IR 05000298/1990006
| ML20034A067 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 03/30/1990 |
| From: | Cummins J, Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20034A066 | List: |
| References | |
| 50-298-90-06, 50-298-90-6, NUDOCS 9004190259 | |
| Download: ML20034A067 (14) | |
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APPENDE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
j NRC Inspection Report: 50-298/90-06 Operating License: DPR-46 Docket: 50-298 Licensee: NebraskaPublicPowerDistrict(NPPD)
P.O. Box 499 Columbus, Nebraska 68601
r Facility Name: CooperNuclearStation(CNS)
Inspection At: CNS, Blair, Nebraska inspection Conducted: March 12-16, 1990
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t inspector:
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@ames E. CummTTis, Reactor Inspector Dare Consultant:
Donald A. Beckman l
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$ 3o 90 Approved:
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.'E. Shgliardo, Chief, Operational Programs D6te Section, Division of Reactor Safety
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Inspection Summary Inspection Conducted March 1316,1990(Report 50-298/90-06)
Areas Inspected: Nonroutine, announced followup inspection of items identified during the emergency operating procedures inspection conducted by an NRC insped *on team from June 27 through July 15,1988(NRCInspection Report 50 4 98/88-200).
Results: Within the area inspected, no violations or deviations were identified.
Two inspector followup items were identified:
(1) additional containment vent pathsforcertainaccidentscenarios,and(2)postaccidentreactorbuilding reentry considerations based on E0P execution requirements. These items will beforwardedtotheOfficeofNuclearReactorRegulations(NRR)forfurther review. The licensee's efforts in correcting and resolving these items were i
effective.
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f 9004190259 900406 ADOCK0500g8 PDR l
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-2-DETAILS i
e 1.
PERSONS CONTACTED l
The individuals contacted during the course of the inspection and those in i
attendance at the exit interview on March 16, 1990, are identified in Attachment A.
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2.
FOLLOWUP OF ITEMS 10ENTIFIED IN NRC INSPECTION REPORT 50-298/88-200 2.1 Background ectors performed an
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a team of insp(EOPs) at the Cooper Nuclear From June 27 through July 15, 1988, inspection of the emergency operating procedures
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Station (CNS). The findings of that inspection were reported in NRC Inspection i
Report 50-298/88-200.
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From March 12-16, 1990, an inspector and a consultant (referred to as inspectors in this report) performed a followup inspection of licensee actions related to the findings reported in NRC Inspection Report 50-298/88-200. The findings of that inspection are reported in this report.
The inspectors reviewed documents, discussed the items with licensee personnel,
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and walked down selected parts of the~ plant to evaluate the status of items
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identified in NRC Inspection Report 50-298/88-200. The inspectors also discussed the licensee's ongoing development of new E0Ps, which will be based on Revision 4 of the Boiling Water Reactors (BWR) Owner's Group (OG) Emergency ProceduresGuidelines(EPGs)asdiscussedinSection3.0ofthisreport.
2.2 Inspection Results
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The inspectors reviewed licensee activities related to the three unresolved items identified in NRC Inspection Report 50-298/88-200.
In addition, the inspectors reviewed licensee activities related_to 23 other items. discussed in the report. A brief description of each item and its location (paragraph and pagenumber)inNRCInspectionReport 50-298/88-200 is provided below followed by a discussion of the. inspectors' findings related to the item.
2.3 Unresolved, Items (Closed)Unresolveditem 298/88200-01:
Plant-specific safety evaluations had notbeenperformeoTortheETant-specificdatausedfortheE0Psnorwasit planned for future revis"lIMis"To the plant-specific procedures generation package and the E0Ps. During the initial inspection the licensee advised that the need for additional evaluation and justification of the deviations from the BWR OG EPGs was under review. (paragraph 3.1,page4)
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The licensee had placed requirements for control of E0P program documents in CNS i
Procedure 4.1, "CNS Controlled Documents Other Than CNS Procedures and Vendor
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Manuals," Revision 3, which required their preparation, review, approval, and
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change control be controlled under Plant Services Procedure 1.10. " Document l
Control." Application of these arecedures should result in performance of safety evaluations for new and c1anged documents when required. The Operations l
SupportGroup(OSG)SupervisorstatedthatCNSProcedure0.22," Preparation, Review, and Approval of Emergency Operating Procedure Changes," Revision 2, '
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would also be revised to specify what documents, calculations, and data would
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be controlled. The inspectors confirmed that a draft revision to 0.22 was in
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preparation.
The licensee had implemented E0Ps prepared in accordance with
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Revision 3 of the OG EPGs and was preparing new E0Ps meeting the guidelines of Revision 4 of the OG EPGS. The OSG supervisor stated that the above controls a
would be fully implemented for the Revision 4 E0Ps, but would not be backfitted to the existing Revision 3 E0Ps. The inspectors performing the prior inspection had found this to be consistent with documented NRC guidance,
previously provided to the licensee by NRR for the OG EPGs, Revision 3
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procedures.
This unresolved item is considered closed.
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(Closed) Unresolved Item 298/88200-02: The licensee's method of calculating drywell temperature used as the entry condition f or the drywell temperature
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control (DW/T) in E0P-2 did not strictly adhere to the method recommended in
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(paragraph 3.1.l(2), page 5 and paragraph 3.1.3, page 8)
The OG EPGs, Revision 3, had recommended using the maximum normal operating
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drywell temperature as the E0P entry condition. The CNS Updated Safety
Analysis Report, Chapters 7 and 14, used a bulk (volumetric) average drywell
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temperature of 135'F as the initial condition for various accident analyses.
i The same value was also used as an input for the calculation of the various E0P
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limits and curves. The licensee had selected the highest actual observed value of about 170*F plus 10 percent, which was rounded to 185'F as the entry condition and specified that it be obtained from the highest reading of five
available control room instruments. The licensee had been asked by the team to
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substantiate the acceptability of:
(1) the entry condition value with respect l
tothedeviationwiththeOGEPGs,(2)theuseofanonaveragedtemperature, L
l and (3) the use of a value about 50*F higher than that used in safety analyses and E0P calculations.
Subsequently, the licensee incorporated a volumetric averaging calculation into
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Surveillance Procedure (SP) 6.2.4.1, " Daily Surveillance Log (Technical
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Specifications)," Revision 65 Attachment A "Drywell Volumetric Average Temperature Calculation," which was based on'the five instruments indicating in
the control room. This indication was used daily to ensure that the drywell
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average temperature was within an administrative limit of 150'F.
The HPPD
Nuclear Engineering Department also performed a more elaborate calculation l
(NEDC 88-317, 12/30/88) using data from additional temperature instruments.
i These calculations confirmed that the SP 6.2.4.1 calculation conservatively bounded the actual conditions. The 150*F DW/T entry condition will be used in r
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the E0Ps prepared in accordance with OG EPG, Revision 4.
In support of the new procedures, Design Change (DC)90-021 was being installed during the March 1990 outage to connect the additional drywell temperature instruments to the safety parameter display system. This will provide the operators with a real time, automatic calculation of the average drywell temperature.
With respect to the OG EPG, Revision 3, E0Ps, the nuclear steam supply system (NS$$) vendor reviewed the 185'F entry condition and potentially impacted E0P calculations and found no adverse effects from the higher temperature limit.
The licensee planned no additional changes to the Revision 3 E0Ps.
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This unresolved item is considered closed.
(Closed)Unresolveditem 298/88200 03: Availability of the reactor water cleanup (RWCU) system was questionable during a loss of offsite power since the system components were not
)owered from the critical (vital) buses during a loss of offsite )ower.
RWCJ was used as an alternate means to inject boron
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should the stand >y liquid control (SLC) system be unavailable.
(paragraph 3.1.1(3),page5)
The licensee had concluded that additional boron injection capability was neces-sary and was installing a design change (DC 90-001) to and hoses for injection of standby liquid control (SLC) provide dedicated tools system sodium pentaborate solution via hose connection to the reactor core isolation cooling (RCIC) system.
The SLC/RCIC flow path would be available for use upon restart from the March 1990 outage, but would not be backfit into the OG EPG, Revision 3, E0Ps.
It was being incorporated into the OG EPG, Revision 4, E0Ps.
The inspectors verified by plant walkdowns that the licensee had staged appropriate hoses, equipment, and tools in the plant so that the RWCU batching tank could be filled from the SLC tank. This material was staged in a sealed tool box marked
"EOP" and was located next to the SLC tank.
In addition, the licensee had staged dedicated hoses and tools marked as " Alternate Boron Injection," in the plant so that the SLC tank could be connected to the RCIC pump suction as an alternate boron injection path.
This unresolved item is considered closed.
2.4 Inspector Followup Items Paragraph 3.1.1(4) page 5 GE Drawing No. 769E950, "EOP Flow Diagram," was referred to in the E0Ps, but was not available for use at the time of the original inspection. The flow diagram was to be used to assist the shift supervisor and shift technical advisors in overall tracking of E0P implementation. The inspectors verified that laminated copies of Revision 3 of the diagrams were available in the control room.
The inspectors had no further questions on this matter.
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-5-Paragraph 3.1.2 page 6 The procedures generation package (PGP) was not controlled as a quality assurance document in accordance with NUREG 0899, " Guidelines for the Preparation of Emergency Operating Procedures," Section 4.4.
The licensee indicated that the QA requirements would be evaluated and applied as appropriate in the next revision of the PGP.
As discussed above, the licensee had added E0P program documents as a general category to the document control program in accordance with CNS Procedure 0.4.1 with plans to more specifically define which E0P-related documents required control. The licensee had issued instructions for control of engineering data and calculations involved in the E0P program.
" Plant Specific Technical Guideline Data Collection Instructions," Revision 0, provided a controlled process for collecting data used in E0P development and included provisions for data verification, engineering review, operations review, and CNS management approval. "BWR EPG Appendix C, Calculation Instructions," Revision 0, provided similar controls for the performance, review, and approval of the E0P calculations. These procedures were being applied to the OG EPG, Revision 4 E0P preparation process.
QA record storage and management provisions had been backfitted to the OG EPG,. Revision 3, E0Ps and were being applied to the OG EPG, Revision 4 E0Ps.
The inspectors had no further questions on this matter.
Paragraph 3.1.3 page 7 Plant-specific E0P calculations (performed by the NSSS vendor) for OG EPG, Revision 3, E0Ps were very informal. Many calculations did not include the calculation's purpose, date of performance, output requirements, source of methodology, or review and approval documentation. Although the licensee's review of the vendor calculations appeared effective in assuring correct and
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acceptable results, the absence of QA controls and engineering discipline was identified as a concern.
The licensee had implemented QA controls and specific work isntructions as discussed in Item 2.5 above. The inspectors reviewed several calculations for the new E0Ps, confirming that the controls were being implemented.
The inspectors had no further questions on this matter.
Paragraph 3.2(1),page9 Emergency Procedure (EP) 5.3~ 7, " Post Accident Venting of Primary Containment,"
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did not include prioritized, multiple vent paths, and did not link with radiation release and dose assessment provisions of the emergency plan implementing procedures (EPIPs). The procedure provided only a single 1-inch piping vent path from the drywell. A draft procedure providing the above features was under licensee management review during the original inspectio..
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-6-The licensee subsequently revised EP 5.3.7 in Revision 16 to include reference to the appropriate EPIPs and to provide another small bore (1-inch) vent path from the suppression chamber. A new revision of EP 5.3.7 was being prepared to include multiple, larger bore vent paths which the licensee considered necessary to reduce containment pressure under certain decay heat scenarios and to include provisions for the standby nitrogen injection system, which was
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being installed during the March 1990 outage. The licensee ex]ected the new procedure to be in place by the end of the March 1990 outage; 10 wever, at the conclusion of-this inspection the licensee had not completed the review of the additional, larger bore vent paths and was not sure which, if any, would be adopted. Region IV is referring the question of the need for additional containment venting paths to the NRC Office of Nuclear Reactor Regulation (NRR). This is an inspector followup item.
(298/9006-001)
Paragraph 3.2(2).page9 An NPPD engineering evaluation of containment venting provisions found that the valves used for venting were capable of operating against expected differential pressures, but was silent with respect to the valve actuator acceptability.
Subsequent engineering evaluation of the actuators had found them to be capable of operating against expected 150 psid differential pressures with the exception of the motor actuators for MOV-1308 and -1310, which would only operate at or below 50 psid. The step sequence of EP 5.3.7 had been revised to accommodate the lower capabilities. The inspectors reviewed New CNSS9976011 J. R. Flaherty to E. M. Mace, January 23, 1989, which forwaroed the Plant Engineering Group's evaluation and backup documentation. The OSG supervtsor further advised that additional valves affected by the pending changes to EP 5.3.7 for large bore venting either had been or would be similarly evaluated.
The inspectors had no further questions on this matter.
Paragraph 3.2(3). page 10 The HPPD engineering evaluation of containment venting found that the standby gas treatment (SBGT) system duct and filter housings could be ruptured by.
pressures encountered during containment venting, particularly if pressurized with no outlet path.
EP 5.3.7 did not include any precautions or guidance regarding assurance of a flow path.
The licensee had included suitable precautions in EP 5.3.7, " Post Accident Venting of Primary Containment," Revision 16, in effect at the time of this inspection.
The inspectors had no further questions on this matter,
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Paragraph 3.2(4),page10 Inspection team walkdown of the SBGT system-found that duct expansion joints
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were made of plastic materials that might not tolerate high containment venting m temperatures permitted by the E0Ps.
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The licensee provided documentation showing that the duct expansion-joints were
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-modified in 1985 by Major Design Change 85-029, "SBGT Cross-Connect and
' Discharge Duct Flexible Connection Upgrade and Drain Header Modification,"
Work Item No. 85-1122. As'part of this modification, the SBGT duct flexible couplings were replaced with, material certified to withstand postaccident temperatures.
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The inspectors had no further questions on this matter.
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Paragraph 3.2(5),page10
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Containment venting procedures did not address contingencies pertaining to
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concurrent events such as loss of offsite power or station blackout with t
respect to the need for access to the reactor building for local operation of the vent valves, e
The licensee had evaluated flow path valve power supplies and had found that
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only two valves (PC-MOV-305 and -306) were AC powered and would require manual operation. All other valves were DC powered from station batteries. The pending revision to EP=5.3.7.was going to include provisions to manually open these valves early in the venting sequence to avoid radiation shine from the piping after it fills with containment atmosphere.- The other general reactor
' building reentry considerations are-discussed below.
The' inspectors had no further questions on this matter.
Paragraph 3.3(1),page11
Some instruments used for E0P entry condition determination had'not been included in the periodic calibration program and/or in the setpoint control program.- The specific findings involved the alarm and-indicating circuits for secondary containment room / area temperature monitors.
The licensee was establishing a periodic calibration procedure and had incorporated the
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instrument setpoints'into their formal program. The licensee further stated-that a review of all instruments and controls used for implementing the E0Ps
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and referenced procedures was in progress'to ensure that these' instruments were
a-calibrated.
The licensee subsequently issued and performed I&C Procedure 14.27.2, " Steam'
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Line Leak Detection Alarm System Calibration," Revision 1, providing for an
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-annual calibration of all affected instruments and control of the setpoint data. Prior problems with instrument drif t had also resulted in replacement of the system during the March 1990 outage as part of a design change (DC 90-121),
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" Replacement of the Steam Leak Detection Alarm System." Design Change DC 90-121 included provisions for the rewriting of I&C 14.2?.2 for the new equipment and a draft procedure was in review and approval at the time of this inspection.
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The licensee completed the review of:all instruments' and contorls used for imple-menting the E0Ps and referenced procedures and made a list of these instruments;
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however, due to'a misunderstanding on the part-of licensee personnel, it was not
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determined which of the instruments was being periodically calibrated, At the time of this inspection, the licensee had developed a list of all instruments referenced in the E0Ps and support procedures. This included the new E0Ps and.
support procedures being developed to the OG EPG, Revision 4.
A total of
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247 instuments were identified. The licensee determined that eight of these._ _
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instruments did not have a specified periodic calibration. The licensee stated that action' had been taken to add these.eight instruments to the preventive maintenance program to ensure-any required calibrations would be performed. The licensee also stated that any additional instruments identified as being used for E0A purposes would be added to the preventive maintenance program.
The inspectors had no further questions on this matter.
l Paragraph 3.3(2)(a), page 12 OperatingProcedure(0P)2.2.69.3,"RHRSuppressionPoolCoolingand
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Containment Spray," Revision 1, was invoked by E0P-2, " Primary Containment'
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Control."Section VII.A,. Step 1.d " Note" of the procedure provided a caution for excessive pump flows and specified a maximum pump motor current and a i
minimum pump differential-pressure which were not indicated in the control l
room. Maximum pump flow or other parameters available in the control room were
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not specified. The licensee stated that the procedure intent would be evaluated as part of a planned task analysis associated with the. detailed
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control room design review.
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Subsequent to the inspection, the licensee determined that OP 2.2.69.3 would
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i not be subject to the task analysis because of a change in procedure strategy between 0G EPG Revision 3 and Revision 4 E0Ps.
However, the procedure was-
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reevaluated and specific maximum flow values were added to the applicable.
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procedure steps and general procedure precautions.
j The inspectors had no further questions on this matter._
i Paragraph 3.3(2)(b),page12 i
Section VII.A Steps h.2.c.1 through 3 of OP 2.2.69.3 had valve, switch, and_
indication nomenclature for residual heat removal (RHR) system core cooling interlocks which was not consistent with labeling on the main' control board.
The licensee acknowledged the discrepancy and planned to correct the control board labels.
The inspectors verified the installation of correct contro_1 board label plates
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which were unambiguous and matched the-procedure nomenclature.
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..The inspectors had no further questions on this matter.
Paragraph 3.3(4), page 13 E0P-3, Attachment 1 provided instructions for installing jumpers in Auxiliary Relay Panels 9-41 and 9-42 in locations which were potentially hazardous to
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both equipment and personnel.- The-licensee had recognized this condition and
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had' initiated Design Change Request 88-196 to install front panel jacks that J
would obviate the need for installing jumpers internally.in the cabinets.
l The inspectors confirmed completion of the actions by review of the completed
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l work package for Design Change 88-196 "PCIS Banana Jack Installation," and by visually verifying the installation of the banana jacks on the outside of the panels.
The inspectors had no further questions on this matter.
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Paragraph 3.3(5),page13 Step RC/Q-9 of E0P-1 required that 275 lbs. of boric acid and 275 lbs. of borax be added to the reactor pressure vessel via the RWCU system,' but no method-was -
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provided for determining actual weights added. The licensee advised the team that the reference to weight in the procedure-would likely be deleted because thecurrentpracticewastouseatemporary)transferhosefromtheSLCtankto L
the RWCU system (discussed elsewhere herein..This method would use the
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ll premixed SLC solution and avoid the need for batch mixing' chemicals for addition via RWCU..
The licensee had revised EP 5.2.14, " Alternate.Means to-Inject Boron'to RPV,"
l Revision 3, to include instructions for transferring premixed SLC. tank contents-l to the RWCU system for injection. The inspectors verified by plant walkdowns l
that the licensee has staged appropriate hoses, equipment, and tools in the
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l-plant so that the RWCU hatching tank can be filled from the SLC tank. This-l material was staged in a-sealed tool box marked "E0P" and was located next'to the SLC tanks. Manual mixing of boron solution in the RWCU tanks is no longer i
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used. The licensee further advised that if, as a last resort, manual' mixing.
was required, the boron is supplied in preweighed bags which would permit determination of injected boron weight.
The inspectors had no further questions on this matter.
Paragraph 3.3(6),page14 During review of EP 5.2.14 (above), the team found that the nomenclature for.
system controls and components did not_ match.the procedure nomenclature. The licensee stated that the item would be reviewed as part of a task analysis performed in conjunction with the detailed control room. design review.
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.The licensee has relabeled the controls and components in the field to match-the nomenclature _in the procedure. The inspectors verified the corrective-actions on a sampling basis.
The inspectors had no further questions on this matter.
Paragraph 3.3(7),page14 i.
The CNS plant specific EPGs included a sequence for opening the safety relief
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valves which did not agree with the sequence given by labeling on the main
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control board. flo-justification.for the deviation was provided in the step deviation documentation.. The licensee stated that the step deviation document would be corrected.
Subsequent to the inspection, the license'e concluded that the EPG sequence was incorrect because of a typographical error. The inspectors verified that the i
error was corrected and properly. documented.
The inspectors had no further questions on'this matter.
Paragraph 3.3(8),page14 E0P-1, Step RC/L-7 referenced the incorrect subsection in Operating
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Procedure 2.2.74 for lining up alternate injection subsystems.
The licensee had been concentrating resources on development of the OG EPG, Revision 4, E0Ps and had evaluated correction of the typographical error in
EOP-1 as not requiring priority correction. Accordingly, this procedure error
was not' scheduled for correction.
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The inspectors considered this a minor error of negligible safety significance and had no further questions on this matter.
Paragraph 3.3(9), page 14 E0P-1, Step RC/P 15, required the operator to verify that suppression pool l
level was at or above 5 feet 6 inches on Panels 9-3 or 9-4.
The level
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instruments read only in feet and not inches._-The licensee planned to correct the reference.
Subsequent to the original inspection, the licensee had concentrated resources i
on development.of the OG EPG, Revision 4, E0Ps and had~ evaluated correction of
l the discrepancy in E0P-1 as not requiring priority correction. Accordingly, this procedure was not scheduled for correction.
The inspectors' considered this a minor discrepancy of negligible safety significance and had no further questions on this matter.
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Instrument Air Yalve IA-1601 was operated as part of E0P-1, Step RC/Q-10.b(3),
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to vent the scram air header. The valve had been recently installed as part of a design change and was not yet shown on valve checklists and piping and
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' instrumentation diagrams.
i The inspector verified that instrument air valve IA-1601 was.shown on Drawing 2010(Sheet 2),"FlowDiagramInstrumentAirReactorBuilding,"
i Revision N36,~and in Operating Procedure 2.2.59A-(page 11 of 206), ~" Plant Air-
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System Valve Checklist," Revision' 3.
- The inspectors had no further questions on this ma'tter.
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Paragraph 3.3(11). page 14 E0P-l', Step RC/P-19, provided instructions for defeating isolation interlocks to make systems available for rapid depressurization and referred the operator
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to GE Drawing 7916266 for determination of jumper and lifted lead installation-
points. The drawing consisted of 13 pages of electrical schematic and logic drawings requiring on-the-spot interpretation by the operators since no specific instructions were provided. The licensee was reviewing the need for
dedicated, preplanned jumpers and will attempt to simplify the procedure.
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For the OG EPG, Revision 4, E0Ps, the licensee was developing,a: master list of
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all jumpers and temporary modifications (lifted leads, etc.) required by the
-E0Ps or supporting procedures. Temporary leads, tags, and documentation will
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be prestaged in the new E0Ps. The provisions were included-in-draft procedures in preparation, review, and approval.
No additional licensee action was planned for the existing OP EPG, Revision '3, E0Ps.
i The inspectors had no further questions on this matter.
l Paragraph 3.3(12), page 15
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Emergency. lighting in the control room appeared insufficient to support E0P implementation during a loss of normal control room lighting. The licensee provided compensatory interim measures and had already planned additional emergency lighting-installation for the 1989 outage.
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In 1989 Design Change 87-15, " Control Room Lighting Modification," installed additional fluorescent and battery-powered lighting in the control room for standby (loss of normal-ac powered lighting) and emergency (blackout, loss of i
all AC power) lighting systems. The inspectors observed the lighting
installations and considered them to be reasonable.
i The inspectors had no further questions on this matter.
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Paragraph 3.3.1, page 15-Equipment needed for E0P plant evolutions.was not (1) identified as E0P equipment, (2)segregatedfromequipmentusedfor.normalplantoperations,and(3) controlled or-inventoried to ensure-availability when needed. The licensee planned to
develop a program for the dedication and control of.EOP equipment.and material.
The inspectors verified that, except for one tool, the licensee ha'd staged the'
i specific tools and equipment identified in Section 3.3.1 of the inspection report.
The tools were staged at appropriate locations in the plant, in' sealed tool boxes-which were conspicuously marked-"EOP" or in some cases, individual tools were secured in the appropriate area with a lanyard (steel wire) and~ labeled "EOP."
The one instance in which the appropriate tool was not available was that a-.
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r wrench was not available for adjusting the safety relief valve' nitrogen supply:
regulator as specified in Abnormal Procedure 2.4.2.3.1, " Relief Valve Stuck Open."
i The licensee stated that the tool had been attached in the area with a lanyard:
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and labeled, but'had apparently been removed._.This item was discussed in
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Section 3.3.1(1) of the inspection report.. The licensee replaced the missing
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tool. Some of stagad E0P items were being inventoried quarterly as part of the preventive maintenance program. The missing wrench had been omitted from the-
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inventory program; however,- during this inspection, the tool was-submitted for
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addition to the preventive maintenance program as were other recently staged tools.
The inspectors had no further questions on this matter.
Paragraph 3.5, page 17 The-licensee's original analysis of postaccident reactor building reentry condi-tions was performed in accordance with NUREG 0737, " Clarification of TMI Action Plan Requirements," Item II.B.2.
The results of the licensee's analysis submitted to NRC concluded that raciation levels were too high to permit reentry, and that the E0Ps in effect at that' time did not require reentry (i.e., the plant design would support all accident operations without requiring personnel to go into the
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reactorbuilding). However, the current E0Ps require extensive personnel entry
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for both first-order emergency actions for basic accident mitigation (e.g.,
closure of failed open safety relief valves and suppression pool makeup) and for contingency actions (e.g., alternate boron injection and emergency control rod.
insertion). The licensee advised _the team that reactor building reentry consi-derations would be reevaluated.-
Discussions with the OSG. Supervisor and the Chemistry and Health Physics
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Supervisor indicated that no formal reevaluation had been performed but that existing reactor building reentry procedure; were reviewed and-found acceptable.
The licensee representatives stated that p%taccident reactor building' conditions i
would be evaluated as they occurred and-with respect to the specific reentry
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tasks to be performed. No correlation to the NUREG-0737 analysis nor preplanning
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of specific E0P tasks with respect to expected radiation levels would be done.
The inspectors were referred by the licensee to EPIP 5.7.15, " Rescue and Reentry,"
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9evision 9, and EPIP 5.7.16, " Release Rate-Information," Revision 13, as the
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primary methods for estimating actual reactor building radiation levels and controlling safe building reentry. The inspectors noted that this postaccident,
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real-time approach to reactor building reentry to support E0P implementation did
- not appear to meet the intent of the above TMI action plan requirement fully.
This is an. inspector followup item-(298/9006-002) and is being referred to
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theOfficeofNuclearRegulation(NRR)forreview.
Paragraph 3.5.2, page 19 and paragraph 3.7.3, page 21 Procedure place-keeping was a major problem for the operators while performing
table-top emergency scenario simulations. The licensee stated that possible
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alternatives to-the existing place-keeping method (using ribbons attached to each binder) would be reviewed.
The licensee was in the process of devnloping flow chart type EOPs based on
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Revision 4 to the OG EPGs. The flowchart type E0Ps would eliminate the place keeping problems that were related-to the dual column text format in use at the time of the E0P inspection.
The inspectors had no further questic.s on this matter.
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3.
UPDATE OF E0PS TO REVISION 4 0F THE OWNER'S GROUP (0G) EMERGENCY PROCNIRS GUIDELINES (EPGs)
The licensee was in the process of updating the E0Ps to Revision 4 of the OG EPGs. Part of.this update was-to change the CNS E0Ps from a dual column text format to a graphic, flow chart format. To accomplish the update and format
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change in a disciplined manner, the licensec had essentially started over and generated a completely new' set of.EOPs enhanced by newly developed plant-specific technical guidelines and E0P writer's guide.
- A review of the new E0Ps was beyond the scope of this inspection. However, it
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appeared to the inspectors, based on a cursory look at the EOP flowcharts and'
discussions with licensee personnel, that the licensee's disciplined approach to developing and establishing the new E0PS and the change from a text format to a flowchart format would result in comprehensive, easy to follow E0Ps that i
would minimize chances for operator error.
The licensee expected to heve the OG EPG, Revision 4, E0Ps fully implemented during the fall 1990.
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4.-
EXIT MEETING
- On March 16, 1990, the inspectors met with Mr. G. R. Horn and other licensee
- personnel identified in Attachment A, and discussed the scope and findings of.
the inspection.
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ATYACHMENT A i
Persons' Contacted Exit Meeting Attendees
NAME ORGANIZATION'
POSITION / TITLE Garrett E. Smith NPPD-CNS QA Manager-
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James R; Flaherty NPPD-CNS Engineering Manager G. R. Horn NPPD/CNS Division Manager Nuclear Operations W. R. Bennett.
USNRC Senior Reactor Inspector J. E. Cummins USNRC Reactor Inspector'
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D. A. Beckman NRC Consultant H. T. Hitch NPPD-CNS Plant Service Department t
D. R. Overbeck NPPD-CNS Purchasing / Materials Supervisor
- G. R. Smith NPPD-CNS Licensing Supervisor'
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L. E. Bray NPPD-CNS Regulatory Compliance Specialist-
- D. W. Bremer NPPD-CNS-Operations Support Group Supervisor R. C. Stewart NRC Reactor' Inspector, RIV
- Denotes primary contacts during the inspection. The inspectors also contacted other members of the licensees. staff to discuss issues and ongoing _ activities.
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