLOW RCP TRIP 1
OP 1203.23 SMALL STEAM GENERATOR TUBE LEAKS 2 ,
OP 1203.24 LOSS INSTRUMENT AIR 3 l
OP 1203.25 NATURAL EMERGENCIES 5 :
OP 1203.26 LOSS OF REACTOR COOLANT MAKEUP 2
OP 1203.27 LOSS STEAM GENERATOR FEED 3
OP 1203.28 LOSS DECAY HEAT REMOVAL SYSTEM 4
OP 1203.29 REMOTE SD 2 i
OP 1203.30 LOSS SERVICE WATER 4 i
OP 1203.31 REACTOR COOLANT PUMP AND MOTOR 2
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EMERGENCY
OP 1103.13 REACTOR COOLANT LEAK DETECTION 04/26/88
OP 1502.04 ATTACHMENT H - REFUELING ACCIDENT 09/10/87
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APPENDIX B
TECHNICAL COMMENTS
This appendix contains technical comments, observations and suggestions for E0P
improvements made by the NRC. Unless specifically stated, these comments are
not regulatory requirements. However, the licensee agreed in each case to
evaluate the comment and take appropriate action. These items will be reviewed
during a future NRC inspection as noted in paragraph 6.
General:
During the simulator drills, the NRC inspectors noted that the EDGs were
allowed to run unloaded for long periods of time. This could seriously degrade
the engines and the engine blowers. It is recommended that the various
procedures which require EDG start be reviewed to ensure that appropriata
cautionary steps are contained therein. It is also recommended that this
subject be emphasized in operator training.
1. Reactor Trip 1202.01
a. Step 3.3: This step indicates that SG level approaching 378" is an
overfilling condition. The step fails to recognize that EFW may have
been started earlier and the reflux boiling setpoint (378") selected
due to a loss of subcooling margin and tripping the RCPs. The
licensee should revise the procedure to clarify this situation.
b. Steps 3.5.5.H and 3.10.5: These steps require placing the auxiliary
feedwater pump in service per the Auxiliary Feedwater Pump Operation
section of OP 1106.16. The steps of this section cannot be accomp-
lished. They raise steam generator levels to 60 inches using the
condensate pumps before starting the auxiliary feedwater pump. At
this time, following a reactor tri,n, steam generator pressure would
be above the shutoff head of the condensate pumps.
c. Step 3.5.6: This step should cover the case of SG levels increasing
to 378" if subcooling margin has been lost,
d. Step 3.10.9.E: This if statement positions the APSRs at 37.5% prior
to the end of cycle but offers no instruction for the end of cycle
case (when they would be fully withdrawn and left fully withdrawn per
OP 1103.15). Clarify the E0P step to include the end of cycle case or
include the 0P as a reference.
e. Step 3.10.18: This step should be revised to delete references to the
main turbine. It is on the turning gear from step 3.10.4.E.
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Appendix B 2
2. Overcooling 1202.01
a. Step 4.8.3: This step directs the operator to restart the RCPs as
needed. No reference is made to restoring or verifying RCP services.
To be consistent with other steps completing the same action the
licensee should revise the procedure to include these items.
b. Step 4.10.4: Same comment as step 4.8.3 noted above in Overcooling.
3. Overheating 1202.01
a. Step 6.2: This step involves the restoration of feedwater to a
possibly dry steam generator and should be preceded by a caution or
instructions to feed slowly until some level inaication is obtained.
b. Step 6.8.4: This step is preceded by a note concerning pressurizer
level indication inaccuracies due to calibration and inaccuracies
above the upper level tap. This note should be reworded to give the
operators a definite pressurizer level at which to be alert for this
problem and to increase their awareness of approaching solid
condition.
c. Step 6.15.2: Sen comment noted in steps 3.5.5.h and 3.10.5 of Reactor
Trip.
4. Inadequate Core Cooling, 1202.01
a. Step 7.4: This step continues to bump RCPs but does not contain the
detail contained in the step above. Specifically it does not warn
the operators to bypass the 480V Bus B5 and B6 UV protection
switches. This could be corrected by referencing back to steps 7.3.1
through 7.3.6 which include the necessary steps or including the
additional steps here. This section also does not contain
instructions for further actions if the RCP bump is successful in
establishing natural circulation flow.
b. Step 7.5.4: This step directs the operator to open the ERV as
necessary to depressurize the RCS to allow the core flood tanks to
dump and LPI to start flowing. A previous step 7.2.1.E had opened
the ERV and its block v .lve. This step should be reworded to alert
the operator to the fact that the ERV may already be open when
reaching this step.
5. Tube Rupture 1202.01
a. Step 8.17.3: This step directs the operator to "leave MSIV open for
steaming later if needed." This step is unclear as to which MSIV is
left open. The licensee should revise Uie step to indicate whether
the valve is to be left open on the affected or unaffected SG.
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b. Step 8.20.3: This step instructs'the o)erator to monitor reactor
building temperature and start reactor Juilding cooling if necessary.
However, no specific threshold for starting' cooling is included in
the step. Additionally, the specific instructions for starting
reactor building cooling -(see HPI Cooldown Step 14.5) are not
included in this step.
6. Degraded Power 1202.01
a. Step 9.6.2: This step neglects ESAS actuation on RB pressure even
though the transfer from RX trip may have been made with a concurrent
LOCA. The licensee should consider revising the procedure to consider
this possibility,
b. Step 9.6.3: This step seems redundant to 9.5. The licensee should-
verify the need for 9.6.3.
c. Step 9.6.3: If entry to this step were RX trip, degraded power, or
ESAS actuation on RCS pressure, HPI would be on line and could
escalate RCS pressure above the thermal shock region. The licensee
should evaluate the trade-off between thermal shock and throttling
HPI; if warranted, add HPI throttling instructions.
d. Step 9.12.5: This step neglects ESAS actuation on RB -pressure
although the high point vents are open. The licensee should consider
revising the procedure.
e. Step 9.12.6: Same comment as step 6.8.4 under Overheating. l
t
f. Step 9.12.6: The Note 5 before this step should be revised to read
"
l
. . . to prevent ESAS on RCS pressure when RCS saturates." !
i
g. Step 9.12.14: The H2 monitor should be brought on service. Although
not an urgent requirement, at some point in the procedure.the recom-
biners should be placed in service.
h. Step 9.13.5 D: This step should precede step 9.13.5.C to alert the
operator who is attempting to control SG pressure of the EFIC 600
psig bypass requirement before he incurs the risk of actuation.
i. Step 9.13.10: This note should specify how many of the note 1
alternatives are required to verify natural circ. Elsewhere, two are
usually required.
7. Blackout 1202.01
a. General: Following a blackout condition with no diesel generators
available, the licensee's prioritization of actions are as follows.
Verify natural circulation, isolate letdown and RCP seal return,
attempt to_ restore offsite power and the emergency diesel generators,
_- - - - - - - - , . . . - - _ _ - - - - . _ . . , - . . - - . - , - . - , . , -
.
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I
.
Appendix B 4
and finally shed DC loads to conserve battery power. Under a
blackout condition the current means of pressure control for the
secondary side is to allow steam generator pressure to relieve
through the main steam safety valves. The NRC agrees with the
licensee's prioritization of actions taken under this scenario,
however, the procedure should be revised to -include direction to
manually operate the atmospheric dump valves to reduce steam
generator pressure and thus reduce the cycle frequency of the main
steam safety valves. Conversations with the licensee indicate this
would be acceptable provided the operation of the ADVs does not
interfere with other high level action steps. Any revisions to the
procedure should indicate this action is to be taken if time and
.nanpower permit,
b. Step 10.5.F: This step directs the operator to use the HPI block
valves to restore pressurizer level until instrument air is.available
for CV-1235. The licensee should revise the procedure to include a
note concerning tne use of HPI block valves CV-1220 or CV-1228 if
possible versus CV-1219 or CV-1227 to minimize nozzle stresses because
of the normal makeup and crossconnect arrangement.
8. Main Steam Isolation 1202.01
a. Step 12.2: This step directs the operator in the event pressurizer
level drops below 20 inches or if RCS pressure drops below 1700 psig,
to manually start HPI. The licensee should revise the procedure to
inform the operator, if necessary to maintain makeup tank level, to
open the BWST outlet valves (CV-1407 or CV-1408) to the operating HPI
pump.
b. Step 12.3: This step directs the operator in the event the
overcooling causes a loss of subcooling margin, to stop all RCPs,
verify that EFW starts, and slowly increase SG 1evels. The licensee
should revise this procedure step to verify / insure full HPI flow if
the overcooling causes a loss of subcooling margin and all RCPs are
tripped,
c. Step 12.3.6.G: This step directs the operator to throttle SW for
minimum flow through the ICW coolers. A quantitative value should be ;
applied to minimum flow, l
1
d. Step 12.5.3: Same comment as 12.3 above in MSI.
e. Step 12.7.7: Same comment as 4.8.3 in Overcooling.
f. Step 12.14.8: Same comment as noted in 12.3 above in MSI.
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Appendix B 5
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9. ESAS 1202.01
a. Steps 13.12.2.C &.D: The conditional statement should be an "or"
statement versus an "and" statement. The licensee should review this
condition to ensure accuracy.
1
- '
b. In response to the requirements of NUREG-0578, ANO tasked NUS to
review shielding capabilities under post accident conditions. The
study concluded that high dose rates would make it impossible to line
up decay heat systems using existing manual valves located in the DH
rooms.
l
Valves BW-8A, BW-8B, DH-1A, and DH-18 are manually operated valves
located in the DH room. Under the circumstances postulated in steps
13.16.3 13.16.4, and 13.16.5, they are inaccessible, thus ruling out
3
accomplishment of these steps. Core damage due to boron
precipitation will be delayed by break flow as long as subcooling is
maintained. However, since loss of subcooling is inevitable, boron
precipitation will occur and will lead to further core degradation.
Conversation with the license indicated that motor operated valves
will be installed on DH-1A and DH-18. The licensee should consider
the same course of action for valves BW-8A and BW-88.
10. HPI Cooldown 1202.01
Step 14.4.5 and 14.17.9: These steps instruct the operator to maintain
reactor coolant pressure and temperature in the thermal shock region
of Figure 2 with reactor coolant pumps running. This is not the correct
operating region.
11. ICS Abnormal Operating 1203.01
following a loss of ICS power, if a reactor trip were to occur the only
means of pressure relief on the secondary side is via the main steam
safety valves. The turbine bypats valves, on a loss of ICS power will
fail closed and even though the atmospheric dump valves will demand to be
open, the isolation valves will be closed. The licensee should include
procedural guidance to open the atmospheric dump isolation valves if this
condition were to occur.
12. Moderator Dilution 1203.17
a. Revise the A0P to recognize those symptoms which are severe enough to
warrant immediate boron injection without waiting for chnmistry
sample results. As written the procedure follows a process of: A0P
entry to a particular section; chemistry sampling, exit to an OP,
await sample results, determine desired concentration, compute,
lineup, and then add boron.
, i
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l l
I
Appendix B 6
i
b. An example of a case which warrants immediate boron injection is
Section I with CRD position to the left of the safety limit curve in
OP 1102.04. When rod position has been shifted back to the LC0
region, a final predeterrined addition may be made to restore rod
configuration.
The NRC concluded that immediate boration was applicable in other
cases such as sections II - IV, given en unexplained increase in flux
level.
13. High Activity in Reactor Coolant 1203.19
Wherever a step directs a TS shutdown, the procedure should direct the
operators to the classification procedure. A TS shutdown requires
classification as a Notification of Unusual Event.
14. Small Steam Generator Tube Leaks 1203.23
Steps 3.3.2 and 3.3.3: These steps direct the operator that once the
affected stean. generator is identified then to minimize the spread of
contamination to the secondary system, close or check closed the following
valves. Unlike the tube rupture procedure this list of valves does not
address the steam supply valves from each SG for the EFW turbine. The ,
licensee should revise the procedure to-include these-valves if they are '
applicable.
15. Natural Emergencies 1203.25
a. Step 6.1.3.A: This step instructs the operator to verify that the
earthquake was actual, but does not give specific details for
verification. This step should instruct the operator to call the
National Earthquake Information Service in Denver, Colorado,
b. Step 6.3.3.D.1: This step instructs the operator to secure cooling i
tower basin blowdown. Unit 1 does not have a cooling tower. The l
licensee should revise the procedure to delete this incorrect
reference.
1
16. Simulation Problems Identified i
a. Annunciator tile K07-B4, ICS & AUX SYS PWR SUPPLY TROUBLE, did
not annunciate on loss of ICS power.
b. Without forced flow on natural circulation cooldown, Tsat is
greater than Tcold.
c. Service water to OTSG through EFW did not function correctly during
blackout.
d. Radiation Levels in RB did not respond to opening of the reactor
vessel vents and the high point vents.
l
- . - - _ _ _ - _ - _ _ _ _ _ - _ _ _ _ _
.
. .
.
Appendix B 7
e. During RCS leak actuation the leak appeared to correct itself, and
then reappear.
f. Diesel generator could not be reset following a loss of riiesel
generator and lockout.
Simulator training in E0P usage should model the reference plant as
nearly as possible. The licensee should review E0P and A0P simulator
training and retraining, and assure that apparent discrepancies such l
as these are eliminated if possible and at least minimized.
1
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_ ._ _ _ _ - __ ________ _______ _
_
. 1
.
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APPENDIX C
WRITER'S GUIDE AND HUMAN FACTORS DISCREPANCIES
This appendix contains technical comments, observations and suggestions for E0P
improvements made by the NRC. Unless specifically stated, these comments are
not regulatory requirements. However, the licensee agreed in each case to
evaluate the comment and take appropriate action. These items will be reviewed
during a future NRC inspection as noted in paragraph 6.
1. Procedure Writer's Guide
a. The guidance provided for persons writing E0P sections and A0Ps is
contained in ANO Operations PWG including Appendix B, AP 1015.10
revision 2, Special Workplan 1409.034 sections related to the
applicable sections of the PWG. The PWG, 1015.10, and the workplan
contain the necessary elements of an E0P writer's guide as defined by
NUREG-0899. However, the inspection team identified a number of
concerns related to the integration of E0P writer guidance along with
technical concerns. It is the inspection team's judgment that
Appendix B to the PWG needs to be reviewed, updated and integrated
into the overall PWG. In addition, the specific elements of the PWG
should be better indexed to provide easier access to the E0P specific
contents of the PWG. Individual discrepancies are enumerated below
to better define this need but are not intended as all encompassing
examples.
b. Ir.struction states that "All cautions should appear in this column
and may appear in the right hand column as well." Since the cautions,
warnings, and notes always apply to the right hand column, they
should always appear in both columns.
c. Direction should be included for instructions that tell the operator
not to go to another procedure. For example, step 12.3 of E0P tab
Main Steam Isolation. The left hand column tells the operator not to
go to LOSS OF SUBC00 LING MARGIN or OVERC00 LING tabs.
d. Boxed Emphasis describes a special form of emphasis used for steps
that are to be taken at the same time as other steps which are not
directly related when it is important that such steps be taken at
that time. This is not clear. Furthermore, the reviewers could find
no examples of this in the E0Ps.
e. Consistency is not maintained between parameter units used in the
procedures and the units on the panels. For example, Step 12.1.2 in
Main Steam Isolation refers to reactor building pressure in psig and
the display on the panel and SPDS is in psia.
f. The instructions for underlining need more detail to ensure
consistency. For example, Reactor Trip procedure Step 2.2.3
underlines "and" inconsistently.
..
1
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t
l Appendix C 2
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g. The definitions for Cold Shutdown and Hot Shutdown are identical. The
Cold Shutdown definition is incorrect.
h. There is no apparent logic applied to the selection of the 17 words
or phrases chosen for definition,
i. The writer's guide docs not include any examples of two column E0P
fo rma t. An example would be useful as a standard to be maintained
for future revisions,
j. Appendix B provides philosophical guidance on writing E0Ps, but, it
does not provide explicit instructions for writing and organizing
E0Ps. The explicit instructions for preparing E0Ps are scattered
throughout the writer's guide. For example, guidance for E0P entry
conditions, cautions and level of detail are scattered throughout the
document which contains this appendix. Some issues such as two
column format are not covered at all. In addition, the table of
contents is not detailed enough to facilitate rapid access to writer
information on issues such as E0P entry conditions.
k. Procedure 1015.10 Attachment 5, Format and Instructions for Abnormal /
Emergency Procedures provides procedure writers with a philosophical
discussion of E0Ps. This section is similar to, but not the same as
Attachment B in the ANO Operations Procedure Writer's Guide. In
fact, some of the instructions in Attachment 5, such as the guidance
on Caution layout are in conflict.
1. The guidance provided in Attachment 5 is not detailed enough to
write E0Ps.
m. Although the E0P conforms to the new Writer's Guide, the A0Ps do not.
Upgrading is programmed to be accomplished over the next two years.
The licensee agreed to prioritize the upgrading of the A0Ps and
important ops.
n. Although the current Writer's Guide is improved over that in use at
the time of submission of the PGP package, there is no composite I
writer's guide. ANO defines (ANO letter of 7/17/84 to NRC) the I
operations procedure guide as the sum of the Writer's Guide plus ;
several administrative procedures. Procedure writers need clear and '
coordinated guidance in order to prepare consistent procedures. The
guidance should be integrated,
o. None of the operators interviewed had received training on the
Writer's Guide. Since they are the procedure users and are often
involved in procedure rewrite, they should receive formal training,
p. Nearly all A0Ps have not been updated using an acceptable Writer's
Guide. Thus, important human factors elements are not included in
the existing A0Ps. '
.
y - - - -
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.
. .
.
Appendix C 3
2. Reactor Trip 1202.01
a. Step 3.5.8: The logic in this step is confusing. The licensee
should revise the step to clarify the situation,
b. Step 3.6: This step considers both NNI and ICS power status lights
in checking for loss of NNI. Because of this, it is necessary to
modify the go to instruction which follows to read "If NNI power
supply failure is detected, . . . ."
c. Steps 3.8. A and 3.8.D: These steps should both include inputs from
d. Step 3.8.F: The parameters for RCS pressure and temperature should
be defined.
e. Step 3.9.B: Delete the ().
i
f. Step 3.10.1.B: Correct typographical error (ligth). '
g. Step 3.10.4.E: Correct the step to read "E. Main turbine on turning
gear . . .".
h. The list of symptoms in Section 1 should be expanded to include
manual trips required by operator judgement, TS, and A0Ps.
i. This procedure does not assign any functions to the STA. The
functions of the STA should be clearly stated in a procedure. The
STA could perform functions similar to the symptom verification
actions required in the note before Step 3.2. The verification of
critical safety functions during a plant transient are and should be
performed by the STA. These STA functions are currently contained in
an uncontrolled document and should be formalized in a unit operating
procedure.
j. Step 3.1: This step assigns the SSA the responsibility to implement
the Emergency Plan using Emergency Action Level Classification (OP
1903.10). Accident classification is a nondelegable responsibility
assigned to the Emergency Director (shif t supervisor) (NUREG-0654).
The licensee should revise step 3.1 to substitute Shif t Supervisor
for SSA.
k. Step 3.10: This step verifies hot shutdown if no abnormal conditions l
exist. Subordinate step 3.10.4.F transfers A3 & A4 power from the '
diesel generators if they are supplying power to A3/A4. EDGs
providing A3/A4 power is abnormal. Clarify "abnormal"in 3.10 or
break out abnormal steps prior to 3.10.
1. In step 3.10.22.C, the operator should be referred to the entirety of
OP 1102.06, not a particular section. Insert a period after ". . .
(OP 1102.06)" and delete the balance of the sentence.
i
-. . - . ..
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.
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. l
Appendix C 4
I
m. Step 3.5.4: This step requires, "Verify at least one RCP pump is i
running." In this instance "verify" does not mean to start the pump )
if it is not running. Step 3.5.5 starts available RCPs. 1
n. Step 3.5.6.B: This step indicates that SG levels are increasing to .
312 inches. This step should recognize that SG levels may be I
increasing to 378 inches if subcooling margin has been lost and the
reflux boiling setpoint has been selected.
3. Loss of Subcooling Margin 1202.01
a. Step 5.2: The "go to" utatement preceding this step sends the
operator back to the ESAS tab if ESAS actuates. The ESAS tab on page
269 sends the operator to the loss of subcooling margin tab. This
could cause the operator to loop back to the ESAS tab after Just
having finished the desired actions of the ESAS tab. The "go to"
statement should be changed to indicate the desired conditions under
which the ESAS tab should be re-entered while performing the steps of
loss of subcooling margin tab.
- b. Step 5.2.4: The note following this section refers the operator to
the ESAS Tab for directions to restore ICW and instrument air. The
directions for the restoration of ICW and instrument air are
contained in Section 13.12 of the ESAS Tab. The reference should be
changed to indicate this section or the steps should be contained
here.
c. Step 5.10.2.A: In this step the operators are directed to determine
hot leg and RV head void volumes from ICC display using Figures
6 and 7. Figures 6 and 7 use the distance from the full indication
in feet to determine the amount of void. For the case of the RV head i
void volume the indicator position switches are two feet apart and it )
is therefore difficult to determine the required distance from the
~
full indication from the ICC display.
d. Step 5.16: The Caution preceding this step requires the operator to
refer to Figure 4. This is contrary to the writer's guide and should
be revised to refrain from giving the operators directions in the
caution stateinents.
4. Overheating 1202.01
Steps 6.13.5 E, 6.14.4.C. and 6.15.5.C use the term, "If RCS is '
saturated." The intended meaning is, "If the RCS margin to saturation is
'
less than 50 degrees F."
5. Inadequate Core Cooling 1202.01
a. Step 7.7 has an applicable caution note just before the step. This
step may be entered from a "go to" statement in Step 7.4. If Step
7.7 is entered in this way, the caution note might be missed. This
._ -_
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.
. i
)
.
Appendix C 5
is an example of a deficiency that exists at several points in
various sections of the E0P.
b. Step 7.8.7 requires use of instruments on Panels C486-1 and C486-2
for monitoring reactor building water level. These panels are not
visible from the main control board operating area. The step should
refer to the reactor building flood level information on the RB
display of the SPDS.
6. Tube Rupture 1202.01
a. Step 8.3.8: This step directs the operator on the action to be taken
if the makeup tank level continues to drop. The licensee should
revise the step to include opening of the makeup tank gas space vent
valve (CV-1257). Additionally, the structure of the step should be
revised to match step 8.9.3.
b. Step 8.7.1: The licensee should revise this step to include the
device numbers for the main steam line N-16 monitors and the main
steam line high range radiation monitors.
c. Step 8.8.9: This step directs the operator to secure letdown if
still in service. The licensee should revise the step to include the
level of detail noted in step 8.9.2 (i.e. the specific valves which
need to be closed to secure letdown).
I
d. Step 8.8.12: This step should be revised to include main feedwater !
recirculation valve numbers (CV-2874 and CV-2876).
e. Step 8.11.1: Same comment as noted in step 8.7.1 above.
f. Step 8.14.1: This step directs the operator to verify that
subcooling margin is greater than 50 degrees F. Other steps within
this and other procedures reference greater than or equal to
50 degrees F. The licensee should revise step 8.14.1 to be more
consistent with other steps completing the same action.
'
g. Step 8.15.7: This step directs the operator.if necessary to use the
ERV to reduce RCS pressure. The licensee should revise the step to
include the ERV valve number,
h. Step 8.20.3: The licensee should revise the step to include the
valve numbers for the loop A and B high point vents.
1. Step 8.21.1: This step directs the operator to isolate the core
flood tanks when RCS pressure is less than 700 psig and subcooling
margin is greater than or equal to 50 degrees F or if subcooling
margin cannot be maintained then allow -the core flood tanks to
discharge. The sequence of steps to isolate the core flood tanks
.
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, ,
.
Appendix C 6
follows an additional conditional statement and does not flow
logically.
J. Step 8.8.3: This step instructs the operator to verify "Turbine
Intercept and Stop Valves," but these valves are not identified or
labeled on the Turbine Control Panel.
7. Degraded Power 1202.01
a. Step 9.5.6: The Caution 1 before step 9 should specify bypass valve
number, MU-1207-3.
b. Step 9.8.2: The left side nomenclature in this step appears to be
superfluous. The licensee should consider deleting this.
c. Step 9.12.15: The Caution 1 prior to this step contains an action
statement (refer to) and therefore should not be contained in a
Caution (per writer's guide). The licensee should revise the step to
be consistent with the writer's guide,
d. Step 9.13.6: The licensee should revise the Note 4 preceding this
step to read "pressurizer level will increase with RCS pressure
decrease as voids . . . ."
e. Step 9.13.8: The licensee should revise the "go to" statement
preceding this step to positive rather than negative (e.g. "If
subcooling margin is regained at this point, continue. If not,
proceed to . . .).
f. Step 9.6.1: The licensee should revise this step to read "Check PZR
level and RCS pressure" to conform to actions which will be completed
in sub paragraphs a-h.
g. Step 9.13.7: This step appears to be poorly worded and confusing to
the inspector and two operators.
h. Step 9.13.8: Recommend deleting the Caution 1 preceding this step;
it is out of context.
l
- 1. Given a reactor trip and exit to degraded power followed by initial l
successful sequencing of the EDGs to A3 & A4, then a loss of A3/4, l
the procedure does not transfer from degraded power to blackout.
8. Blackout 1202.01
a. Step 10.5.7: This step directs the operator that if RCP seal
parameters are normal, restart RCPs as follows, otherwise stay on j
natural circulation flow. Subsequent substeps verify RCP motor low ;
flow cooling alarm clear, RCP HP oil lift and backstop lube oil i
pumps, etc. To be consistent with other steps completing the same I
action, the licensee should revise the procedure to verify that the
seal cooling low flow alarm has cleared.
I
I
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.
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.
Appendix C 7
9. Loss of NNI Power 1202.01
a. Steps 11.6, 11.8, and 11.10: These steps may be entered from "go to"
statements in Step 11.2. Each of these three steps is preceded by a
note which is applicable to the step. When going directly to the
step, the note could be missed.
b. Step 11.8: This step requires that NNI Y-powered instruments be
selected on Panel C13. Step 11.10 requires that NNI X-powered
instruments be selected. Panel C13 has six handswitches for
selecting NNI X or Y powered instruments for SG FW temperatures, SG
downcomer temperatures, and SG operating levels. These handswitches
were not labelled with X and Y positions in the simulator or in the
control room. Similar handswitches for other instruments on Panels
C03 and C04 were properly labelled,
c. Step 11.10: This step should indicate which panels contain NNI X and
NNI Y selector switches for indicators as does Step 11.8.
10. M9.in Steam Isolation 1202.01
a. Step 12.1.2: This step instructs the operator to read reactor
building pressure in PSIG, but the reactor building pressure chart
recorder PR2408 and the Safety Parameter Display System indicate
pressure in PSIA. This is a technical inconsistency between the
procedures and panels,
b. Step 12.3.6.B: This step directs the operator to establish either
normal RCP seal bleedoff or alternate bleedoff to the quench tank.
The licensee should revise the structure of the step to be consistent
with other steps completing the same action.
c. Step 12.4.1: This step directs the operator to verify proper EFIC
MSLI actuation. The licensee should revise the step to include the
direction similar to that in 12.4.2, i.e., "MSIV closed on the
affected SG."
d. Step 12.4.2: This step is also verifying proper EFIC MSLI for the
NFIVs. The licensee should revise the step to include the direction
similar to that in 12. 4.1, i . e . , "If both SGs depressurized, both
valves closed."
e. Step 12.13.3. A: This step directs the operator to use the ERV if
necessary. To be consistent with other steps completing the same
action the licensee should revise the procedure to include the ERV
valve number.
f. Step 12.14.1: This step directs the operator that if subcooling
margin is greater than 50 degrees F, then throttle HPI, etc. The
reference to subcooling margin greater than 50 degrees F is not
consistent with other directions which require a subcooling margin
- .
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.
Appendix C 8
l
greater than or equal to 50 degrees F. The licensee should revise the
step to be consistent with other steps completing the same action.
g. Step 12.17.4.A: This step directs the operator to verify that the
unaffected SG level is being maintained at low level limits by the
auxiliary feedwater pump. Step 12.7.12 of the same procedure also
references auxiliary feed pump low level limits, however, it also
refers to the numerical value of 27.5 inches. The licensee should
revise steps in all procedures completing the same action to be
consistent.
11. ESAS 1202.01
a. Step 13.2: This step considers the -2 min. case. Since 13.2.3
considers the 2 min, case, it is not properly included under 13.2.
The licensee sEould evaluate and revise.
b. Step 13.4.1.D: This step regarding emergency feedwater does not
belong with step 13.4.1 for controlling HPI, LPI, and RB spray. This
should be a separate step 13.4.2 instructing the operator to throttle
EFW as necessary to maintain appropriate steam generator levels.
c. Step 13.6.4: This step instructs the operator to verify EFW isolated
to the affected SG. This is incorrect and should be deleted.
d. Stap 13.6.6: RCSI SPDS display does not include RB conditions such
as temperature and pressure; the RB display does. The licensee
should revise the note preceding this step to read ". . . for
monitoring RCS conditions; RB display may be used for monitoring RB
conditions."
e Step 13.12: This step on the left uses repressurized; on the right
uses depressurized. The licensee should revise the step for
consistency.
1
f. Steps 13.12.2.C &.D: These steps should be "or" gated, not "and" j
gated. The licensee should revise this step. '
g. Step 13.4.1.B: The licensee should clarify "fully depressurized" in i
this step.
12. HPI Cooldown 1202.01
a. Step 14.5: In the NOTE following this step, the instruction should
read "Leakage will stop if the break is in the RC pump or upper i
elevations" rather than "if" apper elevations, j
b. Step 14.7: The CAUTION following this step should read "Delta" T
rather than T. :
!
c. Step 14.4.2.B: Same comment as noted in step 12.3.6.B.
l
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Appendix C 9
d. Step 14.6.1: This step directs the operator to adjust HPI flow to
maintain RC pressure and temperature per Figure 2. The details
column; however, in steps 14.6.1 and 14.6.2 reference both Figures 2
and 3. The licensee should revise the step to indicate to adjust
flow and maintain RC pressure per the applicable curve. Additionally,
step 14.6.1 in the right hand column should be physically moved to be
in line with step 14.6.1 in the lef t hand colun.n.
e. Step 14.10: This step directs the operator to align HPI and LPI for
piggyback operation. The details column states to allow
recirculation of the RB sump after the BWST empties, the HPI pump
suction shall be aligned to the LPI pump discharge as follows. The
following step does not address this action but instead addresses ES
actuation during cooldown. The HPI/LPI lineup does not begin until
step 14.10.2. The licensee should revise the order of the stepr to
provide a more logical sequence,
f. Step 14.13: This step directs the operator to isolate the core flood
tanks when RC pressure is less than 700 psig and subcooling margin is
greater than or equal to 50 degrees F or if subcooling margin cannot
be maintained then allow the core flood tanks to discharge. The
sequence of steps to isolate the core flood tanks follows an
additional conditional statement and does not flow logically.
13. Emergency Boration 1202.01
Step 15.2: Tnis step should read "Power supply breaker" rather than "Power
supply supply breaker."
14. Alternate Shutdown 1203.02
- a. Locations should be provided in the procedure steps which direct
local operation of equipment. For example, Step 10 on Page 13 should
provide the locations of CV-1408, CV-3808, CV-3809, and CV-3810 as
they are all in different rooms.
b. The last step on Pages 15 and 26 requires the shif t administrative
assistant to call out additional operators. There was no operator
call out list available in the technical support center. A list was ;
provided after this discrepancy was identified. A permanent method l
should be established to assure that a current list is available.
c. Step 6 on Page 17 should include equipment numbers for isolating seal
injection and for isolating pressurizer makeup.
d. The SRO may need a 4160 volt breaker charging ratchet and socket in
Step 11 on Page 21. The procedure should assure that this tool is
available.
.
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.
Appendix C 10
e. Detailed steps should be provided in Step 3.5 on Page 32 for manually
aligning EFW suction to the CST or service water. During the
walkthrough the operator was not certain of the number and location
of valves to be manipulated to align EFW suction to the CST (T-41).
f. Step 3.9 on Page 34 requires reducing RCS pressure as necessary by
cracking open the pressurizer auxiliary spray valves from the decay
heat system. This requires positioning six infrequently operated
valves in two different rooms. These valves should be listed and
guidance should be given on which valve should be throttled.
g. Steps 3.2 and 3.5 on Page 48 require isolating instrument air to the
atmospheric dump valves. The procedure should specify that two
instrument air valves must be closed for each dump valve.
15. Above Normal H2/02 Concentration 1203.10,
a. Step 3.2: This step states a TS requirement. It should reference
the specific TS.
b. "H202" should be "H2/02" for consistency of usage throughout the
procedure.
c. Step 3.5.1: This step should include a verbal description for
CV-4803 and CV-4804.
d. Steps 3.5.2 F and 3.8.2: These steps refer to incorrect procedure
step numbers,
e. Step 3.5.2.C: This step should refer to OP1103.05; procedure for ,
pumping the quench tank to clean waste receiver tank. l
f. Step 3.5.2.0: This step instructs the operator to read quench tank l
level in inches, but the control room quench tank meter is in %. The l
meter and procedure should be consistent. !
g. Step 3.5.2.F: This step instructs tho operator to repeat steps ,
3.3.2.A to 3.3.2.E. This is not correct. The operator should repeat !
Step 3.5.2 until H2/02 concentration is acceptable.
h. Step 3.8.2: This step instructs the operator to repeat Step 3.7.1
when he should actually repeat Step 3.8.1 in order to line up to
, purge dirty water waste drain tank T-20.
16. Natural Circulation Cooldown 1203.13
Step 4.27: This step requires the operator to depressurize to less than
200 psig for decay heat removal operation. A caution should be placed
before this step to check RV head and other RCS temperatures (i.e.,
isolated steam generator) prior to depressurization to ensure these RCS
volumes are cooled and thereby allow depressurization without drawing a
bubble in the nead.
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Appendix C 11
1
I
17. Pressurizer Systems Failure 1203.15 l
a. SYMPT 0M Section 1.1 refers to relief valve discharge temperature ;
high alarm at 200 degrees F. However, it is not clear that this ;
alarm is in the control room or on either the SPDS or plant process
computer,
b. Step 3.1.3: This step requires the operators to secure one RCP in
each loop and leave one RCP running in each loop. This step should
be modified to include a statement to leave the C RCP running if
possible to provide better spray control.
18. Loss of Condenser Vacuum 1203.16
a. Step 3.6.2: The note preceding this step is a when action statement
and is inappropriate as a note. The licensee should revise the step,
b. Step 3.6.6: The caution located before this step should be relocated
ahead of 3.6.5.
c. Step 3.6.6: This step contains a typographical error. The licensee
should correct the typo (continued).
19. Moderator Dilution 1203.17
Steps 3.5 and 3.6: Add "on" after heat tracing in Section I and II of 3.6
and Section III of 3.5.
20. High Activity in Reactor Coolant 1203.19
a. Step 3.3: This step of Section I requires increasing letdown flow to I
maximum. Maximum is undefined and varies with system lineup. !
I
d. The notes under Steps 3.4 of Section I and 3.5 of Section II require j
the operator to determine whether projected summed releases will !
exceed 1 MPC for one hour at the site boundary. Two graphs were I
posted on the wall during the walkthrough. One of the graphs had
'
been superseded by the other one. The licensee removed the
superseded graph.
c. Steps 3.1 of Section I and 3.2 of Section II describe TS limits.
These steps should reference the specific TS.
d. The procedure uses the equipment designator RE-1237. Several
operators were of the opinion that the correct equipment nomenclature
should be RI-1237. The licensee should verify proper ID and correct
the procedure as applicable.
e. In Scctions I and II, step 3.1 directs a shutdown to hot standby
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. At those points, the sole indication of a problem
is an alarm on one detector. Recommend revision of steps 3.1 and 3.2
!
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Appendix C 12
)
1
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in both sections to require some additional verification of
unacceptable activity before a shutdown is directed. l
f. Section I, step 3.3, directs increase s .down to maximum. When asked
to determine maximum, it took a qualified operator about four
minutes. The value is dependent upon equipment in service. Although
this step is not urgent, recommend either insert the procedure number
for easy reference or specify the parameter for various equipment
combinations,
g. Specify applicable TS where the procedure refers to TS.
h. Except for equipment names and ID, the wording of step 1.2 in
Sections I and II should be standardized.
i. The licensee should consider deleting step 3.5 from Section II. It
is confusing and not required.
21. Load Rejection 1203.20
a. Step 2.1.2: This step states, "Maximize letdown." Maximize is not
defined and varies with system lineup. During the walkthrough, the
operator stated that he would increase letdown to 160 GPM. After
further thought and consulting another procedure, he determined that
the maximum letdown for the existing system lineup was 123 GPM.
b. Step 3.5: This step could be improved by changing "adjust speed" to
"adjust main turbine speed."
c. Step 3.10: This step states, "Operate moisture separator reheaters
per OP 1102.04 ( Attachnient A)." During the walkthrough, the operator
did not understand the intent of this step. This step saould state
"shut down" instead of "operate" in order to clarify its intent.
22. Loss of Neutron Flux Indication 1203.21
Step 3.1: This step of Section I states ". . . initiate shutdown to hot
shutdown conditions per OP 1102.10 in an additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Refer to
Technical Specification Table 3.5.1-1." This should be reworded as ths TS
requirement is to "place the reactor in the hot shutdown condition within
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />."
23. Loss of Reactor Cooling Flow - RCP Trip 1203.22
Step 3.4: This step states, "Set max load limit /5% below runback limit i
....
"
The operator should be instructed to reduce power to that point
before reducing the maximum load limit. Otherwise a runback will occur,
i
24. Less of Instrument Air 1203.24 i
, a. In Section I, steps 3.1 & 3.5 reconinend substitution of "compressors"
for "units" to avoid confusion (compressor trip vs unit 1/2 RX trip).
.
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Appendix C 13
b. Step 3.4: Insert caution preceding Section I concerning potential
for degradation of air supply to the unaffected unit when cross
connected.
c. Step 3.1: The guidance of Section II is vague and general. The
licensee should revise the step to clarify the situation.
d. Step 3.2.1: Section II of this step trips the reactor (and therefore
invokes E0P 1202.01 RX trip tab). Recommend merge step 3.2.5 with
3.2.1, adding a requirement to continue the A0P also,
e. Step 3.1: This step of Section II states, "If loss of air impairs
operation of any system, attempt to bypass or handjack such
components as necessary until air supply is restored." This guidance
is overly vague and general. Specific instructions should be
provided.
25. Natural Emergencies 1203.25
a. Step 6.1.3. A: This step states, "If any two earthquake annunciators
are in slow or fart flash and are verified as actual, take immediate
action to bring the unit to hot shutdown." There are only two earth-
quake annunciators in Unit 1. If the intent is te. include the Unit 2
annunciators, this should be clearly stated. Guidance should be
provided on how to verify that an annunciator is "actual."
b. Step 6.4: This step instructs the operator to close all watertight
doors, but does not list the watertight doors for both units.
26. Loss of Reactor Coolant Makeup 1203.26
Step 3.5: This step instructs the operator to go to OP 1104.02, Section I
8.11, but there is no 8.11 in the OP.
27. Remote Shutdown 1203.29
a. Several steps in this . procedure contain more than one action item.
Examples are Step 5 or Attachment 1, Step 1 of Attachment 1A, and
Step 2 of Attachment 3A.
b. Identical steps in different attachments should be worded
identically. Examples of discrepancies are:
Step 1 of Att 1 and 1A
Steps 4 and 5 of Att 1 and Steps 5, 6, and 7 of Att 1A
Step 6 of Att 1 and 1A
Step 1 of Att 1 and 1A
Step 4 of Att 2 and Step 3 of Att 2A
Step 8 of Att 2 and Step 5 of Att 2A
Step 1 of Att 3 and 3A
Step 2 of Att 3 and 3A
.
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- Appendix C 14
l
c. Step 3 of Attachment 3 states, "Verify main steam dumps operating to
control main steam pressure at approximately 1010 psig." As there is
no local main steam header pressure indicator near the turbine bypass
valves, this step should be clarified by telling the operator how to
determine main steam header pressure and whether to control the
valves manually.
d. The labels were missing from two of the six demineralizer inlet motor
operated valve handswitches operated in Step 4 of Attachrent 3 at the
time of the walkthrough.
e. Step 4 of Attachment 4 states, "Instruct Plant Guard to notify Plant
Management." In the current site organization there is not a
position entitled Plant Guard. The shift administrative assistant
should make notifications as required by the emergency plan
implementing procedures.
f. At the time of the walkthrough, the pushbuttons on the computer
console used in Step 5 of Attachment 4 were not properly labeled.
Some of the pushbuttons were missing their plastic covers.
g. Step 2 of Attachment 1A opens HPI MOV CV-1227 and Step 4 closes it.
Step 3 would take only a few se. unds to accomplish. The intent of
these steps is not clear. They would cause injection of a small, but
undefined and uncontrolled amount of water into the RCS.
h. Step 3 of Attachment 2A should indicate the location of the "auto,
stop oil press" indication. During the walkthrough, the operator did
not know where to read this pressure.
i. A typographical error in the note after Step 5 of Attachment 3 could
cause confusion. "Open CV-1219 Brkr. 5151)" should be "Open CV-1219
(Brkr. 5151)."
j. The position indication lights for CV-2627 at D15 Breaker 1522
checked in Step 3 of Attachment 3A were burned out. The operator i
could not determine the valve position during the walkthrough. I
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APPENDIX D
NOMENCLATURE DISCREPANCIES IDENTIFIED
BY
NRC E0P INSPECTION TEAM
___________________________________________________________________________
Step /
Procedure Page Procedure Nomenclature Label on Equipment
1202.01 3.2.1/6 Main Generator 5114, 5118
Breakers (5114, 5118)
1202.01 3.2.4/6,7 Nuclear ICW pump Same + number
" "
Non-nuclear ICW pump
" "
CRD Cooling Pump
" "
RCP Seal Cooling Pump " "
Spent Fuel Cooling Pump l
1203.24 3.6/1 ICW-7 ICW-7 Supply
1 solation
ICW-10 ICW-10 Return
Isolation
ICW-1173 ICW-1173
Demineralized
Water Supply
1203.10 3.5.1/2 CV-4804 CV-4804 RB Vent ,
Header Outside '
Isolation
3.5.1/2 CV-47303 CV-4803 RB Vent
Header Inside
Isolation
1203.02 10/9 00-121A 001-21A
7/21 D0-124 D01-24
13/9 00-221A D02-21A
7/21 00-224 002-24
l
14/9 6.9 KV Bus H-1 0.C. 6900 Volt !
Switchgear
Power H-2
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Appendix D 2
19/10 Manual Bypass Switch Manual Selector
switch
Normal Operation Inverter to Load
4/12 MS-250, 251, 252, and IA-26918,C, D,
and
E
253
MS-254, 255, 256, and IA-26928,C,D,
and
E
257
6/17 Equipment # not given
3.7.8/33 CV-3820 CV-3821
3.7.15/33 CV-3820 CV-3821
1/39 Breaker names Different ]
" "
1,2,3,40 " "
"
1,2,3,40 " " "
)
1202.01 76/6.4.5 SW to RB SPRAY P-35 A/B SW to P35A/B L0 l
CLR l
'
LO CLR (CV-3804/5) (CV-3804/5)
1203.07 1/1.1 Process Radiation Process i
Radiation !
Monitor Alarm Hig Rad
1203.26 2/3.6 Makeup Isolation RCS Makeup
Valve
1203.27 1/1.3 OTSG Steam Generator
1203.27 1/2.4 Feedwater Crossover Feedwater Pump
Valve Disch Crosstie
1203.15 1/2.1 ERV Block Valve CV-1000
.
>
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Appendix D 3
1203.15 6/1.1 Soray Valve CV-1008
1203.15 6/2.1.2 Spray Block Valve CV-1009
1203.31 3/2.2 ICW Booster RCP Seal Inj Block
1203.31 3/2.2 ICW Booster RCP Seal Cooling
1203.31 5/1.1 ICW Non-nuclear Loop ICW Loop Low Flow
low flow
1203.13 3/4.8 Feed Makeup
1203.13 4/4.15 P7B Suction Transfer P78 Suction Select
1 e.06 1/1.1 Process Radiation Process Monitor
Monitor High Rad
.-
1233.06 1/1.1 Waste Gas Discharge Gaseous Rad Waste
Water
1203.06 1/1.3 Waste Gas Panel Radwaste
Trouble
1202.01 3.2.1A/6 Main generator breakers 5114 (5118)
(5114 & 5118)
3.2.4/7 (procedure lists only noun name but should list
name and equipment number)
1.10.1C/1 Condenser vacuum Main condenser
pump radiation radiation
__
1203.16 3.6/2 Upper Turbine bypass
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Appendix D 4
3.6/2 Lower Low
3.6.5/2 Turbine bypass valve Turbine bypass low
selector switch
vacuum
override
1203.17 1.3/2 Boronometer Boron
& concentration trend
recorder AR-1290
1.2/3
1203.24 1.1/1 Lo instrument Instrument air
air header pressure header pressure
lo
3.6/1 ICK regulator ICW control
regulator
3.6/1 (none) (Label condensate
supply valve in SU
boiler room & add
reqmt to procedure
step 3.6 to open valve)
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APPENDIX E
LIST OF ABBREVIATIONS
ADV Atmospheric Dump Valves
ANO-1 Arkansas Nuclear Cne , Unit 1
A0P Abnormal Operating Procedure
APSR Axial Power Shaping Rods
AT0G Abnormal Transient Operating Guidelines
B&W Babcock & Wilcox
BWST Borated Water Storage Tank
CRD Control Rod Drive
CST Condensate Storage Tank
DC Direct Current
DPM Decades per Minute
EDG Emergency Diese' Generator
EFIC Emergency Feedwater Initiation Control
E0P Emergency Operating Procedure
EP Emergency Operating Procedure
EPG Emergency Procedure Guidelines
ERV Electromagnetic Relief Valve
ES Engineered Safeguards
ESAS Engineered Safeguards Actuation System
GPM Gallons per Minute
GTG Ganeric Technical Guidelines
HP High Pressure
HPI High Pressure Injection
ICC Inadequate Core Cooling
ICS Integrated Control System
ICW Intermediate Cooling Water
I&E Instrument & Electrical
INP0 Institute of Nuclear Power Operations
LCO Limiting Condition of Operation
LOCA Loss of Coolant Accident
LPI LowPressureInjection
Main Feedwater Isolation Valves
,
MFIV l
MSIV Main Steam Isolation Valve ,
MSI Main Steam Line Isolation l
MOV Motor Operated Valve
MPC Maximum Permissible Concentration l
NLO Non-licensed Operator !
NNI Non-Nuclear Instrumentation 1
NRC Nuclear Regulatory Commission i
OG Owners Group
OP Operating Procedure
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Appendix E 2
0TSG Once Through Steam Generator
PGP Procedure Generation Package
PSIA Pounds per Square Inch Absolute
PSIG Pounds per Square Inch Gauge
P/T Pressure / Temperature
PWG Procedure Writers Guide
PZR Pressurizer
l QA Quality Assurance
l RB Reactor Building
l
RCP Reactor Coolant Pump
, RCSI Reactor Coolant System Inventory
Regulatory Guideline
'
RV Reactor Vessel
RX Reactor
,
SER Safety Evaluation Report
SG Steam Gerierator
SPDS Safety Parameter Display System
, SR0 Senior Reactor Operator
l $$ Shift Supervisor
SSA Shift Administrative Assistant :
STA Shift Technical Advisor l
TBD Technical Basis Document !
l TMI Three Mile Island '
l
'
TS Technical Specifications
UV Urder Voltage
V&V Validation and Verification
i
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