IR 05000313/1988017
| 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 | |
| Preceding documents: |
|
| Download: ML20151K334 (38) | |
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jgt atGg UNITED ST ATES g
'c, NUCLEAR REGULATORY COMMISSION
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ATLANTA, GEORGI A 30323 I
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July 5, 1988
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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 S "Je ff
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Inspection Team Leader: e iN
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Lawyer (/
Date 31gned Inspection Team Members: J. DeBor M. DeGraff P. Kellogg G. Bryan W. Johnson CA W 7/5/8W Approved by:
C. A. JulIaft,sChief Date Signed Operations Branch Division of Reactor Safety SUMMARY Scope:
This special, announced inspection was conducted in the area of review of the adequacy of Emergency Operating Procedures for Unit 1.
No inspection of Unit 2 was conducted.
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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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REPORT DETAILS
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1.
Persons Contacted
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- W. Converse, Operations Assessment Superintendent i;
M. Cooper, Nuclear Quality Specialist
- E. Ewing, General Manager Plant Support
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B. Garrison, Operations Technical Support
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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 l
Other licensee employees contacted included engineers, technicians,
operators, and office personnel.
NRR Attendees
- C, Harbuck, Project Manager, NRR
- G. Lapinsky, NRR NRC Region IV Attendees
- J. Gagliardo, Section Chief
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- A. Howell, Project Engineer
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- Denotes those persons attending the exit interview.
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2.
Exit Interview
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 inspected and discussed in detcil-the inspection findings listed below.
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j Licensee representatives agreed to review and resolve the open i', ems which are documented in paragraphs 6, 7, 8, and 9 of this report. Although i
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
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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
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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
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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
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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:
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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.
j From this PGP, plant specific E0Ps were to have been developed that would
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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
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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
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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.
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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 The NRC reviewed the relationship between the ANO-1 E0Ps and the plant
specific ATOG Parts 1 and 2.
Part 1 of the ATOG, including a sample set
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of E0Ps, was rejected by the licensee as inappropriate for ANO-1.
However, the ANO-1 based AT0G Part 2 was used to develop the plant specific a
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
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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.
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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 maintaine _
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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, not a significant problem.
The inspectors verified that placeks
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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.
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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, and human factors were noted. Technical discrepancies are identified in
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.
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.
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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.
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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 staff in August 1988. This addition is expected by licensee personnel to i
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 NUMBER TITLE REV OP 1202.01 EMERGENCY OPERATING PROCEDURE
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OP 1203.01 ICS ABNORMAL OPERATING
OP 1203.02 ALTERNATE SHUTDOWN
i OP 1203.03 CONTROL R0D DRIVE MALFUNCTION ACTION
OP 1203.04 REACTOR HIGH START UP RATE-
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OP 1203.05 LOSS OF REACTOR BUILDING INTEGRITY
OP 1203.06 WASTE GAS DISCHARGE LINE RADIATION HIGH 4 OP 1203.07 LIQUID WASTE DISCHARGE LINE HIGH
RADIATION ALARM
OP 1203.08 EXCEEDING THERMAL LIMITS ON CONDENSER
DISCHARGE WATER
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OP 1203.10 AB0VE NORMAL H2/02 CONCENTRATION
OP 1203.13 NATURAL CIRCULATION C00LD0WN
OP 1203.14 CONTROL OF SECONDARY SYSTEM
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OP 1203.15 PRES $URIZER SYSTEMS FAILURE
OP 1203.16 LOSS OF CONDENSER VACUUM
OP 1203.17 MODERATOR DILUTION
OP 1203.16 TURBINE TRIP BELOW 43 PERCENT POWER
OP 1203.19 HIGH ACTIVITY IN REACTOR COOLANT
OP 1203.20 LOAD REJECTION
OP 1203.21 LOSS NEUTRON FLUX IND
OP 1203.22 LOSS RC FLOW RCP TRIP
OP 1203.23 SMALL STEAM GENERATOR TUBE LEAKS
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OP 1203.24 LOSS INSTRUMENT AIR
OP 1203.25 NATURAL EMERGENCIES
OP 1203.26 LOSS OF REACTOR COOLANT MAKEUP
OP 1203.27 LOSS STEAM GENERATOR FEED
OP 1203.28 LOSS DECAY HEAT REMOVAL SYSTEM
OP 1203.29 REMOTE SD
i OP 1203.30 LOSS SERVICE WATER
i OP 1203.31 REACTOR COOLANT PUMP AND MOTOR
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.
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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Appendix B
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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.
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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."
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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.
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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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Appendix B
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, 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
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.
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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.
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
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 Revise the A0P to recognize those symptoms which are severe enough to a.
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 boro,
i l
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Appendix B
i b.
An example of a case which warrants immediate boron injection isSection 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 licensee should revise the procedure to delete this incorrect reference.
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 vent. - - _ _ _ - _ - _ _ _ _ _ - _ _ _ _ _
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.
Appendix B
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 as these are eliminated if possible and at least minimized.
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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 The guidance provided for persons writing E0P sections and A0Ps is a.
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.
Consistency is not maintained between parameter units used in the e.
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.
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Appendix C
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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.
Although the current Writer's Guide is improved over that in use at n.
the time of submission of the PGP package, there is no composite writer's guide.
ANO defines (ANO letter of 7/17/84 to NRC) the 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.
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Appendix C
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 RPS and ESAS, respectively.
d.
Step 3.8.F:
The parameters for RCS pressure and temperature should be defined.
e.
Step 3.9.B: Delete the ().
f.
Step 3.10.1.B:
Correct typographical error (ligth).
'
g.
Step 3.10.4.E:
Correct the step to read "E.
.".
.
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 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.
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Appendix C
m.
Step 3.5.4:
This step requires, "Verify at least one RCP pump is running."
In this instance "verify" does not mean to start the pump
)
if it is not running.
Step 3.5.5 starts available RCPs.
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 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 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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.
Appendix C
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).
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
'
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
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.
- 1.
Given a reactor trip and exit to degraded power followed by initial successful sequencing of the EDGs to A3 & A4, then a loss of A3/4, 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 pumps, etc.
To be consistent with other steps completing the same action, the licensee should revise the procedure to verify that the seal cooling low flow alarm has cleared.
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Appendix C
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
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 1202.01-2 min. case.
Since 13.2.3 a.
Step 13.2:
This step considers the 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.
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.
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Appendix C
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 should be established to assure that a current list is available.
Step 6 on Page 17 should include equipment numbers for isolating seal c.
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 availabl.
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.
Appendix C
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.
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
17.
Pressurizer Systems Failure 1203.15 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 maximum. Maximum is undefined and varies with system lineup.
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 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 j
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Appendix C
!
in both sections to require some additional verification of unacceptable activity before a shutdown is directed.
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 i
Step 3.4:
This step states, "Set max load limit /5% below runback limit The operator should be instructed to reduce power to that point
"
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before reducing the maximum load limit.
Otherwise a runback will occur, 24.
Less of Instrument Air 1203.24 i
a.
In Section I, steps 3.1 & 3.5 reconinend substitution of "compressors"
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for "units" to avoid confusion (compressor trip vs unit 1/2 RX trip).
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Appendix C
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 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
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.
Step 4 of Attachment 4 states, "Instruct Plant Guard to notify Plant e.
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.
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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
"
"
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
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 CLR
'
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
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 SW SW 1 e.06 1/1.1 Process Radiation Process Monitor Monitor High Rad
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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
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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O 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 AP&L Arkansas Power and Light 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 EFW Emergency Feedwater E0P Emergency Operating Procedure EP Emergency Operating Procedure EPG Emergency Procedure Guidelines ERV Electromagnetic Relief Valve ES Engineered Safeguards ESAS Engineered Safeguards Actuation System FW Feedwater 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 MFIV Main Feedwater Isolation Valves
,
MSIV Main Steam Isolation Valve
,
MSI Main Steam Line Isolation MOV Motor Operated Valve MPC Maximum Permissible Concentration NLO Non-licensed Operator NNI Non-Nuclear Instrumentation NRC Nuclear Regulatory Commission OG Owners Group OP Operating Procedure
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Appendix E
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 RCP Reactor Coolant Pump l
RCS Reactor Coolant System RCSI Reactor Coolant System Inventory
,
RG Regulatory Guideline
'
RPS Reactor Protection System 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
TBD Technical Basis Document
!
l TMI Three Mile Island
'
l TS Technical Specifications
'
UV Urder Voltage V&V Validation and Verification i
l
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