IR 05000338/1992031
| ML20126E514 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 12/17/1992 |
| From: | Crlenjak R, King L, Mellen L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20126E497 | List: |
| References | |
| 50-338-92-31, 50-339-92-31, NUDOCS 9212290167 | |
| Download: ML20126E514 (16) | |
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OY UNITED STATES
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%,g NUCLEAR REGULATORY COMMISSION.
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titoloN ll p
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g 101 MARIETTA STRE ET, NW.
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ATLANTA GEoRCIA 30323
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Report Nos.:
50-338/92-31 and 50-339/92-31 Licensee:
Virginia Elect +ic and Power Company 5000 Dominion Boulevard Glen Allen, VA 20360 Docket Nos.:
50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name:
North Anna Inspection Conducted: Dec mber 7 - 10, 1992 12 [/8h K
Inspectors:
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D. Mellen, Reactor Inspector Date Signed r /
h 12 O YN
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'l.. King,Ractor/nspector Dat'e Signed
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M NL Approved by:
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R./<rlenjak, Se(tion Chief /
Date Signed Operational Program Section Operations Branch Division of Reactor Safety
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SUMMARY
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Scope:
This was a special announced inspection in the area of Emergency Operating Procedure and Abnormal Operating Procedure followup. The inspectors reviewed the resolution of previously identified comments and the resulting Emergency Operating Procedure and Abnormal Operating Procedure changes.
Results:
The inspectors concluded the licensee had well documented and well prepared responses to previously identified inspection findings. A previously identified concern identified the omission of a procedure to mitigate the consequences of the unavailability of the reactor vessel level indication system during natural circulation cooldown with steam voids present. The licensee developed a procedure to adequately and accurately address this subject (paragraph 2).
The licensee had developed an appropriate methodology to ensure procedural accuracy during changes to plant configuration or accident mitigation strategy changes (Emergency Response Guideline maintenance items) (paragraph 3).
The Abnormal Operating Procedures reviewed were 9212290167 921217 PDR ADOCK 05000338 O
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accurate and would-perform their intended safety functions 1(paragraph-4). The-
- -licensee adequately' addressed specific-technical and' human factors comments
- an'd,-where appropriate, generically applied-specific comments-(paragraph l6),
The Emergency Operating-Procedures were adequate to mitigate the broad b
spectrum of accidents listed in the Westinghouse-0wners Group Emergency i
Response Guidelines.
The basis for deviations from the' Westinghouse-Owners i
Group Emergency Response-Guidelines were well documented and the.
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. justifications for these deviations were~ accurate.
No violations or deviations were identified.
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- REPORT DETAILS-1.
Persons' Contacted M. Allen, Traini_ng Supervisor.
- M. Crist, Procedures Supervisor G. Crisman, Outage Coordinator J. Daily, Coordinator Nuclear Procedures J. George, Reactor Operator J. Hayes, Manager of_ Operations
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y G. Kane, Station Manager
- P. Kemp, licensing Supervisor
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- J. Leberstein, Engineer - Licensing J. Loman, Training J. Smith, Manager --Quality Assui ance
- A. Stall, Assistant Plant Manager - Safety and Licensing B. Starr, Training
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J. Vo_issem, Lead Emergency Operating Procedure Writer
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Other licensee employees contacted included instructors, engineers, o
mechanics,. technicians, operators, and office personnel.
NRC Representatives-
- M. Lesser, Senior Resident Inspector-D. Taylor, Resident Inspector
- Attended Exit' Interview Appendix A contains a listing of abbreviations used in this report.
- 2.
Operations Without_ Reactor Vessel Level Instrumentation' System-
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During the'50 338,339/90-11 NRC E0PLinspection, the inspectors compared'
the North Anna E0Ps with the NRC approved ERGS and found that~the
. licensee had not written an-E0P corresponding to ES-0.4, Natural-Circulation-Cooldown With Steam Void in_the Vessel Without Reactor-Vessel Level-Instrumentation System. The~ inspectors confirmed the licensee had written a procedure to correspond to ES-0.4. -The procedure.
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provided the guidance necessary for natural' circulation-cooldown with
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steam void in reactor. vessel'without RVLIS.
-The inspectors reviewedithe ES-0.4 deviation document and verified the licensee had. accurately documented any deviatio'ns'from the ERGS..The inspectors' concluded the deviations were appropriate and-pr_imarily.
resulted from differences between North Anna and the WOG's' reference plant. The deviations did not adversely impact the-accident: mitigation strategy.
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The inspectors also reviewed the verification and validation documents.
These documents conformed to the requirements of VPAP-0506, E0P Development, Revision, and Maintenance, Revision 2, and were accurately completed.
The inspectors verified the appropriate procedure changes were incorporated.
The inspectors compared the index of North Anna E0Ps and AOPs against the index of WOG ERGS and the list of remaining emergency procedures recommended in Regelatory Guide 1.33.
With the inclusion of ES-0.4 in the accident mitigation strategy procedure network, the inspectors confirmed that the licensee had developed sufficient procedures to encompass the broad spectrum of accidents and equipment failures addressed by the ERGS, Regulatory Guide 1.33, and the UFSAR.
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3.
Independent Technical Adequacy Review of E0Ps and AOPs
At the time of the 50-338,339/91-21 NRC E0P followup inspection, the licensee had not completed the inclusion of E0P comments from internal audits or the 50-338,339/90-11 NRC E0P inspection.
The inspectors reviewed the licensee's current disposition and resolution of these comments and found that the comments had been appropriately dispositioned and the responses were technically adequate.
The inspectors conducted plant and/or MCR walkthroughs on selected portions of the E0Ps and A0Ps.
The walkthroughs were conducted for the following reasons:
1) to confirm that the procedures could be followed and would accomplish the stated purpose; 2) to serify that the listed instrumentation and controls were consistent with the installed plant equipment; and 3) to ensure that the listed indicators, annunciators, and controls were available to the operator.
During the walkthroughs, the inspectors found that all of the E0Ps and A0Ps selected were
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adequate,
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The inspectors reviewed the transition from one procedure to another procedure during the implementation of E0Ps and A0Ps. The licensee had established a formal method for tracking incomplete continuous actions or conditional statements that still were applicable when the operator returned to the original procedure. The inspectors did not note any difficulty in E0P transition.
A0P reference procedures are discussed in paragraph 4.
The license's program for maintaining the E0Ps (including ERG maintenance items) required that all changes to the procedures be accomplished via the normal procedure revision process to ensure that they were properly reviewed and validated prior to their use.
This process included an appropriate methodology to ensure procedural accuracy during changes to plant configuration or accident mitigation strategy improvements. The inspectors reviewed several ERG maintenance items and found the licensee had appropriately dispositioned each of.the items.
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j During th'e 50-338,339/90-11 NRC E0P; inspection, the inspectors noted; several irregularities in the procedure change review proce'ss..The inspectors reviewed several recent_ procedural' changes and found that-
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regulations.
There were no additional examples of-irregularities in:the procedure change review process.
The inspectors considered this item
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A finding identified during the 50-338,339/90-11 NRC E0P inspection was-the use of inconsistent wording for the same action between different steps and between different procedures. The inspectors reviewed
selected E0Ps and found that this inconsistency had been corrected. The-licensee had-incorporated a software package in the E0P development which apparently eliminated this problem.
The inspectors considered:
this item adequately resolved.
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4.
Abnormal Opera _ ting Procedures At the time of the 50-338,339/91-21 NRC E0P followup inspection the AOPs had been upgraded. The licensee responded.to the following comments _on the A0Ps reviewed:
a.
Comment -;l-AP-15 Step 1.e stated to-locally check service water to CC HX if differential pressure was-less than 25 psid. The corresponding RNO stated to restore service' water flow to CC HXs;
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and also instructed the operator to. initiate AP-12, Loss of Service Water, if service water was -not available.
In conditions when there was no service water flow,-the differential pressure would be zero which would satisfy the action statement because the differential pressure was less than-25 psid.
This was: inadequate guidance because it would not direct the operator to restore
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service water or initiate AP-12.
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Response --The inspectors reviewed 1-AP-15 and verified'the-
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procedure had been revised for conditions when there was no service water flow. _ The ' operator _was appropriately directed to locally check service water to.th'e CC HXs and'if it was not'
available to restore service water flow to CC HXs using. applicable steps of 0-0P-49.1, Service Water Normal System Operation, or if j
service water was not available to initiate 1-_AP_-12.
b.
Comment - 1-AP-22.2 Attachment 2, Step 1.d required the operator to close and lock 1-FW-62, which was already locked and closed in its original position. This instruction was inconsistent because.
the other valves in the system which were unaffected by the procedure were not explicitly required to-be verified'in their original position.
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Response - The inspectors reviewed 1-AP-22.2 and the licensee response which clarified why this was not inconsistent.
If dttaChment 3 was used, then 1-FW-62 would be unlocked and opened.
This valve was not manipulated in Attachment 4.
The instructions in Attachment 2 were correct based on the need to return the AFW system to a normal alignment if Attachment 3 was used.
However, if Attachment 4 was used, then there was no need to close and lock 1-FW-62 since it was not opened. OPAP-0002, Operations Department Procedures, allowed the operator to sign off the step and continue with the procadure provided any condition that was not expected was reported to the Shift Supervisor. No procedure changes were required. The inspectors considered this an acceptable response, Comment - 0-AP-27 Step 24.c RNO did not verify open the spent fuel c.
cooler outlet valves,1-CC-281 and 1-0C-292, and the inlet valves, 1-CC-283 and 1-CC-274.
This could lead to isolation of the CC water to the spent fuel pool coolers.
Response - The inspectors reviewed 0-AP-27, Revision 1 and noted Step 24.c RNO had been revised to include appropriate instructions-for disposition of spent fuel pool heat exchanger cooler inlet and outlet valves.
This item has been appropriately corrected.
d.
Comment - 1-AP-52 Note 1, Step 1 and Step 2 required manual control of the manipulator crane if electrical power was unavailable.
Contractors typically performed refueling activities and were not required to perform a Job Performance Measure or the equivalent for manual control of the manipulator crane. This evolution was not considered to be skill of the craft since the manipulator cranes differ from site to site and this task was required to be performed within twenty minutes.
Additionally, the procedure required to perform the manual evolution was not referenced.
Response - The inspectors reviewed 1-AP-52 and noted the licensee had e'ected not to revise the procedure.
The licensee decided to include appropriate instructions in the training of manipulator crane operators. The inspectorr viewed the manipulator crane operator training and found that the there was an outstanding commitment to include crane operators in outage specific training; however, this training was not scheduled to be implemented until June 1993.
The outstanding ccamitment indicated that the manipulator crane operator training had not been revised to include crane operations if electrical power was unavailable. The inspectors review found that the manipulator crane operators were already included in the outage training and would be trained on emergency operations prior to the January 1993 refueling outage.
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The inspectors verified that the appropriate training was. already inplace and that the commitment would be closed in June 1993 when-the revisions were evaluated to ensure long term training would be adequate.
The inspectors discussed the content of this crane operator training with training management and concluded that the training currently in place was adequate.
This item was adequately dispositioned.
The inspectors also reviewed selected A0Ps to determine their technical adequacy. The A0Ps reviewed were accurate and would perform their intended safety functions.
Following the 50-338,339/91-21 NRC E0P followup inspection, the licensee developed an A0P, 1-AP-17, Shutdown LOCA.
The_WOG developed a shutdown LOCA abnormal response guideline, ARG-2.
The purpose of this guideline was to protect the reactor core in the event of a LOCA that occurred after the accumulators were isolated in Mode 3 or in Mode 4.
1-AP-17 covered a broader spectrum of operational-conditions.
It provided instructions to respond to a LOCA that occurred in Modes 4, 5, or 6.
The major difference was the WOG's reference plant had LHS1 pumps which could be aligned in the RHR mode, and if the LOCA occurred in this mode it could be necessary to manually realign the pumps in the SI mode. North Anna had separate LHS1 and RHR pumps which did not require realignment.
The inspectors reviewed 1-AP-17 to confirm that it was written in accordance with the WOG ARG-2 and determined that all differences were justified.
There was no requirement to have a step deviation document for the new procedure. The inspectors also reviewed the step description table for ARG-2 and found all the steps had been justified. Additionally, the inspectors reviewed NE Technical Report 897, Shutdown LOCA Setpoint Document, and confirmed that a sample of setpoints had been adequately justified. 'Most of the setpoints had been previously defined for use in the E0Ps. The inspectors concluded that the ARG had been appropriately implemented.
The inspectors reviewed the network of procedures required to complete certain aspects of 1-AP-52, Loss of Refueling Cavity Level During Refueling. The inspectors also reviewed the procedures required to complete the actions in the referenced procedures. The inspectors found there were many procedures that did not correctly reference existing procedures.
The breakdown is as follows:
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BASE PROCEDURE REFERENCE COMMENTS 1-OP-16.5 1-0P-16.2 REPLACED BY 0-0P-16.2A Note 1 1-0P-16.5 1 0P-26 DELETED 7/27/89 Note 2 1-0P-16.5 1-0P-9 SHOULD BE l 0P-9.1 Note 2 1-0P-63.2 1-0P-63A REPLACED BY 0-0P-63A Note 1 1-0P-51.2 1-0P-35 DELETED Note 2 1-0P-51.2 1-0P-50 DELETED Note 2
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l-0P-51.2 1-0P-46 DELETED Note 2 1-0P-8.7 1-0P-27.1 DELETED Note 1 1-0P-21.4 1-0P-26 REPLACED BY 0-0P-26.9 Note 2 0-AP-12 1-0P-49.1 REPLACED BY 0-0P-49.1, 0-0P-49.2, 0-OP-49.3, and 0-0P-49.4 Note 3 1-0P-26.2 1-0P-23 DELETED Note 2 1-0P-8.3 1-0P-12 DELETED 1/20/92 Note 2 Note 1:
This was a unit specific procedure.
This has be:n replaced by a common procedure.
Note 2:
This was a cover sheet procedure.
This has been replaced by an electronic indexing procedure.
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Note 3:
This procedure was replaced by a series of common procedures
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following a major rewrite of the service water procedures.
The inspectors considered the inaccuracies in referenced procedures to be an inappropriate application of human factors principles in the support procedure network. The inspectors found no examples that would prevent the procedures from performing their intended safety function.
Many of the evolutions periormed by this procedure were time dependent.
The inaccurate procedure references did not appear to present a significant time delay in the implenentation of the procedure.
The inspectors discussed this with plant management and were informed that
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the procedure update program would correct these problems.
To verify that the operational procedural references would have no significant operational impact, the inspectors reviewed the NE Technical Report No. 829, Technical Review of A0P AP-52 Loss of Refueling Cavity
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Level During Refueling North Anna Power Station Units 1 and 2, dated
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February 1991. The technical report provided the background for the development of AP-52. The inspectors verified the assumptions were
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appropriately incorporated into A0P steps and that the restrictions placed on the support procedures by calculational assumptions were included.
5.
Management Control of E0Ps and Interfacing Documents During the 50-338,339/90-11 NRC E0P inspection, the inspectors reviewed the licensee's Quality Assurance group's E0P and AOP audits.
The inspectors reviewed the completed audit report and determined the proposed corrective actions were comprehensive and usually addressed the root cause of the problems.
The majority of the corrective actions had been incorporated into the E0P upgrade. The inspectors verified these corrective actions were adequate.
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The inspectors reviewed the licensee's implementation of a commitment tracking data base, VE-COMS.
The inspectors found individual E0Ps had sections which delineated the specific commitments made for each E0P, the source of the commitment, and other commitment specific requirements. This program ensured the satisfactory implementation of all E0P related commitments.
The inspectors verified the program by tracking selected commitments from their point of origin to their point of procedural implementation. The inspectors found no examples of inappropriately dispositioned commitments.
6.
Follow-up on Previous Inspection Findings (91702)
a.
(Closed)
IFI 50-338,339/90-11-02, Lack of detail in procedures.
During the 50-338,339/90-11 NRC E0P inspection the inspectors found the emergency procedures lacked details.
For example, the steps to perform emergency boration were not identified. Valve locations for hard to find valves were not given in Attachment 2
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to ECA-2.1 and the alternative instrument air valves used for securing the main steam isolation valves on Unit 2 were inaccessible.
To resolve these previously noted discrepancies, the inspectors reviewed the current revision of the E0Ps and confirmed that these specific discrepancies had been successfully resolved. The inspectors also reviewed a selected sample of other E0Ps and confirmed there was sufficient procedural detail to ensure the accident mitigation strategy would be appropriately implemented.
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(Closed)
IFI 50-338,339/90-11-03, E0P technical and human factors deficiencies.
During the 50-338,339/90-11 NRC E0P inspection the inspectors found many procedures that were technically inadequate.
For example, E-1 step 4 required the operator to verify that the S/G blowdown radiation monitors read normal.
This could not be accomplished unless the breakers for one main feed pump were racked (out) to test and closed before resetting the blowdown trip
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valver.
ECA-0.2 did not specify the indications to be checked in order to determine adequate seal cooling.
The inspectors also identified that the operators had trouble locating equipment when performing electrical A0Ps.
The operators did not locate the spare 4160 volt breaker that would be used to crosstie the Unit 2 emergency busses.
To resolve these previously noted discrepancies, the inspectors reviewed the current revision of the E0Ps and confirmed that these specific discrepancies had been successfully resolved.
The inspectors also, reviewed a selected sample of other E0Ps and confirmed that the E0Ps reviewed did not contain technical and human factors deficiencies, The technical and human factors content of the E0Ps was sufficient to ensure the accident mitigation strategy was appropriately addressed, c.
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IFI 50-338,339/90-11-04, Improper use of notes and cautions in procedures.
During the 50-338,339/90-11 NRC E0P inspection, the inspectors also identified several examples of improper use of notes and tautions.
For example, the notes and cautions used in E-3 contained either actions, implied actions, or conditional actions.
To resolve these previously noted discrepancies, the inspectors review 3d the current revision of the E0Ps and confirmed that the specific discrepancies noted in NRC inspection report 50-338,339/90-11 had been successfully resolved.
The inspectors also reviewed a selected sample of other E0Ps and confirmed that notes and cautions did not contain actions and conformed to the WG, d.
(Closed)
IFI 50-338,339/90-11-05, E0P WG deficiencies.
During the 50-338,339/90-11 NRC E0P inspection the inspection team determined that the E0P WG included appropriate topics as indicated by NUREG-0899; however, it did not thoroughly address each aspett of the procedures.
The WG also did not restrictively define the methods designated to assure consistency within and between procedures.
There was also no method to retain procedural consistency over time and through personnel changes.
To resolve these previously noted WG discrepancies, the inspectors reviewed the current revision of the WG and confirmed that the specific discrepancies noted in NRC inspection report 50-338,339/90-11 had been successfully resolved. The inspectors also reviewed a selected sample of E0Ps and confirmed that the WG had been consistently implemented during the procedural development.
The licensee revised the WG to ensure consistency over time and through personnel changes and the inspectors verified that it had been appropriately modifie _ - _
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Exit Interview The inspection scope and findings were summarized on December 10, 1992, with those persons indicated in paragraph 1.
The NRC described the areas inspected and discussed in detail the inspection findings.
No-proprietary material is contained in this report.
No dissenting comments were received from the licensee.
Item Number Description IFI 50-338,339/90-11-02 (Closed)
Lack of detail in procedures IFI 50-338,339/90-11-03 (Closed)
E0P technical and human
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factors deficiencies IFI 50-338,339/90-11-04 (Closed)
In toer notes and cautions in procedures IFI 50-338,339/90-11-05 (Closed)
E0P WG deficiencies
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! APPENDIX A Abbreviations AFW Auxiliary Feedwater
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AOP Abnormal Operating Procedure-
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ARG Abnormal Response Guideline
- ATWS Anticipated Transient Without Scram CC Component Cooling CRDM Control Rod Drive Mechanism E0P Emergency Operating Procedures ERG Emergency Response Guideline FW Feedwater IFI Inspector Followup Item HX Heat Exchanger
- LHSI Low Head Safety-Injection LOCA Loss of Coolant Accident MCC Motor Control-Center MCR Main Control Room NRC Nuclear Regulatory Commission RCP Reactor Coolant-Pump RNO Response Not Obtained
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RSS Reserve Station-Service RVLIS Reactor Vessel level Instrumentation System SI
_ Safety-Injection SFP Spent Fuel Pool-SGTR Steam Generator Tube = Rupture UFSAR Updated Final Safety Analysis Report
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WG Writer's Guide
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WOG Westinghouse Owners Group t
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PROCEDURES REVIEWED-The following are the specific procedures reviewe'd for resolution of NRCL EOP--
inspection 66 338,339/90-11 comments.- Any: additional comments are contained
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in the body of the_reporL 1.
E series procedure comments:
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E-0 Reactor trip or safety injection 2.
E-1 Loss of reactor o.' secondary coolant 3.
E-2 Faulted steam generator isolation
E-3 Steam generator tube rupture j
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ES comments:
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ES-0.1 Reactor trip response-
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ES-0.2A. Natural circulation cooldown with CRDM fans 3.
ES-0.2B Natural cicculation cooldown without CRDM fans 4.
ES-0.3 ~ Natural circulation cooldown with' steam void inivessel L
(with RVLIS)
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ES-1.2 Post LOLA cooldown and depressurization 6.
ES-1.4 Transfer to_ hot leg recirculation 7.
ES-1.5 Transfer. from hot _ leg recirculation to cold leg r2 circulation 8.
ES-3.1 Post-SGTR:cooldown using backfill
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III.
ECA comments:
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ECA-0.0 Loss of all AC power i
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ECA-0.1 Loss of all AC. power recovery without:SI required.
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ECA-0.2 Loss of all AC power with_SI required
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ECA-1.1 Loss of emergency; coolant' recirculation 5.
ECA-1.2 LOCA outside containment 6.
ECA-2.1 ' Uncontrolled depressurization of all steam generators
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ECA-3.1 SGTR with loss of reactor. coolant
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ECA-3.2 SGTR with loss of reactor coolant - saturated recovery _
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-ECA-3.3 SGTR without pressurizer _ pressure: control IV.
FR comments:
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FR-S.1 Response to nuclear power-generation /ATWS.
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FR-C.2 Response to degraded core cooling
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- FR-C.3 Response _ to saturated core cooling
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FR-H.2 Response.to. steam generator overpressure-g 5.
'FR-H.3 Response to_ stean_ generator high level 6.
FR-H.5 ~ Response to steam generator _ low level 7.
FR-P.1; Response To Pressurized Thermal Shock Condition 8.
FR-P.2 Response to-anticipated pressurized thermal shock condition 9.
FR-Z.2 Response to high containment sump level
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Appendix B 2L 10.
FR-Z.4~ Response.to containment positive pressure!
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FR-I.1 Response to high pressurizer level 12.
FR-1,3 Response to voids;in reactor vessel V.
CSFST comments:
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F-0.6 Inventory
VI.
AP comments:
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AP-3 Loss of vital instrumentation
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AP-3.1 Loss of vital instrumentation reactor coolant flow
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AP-3.2 Loss of vital instrumentation pressurizer levelu
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AP-3.3 Loss of vital instrumentation pressurizer pressure
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AP-3.4 Loss of vital, instrumentation loop delta T/TAVG 6.
AP-3.5 Loss of. vital instrumentation containment pressure 7.
AP-3.6 Loss of vital instrumentation steam generator level 8.
AP-3.7 Loss of vital instrumentation steam flow 9.
AP-3.8 Loss of vital instrumentation - feed. flow
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. Loss of vital instrumentation = steam pressure
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AP-3.10 Loss of vital instrumentation turbine'stop valve closure signal 12.
AP-3.11 Loss of vital instrumentation turbine first stage pressure 13.
AP-3.12 Loss of-vital instrumentation autoEstop: oil' low pressure 14.
AP-5.1 Unit,1 radiation. monitoring system 15.
AP-5.2 Common radiation-monitoring system 16.
AP-10.1 Loss of electrical power 17.
AP-10.2 Restoration of 2 *itchyard 18.
AP-10.3 Restoration of RS1 transformers 19.
AP-10.4 Restoration of t.ansfer busses 20.. =AP-10.5 Restoration af "lH" 4160. volt emergency bus-21.
AP-10.6 Restoration af "lJ" 4160 volt emergency bus.-
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AP-10.7 Restoration o,' "2H" 4160 volt emergency bus
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AP-10.8 Restoration:of "2J" 4160 volt _ emergency bus-24.
.AP-10.9.
Restoration of 480 volt emergency bus-125.
_AP-10.10 Restoration of 480 volt _ emergency M.C.C's 26.
AP-10.ll Restoration of-semi-vital busses'
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AP-10.12 Restoration of D.C. Buses 28.
AP-10.13 Restoration of AC vital busses 29.
AP-10.22 Restoration of station' service 480 volt busses 30.
AP-10.23 Restoration of station. service 480 volt MCC's 31.
AP-13 Loss tof one or more circulating water: pumps 32.
AP-14-Low condenser vacuum-33.
-AP-18 Increasing containment' pressure 34.
AP-20 Operation from the auxiliary panel 35.
Loss of'l-FW-P-2 turbine-driven AFW 36.
-AP-24.1 Large ' steam generator tube leak 37.
_AP-24.2 Small steam generator tube leak.
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AP-27.1:
' Loss of spent fuel pool level'
39, AP-30;
-Fuel 1 failure during handling
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Appendix B
40.
AP-33.2 Loss of RCP seal cooling 41.
AP-33.0 in-plant flooding 42.
AP-39.1 Flooding of turbine building 43.
AP-39.2 Service water flooding in auxiliary building 44.
AP-40 Abnormal level in north anna reservoir (lake)
45.
AP-40.1 Potential flooding of turbine building 46.
AP-48 Charging pump cross connect 47.
AP-49 Loss of normal charging 48.
AP-50 Fire protection operations response 49.
AP-50.1 Control room fire 50.
AP-50.2 Emergency Switchgear Room Fire 51.
AP-50.3 Cable vault tunnel fire 52.
AP-52:
Loss of refueling cavity level during refueling
_-
VII.
Procedures Which Deviated from the E0P writer's guide.
1.
E-0 Reactor trip or safety injection 2.
E-2 Faulted steam generator isolation 3.
E-3 Steam generator tube rupture 4.
ES-0.1 Reactor trip response 5.
ES-0.2A flatural circulation cooldown with CRDM f ans 6.
ES-0.2B Natural circulation cooldown without CRDM fans 7.
ES-1.2 Post LOCA cooldown and depressurization 8.
ES-1.4 Transfer to hot leg recirculation 9.
ES-1.5 Transfer from hot leg recirculation to cold leg recirculation 10.
ES-3.1 Post-SGTR cooldown using backfill 11.
ECA-0.0 Loss of all AC power 12.
LCA-0.2 Loss of all AC power with Si required 13.
ECA-1.1 Loss of emergency coolant recirculation 14.
ECA-1.2 LOCA outside containment
-
15.
ECA-3.1 SGTR with loss of reactor coolant - subcooled recovery
-
desired 16.
ECA-3.3 SGTR without pressurizer pressure control 17.
FR-C.2 Response to degraded core cooling 18.
FR-C.3 Response to saturated core cooling 19.
FR-H.2 Response to steam generator overpressure 20.
FR-H.3 Response to steam generator high level 21.
FR-1.3 Response to voids in reactor vessel 22.
FR-P.1 Response To Pressurized Thermal Shock Condition 23.
FR-P.2 Response to anticipated pressurized thermal shock condition 24.
FR-S.1 Response to nuclear power generation /ATWS 25.
FR-S.2 Response to loss of core shutdown 26.
FR-Z.1 Response to high containment pressure 27.
FP.-Z.4 Response to containment positive pressure 28.
AP-20 Operation from the auxiliary shutdown panel 29.
A0P-52 Loss of refueling cavity level during refueling i
--r----.----.-a----___
. _ _ _ _. -
-
..
- .
9 -
-
t_
Appendix BL
Vill, Nomenclature 1.
E-0 Reactor trip or safety: injection-2.
E-2 Faulted steam generator -isolation 3.
ECA-0.0 ~
Loss-of alltAC-power 4.
ECA-2.1 Uncontrolled depressurization offallLsteam generato'rs-5.
ECA-3.1 SGTR with-loss of' reactor coolant - subcooled recovery desired 6.
ECA-3.2 SGTR with loss of reactor coolant. - saturated recovery 7.
ES-0,1-Reactor trip response-8.
FR-S.1 Response to nuclear power generation /ATWS 9.
AP-1.5 Full _ Length Rod Out of-Alignment
_
<
10.
AP-1.7 Malfunction.of Individual Rod ~ Position Indication 11.
AP-10.7 Restoration Of 2H 4160 Volt Emergency Bus 12.
AP-10.8 Restoration Of 2J 4160 Volt Emergency _ Bus
13.
AP-10.10 Restoration Of 480 Volt Emergency MC",s
,
14.
AP-10.12 Restoration of DC Busses.
15.
AP-10.23 Restoration Of Station Service 480 Volt MCCs
'
16.
AP-20 Operation From the Auxiliary Shutdown Panel 17.
AP-30 Fuel failure During Handling 18.
AP-33 Reactor Coolant Sump Seal Failure 19.
AP-33.2 Loss of RCP Seal Cooling
,
1 I
r