IR 05000271/1988200
| ML20151R792 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 07/29/1988 |
| From: | Dyer J, Haughney C, Macdonald J, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I), Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20151R777 | List: |
| References | |
| 50-271-88-200, NUDOCS 8808120302 | |
| Download: ML20151R792 (28) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION Division of Reactor Inspection and Safeguards Report No.:
88-200 f
Licensee:
Vermont Yankee Nuclear Power Corporation RD 5 Box 169 Ferry Road Brattleboro, Vermont 05301 Docket No.:
50-271 Facility hame:
Vermont Yankee Nuclear Power Station Inspection Conducted:
June 1-10, 1988 1nspector:
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- J./E, Dyer, Team Le(#er, NRR/DRIS D(te Signed W D Zrd C WV 74:v/88 J. P/cdonaTU, Residenginspector, RI Da'te Signed Consultants:
- K. M. Spencer (INEL-EGG)
- W. E. Gilmore (INEL-EGG)
- D. Waters (Beckman-Prisuta)
- P. R. Farron (NEC)
Accompanying Person 1:
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. Team Inspection 17 ate Signed AppN(isa d Deve op ent Section #1, DRIS, NRR M
Approved by:
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- Attended Exit Meeting on June 10, 1988 8%$8QQ$$[ $$N O
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Scope:
An NRC inspection team performed a special, announced inspection to review the licensee's program for implementing Emergency Operating Procedures (EOPs)
as required by NUREG 0737 Supplement 1.
The inspection effort was performed i
in accordance with Temporary Instruction TI 2515/92 and evaluated the overall
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E0P development process, validated specific portions of the E0Ps. reviewed E0P training and assessed the human factor engineering of system design and E0Ps.
Results:
The inspection team concluded that the station operators could successfully accomplish the Vermont Yankee E0Ps to manage the different postulated casual-ties within the plant.
The team noted strengths with the material condition and cleanliness of the station, operator knowledge of E0Ps, and supplemental activities undertaken by the licensee for accident management beyond the Emergency Procedure Guidelines (EPG) guidance.
The deficiencies noted during the inspection included inadequate notification of the NRC for deviations from the NRC approved EPGs, improper implementation of the E0P verification and validation process, and incorrect development of the Procedures Generation Package (PGP) Writer's Guide.
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Table of Contents PAGE 1.
INSPECTION OBJECTIVES.......................................
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BACKGROUND...............................................t
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3.
DETAILED INSPECTION FINDINGS................................
3.1 Emergency Operating Procedure (E0P) Program Evaluation......
3.1.1 Procedure Generation Package (PGP) Review...................
3.1.2 Licensee Validation and Verification of E0Ps................
3.1.3 Response to IE Information Notices..........................
3.1.4 Supplemental Safety Activi ties..............................
3.2 Comparison of E0Ps to Emergency Procedure Guidelines (EPGs)......................................................
3.2.1 Unjustified Deviations from the EPGs........................
3.2.2 Justified Deviations from the EPGs..........................
3.2.3 Accuracy of Deviation Document..............................
3.3 Simulator Validation of E0Ps................................
3.3.1 Simulator Scenario No. 1....................................
3.3.2 Simulator Scenario No. 2....................................
3.3.3 Simulator Scenario No. 3....................................
3.3.4 Validation of E0P Entry Conditions..........................
3.4 Walkthrough Validation of E0Ps..............................
3.4.1 Technical Adequacy of Procedures............................
3.4.2 Availability of-Special Tools and Equipment.................
3.4.3 Station Material Condition..................................
3.4.4 Con tai nme n t Ve n ti ng Pa thways................................
3.5 Verification of E0Ps........................................
3.5.1 Adequacy of PGP Writer's Guide..............................
3.5.2 Impl enientation of PGP Wri ter's Guide........................
3.5.3 Verification of Hardware-Procedure Interface................
3.5.4 Verification of Calculations and Setpoints..................
3.6 Operator E0P Training.......................................
3.6.1 Site Specific Simulator.....................................
3.6.2 Operator Requalification Training for E0Ps..................
i 3.6.3 Operator Training on E0P Changes............................
4 MANAGEMENT EXIT MEETING.....................................
Appendix A - Personnel Contacted......................................
A-1 Appendix B - Documents Reviewed.......................................
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INSPECTION OBJECTIVES The inspection team reviewed the licensee's Emergency Operating Procedures
(EOPs), operator training and plant systems to accomplish the following objectives in accordance with NRC Temporary Instruction (TI) 2515/92:
(1) Determine whether the E0Ps conformed to the vendor generic guidelines and were techaically correct for the Vermont Yankee Power Plant.
(2) Assess whether the E0Ps can be carried out in the plant under the expected environmental conditions with the most limiting operating crew complement.
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(3) Evaluate whether the plant staff has been adequately trained to perform the E0P functions in the time available.
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BACKGROUND Following the Three Mile Island (TMI) accident, the Office of Nuclear Reactor Regulation developed the "TMI: Action Plan," (NUREG-0660 and NUREG-0737) which required licensees of operating plants to reanalyze transients and accidents and to upgrade Emergency Operating Procedures (E0Ps) (Item I.C.1).
The plan also required the NRC staff to develop a long-tenn plan that integrated and expanded efforts in the writing, reviewing, and monitoring of plant procedures (ItemI.C.9). NUREG-0899, "Guidelines for the Preparation of Emergency Opera-ting Procedure," represents the NRC staff's long-term program for upgrading EGPs, and described the use of a Procedures Generation Package (PGP) to prepare E0Ps.
The licensees formed four vendor owners' groups corresponding to the four major reactor vendor types in the United States: Westinghouse, General Electric, Babcock & Wilcox, and Combustion Engineering. Working with the vendor company and the NRC, these owners' groups developed generic procedures that set forth the desired accident mitigation strategy.
For General Electric plants, the generic guidelines are referred to as Emergency Procedure Guidelines (EPGs)
which were to be used by licensees in developing their PGPs. The NRC has issued generic safety evaluation reports (SERs) for approval of Revisions 2 and 3 of the EPGs.
Revision 4 of the EPGs is currently under review by the NRC. Generic Letter 82-33, "Supplement 1 to NUREG-0737 - Requirements for Emergency Response Capability" required each licensee to submit to the NRC a PGP which included:
(1) Plant Specific Technical Guidelines (PSTGs) with justification for safety significant differences from the EPG.
(2) A Plant Specific Writer's Guide (PSWG).
(3) A description of the program to be used for the verification and valida-tion of E0Ps.
(4) A description of the training program for the upgraded E0Ps.
Submittal of the PGP was made a requirement by Confirmatory Order to the Vermont Nuclear Power Corporation dated June 12, 1984. Plant specific E0Ps were to have been developed that would provide the operator with directions to mitigate the consequences of a broad rrnge of accidents and multiple equipment failures.
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l A representative sample of E0Ps from each of the four vendor types have been I
selected for review by NpC teams from Regions I. II, III and IV.
Emergency l
Operating Procedures for 13 additional plants with GE BWR Mark I containments were selected for review by teams from the NRC Office of Nuclear Reactor Regulation (NRR).
This inspection at the Vermont Yankee Nuclear Power Corporation was one of the supplemental reviews conducted by NRR.
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DETAILED INSPECTION FINDINGS 3.1 Emergency Operating Procedure (EOP) Program Evaluation The inspection team reviewed the licensee's program for upgrading E0Ps in accordance with Section 7 of NUREG 0737 (Supplement 1), "Upgrade Emergency Operating Procedures," to determine whether the intent of NUREG requirements had been accomplished and that proper documentation had been submitted to the NRC for review. The program documentation reviewed is listed in Appendix B to this report. The team concluded that the licensee had expended a signifi-cant amount of resources to improve the E0P pro revisions to the Procedure Generation Package (gram as evidenced by the four PGP), five revisions to the E0Ps, responses to IE Information Notices and supplemental studies performed for containment safety.
However, the team was concerned that the licensee had also made significant deviations from the EPGs and that these deviations had not been adequately documented and submitted for NRC review.
3.1.1 ProcedureGenerationPackage(PGP) Review The licensee has comitted to implement Revision 3 of the EPGs, but has never submitted the Plant Specific Technical Guidelines (PSTGs) for NRC review as required by NUREG 0737 (Supplement 1).
In response to an NRC letter, dated September 9, 1984, requesting additional information including the PSTGs, the licensee stated that the information comprising the PSTGs was available at the station for NRC review.
The inspection team found no other evidence that the PSTGs had been reviewed and approved by the NRC and concluded that the current PGP submittal did not satisfy the requirements of NUREG 0737 (Supplement 1). The team was concerned about the lack of the PSTG submittal because the licensee had taken significant exceptions to the EPGs as discussed in Section 3.2 of this report, which appeared to place the licensee outside the scope of the generic safety evalua-tion report issued for Revision 3 of the EPGs.
3.1.2 Licensee Validation and Verification of E0Ps The licensee has issued as many as five revisions to selected E0Ps in a continued effort to improve procedure quality. The inspection team reviewed the documentation associated with the validation and verification of these revisions and made the following observations:
(1) The initial verification of Revision 'l of the E0Ps was completed on August 31, 1984 by an independent contractor.
Procedure OE 3105,
"Secondary Containment Control," was not part of this verification package. The verification report identified that several E0P supporting documents were missing from the verification package and prioritized the procedure deficiencies found for resolution either before or after E0P implementation.
The licensee dispositioned the findings and reviseo the E0Ps as necessary.
(2) The initial validation of Revision 1 of the E0Ps was completed on February 22, 1985 with the assistance of an independent contractor and the Dresden simulator.
Procedure OE 3105 was not part of this validation package.
All E0P decision steps not validated on the simulator were addressed by a-3-
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table top review.
The validation was documented in accordance with the PGP and appeared to be compreher.sive.
(3) The licensee initially verified and validated procedure OE 3105, Revision 0, before issuance in April 1986 using PGP guidance. The documentation for the verification appeared to be limited to a signature on the proce-dure cover page.
The details of the validation were not included in the E0P package so the team could not determine whether all decision paths had been validated.
(4) The documentation for verification and validation of subsequent E0P revisions did not appear to be adequate as was previously identified by the licensee in the independent audit (see Section 3.1.3).
3.1.3 Response to IE Information Notices In August 1986, the NRC issued IE Information Notice 86-64, "Deficiencies in Upgrade Programs for Plant Emergency Operating Procedures," to alert licensees to problems found during NRC reviews of PGPs and E0Ps. The licensee's internal response to IE Information Notice 86-64 reviewed the existing development program and concluded that the existing PGP and E0Ps were satisfactorily implemented.
In response to Information Notice 86-64 (Supplement 1), issued on April 20, 1987 to describe further E0P and PGP problems, the licensee performed an :ndependent audit to determine whether problems existed with the Vermost Yankee E0P development program. The audit followed the guidance provide 0 in NRC Temporary Instruction (TI) 2515/79, "Inspection of Emergency Operatu.g Procedures," and revealed the following problems:
(1) Not all deviations from the EPGs were identified in the controlled deviations document.
(2) Calculations performed to support the E0Ps were not properly controlled.
(3) The PGP Writers Guide did not address all the issues specified in NUREG 0899.
(4) The PGP Writers Guide was not properly implemented for the E0Ps.
(5) There was no mechanism for ensuring E0P revisions were properly verified and validated.
The licensee had developed a corrective action program for the deficiencies identified in the audit with all items scheduled for completion by November 1988. A followup audit was also scheduled after November 1988 to verify that the corrective actions were adequate. The team commended licensee management for conducting the independent audit and concluded that the proposed corrective actions were appropriate for the audit findings.
However, a concern was raised about the potential uncertainty of the schedule.
The licensee was planning to implement Revision 4 of the EPGs upon NRC approval by a generic safety evalua-tion report (SER).
The licensee believed the issuance of this SER to bc iminent and was delaying their nert revision to the E0Ps to incorporate both the audit findings and the EPG, Revi"on 4 changes.
The team was concerned that the corrective actions for the h dependent audit should not be delayed if the NRC SER for Revision 4 of the EPGs were not promptly issued.
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3.1.4 Supplemental Safety Activities The licensee has performed two studies which supported their decisions for the primary containment control E0Ps.
The first was the "Vermont Yankee Contain-ment Safety Study", dated August 1986, which analyzed the expected performance of the Vermont Yankee Nuclear Power Plant containment under postulatpd event scenarios.
This study identified 37 items which would improve safety at the Vermont Yankee plant in the event of station blackout or other severe accident scenarios.
During the inspection, the team verified the adequacy of seven of these items which enhanced the E0Ps beyond the EPG guidance. Additionally, the licensee had developed "Vermont Yankee Containment Venting Guidelines," which provided a listing of 32 containment venting paths, the advantages and disadvantages of each path and expected availability under the various scenarios. These guidelines were available in the Technical Support Center for licensee management to consult and provi<ie recommendations to the Shif t Supervisor for event management.
The inspection team concluded that these
'tudies contributed significantly to tia safety of the plant.
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3.2 Comparison of E0Ps to Emergency Procedure Guidelines (EPGs)
The inspection team compared the E0Ps with Revision 3 of the EPG and identified deviations from the owners' group guidance. These deviations were compared with the licensee's controlled deviation document to review the adequacy of the justifications. The team concluded that deviations from the EPGs in the E0Ps had not always been properly identified and justified. The licensee had previously identified a similar concern during their independent audit und had scheduled corrective action comensurate with the next revision to the E0Ps.
3.2.1 Unjustified Deviations from the EPGs The inspection team identified the following deviations from the EPGs in the E0Ps which were not identified in the deviation document:
(1) The licensee decided to refonnat the 20Ps so that the various ':N decision paths for Reactor Pressure Vessel (RPV) Control were separn ed into three procedures:
OE 3100, "Reactor Scram Control," Revision 4. OE 3101.
"Reactivity Contrci," Revision 4, and OE 3102, "RPV Level Control,"
Revision 5.
These E0Ps were independent of each einer and the decision paths were not entered simultaneously as described in the RPV Control EPG.
This arrangement resulted in a situation whera the step to confirm emergency core cooling system (ECCS) initiation, emergency diesel genera-tor starting and containment isolation signals was only implemented for Procedure OE 3102 and not the other E0Ps.
(2) Frocedure OE 3101, steps LC-3 and LC-4 appeared to direct entry into emergency depressurization in a sequence different from that specified in the RPV Control EPG, Contingency 6, "RPV Flooding." The team was concerned that this resequencing might delay isolation and controlled depressurization of the RPV, (3) Procedure OE 3101 required continued E0P actions for stuck rods even when reactor power was less than the average power range monitor (APRM)
down scale trip setpoint (2%). The reactor power control path of the RPV-5-
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Control EPG allcwed the operator to exit the E0P to the scram recovery procedure if power was less than the APRM downscale setpoint. Although this deviation appeared to be conservative, the team was concerned that remaining in the E0P unnecessarily may distract the operators from other more significant concerns.
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Procedure OE 3105, "Secondary Containment Control," Revision 2, specified an E0P entry condition as a reactor building exhaust radiation level reading of 14mr/hr, the Technical Specification limit.
This level appeared contrary to the Secondary Containment Control EPG, which speci-fied an entry condition as the value initiating an isolation of the reactor building ventilation system. The isolation setpoint was 12mr/hr at the Vermont Yankee Nuclear Power Plant. The team was concerned that because the ventilation system isolated before reaching the entry condi-tion radiation level, the E0P would not always be entered wtan intended.
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Procedure OE 3102 did not require isolation of the high pressure core injection (HPCI) and reactor core isolation cooling (RCIC) systems when flooding the RPV with rods remaining out of the ccre and a feedwater pump available. The team was concerned that flooding the RPV with HPCI and RCIC systems, which feed to the top of the core, could dilute the boron concentration on tho top of the core from the standby liquid control system.
The -fe $ ater system should be used to allow flow from outside the shroud up into the core through the plenum to allow mixing with the concentrated boric acid in the core.
3.2.2 Justified Deviations From the EPGs The licensee did not implement several significant actions in the E0Ps that were prescribed in Revision 3 to the EPGs. These exceptions were identified in the controlled deviation document, "Vennont Yankee Nuclear Power Corporation Technical Justifications for Deviations, Additions and Alterations from the BWR Owners' Group Technical Guidelines," with the licensee's reasons for deviating from the owners group guidance. Because the licensee had not submitted the PSTGs as part of the PGP, the NRC had not reviewed the following significant deviations and justifications:
(1) There was no E0P for implementing the Radioactivity Release Control EPG.
The licensee's justification was that the EPG guidance wat an unnecessary duplication of the actions of other E0Ps for indications other than high radioactivity release rate.
The only event which would cause a high release rate was a high energy line break, which by itself would initiate emergency depressurization either by the size of the breck or other E0Ps for RPV level, primary containment or secondary containment control.
(2) Procedure OE 3105 allowed the plant to remain operating with a stuck-open safety relief valve (SRV) until torus water temperature approached 110*F.
The Torus Temperature Control EPG required scraming the reactor if the SRV could not be closed within two minutes.
The justification provided by the licensee was to offer alternate actions to initiate torus cooling and, if the torus water temperature could be maintained below 110*F, con-duct an orderly shutdown instead of scramming the reactor. Licensee studies supported the conclusion that torus cooling could support a single stuck-open SRV so that the scram would only be required if there were problems with torus cooling.
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(3)
Procedure OE 3105 did not require emergency depressurization for high radiation levels in the secondary containment. The licensee's justifi-cation for this deviation from the Secondary Containment Control EPG explained that the basis for emergency depressurization would be to reduce the release rate of a primary system discharging into the secondary containment.
If this situation were to occur, there would be other indications such as high temperature or levels in the secbndary containment which would already lead to emergency depressurization.
(4) Procedure OE 3105 initiated emergency deprecsurization only after the maximum safe operating temperature was exceeded in two areas, as defined by a limiting condition matrix, instead of a single area as specifieo in the Secondary Containment Control EPG.
The limiting conditions matrix was a tabulation of area pairs affecting both redundant trains of a safety function. The licensee's justification was that emergency depres-surization should only occur when the preservation of reactivity control, ECCS initiation and cooling, RPV level and pressure control, decay heat removal, or post-accident monitoring functions were in jeopardy.
(5) The licensee decided not to implement the RPV Control EPG, Contingency 7,
"RPV Power / Level Control." The justification cited the concerns raised about the contingency in the NRC generic safety evaluation for Revision 2 of the EPGs and problems with Vermont Yankee operators accepting the concept to lower water level during an event when rods remained out of the core and the core was generating power.
Subsequently, the licensee performed further analyses of RPV power / level controi actions and gained operator acceptance of the concept.
The licensee now planned to implement RPV power / level control actions during the next major revision to the E0Ps.
(6) Procedure OE 3100 allowed the mode switch to be placed in either the
"shutdown" or "refuel" position while the RPV Control EPG specified only the "shutdown" position. Placing the switch in "shutdown" provided a backup scram signal in the event rods remained out of the core.
During the simulator validation, the team observed that the operators used the
"refuel" position exclwively to obtain a rod permissive light for rod bottom indication. The team noted that Procedure 3100 did require the initiation of a manual scram signal if all rods were not fully inserted which energized the same scram relay as the "shutdown" positica, but this justification was not identified in the deviation document.
3.2.3 Accuracy of Deviation Document During the comparison of the E0Ps with the EPGs, the team became concerned about the accuracy of the controlled deviation document, "Vermont Yankee Nuclear Power Corporation Technical Justification for Deviation, Addition, and Alteration from the BWR Owners' Group Technical Guidelines." There were several instances where identified deviations did not agree with the text of the E0Ps.
Further review by the team and interviews with licensee personnel responsible for maintenance of the deviation document revealed that changes were incorporated on a chronological basis when the procedures were revised and that a validation of the complete deviation document was not always per-formed.
The licensee had identified this problem during the independent audit and had scheduled a complete review of the deviation document as part of the next major revision to the E0Ps.
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3.3 Simulator Validation of E0Ps The inspection team validated portions of the E0Ps using the licensee % site specific,imulator. The licensee provided qualified station and simulator operators to support the validation. T!.ree event scenarios were performed on a crew of four operators and a fourth scenario was conducted with,the assistance of the simulator operators to test E0P entry conditions. These scenarios were designed to test the maximum number of E0P decision paths during the available simulator time and were not suitable for testing licensed opera-tor performance.
Event sequences were accelerated by the use of malfunctions beyond the design bases of the plant.
In two scenarios, limitations in the controlling software caused the simulator to malfunction, ending the scenario before the decisien paths were fully tested.
During this validation, the team identified deficiencies with the E0Ps that could cause operators problems during an actual casualty.
3.3.1 Simulator Scenario No. 1 From starting conditions of 100% reactor power and no equipment out of service, the malfunctions of a turbine trip, loss of turbine bypass function and failure to scram (ATWS) were initiated. This scenario was designed to validate the following E0P flowpaths under dynamic conditions:
OE 3101 Rod Insertion, Level Control and Borun Injection
OE 3102 RPV Emergency Depressurization with Rods Out
OE 3103 Drywell High Pressure Control
OE 3104 Torus High Water Temperature Control The inspection team made the following observations during the conduct of the validation and af ter debriefing plant staff following the simulation:
(1) The rod insertion, level control and boron injection E0P flowpaths were properly executed by the operating crew.
(2) The crew delayed RPV emergency depressurization because they were not aware that the heat capacity temperature limit (HCTL) curve for the torus was exceeded by plant conditions.
(3) An operator initially misread torus water level as being above the nozzles and torus sprays were not promptly initiated to reduce torus and drywell pressure.
This mistake was corrected a short time later by another operator and sprays were used to control prossure.
(4) The net positive auction head (NPSH) curve was violated for the residual heat removal (RHR) pumps taking suction on the torus.
During the simula-tion debrief, concerns were raised by the operators about the location of the RHR purrp NPSH graph on the flowchart with respect to the sequence of steps being followed during the scenario.
The only NPSH graph was located near the torus pressure control decision path, although the temperature control flow path was a significant variable in the curve and the graph was referenced on two occasions in the decision path.
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3.3.2 Simulator Scenario No. 2 From starting conditions of 100t reactor power with no equipment out of service, the malfunction of an unisolable major steam leak in the HPCI pump room was initiated. When the reactor was scra m ed, five rods failed to insert.
This scenariowasdesignedtovalidatethefollowingE0Pflowpathsunderpynamic conditions:
OE 3100 Manual Scram
OE 3101 Rod Insertion OE 3102 RPV Emergency Depressurization
OE 3104 Torus Water Temperature Control
OE 3105 Secondary Containment High Temperature Control During the scenario the simulator malfunctioned causing the feedwater system to operate sporadically, complicating the validation.
The inspection team made the following observations during the validation and after debriefing the plant staff following the simulation:
(1) The operating crt.w properly entered Procedure OE 3105 and manually scramed the reactor.
(2) An operator failed to bypass the scram discharge volume high level scram input and reset the scram. This inaction prevented the use of the control rod drive system to drive the rods into the core and caused the scenario to deviate from the desired path of depressurization with all rods inserted. The crew's actions for the alternate reactivity control decision path in Procedure OE 3101 were correct.
(3) The crew unnecessarily flooded the reactor up to the safety relief valves instead of controlling level in a prescribed band.
Interviews with the operators involved revealed that Procedure OE 3102, Step LC/B-2, was cumbersome to use. The intent of the procedure was to initiate flooding and then control within a prescribed band.
Instead, because the action block contained terminology to flood until a contingency was met, the operator continued flooding above the desired level. This procedure structure problem was previously identified during the independent audit and was an example where the licensee had not followed the PGP Writer's Guide.
3.3.3 Simulator Scenario No. 3 From starting condition of 100% reactor p wer with no equipment out-of-service, the malfunction of an unisolable steam leak in the tunnel was initiated. Addi-tionally: when the operators manually scramed the reactor, all rods remained out and the RHR isolation valves failed to open when operators attempted to spray the drywell.
This scenario was designed to validate the following ECP flowpaths under dynamic conditions:
OE 3101 Rod Insertion, Boron Injection, Level Control
and Pressure Control OE 3102 Emergency Depressurization and Level Restoration
at Power OE 3103 Drywell Pressure Control Containment Venting
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OE 3'.04 Torus High Temperature Control The major emphasis of this scenario was to detemine whether adequate guidance was provided to make containment venting decisions.
The simulator inadvertently aborted the scenario before this objective could be rea';.ed, but the team made the following observations during the simulaticn:
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(1) The crew properly implemented the actions in Procedure OE 3101 for reactivity control with stuck rods and failure of the standby liquid control system.
(2) The decision to depressurize the RPV was delayed and the to m HCTL curve was exceeded for a few minutes before emergency depressurization.
The actions taken by the crew during depressurization appeared adequate.
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(3) The corrective actions for drywell pressure control described in Procedure OE 3101 were not taken until drywell pressure was 17 psig.
This delay prevented the use of the standby gas treatment system to reduce drywell pressure and appeared to occur when the Shift Supervisor became overloaded while managing the RPY pressure and level, reactivity, and torus tempera-ture contrul problems.
The Shift Supervisor delegated the conduct of Procedure OE 3103 for drywell pressure control to the Senior Control Room Operator (SCRO). The SCR0 verified the entry conditions, but then became distracted and did not take any actions to mitigate the high drywell pres-sure. The Assistant Control Room Operator (ACRO) subsequently advised the Shift Supervisor that drywell pressure was 17 psig and the corrective actions were initiated.
Just as these actions were initiated, the simula-tor aborted the scenario and the validation was stopped.
The inspection team identified two causes for this observed problem.
The first was that the crew was short-handed for the validation; missing an on-shift engineer who monitors plant response to the casualty.
The team concluded that the shift engineer could have detected the lack of drywell actions much sooner in the scenario.
The second cause was a lack of training on management of complex casualties as a team on the simulator.
The licensee had promulgated guidance for assigning responsi-bilities during E0P performance in en Operations Department Memo dated April 15, 1985. This memo provided general areas of responsibility for control of the casualty, but left specific assignments to the Shift Supervisor. The inspection team cuncluded that training on complex casualties was weak as discussed in Section 3.6.2 of this report and that the crew performance as a team reflected this lack of team training.
3.3.4 Validation of E0P Entry Conditions The inspection team used the simulator to validate the availability of the indication referenced by the E0Ps under a loss-of-offsite power condition.
All instrumentation required for E0P entry was available under these condi-tions, but indication for one ent9 wr.dition to Procedure OE 3105 for Secondary Containment Control wc:. not available. The entry condition of a continuously running sump pump was not available since it was supplied from a nonvital bus. There was backup indication of a high room level alarm.
The use of a continuous sump pump running as an entry condition was a deviation from the EPGs which identified a high sump level alarm as the entry condition,
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but the consequences of a loss-of-offsite power were not discussed in the justification.
3.4 Walkthrough Validation of E0Ps The inspection team conducted walkthroughs of all the appendices to the E0Ps and the operating procedures referenced in the E0Ps to accomplish activities outside the control room. The specific appendices and procedures validated by the walkdowns are listed in Appendix B of this report. The walkthroughs were conducted with the operators expected to perform the procedures in an emergency and validated the following concerns:
o adequacy of procedure guidance o ability of operators to perform the procedures o availability of special tools and equipment in the plant o material condition of the systems and equipment being operated by the procedures.
Additionally, the team walked down the various pathways for venting the con-tainment as described in the "Vermont Yankee Containment Venting Guidelines."
The inspectic.) team determined that the guidance provided for E0P activities outside the control room was adequate and was impressed with the operators'
knowledge of the E0Ps, equipment material condition, and plant cleanliness.
3.4.1 Technical Adequacy of Procedures The overall technical adequacy provided by the appendices and operating pro-cedures referenced in the E0Ps appeared to be adequate. With the information in the procedures, plant operators responsible for performing the activities were able to walkthrough the tasks for the inspection team. The team did identify the following deficiencies with the procedures during the walkthroughs:
(1) Procedure OE 3101, Appendix C, "Boron Injection Using Control Rod Drive System from Standby Liquid Control Tank," Revision 4, directed the operator to connect 200 feet of hose from the standby liquid control tank to the control rod drive (CRD) pump inlet, but did not provide guidance for venting the hose. The team was concerned that air in the line could bind or damage the CRD pump. The licensee tested the hoses and concluded that the self-venting features of the hose were inadequate for the intended use and committed to revise Appendix C to include venting guidance.
(2) Procedure OE 3104, Appendix D "Torus Makeup From Core Spray System,"
Revision 4 referenced valves CST-2, CS-8A and CS-8B as being locked in position, but during the walkdown the team found these manual valves to be unlocked. The operators stated that the valves had been locked in the past, but when the locks were intentionally removed, the procedure was not updated. The licensee comitted to revise Appendix D to reflect the unlocked positioning.
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(3) Procedure OE 3101 Step RC/R-29, directed that the CRD hydraulic control unit (HCV) withdraw line be vented, but did not reference a procedure by which this was to be accomplished. The operators interviewed were aware that this was to be accomplished by Procedure OP 2111. "Control Rod Drive System," Revision 16.
Procedure OP 2111 did not provide guidance for obtaining keys for access to plant areas where the special tool; and fittings for this evolution were kept and did not caution the operator that under E0P conditions, the discharge being vented could be a dual phaso mixture of steam and liquid that could cause injury.
During the inspection, the licensee comitted to revise the procedure to provide better guidance for the HCV venting evolution.
(4) i'rocedure OE 3101, Appendix D. "Boron Injection Using Reactor Water
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Cleanup System" Revision 4, required coordinated action between the control room and the reactor water cleanup system local control panel in the reactor building.
The delegation of responsibilities between the two locations was not delineated in the procedure and in one instance an operator incorrectly stated that a specific valve control operation would be performed from the control room when it should have been performed from the local control panel.
The licensee committed to revise the procedure to clarify the responsibility for performing the actions between the two locations.
(5) Procedure OE 3105, Caution 24, stated that isolation interlocks may need to be bypassed under certain plant conditions in order to operate the reactor building ventilation system in accordance with Step SC/T-5.
heither the step nor the caution statement referenced Appendix A.
"Bypassing Reactor Building HVAC Trips," Revision 2, which described how to defeat the interlocks.
(6) Procedure OE 3102. Step LC/D-13, referenced Cautwn 22 which stated,
"Defeating isolation interlocks may be required to accomplish this step."
The step directed rapid depressurization of ths RPV using the turbine bypass, mainsteam line drain, HPCI, RCIC and RPV head vent systems.
No E0P appendix existed to direct how the interlocks were to be defeated.
3.4.2 Availability of Special Tools and Equipment The availability of tools and equipment in the plant appeared to be adequate
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to accomplish the activities required by the appendices and procedures referenced in the E0Ps.
The licensee had prestaged special E0P toolboxes in the various areas of the plant and supporting equipment and chemicals were designated for E0P use only and set aside ? rom other equipment and supplies.
The inspection team inventoried the E0P tool boxes and identified shortages of electrical tape, electrical jumpers and knives in some of the tool boxes.
In all cases the operators could identify where these replacement supplies and alternate tools were available, but the team was concerned that this shortage would cause unnecessary delays in accomplisaing the procedure task.
The licensee agreed with the team and restocked the E0P tool boxes with the identified shortages during the inspection.
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3.4.3 Station Material Condition The inspection team reviewed the material condition of the station during the plant walkdowns to ensure that necessary equipment and components were accessible and functional.
The overall material condition of the plant appeared to be excellent and all material deficiencies identified could be compensated for by the operators.
The team made the following observations:
(1) Plant cleanliness was exceptional.
During plant operations, the torus areas and ECCS rooms were accessible to personnel without the use of anti-contamination clothing.
Also, the team did not observe any interference in the reactor building due to scaffolding or maintenance activities.
The team concluded that plant clean-liness was a strength when considering the ease of personnel movement for accomplishing E0P activities outside the control room.
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(2) During the plant tours it was observed that there was no battery operated emergency lighting in the torus catwalk area and very limited lighting in the area underneath the torus. There were several locations in these areas where adequate lighting was needed for both personnel safety reasons and equipment operation following certain accidents. The licensee indi-cated that the battery operated lights were placed in locations where equipment operation would be required following a station blackout or following a fire which necessitated shutdown from outside the control room. Otherwise, lighting was provided in these areas from vital busses.
The t,,vrttors assisting the team in the walkdowns indicated a concern for adequate lighting and had compensated for it by carrying flashlights when in the areas.
(3) The team was impressed that all major valves and components were identified or tagged in some manner. However, the team observed that minor tagg%g deficiencies existed, such as use of temporary labels on the RWCU local panel in the Reactor Building, and the use of magic markers for identifying valves.
None of these instances hampered the operator's knowledge of the valves and their function, indicating their capability to compensate for the lack of ideal tags. The licensee informed the team that a program existed to replace damaged or missing tags whenever valve lineups were performed. This program should correct the deficiencies observed.
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(4) The team noted that noise levels in the below grade areas of the Reactor Building were significant, and would be very high following an accident when emergency equipment (HPCI, RHR) would be operating.
The only comu-I nications equipment available was the Gaitronics public address system and, in some locations, sound powered phones.
Plant operators indicated that they anticipated comunications problems in the post-accident environment, and also indicated that portable radio comunications might not be possible in these areas.
The inspection team concluded that the operators could adequately compensate for the anticipated problems, but that doing so would further complicate accident management.
I (5) Procedure OE 3103, Appendix A, "Primary Containment Spray Using the Fire System to RHR System," Revision 5, directed operation of RHR system manual cross-connect valve, RNR-20.
Operators interviewed expressed concerns as-13-
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to whether this valve would operate since it had not been recently cycled.
The licensee conunitted to look into the operating history of valve RHR-20 and take appropriate actions to ensure it properly operated.
The operators identified an alternate cross-connect path through valves RHR-56 and RHR-75 which would bypass RHR-20 if problems were to occur.
t 3.4.4 Containment Venting Pathways The inspection team performed walkdowns of the various pathways outlined in the
"Vermont Yankee Containment Venting Guidelines" to assess the material condition and accessibility of components considered by the guidelines.
No deficiencies
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were noted with the material condition of any of the components identified i
in the venting lineups. Additionally, the operators accompanying the team l
on the walkdown were quite familiar with the potential use of the paths even-l though those decisions were intended to be made by the Technical Support Center personnel and Shift Supervisors.
3.5 Verification of E0Ps The inspection team performed an independent verification of the PGP Writer's Guide development and implementation E0P-hardware interface and E0P calculations to determine whether the licensee had properly accomplished the verification process.
Based on the findings, the team concluded that the verification of the current revision of the E0Ps was not adequate.
The licensee had previously identified similar oeficiencies in their independent audit and had scheduled corrective actions to resolve the verification issues before issuance of the next E0P revision.
3.5.1 Adequacy of PGP Writer's Guide The inspection team reviewed the licensee's E0P Writer's Guide as described in Section 4.0 of the PGP (Revision 01) to determine whether the methods and guidance of NUREG-0899 had been properly incorporated.
The team concluded that the licensee had not properly incorporated the NUREG-0899 requirements for the following areas:
NUREG-0899 AREA SECTION
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l Formulas and Calculations 5.6.9 Verification Step; 5.7.2 WARNING, CAUTION, and NOTE Statements 5.5.3 Placekeeping Aids 5.5.4 Sequencing 5.7.1 l
Consistency Between Staffing and Procedures 5.8.1 l
Division of Responsibility 5.8.2 j
Correcting Discrepancies 3.3.5.2 l
The licensee was aware that their writer's guide was not in accordance with NUREG-0899 based on a finding identified during the independent audit of the E0P program.
Corrective action was scheduled to revise the PGP Writer's Guide to be in agreement with NUREG-0899 in July 1988.
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3.5.2 Implementation of PGP Writer's Guide The inspection team performed an independent verification of E0P flowcharts and appendices to detennine whether the writer's guide was properly imple-mented.
The following deficiencies were noted:
(1) Procedure OE 3103, Graph DW/P-2, did not conform with the guidance of the PGP Writer's Guide, Section 2.10 "Component Identification."
The PGP Writer's Guide directed that values used in the flow charts should conform to plant instrument readings. The graph was labeled
"Containment Water Level (ft)" on the x-axis, while the control room instrument was identified as "Torus Water Level."
(2)
Procedure OE 3103, Step DW/T-14 did not conform with the guidance of the PGP Writer's Guide, Section 2.2, "Complexity." The PGP Writer's Guide directed that the number of actions called out in an action block be limited tc one. Step DW/T-14 appeared to provide direction for several actions concerning spraying the drywell and directions for actions to be taken when drywell sprays were no longer required.
(3) There was no abbreviation list associated with the E0Ps reviewed as directed by the PGP Writer's Guide, Section 2.4.b
"Abbreviations."
(4) The Appendices did not conform with the format and style outlined in the PGP Writer's Guide, Section 3.0, "Appendices Guidelines."
(S) Procedure OE 3012, Step LC-11, directed RPV emergency depressurization in accordance with the steps provided on another sheet of the E0P. Step LC-12 was located immediately below step LC-11 a' d directed that injec-tion from sources outside the primary containmen; be secured, except for boron injection and CRD, when RPV pressure is below 280 psig. The team concluded that placement of step LC-12 increased the potential for this integral step to be overlooked and was an example of improper step sequencing.
(6) Administrative control for the job performance aids posted in the control room appeared to be weak. A master list of the aids was kept in the "Operator Aid Status Book," but there was no control over the aids posted in the control room for operator use.
(7)
The temperature in the drywell was re'ferred to inconsistentl OE 3013 6s Drywell Atmospheric Temperature (entry condition)y in Procedure Temperature (Step DW/T-2), and Drywell Average Air Temperature (ywell
, Dr Step DW/T-9).
The team concluded, based on the above findings and the format deficiencies identified with other procedures in the validation process, that the licensee had not properly verified the E0Ps in accordance with the PGP Writer's Guide.
The licensee was already aware of this general concern from the independent audit conducted of their E0Ps.
The corrective actions for these findings was scheduled for implementation on the next revision in August 1988.
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3.5.3 Verification of Hardware - Procedure Interface The licensee accomplished the verification that correspondence existed between the E0Ps and plant hardware as part of their detailed control room design review (DCRDR).
The inspection team performed an independent review'of the E0Ps and the control room and identified several human engineering dgficien-cies.
In each case, however, the team's deficiencies were already identified in the licensee's DCRDR document and a corrective action was scheduled to resolve each deficiency.
The team concluded that the licensee's hardware -
procedure interface verification was adequate.
3.5.4 Verification of Calculation and Setpoints The team selected seven calculations and bases for figures and setpoints used in the E0Ps. These calculations are identified in Appendix B to this inspec-tion report. The following deficiencies were noted:
(1) The torus volume used for Torus Water Level Indication Curve T/L-1 was inconsistent with the value used in the calculation of Pressure Suppression Pressure Curve DW/P-2. The results of this difference were minor and did not affect the curves, but the licensee could not confirm the correct value.
(2) The calculation procedure used for determining the Pressure Suppressior, Pressure Curve DW/P-2 was from Revision 2 (draft) of the EPGs.
The licensee could not confirm whether this calculation was correct and applicable to the Revision 3 EPGs they had implemented.
(3) The calculation package for the Pressure Suppression Pressure Curve DW/P-2 had several annotations in the margins indicating that the various input values to the calculation were incorrect. The licensee could not confirm what the correct inputs should be or whether the errors were safety signi-ficant.
(4) The calculation package for the Drywell Spray Initiation Pressure Limit Curve DW/P-1 could not be reconciled witn the design inputs. The total mass flow rate to the drywell and wet well calculated in the package could not be reproduced using the licensee's input data.
In another area of the calculation package, the total mass flow rate to the wet well was identified on the input data sheet as 350 gpm, but the value used for computer input was 332.5 gpm.
For both of these problems, the resulting error to the curves appeared to be minor, but indicated a lack of proper control over calculations.
The team concluded that, although none of the deficiencies were safety sig-nificant, the inconsistencies were indicative of a poor program for independent verification of calculations. The licensee had already identified this same problem during the independent audit of the E0P program.
Procedure AP 0017.
"Calculations and Analyses," Revision 0, was issued on June 6, 1988 to provide centrol for calculations, and verification of all E0P calculations and bases was to be completed in September 1988 as part of the audit corrective actions.
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3.6 Operator E0P Training The inspection team reviewed the use of the simulator for EOF training, adequacy of requalification training and methods for training on E0P changes.
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The licensee had conducted a significant amount of training using the Dresden simulator and classroom sessions during the initial implementation of the E0Ps in 1985.
Since then the requalification training program has incorporated E0P review as a recurring topic, 3.6.1 Site Specific Simulator The inspection reviewed the use of the site specific simulator for training and validation of E0Ps. The Vermont Yankee site specific simulator had a minimum number of outstanding modifications and adequately reflected the design of the plant.
The software support package for the simulator computer was not designed for E0P training and would not provide indication for signifi-cant accident conditions in the plant.
During the three scenario runs by the inspection team the simulator twice malfunctioned and aborted the valida-tion prematurely.
Despite this shortcoming, the team concluded that the simulator appeared to be a significant asset for E0P training, offering a dynamic environment for operators to work through the E0Ps and make decisions on a real-time basis.
3.6.2 Operator Requalification Training for E0Ps The inspection team reviewed the requalification training conducted since April 1986. A list of the documents reviewed is provided in Appendix B to this report. The requalification training sessions consisted of a classroom presentation of the E0P to be demonstrated, a step-by-step walkdown of the E0P and a real-time scenario run on the simulator.
There have been 16 E0P scenarios performed by each crew since April 1986 which involved the following casualties:
o Anticipated Transit Without Scram (ATWS)
o Stuck-Open Relief Valve o
Steam Leak in the Drywell o
Loss of Feedwater o
Steam Leak in the Secondary Containment o
Loss of High Pressure Emergency Core Cooling System (ECCS)
Occasionally, two of the above casualties would be combined to test multiple E0Ps at the same time, but most of the time the simulated casualty scenarios were not complicated and the operators were able to exit the E0Ps after one or two decisions. The team could not find any scenarios where a low pressure ECCS was lost. The inspection team traced through the 16 scenarios and identi-fied the following E0P steps which were not covered by requalification training:
(1) Procedure OE 3102, Steps LC-10 through LC-18, covering RPV level control-steam cooling activities.
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(2) Procedure OE 3102, Steps LC/F-8 through LC/F-16 covering RPV level control with no level indication and all rods fully inserted.
(3) Procedure OE 3103, Steps DW/T-9 through DW/T-13, concerning drywell temperature control when temperature is above 260*F.
(4) Procedure OE 3103 Steps DW/P-11 through DW/P-22 concerning dry'well pressure control below the primary containment pressure limit.
(5) Procedure OE 3104, Steps T/L-4 through T/L-14 concerning torus low water level control.
(6) Procedure OE 3104, Steps T/L-16 through T/L-30 concerning torus water level above the torus load level limit curve.
l (7) Procedure OE 3104 Steps T/T-10 through T/T-15 concerning torus water l
temperature above the torus heat capacity limits.
(8) Procedure OE 3105 Steps SC/R-3 through SC/R-6 concerning secondary containment high radiation level control.
(9) Procedure OE 3105 Steps SC/L-3 through SC/L-3 through SL/L-10 concerning secondary containment high water level control.
The inspection team concluded that operator training on the more complicated E0P scenarios identified above could be enhanced significantly by)further use of the site specific simulator. The steps identified in Items (4 and (7)
above, were exercised during the validation part of this inspection (Section 3.3) and the team noted that the operators were not as familiar with the actions taken under these conditions as during the initial steps of E0P i
performance.
The licensee stated that their intent was to concentrate simula-tor training sessions on scenarios that were the most realistic.
The more remote scenarios were covered by classroom training and would be factored into future requalification training based on licensee management assessment of operator training needs.
The licensee has scheduled a thorough period of ESP training in the future before a major revi.cion to the E0Ps is implemented and agreed to factor the findings of this inspection into future training plans. The inspection team agreed with the licensee 4 proposed approach to l
future E0P training.
3.6.3 Operator Training on E0P Changes Since the initial training on Revision 1 of the E0Ps in 1985, the licensee has made several revisions to the original E0Ps and issued Procedure OE 3105 for secondary containment control. The inspection team reviewed the training conducted for these changes and made the following observations:
(1) Simulator training for Procedure OE 3105 was conducted in early 1986.
The team could not determine the extent of the training, but simulator scenarios were used for at least some of the decision paths and walkthrou.l s of the remaining paths occurred. The team considered this b
adequate training.
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(2) The majority of the E0P revisions were classified as minor changes not requiring a dedicated training session for operators.
For these minor changes, the training consisted of a written sumary of the change pro-vided in an operations department memorandum that was required reading for all crews before the E0P change was implemented. The team reviewed the nature of selected changes and agreed that the operations memorandum review was adequate. The team also reviewert the completed sign-off sheets for the training memoranda and confinned that all operators had reviawed the memo before procedure change implementation.
(3) There appeared to be some problems with the training conducted for imple-mentation of Revision 3 to Procedure OE 3103 for drywell temperatura and pressure control.
The revision incorporated steps for an alternate method of spraying the drywell in two situations and the torus in one situation using the fire system and implemented Appendix A to OE 3103 to describe how to connect the fire system to the containment spray system.
The licensee could not find the documentation for the training on Appendix A to Procedure OE 3103, but operators interviewed remembered the lectures and plant walkthroughs of the procedure. Additionally, the operations memorandum that described the change incorrectly stated that new steps were added to spray the drywell using the fire ;ystem in three situations within the E0P, when actually the orocedure was revised to spray the drywell in two situations and the torus in one situation.
(4) The operations memorandum that described the minor change made by Revision 2 to Procedure OE 3101 appeared to be incorrect. The memo included a change to delete the words "if not shutdown before" to Sten RC/B-2 which airected the initiation of the standby liquid control system.
However, the procedure was not changed and the contingency clause still existed in Revision 4 of the E0P.
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4.
MANAGEMENT EXIT MEETING An exit meeting was conducted on June 10, 1988 at the Vermont Yankee Nuclear Power Plant.
The licensee representatives at the exit meeting are identified in Appendix A of this report. Mr. C. J. Haughney, Chief. Special Inspection Branch, NRR, represer.ted NRC Management at this meeting. The scope of the inspection was discussed and the team leader presented the findings and answered licensee questions.
The licensee was informed that some observations could become potential enforcement findings and these items would be followed up by NRC Region I.
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O APPENDIX A PERSONNEL CONTACTED S. Aprea Operations
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L. Cantrell Operations A. Chesley Training Simulator Supervisor L. Doane Operations R. Faupel Operations
- R. Grippardi QA Supervisor
- J. Herron Technical Program Manager M. Horn Operations
- G. Johnson Operations Supervisor M. Kriden Training
- D. LeBarge Operations G. LeClaire Assistant Operations Supervisor I. Marsden Technical Support Supervisor B. Metcalf Operations
- R.-Pagodin Technical Services Superintendent
- M. Palionis Operations W. Paul Operations
- J. Peletier Plant Manager W. Pittman Operations R. Slater Operations R. Slaunwhite Training
- R. Sojka ERFIS Project Manager
- R. Spinney Training Manager D. Tuttle Training
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- M. Varno Project Engineer C. Wamser Operations
- R.
Wanzek Operations Superintendent
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. * Attended the Exit Meeting on June 10,1948 A-1 I
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APPENDIX B DOCUMENTS REVIEWED 1.
Emergency Operating Procedures (E0Ps), Appendices and Operating, Procedures
OE 3100 Scram Procedure Revision 4 Appendix A Scram Conditions Appendix B Primary Containment Isolation Groups
OE 3101 Reactivity Control Procedure Revision 4 f.ppendix A Deenergization of Scram Solenoids Appendix B Individual Control Rod Scrams Appendix C Boron Injection Using CRD System From SLC Tank Appendix D Boron Injection Using RWCU Appendix E Manual Isolation and Venting of the Scram Air Header Appendix G Bypassing of Group I Isolation Signals Ap,.endix H Local Firing of Squibb Valve OE 3102 Reactor Pressure Vessel (RPV)
Revision 5 Level Control Procedure Apper: dix A Alternate Injection Using RHRSW System Appendix B Alternate Injection Using Fire System to RHR Appendix C Alternate. Injection From Condensate Transfer System OE 3103 Drywell Temperacure and Pressure Revision 5 Control Procedure Appendix A Primary Containment Sprrv Using Five System to RHR OE 3104 Torus Temperature and Pressure Revision 4 Control Procedure Appendix A Torus Makeup from HPCI Appendix B Torus Makeup from RCIC Appendix C Torus Makeup from RHR System Appendix D Torus Makeup from Core Spray System Appendix E Torus Makeup from RHRSW System Appendix F Torus Level Reduction Using HPCI Appendix G Torus Level Reduction Using RCIC
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OE 3105 Secondary Containment Control Revision 2 Procedure Appendi'
Bypassing RX Bldg HVAC Trips
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0F 2125 Containment Atmosphere Dilution Revision 11 System
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OP 2111 Control Rod Drive System Revision 16 2.
Detailed Control Room Design Review Documentation Detailed Control Room Design Report - Summary Support Supplement (w/ enclosures) dated June 25, 1987.
Vermont Yankee Detailed Control Room Design Review, Final Report (Volumes I and II).
Vermont Yankee DCRDR Expanded Task Analysis (OPVY 283/30 Vermont Yankee Findings File Report dated March 7, 198e.
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E0P Validation and Verification Documentation Operating Emergency Procedures Simulator Validation Project -
Methodology and Results (GP-R-212134), dated February 22, 1985.
Review of Operating Emergency Procedures for Vermont Yankee Nuclear Power Station, dated August 1984.
- Validation of E0P Appendices (Meme) dated March 15, 1925.
Validation Report for OE 3105, Revisien 0, April 2986.
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Training Documentation LOR - OE 3105 Secondary Contairment Control LOR - OEPRT Intagrated Operational Emergency Procedure Trainir.g (Simulatc.')
LOR - 2.3 Operational En'ergency) Procedure Refresher Training (Simulator for Reactor Operator Licensed Personnel
LOR - 3.S LOR Training Cycle Three Simulator LOR - 4.4 Emergency Operating Procedure Refresher LOR - 87.2 Automatic Depressurization System LOR - TDM 87.234 On-Shift Training, Outage Mods LOT - 09-001 Reactor Scram Response
LOT - 09-008 Drywell Pressure and Temperature Control
LOT - 09-009 RPV Level Control
LOT - 09-010 Torus Temoerature and Level Control
LOT - 09-011 Reactivity Control LOT - 09-012 Secondary Containment Control
LOR - 3.3/2.3/1.4a Annual /Bi-Annual Reactivity Manipulations
LOR - 2.36/1.46 NRC Exam Style Scenario 5.
Calculations and Setpoint Bases Documentation Maximum Safe Operating Value for Area Water Levels (0E 3105)
Torus Water Level Indication Correlation, Curve T/L-1 (0E 3104)
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Pressure Suppression Limit Curve DW/P-2 (0E 3103)
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Sizing L iculation for Hose Connecting SLC Tank to CRD Pump Suction (0E 3101 Appendix C)
Drywell Spray Initiation Pressure Limit Curve DW/P-1 (0E 3103)
Instrument Inaccuracies in Control Room Indications (Caution 31)
Bases for 280*F Drywell Temperature as Action Level (0E 3103, Step DW/T-9)
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Bases for 14mr/hr Reactor Building Ventilation Exhaust High Radiation Level Entry Condition to Secondary Containment Control (0E 3105)
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Procedure AP 0017, "Calculations and Analysis," Revision 0 6.
Miscellaneous Documentation Vermont Yankee Containment Veriting Guidelines Audit Report of Emergency Operating Procedures for Vermont Yankee Nuclear Power Corporation, dated December 10, 1987 (w/ response and commitments)
Vermont Yankee Nuclear Power Corporation Procedure Generation Package (Revision 1), FVY 87-106, dated November 17, 1987 Vermont Yankee Internal Responses to IE Information Notice 86-64 (Supplement 1)
Vermont Yankee Nuclear Power Corporation Technical Justifications for Deviations, Additions, Alterations from BWR Owners' Group Technical Guidelines, Revision 1 0-3
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Mt Warren P. Murphy-4-August 10, 1988 Distribution:
(w/ encl)
cDocket; File +50 271 I l
DRIS R/F RSIB R/F PDR.
LPDR NSIC TMurley, NRR JSniezek, NRR BGrimes, NRR.
CRoe, NRR JZwolinski, NRR CJHaughney, NRR JEKonklin, NRR JEDyer, NRR BBoger, NRR RWessman, NRR VRooney, NRR JCraig, NRR WRegan, NRR JPersinski, NRR WKanc, NRR JWiggins, RI
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DHaverkamp, RI DFlorek, RI GGrant, SRI '.ermont Yankee JMc0n:ald, R1 Verra.>nt Yankee fiPerkins, RI (DRMA)
RBoras, RI ACRS(3)
OGC(3)
1S Distribution
. Regional Administrators Regional Division Directors Team Members
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0FC
- RSIB:DRIS:NRR
- RSI TDRIS:NRR :RSI
[ f D:NRR :ADiq US:NRR
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- JEDyer:jjg
- L olm
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- BEGrimes
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.DATE :07//$ /88
- 07/T%88
- 07/1T/88
- 071.29/88
/18/88
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