IR 05000298/1988200
| ML20154L096 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 09/06/1988 |
| From: | Cummins J, Haughney C, Norrholm L Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20154L094 | List: |
| References | |
| 50-298-88-200, NUDOCS 8809260095 | |
| Download: ML20154L096 (30) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION _
Division of Reactor Inspection and Safegusrds ~
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Report No.: 50-298/88-200 Docket ho.: 50-298 Licensee: Nebraska Public Power District P.O. Box 499 Columbus, NE 68601 Inspection At: Cooper Nuclear Station Brownville, NE Inspection Conducted: June 27 through July 15, 1988 Team Leader' klkwle i 1sVAten W2llC hJpes E. Cumins, Team Leader Date'51gned
$6nior Operation Engineer, NRR Accompanying Personnal: Wayland R. Bennett, Senior Resident Inspector, RIV Consultants: Donald A. Beckman, Prisuta Beckman Associates, In James W. Chase Nuclear Engineering Consultants. In John F. Hanek, EG8G Idaho, In Michael Mecherikoff, EG&G Idaho, In Other NRC Personnel Attending the Exit Meeting:
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L.J. Norrholm, Section Chief NRR ~
l J.J. Jaudon, Deputy Director, DRS, RIV G.L. Constable. Section Chief, RlY j W.O. Long, Project ManagerpFD4r .
Reviewed by: . dt A/ 6 Leif J/ NorthoM, Chief. Teati
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3 68 Dage 5v)ned
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' InspecAion' Appraisal and Development Section #!, DR,lS, ,
[4 Approvedbyp% Charles /J.jyaughney,Chie,,,7 c)
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I6 Date Tigned g Inspect'ionaranch, DRIS, NRR i
$809260095 880921 PDR ADOCX 05000298 I Q PDC i
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TABLE OF CONTENTS
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1,0 INSPECTION SCOPE ....................................... 1 BACKGROUND ............................................. 2 DETAILED lhSPECTION FINDINGS ........................... 3 Program and Precedure Review ........................... 3 3. Comparison of Owners' Group Emergency Procedure l Guidelines With CNS E0Ps ............................. 3 Quality Assurance for Plant-Specific Emergency
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3. Procedure Guidelines ................................. 6 3. EOF Calculations ....................................... 7 Containment Venting .................................... 8 E 0 P W a l k d own F i ..d i n g s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
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3. Special Equipment and Tools ............................ 15
- Validation and Verification Program .................... 16 Postaccident Rear. tor Building Habitability and
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Reent ry Con side ra ti on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 E0P Simulation Using Classroom Walkthrough ............. 17
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3. Scenario Descriptions .................................. 18 3. Scenario Observations .................................. 19
- E0P Training ........................................... 21
- 3. I n i ti a l T ra i n i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 3. Requal i fi c a ti on T rai ni ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 3. Observations ........................................... 21 j Human factors Review ................................... 22 3. Hardware / Procedure Interface ........................... 22 3. Adherence to the Writer's Guide and NUREG-0899 ......... 22 l 3. Implementation of E0P Contingency Procedures . .. . ..... . . 22 3. Supplemental Information ............................... 23 Ongoing Evaluation of E0Ps ............................. 24 4 .'O POSTACCIDENT COPEUSTIBLE-GAS CONTROL ................... 24
. EXIT MEETlhG/ PERSONS CONTACTED ......................... 25 ATTACHMENT A - PERSONS CONTACTED EXIT MEETING ATTENDEES .......... Al ATTACHMENT B - LICENSEE ' S DOCUMENTS REVI EW[D . . . . . . . . . . . . . . . . . . . . . B1 ATTACHMENT C - ABBREVIATIONS AND ACRONYMS ........................ C1
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1.0 INSPECTION SCOPE
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Thra intrection was perfortned to verif that the Cooper Nuclear Station (CN3)
e:r.ergency operating procedures (EOPs)y:were technically accurate;'that their ,
specified actions could be physically carried out in the plant using existing (quipur.t. instrurrer.tatier., and controls; and that the plant staff could 4 ccrrectly perfore, the procedures. Tht it.spectier, v.es conducted in acccrearce
witt the puic6tice in Terrporary Instructior, (TI) 251E/92. "Erergency Opert.tirn l
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frecedures Tear Ir.spections."
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'. 2.0 BACKGROUND Following the Three Mila Island (THI) accident, the Office of huolear Reactor kegulation developed the "TMI Action Plan" (NUREG-0660 and NUREG-0732.), which required licensees of operating plants to reanalyze transients and ascidents '
and to upgrade emergency operating procedures (EOPs) (Item 1.C.1). The plan also required the NRC staff to develop a long-term pisn that integrated and expanded efforts in the writing, reviewing, and monitoring of plant procedures (Item 1.C.9). NUREG-0899, "Guidelines for the Preparation of Emergency Operating Procedures," represents the NRC staff's long-term program for upgrading E0Ps and describes the use of a procedura generation package to prepare E0P The licensees formed four vendor owners' groups corresponding to the four major reactor types in the United States; Westinghouse, General Electric (GE),
Babcock and 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 GE plants, the generic guidelines are referred to as emergency procedure guidelines (EPGs). These EPGs were to be used by licensees in developing their procedure generation package (PGP). Submittal of the PGP was made a requirement by Confirmatory Order dated June 15, 1964. Generic Letter 82-33, "Supplement 1 to NUREC 0737 -
Requirements for Emergency Response Capability," required each licensee to
- submit to the NRC a PGP that included
(1) Plant specific technical guidelines (PSTGs) with justi/ication for safety-significant differences from the EPGs (2) a plant specific writer's guide (PSWG)
(3) a description of the program to be used for the verification and
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validetion of the E0Ps j (4) a description of the training program for the upgraded E0P The licensees were tv develop plant-specific E0Ps that would provide the operators
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multiple-equipment failure l For various reasons, there were long delays in obtaining NRC approval of many of the PGP Nevertheless, the licenseesihave all implemented their E0Ps. To determine the success of this implementation, a series of NRC inspections are ,
being performed to examine the final product of the program: the E0Ps. A representative sample of each of the four vendor types has been selected for review by four inspection teams from Regions 1 !!, !!!, and IV.
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! An additional 13 inspections, including this one at CNS, are being perfor.med at
- f acilities with General Electric Mark 1-type containments. The latter inspec-tions are being conducted by the Office of Nuclear Reactor Re,ulation and include a dttailed review of the containment venting provisions of the E0Ps -
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3.0 DETAILED INSPECTION FINDINGS 3.1 Prtgram and Procedure Review Documents reviewed during the inspection are listed in Attachment B.'--
3.1.1 Comparison of Owners' Group (OG) f.mergency Procedure Guideline With CNS E0Ps The inspection team reviewed the owners' group emergency procedure guidelines (OG EFGs) and compared them with the CNS plant-specific technical guidelines (PSTGs). The PSTGs at CNS were identified as the CNS EPGs. The review was conducted to identify any ttchnical deviations between the OG EPGs and CNS EPGs and to determine the adequacy of the licensee's documentation and justification for any technical deviations. Observations made by the team during the review included:
't (1) The licensee did not submit the PSTGs as part of the procedures generation
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package to the NRC for review as required by NUREG-0737 Supplement 1, .
Item 7.2.b. This omission appeared to be significant because the licensee in developing the emergency operating procedures (EOPs) deviated in several
instances from the NRC-approved OG EPGs without providing adequate documented justificatio This led to the implementation of the CNS E0Ps without a -
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femal safety evaluation, i
Revision 3 of the OG EPGs had been approved in an NRC safety evaluation report and was intenced by the NRC to form the basis for the development of the PSTGs. Documentation provided by the licansee indicated that the NRC safety evaluation report would have been sufficient had the OG EPG Revision 3, been used exclusively for developing the CNS E0Ps. Nuever, the licensee used draft OG EPGs, Revision 31, to develop the r,lant-specific procedures. Revision 31 contained technical differences from
Revision 3, which, as a minimum, shecid have been subjected to a site
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specific safety evaluation. Examples of G,ese technical differences included:
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- - In E0P-1, Contingency 6. Step C6-3.2, a phrase was added to maintain the pressure of the reactor pre Mure vessel as low as practical'by throttling injection due to rdi ductility transittun temperature considerations.
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- Reactor flow stagnation power was deleted from the CNS EPGs.
l - The CNS EPGs includeJ flow stagnation water level resulting from t
deletion of the retetor flow stagnation powe The step on filling reference legs was deleted from the CNS EPGs,
- The CNS EPGs allowed intermittent use of residual heat removal pumps for purposes other than low pressura coolant injection mode operatio _ _ _ _ _ _ _ _
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The licensee told the team that it had asked the NRC staff how it was to justify a plant-specific safety evaluation in that some of the
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operations required by the E0Ps placed the plant outside technical speci-t1 cation requirements. The licensee provideo a telephone f.onversation record memorandum that documented an infomal NRC staf f positfAn indicating that a formal licensee safety evaluation was not required because the hPC staff had performed and documented a generic safety evaluation of the OG EPG, Revision The team concluded that a plant-specific safety evaluation should have been performed on the plant-specific data used for the E0Ps and for future revisions to the plant-specific procedures generation package and E0P The licensee stated that the need for additional evaluation and justifica-tion of the deviations from the OG EPGs, Revision 3, was under revie Pending further NRC review of the licensee's review of adoitional evaluation ai.c justification, this is an unresolved item (298/88200-01).
(2) The team determined that the licensee's method of calculating drywell temperature useo as the entry conditiun (drywell temperature control (DW/T)) for E0P-2 did not strictly 3dhere to the method recomended in the OG EPGs. The licensee developcd the value for the entry-condition temperature by selecting temperature monitors (TE-505 series instruments)
in the vicinity of the reactor pressure vessel level instrument reference 16cs and safety relief valves as recommended by the EPGs. The tempera-ture c6ia for the instruments for the past four years were then revieweo, the highest value observed (171'F) was selected, a 10-percent margin was codec, and a roundea value of 185'F was assigned as the E0P-2 entry concitio The OG EPGs recomendec using the maximum normal operating temperature, if there was no drywell temperature technical specification limiting condi-tiun for operation, as the entry M ndition, not the highest observed temperature, as was epparently don The tean observed the entry-condi-tion instruments during near peak sumer-heat conditions and found that the nominal average temperatures were in the 155'-160'F range. The team noted that the licensee's method of detemining the entry-level temperature resaltec in a higher than warranted entry-condition tgmpera-ture. Discussions with the licensee indicated that it believed that its method was in accordance with the OG EPGs; therefore, it had not developec a technical justification for the apparent ceviation f rom the recomendo-tion in the OG EPG to justify the method uted.
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The team further noted that in the CNS Updatec Safety Analysis Report Chapters 7 and 14, a bulk (volumetric) average containment temperature of 135'F was used as the initi61 condition for various accident analyses and that the same temperature was used as an input for the calculation of various E0P limits and curves. The licensee had not determined actual
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buli average temperature for comparison with this temperature. The licensee performed a special calculation during the inspection that shqwed that the actual bulk average temperature was acceptabl .
The E0P entry-conoition terperature of 185'F, hoaever, implied that containment teeperature would increase by about 30 cegrees over that observec ouring this inspection before emergency actions would be imple-mentec. The licensee was asked to correlate the change in "nominal"
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bulk average containment temperature with the E0P entry condition to
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ce m strate that the rise in containment temperature before energency actions were implemented would not adversely affect either the contain-ment response to analyzed accidents or the E0P limits. Section 3. of this report discusses this entry-condition temperature as it relates to the E0P At the close of the inspection, the licensee was continuing to evaluate the
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above. At the exit meeting for this inspection on July 12, 1988, the licensee told the team that preliminary information from the nuclear steam supply systen vendor indicated that the effect on containment response to accidents appeared negligible (GE letter from J. Torbeck to K. Walden, July 11, 1988). This letter, however, noted only that an increase in containment temperature from 135' to 150'F would have a negligible effect on the maximum pressure and tenperature and the dynamic loads calculated during a loss-of-coolant accident and did not address the other correlation
, concerns discussed abov . The licensee was perfoming additional analyses to justify increasing the l
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average design temperature from 135' to 150'F and had initiated a work *
- request to establish a method for periodically detemining actual ,
l bu'k average temperature. The licensee planned additional analyses to I
correlate the rise in overage design temperature with the 185'F entry condition. Pending licensee resolution of the adequacy of the method ,
used to determine the entry level temperature of 185'F, this is an unresolved item (298/88200-02).
(3) The OG EPGs listed seven systems that could be used as alternative means '
a for injecting boron into the reactor should the standby liquid control
- system fail. The plant-specific "step deviation documentation," which ,
i justified deviations between the OG EPGs and the CNS EPGs, did not identify i
a deviation, although the licensee elected to use only one alternate flow .
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path via the reactor water cleanup (RWCU) syste !
- The team quotioned the availability of the RWCU system during a loss of (
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, offsite rower in that the system components were not powered from the
- critical (vital) buses during a loss of offsite power. The licensee
' stated that the use of the reactor core isolation cooling system (a recommended by the BWROG EPGs) was under review to determine an additional
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boron injection method. The licensee planned to document the reasons fer i not using the other injection flow paths reconrnended by the OG EPGs.
j Pending the completion of this documentation, this is an unresolved item
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I (4) GE Orawing ho.76-950, "EOP Flow Diagram," was referred to in the E0Ps but
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was not available for use at the time of this inspection because it was l being revised to reflect the changes made by Revision 4 to the E0Ps ;
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i l Section ll.B of Emergency Procedure (EP) 5.8, "Emergency Operating Proce-l dures," Revision 4, stated that tne flow charts provided a quick overall ;
! view of the actions the operator was expected to take and could be used !
by the st6 tion shift technical advisor or management to follow the E0Ps [
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, and that the flow charts showed the interrelationships between the procedures, as the E0Ps addressed the entire plan The team felt that the flow charts could be a valuable tool to help with placekeeping and that not having them available for the use ind$4ated in
- EP 5.8 could detract from the response to an event. The licensee stated
! that work on the revisions to the flow charts had been expedited and was j expected to be completed within about a mont .1.2 Quality Assurance for the Plant-Specific Ercergency Procedure Guidelines l
NUREG-OS99. "Guidelines for the Preparation of Emergency Operating Procedures,"
Section 4.4, "Quality Assurance," states that the plant-specific technical guidelines (emergency procedure guidelines, EPGs) should be subject to examina-tien under the plant's overall quality assurance (QA) program to ensure that they are accurate and up to dat '
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The initial CNS EPGs and associated calculations were not controlled und3r the licensee's QA program, although the E0Ps themselves were. The licensee stated that the CNS EFGs and associated calculations and bases were developed about
, 1962-84 and were not subject to the QA program that existed at that time.
The tean reviewed the current administrative and QA program procedures for
- applicability of the QA program provisions to the E0P program. Procedures
reviewed included:
- "NPPD QA Program for Operation Policy Document," Revision 4 l - Administrative Procedure 0.4.1, "Controlled Documents Other Than CNS Procedures and Vendor Manuals," Revision 0 t
- Administrative Procedure 0.22 "Preparation, Review, and Approval cf Emergency Operating Procedure Changes," Revisicn These documents did not include QA requirements for the following:
l . configuration control and design verification of the plant-specific-j EPGs and associated calculations and input data -
- forval document control provisions for plant specific EPG elements
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control of EPG documents as QA record),
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! Except for final calculations performed by the nuclear 1, team supply system i (h555) venoor under the vendor's QA program, no formal controls were described
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in the licensee's procedures. The licensee had applied infonnal controls to the program that included independent verification by the licensee of N555 l vendor calculations, informal peer review and supervisory approval, and orderly
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maintenance of original copy records. These activities provided some assurance of program integrit '
The licens$e acknowledged the above and indicated that QA requirements woulo I be evaluated and a'.splied as appropriate to the next revision of the procedures generation packag _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ __ __ . _ _ _ _ _ ____
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3.1.3 E0P Calculations The owners' group emergency procedure guidelines (OG EPGs) included a number of plant-specific limits, setpoints, and action levels that required. calculation of plant-unique values. Appendix C of the EPGs provided detailed dirActions for developing input data and perfoming these calculations. The team reviewed a sample of the input data development and final calculations for CN EPG, Appendix C, Table Cl T4, "Plant-Data." requireo separate development and calculation of plant-specific valtes for use as input data for the emergency operating procedure (EOP) limit, setpoint, and action-level calculations and curve The licensee had contracted with the NSSS vendor to perfom these calculations. The team reviewed the calculations and source data for Table Cl-T4 developed by the vendor in 1983-84. Specific calculations reviewed in part or in whole included:
- reactor pressure vessel water volumes
- reactor pressure vessel water masses
- drywell volumes, pressures, and eouipment elevations
- suppression pool volumes, pressures and equipment elevations
- downcorer volumes, pressures, and equipment elevation In general, these calculations were very infomal. They were performed on plain paper with no identification of the perfomer and no evidence of review by the perfoming organization. Typically, the calculations did not include the purpose, date of performance, output requirements, source of the calcula-tion methodoloey, or documentation of calculation checking and contained only a limited description of input assumptions and input data source The Table C1-T4 calculations and results had been independently verified by the licensee, and verification was documented by initials or signatures on the individJal calculations. The licensee had identified anc resolved a number of discrepancies in the vendor calculations. The team interviewed personnel involved in this verification and found that, notwithstanding the lack of engineering discipline in the presentation of the calculations by the vendor, the licensee's review was effective in verifying their validity and identify-ing and resolving discrepancie _
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The licensee acknowledged the above and stated that the calculations had been performed before the implenentation of current, more rigorous, QA controls for such activities. The licensee was preparing for implementation of Revision 4 of the OG EPGs and stated that this effort would be tubject to more rigorous control The team also ;eviewed a sample of calculations, design verification and discrepancy resolution documentation, and related correspondence for the final Appendix C calculations listed belo E0PFigures1-1and1-2,lowpressureenelantinjection(LPCI)sndcore spray net positive suction head curv conversion of suppression pool pressure to drywell pressure
- EGP Figure 2-3, "Drywell Spray Initiatior Pressure Limit"
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- E0P Figure 2-4. "Pressure Suppression Pressure"
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E0P Figure 2-5. "Primary Containment Design Pressure" -
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- E0P Figure 2-6. "Primary Containment Pressure Limit"
- drywell spray flow rate
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suppressionpoolcoolingsprayinitiationpressure(SPCS!P).
The team verified the correlation of input data from Table C1-T4. perfomed checking calculations, and confimed to the extent possible that the calcula-tions had been performed in accordance with the Appendix C procedures. The team noted that these vendor performed calculations included input assumptions, bases, and the identification of the perfomer and checke As discussed in Section 3.1.1 of this report the team identified t concern regarding the design-basis, average drpell temperature of 135'F. which was used as the basis for the accident analysis in the CNS Updated Safety Analysis Report and as an input to the E0P calculations for drywell spray flow rat SPCSIP, and E0P Figure 2-4 (above). EOD-2. "Primary Containment Control ."
specified an entry condition of 185'F drywell temperature. The licensee was unable to correlate this entry condition temperature with the actual drywell temperature at the beginning of the accident and the average design temperature value of 135' The licensee had not evaluated the effects that the elevated drywell temperatures might have on plant perfomance at the time of E0P entry. As part of the evaluation of this latter issue, the team perfomed sensitivity calculations for SPCSIP and E0P Figure 2-4. using all original vendor input data except that drywell temperature was varied over the range of 135* to 165"F. These calcula-tions showed that the effect of drywell temperature on SPCSIP was probably negligible but that the effect on the pressure suppression pressure curve of Figure 2-4 was potentially significant (2- to 4-percent nonconservative) in the range of normal suppression pool levels. This was discussed with the licensee who stated that the contairenent temperature considerations were under evaluation and their effect on E0P limits and curves would also be consWere The' licensee further stated that a revision to the existing E0Ps was being developed in accordance with Revision 4 to the OG EPGs and that Revision 4 appeared to address this concern by specifying the use of either maximum or minimum drywell temperature (DW/T) values , based on which was most conservative for the specific calculation rather than an averag .2 Containment Venting The team reviewed the provisions in E0P-2 and Emergency Procedure (EP) 5. "Post Accident Venting of Primary Containment." Revision 2. for confomance with the owners' group emergency procedure guidelines (OG EPGs), acceptability of the engineeMrn bases for the procedures, and the ability of the t>perators alkthrough scenario E0P-2 requ. ired to implement initial t uofpre venting .wcontainnent (he .as during w(within technical specification radioactive release limits) when drywell pressure reached 2 psig. Emergency venting was required, without consideration of containment temperature or radiation-8-
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releases, when containment pressure approached the primary containment design pressur EP 5.3.7 was issued in July 1987 and provided instructions for the ne of a single vent path from the containment drywell through sm&ll-bore (1-inch) vHves and piping to the standby gas treatment system. The procedure did not provide for other backup or prioritized flow paths, nor did it include specific instructions for monitoring radiation release concentrations or assessing offsite doses. Radio-
, active discharge and dose assessment considerations were, however, briefly addressed in the discussion section of the procedur The licensee had been studying other venting options since July 1987. A draft revision to EP 5.3.7 prepared at that time was evaluated by the licensee's
, engineering personnel (memorandum from G. McClure to E. Nace "Post Accident
- Venting of Primary Containment Evaluation", dated May 4, 1988). This revistun
I of the procedure, which had not been issued at the time of this inspection, provided for venting through both small-bore (1-to 2-inch) and large-bore (20- to 24-inch) valves and piping from both the drywell and suppression pool,
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provided prioritization logic for use of the paths, and addressed the radiation release and dose assessment considerations. The operations support staff I supervisor stated that the draft procedure nad not been issued pending addi-
, tional information from the owners' group on decay heat removal and NRC j approval of the OG EPGs, Revision 4. The licensee was also conducting a study of potential overpressurization and failure of the vent path and the qualifica-
) The team had the following observations and concerns regarding the licensee's
- program provisions for containment venting
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(1) The issued version of EP 5.7.3 did not include a number of the specific
! provisions included in the draft as indicated above. The team considered
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the issued version to be deficient in areas such as prioritized, multiple
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vent paths, and release and dose assessment linkage with the emergency plan implementing procedures. The licensee should consider issuing a revised procedure based on the draft that omits the use of equipment
, and flow paths deemed inappropriate by the engineering evaluation. The l
. team acknowledged the licensee's netd to resolve issues involving the i use of the large-bore vent paths before issuing procedures for their j use as discussed further below.
i (2) The engineering evaluation above noted that the valves used for venting
, had been evaluated in conjunction with the manufacturers' specifications j and found acceptable for operation at the differential pressures expected i at containment design pressure. Teleconference memoranda documenting
- these discussions for the small-bore valves (MOV-305 -306. -1308, and
! -1310) addressed only the valves and not the capability of the actuators, d
The team requested that the licensee substantiate that the actuators and i
the actual actuator torque switch settings were capable of operating the j valves as required. The licensee told a team member on July 14*, 1980.
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that it had been confirmed that the valves were capable of withstanding l up to 150 psid, although documentation was not yet available at the j site. At the close of the inspection, the licensee was researching the I above.
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(3) The engineering evaluation included analysis of the standby gas treatment (SBGT) system design pressure versus expected venting pressures. The 3 evaluation found that the SBGT duct work, fabricated of 14 tauge welded stainless steel, would not sustain the full containment design pressure of 65 psig but could be expected to rupture at approximately 63 pst Additicnally, the evaluation found that the SBGT filter housings were
- designed for a "leaktight" pressure of 2 psig; no design maximum pressure was specified. Considering the above conditions, the SBG1 could not sustain the pressures encountered when venting through the large-bore valves, but the evaluation found that venting through the small-bore l valves and piping would not threaten i,he duct and filters 'ecause o of the low flow rates calculate However, neither the issued nor the draft procedures nor the engineering evaluation considered the case of inadvertent downstream isolation of 3 the SBGT system when aligned to vent the containment, resulting in an
equalization of containment pressure with the SBGT system. Such down-stream isolation could occur if SBGT fan stoppage resulted in the closing of interlocked outlet valves. A simple precaution for the operator 1 the venting procedure appeared to be warranted.
I The licensee acknowledged the above concern and its evaluation was in
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progress at the close of the inspection.
(4) E0P-2 initially limited venting temperature to 2129 (Step PC/P-2.b)
- on the basis of containment cooling considerations. However, if contain-
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ment pressure exceeded the primary containment pressure limit. Figure 2 6 I Step FC/P-8 instructed the operator to vent the containment irrespective of containment temperature.
I The team's walkdown of the SEGT system found that some components (e.g.,
l duct expansion joints) were made of plastic materials that may not have tolerated high temperatures and coulo warrant additional compensatory actions if high-temperature venting was necessar i The licensee acknowledged the above concern and was evaluating it at the
- close of this inspectio ~
l (5) Neither the issued nor the draft procedures addressed contingencies !
pertaining to ventirq such as loss of offsite power (diesel generators
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available) or station blackout (loss of all ac power) with respect to the need for access to the reactor building for local operation of the vent
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l l valves. Additionally, as discussed in Section 3.5 of this report, the
- licensee had not made any plans in regard to the need for access to perform l such local operations with respect to accident radiation levels in the l j reactor building, i In response to the team's inquiry on this matter, the licensee stated that i j all valves in the flow path were dc battery powered and would bt available !
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during either scenario until the batteries failed except for val,ve MOV-306.
l the small-bore drywell vent isolation. The licensee also indicated that I this matter would be given further consideration for future revistuns of the procedures.
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,, . , t 3.3 EOF Walkdown Findings To ersure that the E0Ps could be successfully carried out, the team perfomed walkcown evaluations of all the E0Ps and supplemental procedures tefarenced in the E0Ps. The team verified that E0P instrument and control designations were consistent with the installed equipment and that indicators, annunciators, and ;
controls referenced in the E0Ps were available to the operators. It also '
verified the location and control of E0Ps in the control room. The team I physically verified that activities which could be required outside the control room during an accident could be physically performed and that tools, jumpers, and test equipment were available to the operators. It also reviewed j post-accident radiation and environmental considerations r,1ade by the licensee in regard to local operations in the reactor building.
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During the plant walkdowns, the team identified the following discrepancies:
(1) E0P-3, Section SC/T, "Secondary Containment Temperature Control," Table 3-1 ,
specified the entry conditions and action levels for elevated temperatures i in about 30 rooms and areas of the secondary containment. The table l l included the maximum nomal operating temperature, maximum safe operating l 1 temperature, and a temperature monitor alam setpoint (corresponding to !
] the maximum nonral operating temperature) for each area, h During the walkdown on July 6, 1988, the team observed that the actuai
! (as-found) setpoints for the temperature monitor alams on control room '
panel 9-21 were about 10-15'F lower than those specified in E0P-3 and did not correspond to the entry and action-level temperatures; for example, ,
the as-found setpoints for eight residual heat removal loop A and B area t i temperature channels ranged between 145'F ano 148'F instead of being at i 160'F as required.
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l The licensee stated that the above condition had been identified by its
- staff and was a result of instrument drif t. The instruments were not l l periodically calibrated but were recalibrated only for corrective mai l j tenance. The most recent cilibration had been perfomed during August i
. . 1987. The licensee had determined that part of the drift problem was i attributable to a new digital indicator installed in June 1988 and 4tated l
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that it was trying to solve the problem. The licensee also stated that i the frequency of monitoring this instrument drif t was going to be increased '
until the drift problem was finally solve The licensee had recalibrated
. the instruments successfully en July 7, 1988, and was preparing a new ,
i calibration procedure that would cecommodate the instruments' drift l l characteristics. The licensee was going to perform this calibration !
procedure at a frequency that was also based on the instruments' drift !
j characteristic l l i The licensee stated that two sets of instruments (four steam tunnel i temperature monitors and eight residual heat removal (RHR) area monitors) i had not had their setpoints controlled as part of the engineering configu- l
- ration ranagement setpoint log program. These setpoints were beJng i
! incorporated into the program at the close of this inspection. The i i licensee also stated that a review of all instruments and controls used l l for implemerting the E0Ps and referenced procedures was in progress to
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(2) Operating Procedure OP 2.2.69 1 "RHR Suppression Pool Cooling and Containment Spray," Revision 1, was invoked by various sections of E0P-2,
"Primary Containment Control." 1he following two discrepanc.ies were noted in this procedure *
(e)Section VII.A. Step 1.r, note, cautions that RHR pump capabilities may be exceeded when the suppression pool cooling throttle valve was opened and specified a minimum pump differential pressure and a maximum pump motor curren These parameters were not displayed in the control room. Differential pressure was indicated only on pump suction and discharge gages at the pump. Motor current was indicated only at the motor control cente The licensee stated that the operators were trained to monitor available control room flow indications for stable pump perfonnance and to dispatch operators to the above local indication locations should any aberrant conditions be observed. Licensed personnel generally confirmed the above but also indicated that their percep-tions of stable flow and conditions that would require local monitor-ing were not consistent. Further, toe locations where local pump pressure indications could be obtained would probably be inaccessible during accident scenarios involving core damage because of the levels of radiation from the RHR pump and piping. Postaccident plant access is discussed in Section 3.5 of this repor The licensee stated that the procedure intent would be evaluated by the task analysis of E0P referenced procedures being performed as part of the detailed control room design revie Section Yll,.A. Steps h.2.c.1 through 3, provided instructions for overriding the containment cooling 2/3 core coverage valve control psreissive. The valve, switch, and indication nomenclature used in the 4.nstructitJ.s was not consistent with that on the main control board switenes and indications. For example, Step 1 required that
. th permissive keylock switch be placed in the "manual override" positton. The switch was never removed from that position until Step 3 requ', red that the switch be again placed in the "u nual" positio '
Furthermore, the names in the procedure did not match those on the main conteol board. The senior reactor operator accocpanying the team on the walkthrough was unable to interpret the procedure with respect to the actual controls to permit adequate performance of the
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ste The licensee stated that the procedure and main control board labels had been reviemed, confirmed to be discrepant, and would be correcte (3) Reactor pressure vessel level indicator LI-92 (steam norrie range level)
(used in E0P-2 Table 2-1) was equipped with a dual-indicator reale. One scale was based on the "instrument zero" scaling that had been tradt-tionally used at CNS. The second scale was baset on top-of-active-fuel (TAF) scaling tn which the licensee was changing as a human factors improvement. Both scales were displayed as an interim measure by the-12-
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licensee until the personnel became accustomed to the TAF scale, at which time the instrument zero scale would be remove The instrument was intended to measure level in the range athhich the main steamline nozzles would flood and was equipped with a placard intended to correlate the two scales with the scale elevation of the steamline nozzles. However, the placard was so cryptic that only one of i six lhensed operators polled was able to interpret the infomatio !
l The licensee stated that its review confirmed the above discrepancy and {
the placard was change I (4) E0P-3, Attachment 1. provided instructions for installing jumpers in relay l panels 9 41 and 9-42 to bypass the high drywell pressure and low reactor :
vessel level group 6 isolation signal to permit operation of the reactor
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building heating, ventilation, and air conditioning system. The licensee's '
- prestagIng of these and other jumpers and the placing of required authori-zation Ncuments in a specially designated box in the control room were i consideied to be good practice. The licensee had twice successfully i demonstrated the actual installation of the jumpers and had performed a i a functional test of the installed jumpers in accordance with Special Test l
- procedure No. 85-22. *RB HVAC Interlock and Containment Level Recorder I l Testing " in 198 The physical location of the jumper installations however, presented j hazards from both equipment damage and personnel shock. The jumpers had j to be installed using a screw driver and spaded wire lugs in a narrow i teminal strip area about head high and two feet inside a vertical relay
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cabinet. Installation under stress conditions would be difficult. The
- licensee had recognized this and had initiated Design Change Request l'
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No. 88 196 on June 14. 1988, to install front panel jacks that would pemit bypassing of the isolation signal without the need to enter the
, cabinet. On June 29, 1988 the plant staff had requested that this ;
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inodification be given imediate priority for installation at the next !
outage of sufficient duration, l ~
j ($), Step RC/0-9 of E0P-1 required that injection of boron into the reactor
- vessel via the reactor water cleanup (RWCU) system be discontinued when
275 pounds of boric acid and 275 pounds of borax had been added. A !
j strulated walldown of the procedure detemineo that no procedure or '
I rethod was provided for determining the weights of the substances ;
added. The licensee had identified this concern during the verification t and validation program in 1984 and had dealt with it by stating that l a procedure would be developed to detemine the weight I j The licensee advised the team that the reference to weight in the proce- ;
cure would likely be deleted because the current p actice was to use a
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I I temporary transfer hose from the standby liquid control (SLC) tank to RWCU l
] system. precluding the need to mix boric acid solution in the RWCU system, ;
i and the level in the SLC tank would be t. sed as a basis for boron additio l (6) Emergency Frucedure EP 5.2.14. * Alternate Means To inject Boron to RPY,'
Revision 2. which had been developed to support the E0Ps. required filling I the RWCU precoat tann from the *,LC tank and then filling the RWCU
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demineralizer from the prece t tank. The level to which the precoat tank was to be filled was not specified, and the point at which the precoat i pump was started was vagu In addition, the procedure required pumping :
down the precoat tank to the "low level mark;" however, two 4tation .
operators could not find the low level mar (
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The procedure further required that certain switches be operated to 4 prepare the RWCV system for boron injectio The nomenclature in the !
procedure was sufficiently different from the actual switch positions so !
that the operators were confused about the correct operation of the '
switche For example, the procedure called for operating RWCU-AO-17A,
, yet the valve is labeled 12 4 17A. The licensee stated that it has
! comitted to perform a task analysis for these E0P related procedures as part of the resolution of a human engineering discrepancy identified uncer .
j the cetailed control room design review progra {
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l (7) In the CNS emergency procedure guidelines (EPGs) the following sequence i for opening the safety relief valves was given: G,A,E. F.B, '
. AND 0; however, on the main control board the following sequence was :
j specified: D G A E. H. C. F. AND B. The justification for this l
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deviation from the CNS EPGs was not documented. The licensee stated that i
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the step deviation documentation would be correcte .
! (8) E0P-1. Step RC/L-7, referenced Operating Procedure (0P) 2.2.74, Section !
j Vll.1, for lining up alternate injection subsystems. The correct refer- !
- ence was OP 2.2.74,Section VII.H. The licensee advised the team that the
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correct reference will be incorporated.
j (9) Step RC/P-15 of E0P-1 required the operator to verify that suppression
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pool water level was at or above five feet six inches on panel 9-3 or 9 4 j The level instruments on these panels read only in feet and not in inches.
The licensee advised the team that the procedure would be corrected to '
j read 5 1/2-fee (10) Step RC/0-10.b(3) of E0P 1 required venting of the scram air header by the i
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remval of a pipe cap and the operation of instrument air (IA) valve t IA 1601. This valyc was not shown on the control rod drive (CRD) system piping and instrument diagrams, although the piping section in which the
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- valve was located was sho n. The valve also was not included on either l 1 the CRD or IA valve lineup checklists. The licensee stated that the valve j l was part of an open design change package and that the drawings and valve ;
j lists will be revised to reflect its' installatio !
(11) Step RC/P-19 of EONI stated, "If defeating isolation interlocks is required, }
refer to GE Drawing 7916266, Primary Containrent Isolation System (and l j applicable system drawings if necessary)." The referenced CE drawing :
- contained 13 pages of electrical scherratic and logic drawings. The '
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obsence of specific jumper and lif ted lead instructions and prestaged materials appeared inappropriate. The team questioned the avaliability [
! of staff, time, and materials during an emergency to research, waluat l i
and implement interlock defeats. The licensee was reviewing the need for !
j dediceted, preplanned jumpers and will attenpt to simplify the proce- !
j dure acccrdingl !
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, . (12) Emergency lighting in the control room appeared insufficient to support FOP implementation during a loss of nortnal control room lighting. Spec fically, lighting fixtures available for the control room supervisor's
, (CRS) desk and other areas where procedures were used appecred .to be inadequat The licensee advised the team that additional emergency lighting was planned for installation during the next (1989) annual outage and that
dedicated battery-powered lanterns had been placed in the control room
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emergency lockers on July 12, 198 .3.1 Special Equipment and Tools
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At various points the E0Ps required special equipment (e.g., tools, hoses) for I
- the successfull completion of a task. The team reviewed the prestaging of these items with regard to their availability during walkdowns and their
- availability for use during accident conditions. The team found that most of l the equipment needed in the control room was prestaged with the appropriate i paper work to support its use. In addition, the team found that the control '
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] room special equipment was stored in a specially rarked box identified for E0P use.
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1 The equipment needed for plant evolutions did not receive the same control.
] Typically, the equipment was not identified as "EOP equipment," was not segre.
< gated from equipment used for nortnal plant operation and was not controlled or !
) inventoried to ensure availability when needed. The licensee had no procedures l
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or practices in this regard. Specific examples included the following: :
I (1) Suppression pool temperature control in E0P-2 required operator action l in accordance with Abnorral Procedure (AP) 2.4.2.3.1, "Relief Valve Stuck i Open," if safety relief valves (SRVs) were stuck open. AP 2.4.2.3.1, t
- Section IV.F. required (nat the SRV nitrogen supply regulator setting be I 1 verified or adjusted, if other attempts to close the valves hao failed.
j The regulator was located on an elevated catwalk in a cohtaminated area F above the control rod drive (CRD) hydraulic control units (HCUs) and
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, required a wrench for adjustrnent. No tool was staged in the imediate [
l vicinity or specifically identified for this operatio Several Ikensed ,
j personnel could not state with certainty (without entering the area), l
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, whether a wrench was needed to operate the regulato (2) E0P-1. Step RC/Q-20s, requi;ed the operator to connect a vent rig to valve
! CRD-157 for each rod. Special vent rigs and wrenches needed to perforin
- this evolution were located adjacent to the north HCUs only. None were located at the south HCus. In addition, the tools located near the north j HCUs were also used for periodic venting of the units following refueling ;
] outages and here not specifically stagcc or identified for E0P us ;
- i i The team expressed concern about the availability of these tools during an
! erergency. In additinn, the lack of tools at the south HCUs could result
in unnecessary delays because of the requirements to dress and undress in !
j anticentamination clothing to transfer the tools from the north HCUs,
! since the HCUs were located in differen' raciologically controlled area (
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+. Additionally, the normal operating ambient temperature in the HCU overhead I 3 area was more than 100'F. 1he licensee had not considered the temperature i effects on personnel resulting from loss of ventilation in the area during l
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an accident. Nor had the temperature rise in this area caused by venting !
the CRD water steam mixture been considered in regard to such needs as L temporary emergency ventilation and high-temperature gloves. Further, ;
, emergency lighting was not tveilable in the area to perinit perferirance '
during a loss of nortr.41 lightin ;
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I (3) EOF-1 required the connection of a hose from the standby liquid control
. tank to the reactor water cleanup precoat tank. The hoses and tools were 1 i staged but were not identified for E0P use only. In addition, they were *
j stored with other equipment used during routine plant operatie !
I (4) E0P 1. Step RC/Q-10.b. required the removal of a pipe cap to depressurire '
the scram air header in an atten.pt to insert control rods. A wrench was j needed to remove the pipe cap. A wrench was located in the imediate j vicinity; however, the wrench was not specifically designated for E0P use L so its availability for emergency use was not ensured.
l The licensee advised the team that a progran for the dedication and control of t E0P material and equipment would be developed to address the abose concerns and !
that the specific deficiencies identified would be corrected, f 3.4 Validation and Verification Program
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l The team reviewed the validation and verification program established by the ;
- licensee to support the implementation of and revisions to the E0Ps. This a program was modeled after Institute of huclear Power Operations 83 004 l
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"Emergency Operating procedures Validation Guidelines." In its review of this i program, the team found that CNS met the intent and requirements of this guide.
j The program included a review of associated documentation and personnel ;
1 qualifications. Because the lie.ensee did not have a strulator, the program i j included verification of the plant-specific procedures at the Dresden simulato l The team reviewed the discrepancy sheets from the program to ensure that the f
!j identified discrepancies were properly dispositioned. Although the disposition j s process appeared generally satisfactory, the disposition of the following l l discrepancies appeared to be improper or inadequate: ,
- t l (1) Discrepancy 84 recomended that jumpers be prestaged. The licensee's !
i response to the discrepancy stated that all jumpers would be prestaged, j However, the team found that jumpers required by E0P-1, Step RC/P-19 l
], (discussed in Section 3.3(11) above), had not been prestaged, nor had the ;
specific installation locations been identified. The licensee was i l reviewing the need for presteging ECP related material at the conclusion ;
j of this irspectio ,
d (2) Ciscrepancy 3 stated that a method was needed to determine the weight of !
f borcn to be added via the alternate injection method (previouslf 1115 cussed !
in Section 3.3(5) above). The discrepancy disposition stated that a !
, procedure would be developed to provide a riethod. As discussed in Section f
) 3.3(5) of this report, no procedure was ever develope l l
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, In gene al, the validation and verification program implemented at CNS W"rM to be acceptabl ~ e,oltaccident Reactor Building Habitability and Reentry Considera.tions
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The CNS E0Ps required entry into the r2 actor building during and after an accident to perfore local operations. In some cases, these local operations were backup actions due to other failures, (e.g., alternate boron injection on standby liquid control system failure and emergency control rod insertion on !
scramfailures). In other cases, the actions were first-order emergency actions i required for basic accident mitigation (e.g., closure of failed-open safety relief valves or condensate storage tank makeup to the suppression pool via the core spray system).
The tean reviewed Emergency Plan Implementing Procedure 5.7.15. "Rescue and Reentry," Revision 6, which provided the instructions for personnel reentry into the reactor building, and detemined that it included only very basic infomation on maximum dose limits and precautions for reentry. The procedure did not include specific reentry routes for expected E0P operations nor any infcrmation on anticipated dose rate NUREG-0737, "Clarification of TMI Action Plan Requirements," item !!.B.2,
"Design Peview of Plant Shielding and Environmental Qualification of Equipment for Spaces / Systems Which May Be Used in Post Accident Operations," required each licensee to provide for adequate sccess to plant areas to pemit an operator to aid in the mitigation of or recovery from an accident. This item required the licensee to identify the plant areas requiring such access and to anal {ze the adequacy of radiation protection based on specific source term The .icensee's evaluatier, and status were provided to the NRC in letters dated i November 20, 1979 January 11, 1980. December 30, 1980, and April 16, 198 NRC respense and acceptance of the licensee's position was documented in an NRC e safety evaluation report dated Varch 11, 19E3, which was based, in part, on NRC Region IV Inspection No. 50-298/82-32 of November-December 1982. Using the ,
NRC specified source tems, the licensee had conclude ( that the postaccident radiation levels within the reactor huilding would preclude personnel reentry and stipulated that the plant design would support all accident operations without requiring reentry. These analyses and conclusions predated the tvail-ability of the current E0Ps and apparently did not consider the E0P reentry requirement Discussions with the licensee's plant licensing and support staff personnel indicated that the reactor building radiation environment was informally considered during the preparation of the E0Ps; however, correlation with huREG 0737, item !!.B.? data had not been made. The licensee stated to the team that the reentry requirement, reactor building radiation levels, and operator protective actions would be reevaluate .6 E0P Simulation Using Classr_oom Walkthrou;hs
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To ensure that the E0Ps could be correctly implemented during emergency conditions, four accident scenarios were developed and conducted in which three licensed senior reactor operators (SR05) and one shif t technical advisor participate Each SRO was given the opportunity to function as the control room supervisor and to direct simulated plant operations using the E0Ps. The-17-
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scenarios were conducted to: (1) detennine if the E0Ps provided the operators I with sufficient guidance so that their required actions during an emergtncy '
are clearly outlined (2) verify that operator actions were notaluplicated l in the procedures unless required. (3) verify that the transition,between E0Ps and other supplemental procedures could be accomplished satisfactori,ly, and (4) i verify that procedures in different E0P sections could be executed concurrentl ;
Because CNS did not have a $tta specific simulator and the plant was operating ,
at full power, it was necessary to conduct table-top scenarios in the classroom ;
to evaluate the E0P j Realistic scenarios with an accurate time line ire developed by the hRC operator examiner team member. The operators were given the initial plant ,
conditions, rajor equipeent out of service, and the initiating event. The !
control room supervisor directed the reactor operator and balance of plant !
operator to perform the actions as required by the E0Ps. The NRC operator j examiner functioned as the controller. The controller provided plant status, !
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equipment status, and plant parameters to the operators. The plant panmeters were periodically updated on 6 calculated time base as the accident scenario '
progressed. The licensed SR0s were directed to simulate actions and responses based on this input from the controller. Two 'eam members monitored the control room supervisor's ability to direct p1;nt operations in accordance with the E0P .6.1 Scenario Descriptions The first scenario was designed to be a simple introduction to familiarize the licensed operators and the NRC team with the expected response of the plant operators and the controlle This scenario involved a total loss of feedwater with the resultant reactor scram occurring on low reactor pressure vessel (RPV)
water level. All safety systems were allowed to function as designed to restore level. E0P-1 was entered on low RPV water level, which required the control room supervisor to execute the sections entitled "RPV Water level Control (RC/L)," "RPV Pressure Control (RC/P)," and 'RPV Power Control (RC/0) "
concurrently. The heat addition to the suppression pool from the high pressure coolant injection system and the reactor core isolation cooling syster exhaust steam required entry into E0P-2 when the suppression pool temperature exceeded 95'F. E0P-2 required the control room supervisor to execute sections entitled
"Suppression Pool Terperature Control (SP/T)," "Drywell Temperature Control (Ch/T) " "Primary Containment Pressure Control (PC/P)," and "Suppression Pool Level (SP/L),"concurrently. The scenario was terminated when RPV level was restored to the range of +15 to +55 inches, and suppression pool cooling had recuced the suppression pool temperature to less than 95' The second scenario included a failure of the traversing incore probe (T!P)
drive mechanism withdraw limit switch which allowed the TIP pi ibe to be with-drawn into the drive mechanism. Area radiation levels exceeding the matir W safe operating value required entry into E0P-3. E0P 3 required the control room supervisor to execute the sectiuns entitled "Seconcary Containe nt Terperature Control (5C/T)," "Secondary Containment Radiation Control (SC/R),"
and "Secondary Contair. rent Level Control (SC/L) " concurrently. The scenario was terminated when the reoutred actions ci E0P 3 and temporary shielding installation had been simulate ,
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The third scenario involved a loss of all high pressure injection systems. The initial ennditions given the operators included high pressure coolant injection system and B control rod drive pumps out of service,100-percent-rated power, and end of core life with all rods out. The initiating event wasa r.upture of the comen suction line between the condenser hotwell and the condensA's pump This fails e resulted in a total loss of condensate and feedwster pumps result-ing in a reactor scram on RPV low level and a Group I isolation on low cor. denser vacuum. The reactor core isolation cooling (RCIC) system received an initiation signal but was immediately tripped and isolated be:ause of a steam leak in the RCIC room. The control room supervisor entered E0P-1 on low RPV level and high RPV pressure. E0P-2 was entered on high suppression pool temperature. E0P-3 was entered on a high RCIC area temperature. RPV pressure was controlled by the use of safety relief valves with low-low set logic in control. With only one control rod drive pump available, RPV level decreased to top of active fuel (TAF). When RPV level reached TAF, the control room supervisor ordered RPV emergency depressurization, which allowed the low pressure coolant injection and core spray systems to inject and restore leve E0P-2 was exited when the suppression pool temperature was reduced to less than
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95'F. E0P-3 was exited when the RCIC system steam leak was isolated and the RCIC area temperature decreased below its maximum normal operating valu The fourth scenario involved a pip rupture in the turbine digital electro-hydraulic (DEH) control system with , failure to scram. The DEH failure resulted in a turbine trip and bypas, valve failure; the RCIC system functioned nomally on low RPV level. The control room supervisor was required to execute concurrendy RC/L, RC/Q, RC/P, ar)d level power control from E0P-1. E0P-2 was entered on high suppression pool temperature. RPV level was lowered to TAF in accordance with level power control. The residuai heat removal system automa-tically realigned from suppression pool cooling to low pressure coolant injec-tion at -145.5 inches, at which time both suppression pool cooling discharge valves failed closed. The suppression pool temperature exceeded the heat capacity temperature limit of E0P Figure 2-1, which required emergency RPV depressurization. This scenario was terminated when the hot-shutdown weight of
. boron was injected end RPV level was maintaine.1 be.tWPPn +15 and +55 inche .5.2 Scenario Obscrvations Plicekse $ g (finding and keeping the correct place in the E0Ps) was a major problem for the operators while perfoming the table-top scenarios. The team also determined from discussior.s with the operators that placekeeping wts a problem when performing the E0Ps on the simulato It appeared to the team th9t the E09s were cumbersore to use because of the, numerous concurrent actions that must be performed and the large voltm of text tr.at bad to be read. During the execution of the classreom scenarios, the control room supervisor f requently lost his place while attempting to execute the required E0P and contingency actions. The supervisor and other operators appeared to know what action had to be taken, but the supervisor had a problem locating the correct steps in the E0P Mechanisms irplemented by the licensee to aid in placekeeping included: divi-ding the E0Ps into separate binders with E0P-1 in one binder, E0P-2 in a second binder, and E0P-3 and EUP-d in a third binder; attaching colored ribbons to-19-
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each binder for marking pages; and placing a blank line at each action to check off completion of the actio ~
However, in practice it did not appear that the ribbons were effecti.nly used or that the blank lines were checked off to assist in tracking. A contributing factor to the placekeeping problem appeared to be the lack of training given the operators in this are Another problem observed during execution of the classroom scenarios was that the control room supervisor did not have time to read the cautions, nutes and special operator instructions (501s) that were a'1 essential part of the E0P In general, these items were well marked and were inserted in line with the logic flow. However, when the E0P logic directed a jump to a specific step, the tendency was to ignore any cautions, notes, or 501s preceding the step snd proceed directly to the instructions following the step labe The team felt that the dual-column format as implemented in the CNS E0Ps could The usual dual-column format has >
be thecontributing conditions (toifs)the placekeeping in the left columnproble and the actions (THENS) in the right column. In the implementation at CNS, the left column of right-hand pages)
contained primary actions (both conditions and actions)(, and the right column contained contingency actions (both conditions and actions), which were alter-natives if the conditions of the primary action were not met. This was intended to save reading the right column if the primary action worked. The writers' guide also allowed supplementary information to be put in the right column, if it was brief; otherwise it'was to be placed on the left (facing)
pag During the review, the team noted the following deviations from the above concept:
(1) Some of the action steps in the right colurrn were not "contingency" but rather "how to do it" actions for the primary action (e.g., Step RC-3),
(2) Sunetimes it was not cler whether . paragraph in the right column was
, . part of an action step or just supplemental information. (e.g., Step l Tv/L-3, right column, last paragraph). -
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(3) The operatort, appeared to save no time, since both colue.s had to be rcad to see what was in the (4) In some cases the centingency actionk appeared to oe more like a prirury action, (e.g., Steps RC-4. RC/L-2),
(5) In some cav.s there did not seem to be a logic path to o right-column step. (e.g., Step RC/L-8, which perhaps should be a special operating instruction).
(6) In numerous cases action steps did not have the checkoff line and some l supplemental information items di .
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operators could be making assumptions and taking action without benefit of the accident mitigation strategy and supplemental infortnation (e.g., cautions, notes, and special operating instructions) contained in the E0Ps which were developed on the basis of operation of the entire plant and its inter.related system Overall, the operators felt and appeared confident that they could navigate through the logic, and this format was acceptable to the .7 E0P Training 3. Initial Training The team reviewed the initial training conducted to implement the CNS E0P This training consisted of five days of classroom D. ' inn three days of simulator training on the CNS E0Ps at the Dresden . .ve, and a 4-hour in-plant walkthrough conducted by the CNS training ',taf .
3.7.2 Requalification Training E0P-related requalification training was conducted during each annual training period. Classroom discussions of the E0Ps were conducted with the primary emphasis being on explanation and uraerstanding of the steps and cautions contained in the E0Ps. To improve operator performance with the E0Ps, the licensee had recently impl.mented training with classroom scenarios using an instructor as a controller. Training was also provided on all revisions to the E0Ps. The CNS shift technical advisors were included in the E0P training session In-plant training walkthroughs that emphasized familiarization with the equipment and operations required outside the control room were cunducted on a biannual basis. Nonlicensed station operators were included in the portion of the walkthrougns conducted outside the control roo CNS operators attended five days of unual requalification traininc at the Dresden simulator. This trainirig consisted of classroom discussions and '
simulatn scenarios that emphasized E0P-1 and E00-2. The Dresden simulMor modeling would not support the otrformance of E0P-1, Attachment 3, "Altertiate Shutdcwn Cooling." Howaver, all other contingency procedures of E0P-1 and E0P-2 were performeJ. Simulater roodeling wculd not support training on E0P-3
! and E09-4. Classroom scenarios were used to train the operators on the use of E0P-3 and E0P.4, and these two E0Ps werc numally parformed during the annual emergency plan dril .7.3 Observations l
! The team concluded that the CNS E0P initial and requalification training for the licensed operators and shift technical advisors (STAS) was adequate, with
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the exceptiun of the demonstrated weaknesces in placekeeping methods discussed abov ! Implementation of E0P table-top classroom scenarios that required the operators to perform more than one E0P concurrently could improve the operators' place-keeping abilities. The licensee stated that possible alternatives to the
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existing placekeeping method using ribbons attached to each binder would be re.iewed and mare emphasis would be given to placekeeping in future E0P training session _
The team expressed concern regarding the nonlicensed station operaCor trainin The licensee stated that the station operators were included in the biennial plant walkthrough portion of the licensed operator and STA training. No additional walkthroughs were conducted for those station operators who were qualified curing the period between the biennial licensed operator walkthrough This concern was. discussed with the operations training supervisor who, in response to the team's inquiries, initiated a training work request to include E0P training for in-plant evolutions and equipment in the station operator certifi-cation progra .8 Human Factors Review To evaluate the adequacy of the E0Ps with respect to human factors principles, the E0Ps were compared with NUREG-0899, "Guidelines for the Preparation of Emergency Opeiating Procedures," and the CNS E0P Writer's Guide, Revision Frequent reference was also made to the CNS E0P Training Manual (INT 008-04-01 through 04-13), the CNS EPGs, Revision 2, and the step documentation (deviation rationale) relating the CNS EPGs to the E0Ps in order to determine the rationale for the implementation of the E0Ps. Human factors issues were also evaluated ano discussed during the control room and plant walkoowns, the simulated (classroom) event simulations, and interviews with CNS personne . Hardware / Procedure Interface The control room panels had been recently redesigned ano, with minor excep-tions, were well organized, well marked, and accessible. References to the displays and controls in the E0Ps were generally very good. The CNS unique safety parameter display system appeared to be effectively used and was appro-priately referenced in the E0Ps. Comunication within the control room and witn the plant station operators appeared to be good, although a formal repeat-back nethod of oral comJnication was generally not used. Radios were available and were sometimes used. Nonnal lighting in the control room was good, but emergency lighting in case of station blackout appearea to be ihadequate; stops were being taken to improve. the emergency lighting level pace for laytog out the E0P books during implemer,tation was adequate; multiple copics o' referenced procedures were available and had been assembled into a single volume. In-plant equipnent was well labeled (with minor exceptions),
ana the spaces w ve clean and accessibl .8.0 Adherence to the Writer's Guide and NUREG-0899 The writer's guide incorporated the requirements of NUREG 0899 and additionally specified format and organizational requirements for the E0Ps. General acherence to the writer's guide was found to be very good, especially in regards to page layout anc general organization. The team discussed a number of specific deviations in detail with the CNS staff and found that none of the deviations rendered the E0Ps unusabl _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . - _ _ - _ . - _
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. 3. Implementation of E0P Contingency Procedures The ovr.er's group emergency procedure guidelines (0G EPGs), Revis.fon 31, and the CNS EPGs, Revision 2, both identified seven contingency procedures. The first four of these procedures were implemented in the CNS E0Ps by' inserting them into the normal logic flow of E0P-1, not necessarily defined by name. The other threE were placed in separate sections as attachments to E0P- The justification for inserting the first four contingency procedures into the logic flow but leaving the last three as separate attachments was unclear. The step documentation stated that this had been done, but did not explain wh The training manual explained that the attachments were kept separate so they could be referenced in all the EGPs, yet the attachments were not the contin-gency procedures that were referenced the most. The procedure pertaining to emergency depres'.urization was referenced 18 times, in all E0P sect Ons, yet was inserted. The procedure pertaining to level power control was referenced twice, in E0P-1 only, but was separate. The training manual also stated that the inserted versions were reproduced fully wherever they were required in the
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procedures. This was not done; all 18 references to emergency depressurization referred to a single location (procedure tab 6). There did not appear to be any benefit to inserting the contingency procedures, especially since the operators seemed to regard them (and identify them by name) as separate groupings of procedural actions even when they were inserte The inconsistent treatment of the contingency procedures did not appear to help the operators and could contribute to the complexity of the logic flow. Inser-tion blurred the distinction between the normal conditions requiring the use of the E0Ps and the morn degraded conditions requiring the use of the contingency procedures, and created a disconnect between the need to identify these situa-tions in training and the effort to hide the distinction by insertion of the
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procedures.
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3. Supplemental Infonction A great deal of supplemental ini rmation was incorporated in the EOFs to support
, the action steps. The team found that the level of detail was approp ia N cnd
! that the repetition of infonnation wherever needed reduced referencing and the I turning of pages. Further supplemental infonnation appeared warrantd as'
follows:
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(1) Page 28A, Use values rather than "high," *medien, aM "la.'
(2) RC/L-1 Suggest list of possibilitie (3) RC/Q-9a Identify Key No. 54-55.
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! (4) RC/Q-12 Specify expected indicatio (5) RC/P-19 Supply references for main condenser and heed vent, i (6) E0P-1, Page A3-10 Cooldown rate - include method of observatio (7T E0P-1, Page A2-9b Supply procedure to restore automatic depressurization system to standby.
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(8) RC/P-19 Reference to GE Drawing 791E266 is impractical;
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provide procedur (9) Calculations Provideextrasheetsforrepeatcalculat{ont Ongoing Evaluation of E0Ps -
Paragraph 6.2.3 of NUREG-0899 states that licensees should consider estab .
litb ng a program for the ongoing evaluation of the E0Ps. The licensee had not implemented a formal, proceduralized, ongoing E0P evaluation program. However, the team verified that engoing evaluation had been performed by discussions with cognizant licensee personnel; review of Procedure 0.22. "Preparation, Review, and Approval of Emergency Operating Procedure Changes," Revision 2; and review of the development of the current CNS E0P Procedure 0.22 required that the E0Ps and the E0P plaat dat.a table be reviewed annually. This procedure also required that the E0P; be reviewed within 90 days after the hdC issues a safety evaluation of th>r Boiling Water Reactor
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Owners' Group emergency procedure guidelines (BWROF EPGs). The licensee stated that the E0Ps would be updated in accordance with Revision 4 of the BWROG EPGs when they are approved by the NR Since their implementation in 1985, the CNS E0Ps have been revised three times (Revision 4 was in effect at the time of this inspection). The need for these revisions was. primarily identified through feedback from operator requalifica-tion and E0P simulator training. Licensee personnel stated that they were considering adding an E0P feedback report form to Procedure 0.22 to make it easier for personnel to provide feedback on the E0P .0 POSTACC10ENT COMBUSTIBLE-GAS CONTROL The CNS E0Ps provided no postaccident combustible-gas control instructions in the event the containment hydrogen and oxygen concentration limits were exceeded. Unlike later BWR-4 plants, CNS did not have a nitrogen containment atmosphere dilution (hCAD) system. The licensing basis for CNS called for such a system to be installeo during the first refueling outage. Howevce, tn air cont 31nment atmosphere dilution (ACAD) system was installed inctead. St6ff review and approval of the ACAD system was nearly complete at the time of,the accident et Three Mile Island (TMI). At that time the revi w was termiaated to coricentrate on TMI-related work. The hydrogen /recombiner rule, 10 CFR 50.44, was subsequently issued, and the review of the ACAD system was never resume By letter dated July 1, 1986, the NRC staff advised the licensee that it should attempt to demonstrate thr.t the containment nitrosen inerting system could be successfully used under uutaccident conditions as a nitrogen dilution syste The licensee has orepare:I a draft response but was awaiting NRC staff guidana before submitting it. Cys:er Creek, Millstone-1, Quad Cities 1 and 2, end Dresden also did not hav6 i1 CAD systems and were similarly affecte .
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5.0 EXIT MEETING / PERSONS CONTACTED Gn July 10, 1988, the team and other NRC representatives met with licensee personnel and discussed the scope and findings of the inspection.- Persuns cor.tacted by the teans and attendees at the exit meeting are identified in Attachment Mr. J. J. Jaudon, Deputy Director, Division of Reactor Safety, RIV, and Mr. L. J. Norrholm, Section Chief, Special Inspection Branch, NRR, represented NRC management at the exit meeting. During the inspection the'
team al:0 contacted other members of the licensee's staff to discuss issues and ongoing activitie .
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ATTACHMENT A PERSONS CONTACTED -
EXIT MEETING ATTENDEES I~-
NAf!E ORGANIZATION TITLE
- P.L. Ballenger NPPD Operation Engineering Supervisor
- L.E. Bray NPPD Regulation Compliance Specialist D.W. Bremer NPPD Operations Support Group Supervisor
- R. Brungardt NPPD Operations Manager D.M. Dea NPPD Senior Reactor Operator M.C. Daus NPPD Consultant
- J.R. Flaherty NPPD Plant Engineering Supervisor
- R.A. Gardner NPPD Management Trainee - Operations M.D. Hannaford NPPD Reactor Operator D.P. Helms NPPD Station Operator G.R. Horn NPPD Nuclear Operations Division Manager D.T. Kuser NPPD Operations Support Group Engineer H.A. Jantzen NPPD instrume;Itation & Control Supervisor B.A. Lipsemeyer NPPD Shift EJpervisor
- J.M. Meacham NPPD Senior Manager, Technical Support
- G.R. Smith NPPD Licensing Supervisor
- G.E. Smith NPPD Quality Assurance Manager
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- Denotes those present at the exit meeting o.: July 12, 198 A-1
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ATTACHMENT B LICENSEE'S DOCUMENTS REVIEWED -
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NUMPiR TITLE REVISION
E0P-1 Reactor Pressure Vessel Control 4 E0P-2 Primary Containment Control 4 E0P-3 Secondary Containment Control 4 E0P-4 Radioactive Release Cor, trol 4 E0P-C Operator Precautions 4 EP Emergency Operator Procedure Introduction 4 EP 5.2.14 Alternate Means To Inject Boron to RPV 2 EP 5. Post Accident Venting of Priinary Containment 2 EP Emergency Operating Procedures 4 OP 2.2.6 RHR Suppression Pool Cooling and Containment 1 Spray
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AP 2.4.2. Relief Valve Stuck Open 17 OP 2.2.73 Standby Gas Treatment System 17 OP 2.2.40 HVAC Orywell Cooling 9 SP Reacter Building HVAC Interlock and 0 Containment Level Recorder Testing 0.22 Preparation, Review, and Approval of Emergency 2 Operating Procedure Changes 0. CNS Controlled Documents Other Than CNS 0 Procedures and Vcndor Manuals 0.36 Industrial Safe Work Permit Draft INT 0800 CNS Training Manual (EOPs) 0-04-01 through-04-13
-- BWR Owners' Group Emergency Procedure . 3 & 3I Guidelines, including Appendice; A, B, and C
-- CNS Energency Procedure GuiJelines 2
- CNS Step Deviation Documentation NA
-- CNS Procedures Generstion Package 2 -
NPPD QA Prngrara for Operation Policy 4 -
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ATTACHMENT C ABBREVIATIONS AND ACRONYMS -
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ACAD air containment atmosphere dilution AP abnormal procedure BWROG Boiling Water Reactor Owners' Group CNS Cooper Nuclear Station CRD control rod drive CRS control room supervisor DEH digital electrohydraulic E0P Emergency Operating Procedure EP Emergency Procedure EPGs emergency procedure guidelines GE General Electric HCU hydraulic control unit IA instrument air
. NCAD nitrogen containment atmosphere dilution NPPD Nebraska Publi. Power District NSSS nuclear steam supply system OG owners' group OP operating procedure PGP procedure generation package PSTG plant-specific technical guidelines PSWG plant specific writers guide RCIC reactor core isolation cooling system RHR residual heat removal RPV reactor pressure vessel RWCU reactor water cleanup SBGT standby gas treatment SLC standby liquid cor, trol 501 special operating instruction SRV safu y relief valve TAF top of a:tive fuel T1 temporary instruction r! traversing incere probe '
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TMI Three Mlle Island "
E0P Control Section Designations RC/L reactor pressure vessel / level RC/P reacter pressure vessel / pressure RC/0 reactor pressura vessel / power DW/T drywell/temperture PC/P primary containment / pressure SP/T suppression pool / temperature SP/L suppression pool / level *
SC/L secondary containment / level *
SC/P secondary containment / radiation SC/T secondary containment / temperature
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