IR 05000382/1988018
| ML20153D715 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 08/09/1988 |
| From: | Gagliardo J, Stewart J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20153D699 | List: |
| References | |
| 50-382-88-18, NUDOCS 8809060021 | |
| Download: ML20153D715 (27) | |
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APPENDIX i
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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NRC Inspection Report:
50-382/88-18 Operating License: NPF-38
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Docket:
50-382 Licensee:
Louisiana Power & Light Company (LP&L)
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142 Delaronde Street New Orleans, Louisiana 70174 Facility Name: Waterford Steam Electric Station, Unit 3 Inspection At:
Taft, Louisiana
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Inspection Conducted:
July 6 - 14, 1988
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Inspector:
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Q.PUStewaht, Team [eader,RegionIV Date/
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l Team Members:
J. O'Brien, Senior Reactor Inspector, Region V
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L. Defferding, Licensing Examiner
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C. Tolbert, Human Factors Specialist j
P. Bibb, Resident Inspe-tor, St. Lucie W. Smith, Senior Resident Inspector, Waterford 3
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Approved:
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J A E. Gagjiardo, CE E0P Manager, Region IV Date
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Inspection Summary Inspection Conducted July 6-14. 1988 (Report 50-382/88-18)
Areas Inspected:
Special team inspection of Waterford 3 Emergency Operating l
Procedures (EOPs) including the following areas:
i Basic E0P/CEN-152 comparison
Technical adequacy review of the E0Ps i
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Control room and plant walkdown l
- Simulator
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j E0P ongoing evaluation
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Human factors related guidance
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Results:
No unsafe operational conditions and no violations or deviations were identified. Although several technical and human factor weaknesses were found,
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j the emergency operating procedures were found to be adequate to support
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The licensee has comitted to review i
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the identified weaknesses and the appropriate corrective actions to resolve
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them.
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Open Items Sumary: During this inspection, eight open items were identified witch will require followup.
The open items include:
(1)correctionof
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technicaldeficienciesidentifiedintheEmergencyOperatingProcedures(EOPs);
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(2) incorporation of instrumentation safety margins into the E0Ps, when the r
CEN-536studyidentifiestheappropriatemarginsneeded;(3)validationofall
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E0P revisions with a nonnal operating shift; (4) correction of the plant
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i equipment deficiencies associated with the implementation of the E0Ps; l
(5) upgrading the safety function recovery procedure training programs
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(simulator and classroom); (6) upgrading of E0P evaluation program elements for
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providing feedback of operator concerns and difficulties with the E0Ps; i
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j (7) incorporation of operator's ability to perform during emergency or abnormal
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conditions in annual perfonnance appraisal; and (8) upgrading of quality
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assurance oversight of E0P development and implementation.
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DETAILS 1..
_ Persons Contacted Principal Licensee Egloyees e
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- R. P. Barkhurst, Vice President, Nuclear Operations
j N. S. Carns, Plant Manager, Nuclear
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D. P. Packer, Assistant Plant Manger, Operations and Maintenance t
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D. E. Baker, Operations Assistant
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L. W. Laughlin, Licensing Engineer
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R. S. Starkey, Operations Superintendent
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j S. A. Alleman, Quality Assurance Manager j
J. G. Hoffpauir. Assistant Operations Superintendent
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G. G. Davie, Shift Supervisor
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i D. P. Clark, Operations Training Supervisor
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C. Boudreaux, Training Supervisor
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W. L. Smith, Simulator Supervisor a
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- Denotes those attending the exit reeting on July 14, 1988.
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The inspectors also contacted other licensee employees during the course f
l of the inspection, including training instructors, shift supervisors,
J control room supervisors, reactor operators, plant equipment operators, I
j and procedure writers.
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1 Also in attendance at the exit meeting on July 14, 1988, were the
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following NRC and NRC contracted staff personnel:
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I J. Jaudon, Deputy Division Director, Region IV G. Lapinsky, Jr., Human Factors Branch, NRR j
P. Stewart, CE E0P Tecm Leader, Region IV j
J. O'Brien, Reactor Inspector, Region Y
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C. Tolbert Human Factors Engineer, SAIC
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L. Cefferding, License Examiner, Battelle Northwest Labs t
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W. Smith, Senior Resident Inspector Waterford 3 i
2.
Waterford_3 (W3) E0_P/CEOG CEN-152 Procedure Corparison (25592)
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j A coeparison of the W3 Energency Operating Procedures (EOPs) and the l
l Cosbustion Engineering Owners Group (CEOG) Emergency Procedure
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Guidelines (EPGs) CEN-152. Revision 2, was conducted.
The objective of
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this review was to ensure that the licensee had developed sufficient g
procedures in the appropriate area to cover the broad spectrum of j
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accidents and equipaent failures that must be considered. All of the licensee's E0Ps are listed in Appendix A of this inspection report.
The
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inspectors reviewed the licensee's E0Ps and noted that procedures were l
irplemented in accordance with the CEOG recomendations.
In addition, the
licensee implerented Erergency Operating Procedure OP-902-005, Revision 2
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' Degraded Electrical Distribution Recovery Procedure." The purpose of
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this procedure was to check that a degraded electrical distribution has l
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occurred and adequate core cooling capability exists following a loss of AC power to electrical busses while maintaining other safety functions
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through nomal methods.
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l The comparison included reviews of the licensee's documentation and
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interviews with personnel to verify that.any deviaticns from CEN-152 were l
justified. Other minor discrepancies and human factors deficiencies were identified in the paragraphs below and in the appendices to this l
Inspection report.
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The inspector detennined that the licensee had adequately developed plant
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specific E0Ps to implement CEN-152 Revision 2.
The changes from CEN-152
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reconnendations were reviewed with the bases established and were documented by the licensee.
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Independent Techn_ica_1 Adequacy _ Review of the_E0_Ps (25592)
l The W3 E0Ps listed in Part I, Appendix A, were reviewed to ensure that the l
procedures were technically accurate and incorporated the guidelines of
CEN-152, Revision 2.
f This review verified that the CEOG step sequence was followed, except for l
the minor deficiencies identified in Appendix B of this report.
In each
case the licensee committed to reorder the step sequence to be in
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agreenent with CEN-152 Revi:, ion 2.
The team determined that the
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licensee's responses in each case were adequate, j
The review also verified that transfer between procedures was well defined
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and appropriate for procedures perfonned concurrently, that minimum
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staffing was met, and that notes and cautions were used correctly.
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deviation from CEN-152 was reviewed to ensure that safety significant (
deviations were reported to the NRC as recuired, that deviations warranted by specific plant design were incorporatec, and prioritization of accident mitigating strategies were correct, j
The team determined that, in general, the E0Ps adequately incorporated the procedure guidelines of CEN-152 Revision 2.
The sunnary of the findings l
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and observations of the W3 E0Ps is as follows:
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l Entry / exit points to the W3 E0Ps were clearly stated and could be
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followed by trained reactor operators. The licensee agreed to
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incorporate minor addition 61 entry condition clarifications to be in i
agreenent with CEN-152 (as noted in Appendix B).
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Notes within the E0Ps were generally clear and appropriately located
in the E0Ps.
The CEN-152 prioritization of the accident safety function
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investigation hierarchy was maintained in the E0Ps.
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The plant specific values for plant protection system setpoints
(e.g.,SIAS,CIAS,CSAS)wereconsistentwiththeplantdesign
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values.
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During the E0P review, the team identified a' number of technical concerns
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in the E0Ps, and they are listed along with the licensee's responses in i
The identified concerns focused in two areas:
App)endix B of this report. steps out of' sequence with the step order specified in th l
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l guidelines without providing technical justification for the difference in
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sequence; (2) clarification of the preferred instrumentation to be utilized to verify a plant parameter.
During the inspection, the licensee
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either provided the clarification to the E0P deviations from CEN-152 or j
l acknowledged the technical deficiencies, which were identified by the
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l inspection team.
The licensee agreed to correct E0P deficiencies as l
required to be consistent with CEN-152 in the next revision to the W3
E0Ps. The team detemined that the licensee's resolutions were l
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acceptable.
The licensee's correction of the deficiencies identified in i
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Appendix B will be followed up after the issuance of the next revision of i
l the E0Ps, which is scheduled for the first quarter of 1989.
This is an
i openitem(382/8818-01).
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The team also identified that the licensee has been a participant in CEN
l TASK 536, which is a task for developing a methodology for determining i
l instrument errors to be included in the appropriate E0Ps for adverse I
containment environments.
The licensee is awaiting the results of this
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project and will revise its E0Ps accordingly. This item will be followed
i up after the completinn of CEN TASK 536.
Thisisanopenitem(382/8818-02).
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The team observed that the W3 E0Ps, except for OP-902-000, the emergency t
j entry procedure (standard post-trip actions), were all in a single column
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fortnat.
The CEN-152 guidance callr, for the utilization of a dual column
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fomat. Licensee representatives (departrent level) stated that they had l
no plans to go to the dual column fortr.at. At the exit interview, the
inspection team comunicated to the licensee's senior management, that i
although it was not an NRC requirerent to use a dual column fomat, the licensee should consider the advantages of the dual column format, and i
understand why the CEOG recomended the implerentation of a dual column l
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femat in the E0Ps.
This item is also discussed in Section 7.C. of this
report.
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J Additional technical deficiencies identified during observation of the i
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simulator scenarios are addressed in Section 4 of this report.
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j No violations or deviations were identified in the review of this program
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Review of Validation Program apd Independent Verification of the E0Ps
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_(25592)
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As a result of the THI-2 accident, NUREG-0899 was issued in August 1982 to t
establish the guidelines for the development and implenentation of E0Ps,
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which would provide the operators with directions for mitigating the j
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consequences of a broad range of accidents and equipment failures.
Paragraph 3.3.5 of this NUREG indicated that, after development, the E0Ps
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were to undergo a process of verification / validation to determine that the procedures were technically adequate, addressed both technical and human factors issues, and would be accurately and efficiently carried out.
The licensee provided documentation to show that their verification program met t1e following purposes: confinn the procedures are technically accurate and are written correctly for ease of use.
The licensee's verification program contained the following table-top reviews:
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To compare each procedure to the applis,able generic and plant
specific technical guidelines and to other source data such as j
Technical Specifications and FSAR.
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To compare each procedure against a checklist of criteria drawn from
i the Writer's Guide.
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The lir.ensee also provided documentation to demonstrate that the
validation program met the stated purpose of den.onstrating that the actions soecified in the E0Ps can be followed by trained operators to
effectively manage emergency cor.ditions (except as noted below). The three elements of the validation program were:
A table-top review where control room personnel talk through the
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steps of the procedure.
A control room walkthrough where control room personnel perfom a
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Simulator exercise where control room personnel perform the
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procedure, including execution of control actions on a real time
plant simulator. The control room walkthrough and simulator exercise
used prepared scenarios.
All new procedurus had been validated and
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approved.
The inspection team conducted its own control room, simulator, and plant walkdowns of the E0Ps listea in Part 1 of Appendix A of this report to ensure that the procedures were validated and verified by the licensee, i
During the walkdewns; instruments and controls were verified to be correctly labeled (except for those deficiencies indicated in Appendices C and D). The team also verified that the indications i
referenced in the procedures were available to the operator and values
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were not overly specific for the available indicators. Administrative i
procedures were reviewed to ensure that adequate controls existed to incorporate changes to the E0Ps, that the latest revision was available to the operators, ar.d that they were easily accessible.
The team found that
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the docu:rentation indicated the discrepancies had been adequately
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addressed and corrected, comprehensive reviews had been conducted, table top reviews were adequate, walkdowns had been completed and docusented, and human factors personnel had been involved in the program.
During the performance of simulator scenarios, the team identified several
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deficiencies.
During the use of the functional recovery procedure.
OP-902-008 E5, the inspectors noted that two independent operating crews had difficulty identifying which success path to use, from the resource assessment tree, for the loss of feed scenario with condensate purps
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available.
The success path, on the tree, failed to include the option to depressurite the steam generator and feed with the condensate punps.
Operating steps covering this option were included in the body of the procedure, i
Path V3, Step 19.5 of this sane procedure directed the operator to fully
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open the atmospheric durp valve in order to depressurize the steam generator so they could be fed with condensate punps.
This rapid depressurization causes e very rapid reactor cooldown.
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DiscussionwiththeplanipersonnelnotedthatthevalidationoftheE0Ps l
was completed by procedure writers and senior staff.
This validation by highly experienced personnel caused several deficien::ies to be overlooked that probably would have been identified if regular operating shifts had been used.
The licensee agreed to review and correct these deficiencies a
and to use nonral operating crews to validate all new procedure revisiens.
l This is an open item (382/8818-03).
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In addition the NRC inspectors, during the control room simulator and I
in-plant walkdowns, identifieri the deficiencies listed in Appendix 0.
The
licensee conrnitted to make the appropriate procedure revisions as noted in l
Appendix D.
The licensee's revisions of the E0Ps and associated
docunentation for the correction of the noted procedural deficiencies in
Appendix 0 will be followed up in a later inspection.
This is an open
item (382/E818-04).
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No violations or deviations were identified in the review of this program i
area.
I 5.
E0P Training (25592)
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The inspection team assessed the adequacy of the E0P training by reviewing
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three areas.
The first dealt with observing an unrehearsed operating crew
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perfonning the E0Ps in the site-specific simulator with scenarios designed to exercise each of the E0Ps.
The second effort was to review the lessnn i
plans and treining records for the hot licensed and requalification i
operator training programs as they pertained to E0P training.
Finally, interviews were conducted of a selected sample of the operations staff.
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Sinciatcr Scenarios
The team's license operator examiner and reactor inspector developed j
scenerios similar to those used for licented operator exams and E0P training.
During the perfonnance of these scenarios with the
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unrehearsed operating crew, the entire NRC E0P inspection team had
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i the opportunity to: observe the operator's performance to validate
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or dismiss any concerns that may have been raised during the
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table-top reviews of the E0Ps; assess the licensee's operating
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j philosophy (possibly as it differs from CEOG tuidance in CEN-152);
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assess the human factors elements (place keep < ng, assignment of
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of the procedures in a "real time" atmosphere; observe how the i
operators diagnose accident conditions and transition from one E0P
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to another.
The team made the following observations:
The operators exhibited adequate kn'owledge of the E0Ps and the
l CEN-152 guidance.
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The operators were not familiar with the Resource Assessment
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Trees for the success path selection in the Safety function I
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Recovery Procedure (SFRP).
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The operators had difficulty in the' controlling plant cooldown
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rate using the SFRP.
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The operators were more comfortable using the optimum recovery
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j procedures than the SFRP.
j Other human ~ factors observations were identified and are
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addressed in Section 7 and Appendix C of this report.
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Fomal Training Programs f
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1.esson plans and simulator scenarios used for E0P training were
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l review (d to determine whether the training covered the technical l
basis for the procedure, as well as the structure and format, of the j
i E0Ps. The lesson plans, procedures, and material reviewed are listed t
l in Part 3 of Appendix A.
This review included a review of attendance l
l sheets for randomly selected lesson plans, and how the licensee i
handled makeup training for those who missed the normally scheduled i
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i training.
At the time of the inspection, the licensee's E0P training program f
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consisted of the initial training prior to E0P implementation l
(December 1984) consisting of approximately 40-50 hours. Subsequent (
to that tirre, the training was given as part of the hot license
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j operator training for Reactor Operators and Senior Reactor Operators.
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All of the operators having this training have maintained their l
proficiency with E0Ps by completing the following:
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i An initial required read;ng program covering all the E0Ps (over l
j a 1-year cycle).
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Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of lecture on E0P review.
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A portion of the 1-week simulator training at the facility's
site-specific simulator during each cycle of requalification training.
The annual requalification exam.
- The ongoing required reading program, which comunicated new l
infonnation to the operators as revisions were made to the E0Ps.
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i The above training program met the minimum requirements as comitted
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l by the licensee and was comparable to training programs for other t
utilities.
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t Additionally, the inspectors reviewed the existing training lesson
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plans and rnaterials listed in Part 3 of Appendix A that were used for
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both the lecture and sienulator training.
These lesson plans i
l adequately covered the technical basis behind the procedures, as well
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as the structure and fonnat of the E0Ps.
The inspectors did not note
any content of the lesson plans and raterials that might account for the problems observed concerning the use of the Resource Assessment i
j Trees and control of the plant cooldown rate.
These items were
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discussed among the team members and with the facility staff, and it
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was agreed that it was a procertural problem; these items are addressed in paragraph 4 of this report.
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The review of the training schedules and attendance sheets indicated
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that approximately an equal amount of training was conducted on each i
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of the procedures. Since the SFRP is rnore complicated than the Optirnum Recovery Procedures (ORPs), it was expected that more i
j training effort should have been conducted on the SFRP. After
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discussing this with the training staff, the licensee comitted to
i evaluate the adequacy of the training and to revise, as necessary, to
erphasize the SFRP. Thisisanopenitem(382/8818-05).
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Operator Interviews
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Operators were interviewed to detennine their understanding of the
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E0Ps and their responsibilities and required actions, both I
individually and as a team. Additionally, operators were interviewed
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to detennine whether they felt that actions were duplicated by other j
operators, whether they were knowledgeable of the requirements for J
transition from one procedure to anothh, and whether training was t
conducted on revised E0Ps before they were irr.plemented.
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The operators had few coments concerning the attributes discussed i
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above. However, they did express some concerns about using the SFRP.
i They felt that too such time was wasted confinning what was already
verified in the ORPs before irplerrenting the success paths in the r
SFRP. They also stated that they were more confident using the i
event-based ORPs.
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They also confirmed that they were more confident using the ever.t-based ORPs.
Further comments are addressed in the Human Factors section of this report under the heading "Differences in Operators' Interptetations."
No violations or deviations were identified in the review of this program j
area.
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6.
Ongoino Evaluations of E0Pc (25592)
l The procedures and instructions listed in Part 2 of Appendix A were reviewed to determint if the licensee had an acc etable program for the
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ongoing evaluation " E0Ps in accordance with the guidance of
Section 6.2.3 of N# 1-0899.
The team also reviewed other records and documents and interviewed licansee personnel to verify that the above
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requirements had been implemented.
i The latest revision of the E0Ps (Revision 2) had been issued in f
January 1987.
The technical c:fequacy of the revised E0Ps was deteritined by a verification and validation program which was performed by liidividuals, most of whom were in the operations department.
A human factors specialist was also utilized, but no personnel from plant i
engineering were involved.
Licensee representatives indicated that Plant i
Engineering was represented during the PORC review, which involved several l
hours of briefing by the administrative supervisor. The team verified j
that the Acting Technical Support Superintendent was in attendance at PORC
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Meeting 87-08 when the E0P revisions were discussed.
This limited review
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by Plant Engineering did not appear to constitute an adequate technical
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review of the E0Ps.
Some of the technical deficiencies identified by the team and documented in other sections of this report may have been i
identified and corrected by I more indepth review from plant engineering.
The guidance of NUREG-0899 specifies that the lic6nsee's ongoing
evaluations should include feedback on technical adequacy and format / style i
of the E0Ps based on operational experience, training, and exercises. The
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licensee's program for evaluating the technical adequacy of their E0Ps was t
very informal and only marginally adequate.
Procedure UN1-1-012 required
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a review of procedures for technical and administrative adequacy every
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24 months.
This procedure did not. however, address the requirements for
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an evaluation based on operational or training exoeriences.
Instruction 01-019-00 provided a form entitled "Proced"-- Change Request"
and stated that operations personnel requesting a change to a procedure should utilize this form.
The licensee's training department issued a
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handwritten daily instruction, dated July b. 1988, which required the use i
of this form by all trainers and trainees.
This was issued after the
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inspector had raised the issue on that date.
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The use of the Procedure Change Request Form was the only formalized means i
of providing feedback regarding the technical adequacy of the E0Ps.
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daily instruction issued by the Training Department was the only l
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j requirement to use this form; and this requirement (very informal), was applicable only to those who were being. trained at the Training Center.
As noted above, the licensee's evaluation program was only marginally acceptable for the feedback of training experience.
The team found no indications of a program element to assure feedback based on operational experience and exercises. Licensee representatives agreed to review this potential weakness in their program and to revise the program if
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appropriate. This is an open item (382/8818-06).
t The team also noted that the evaluation of *affing ar.d staff
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qualifications regarding the use of the E0Ps was'in need of further review. The Training Department had a poliev of evaluating the
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performance of trainees at the simulator.
These evaluations were documented and forwarded to the individual's supervisor.
The program for evaluating the performance of the or rators in the use of the E0Ps onshift
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was marginal. The evaluation was it:1uded in the annual performance appraisal of the operators and did not specifically address the operator's ability to deal with emergency or abnormal conditions. This approach also failed to assure input from all of the shift supervisors whom an individual operator. night work for during the appraisal period.
This area needs to be reviewed and reevaluated for adequacy in meeting the intent of the NUREG-0899 guidance.
This is an open item (382/8818-07).
The team also noted that the program for evaluating the adequacy of the E0Ps did not address the need for feedback regarding the format, style, or content of the E0Ps. The team noted that 50 coments had been compiled to be considered for the next revision of the E0Ps.
These coments dated back to the issuance of Revision 2 in January 1987. Of the 50 comments only 3 of them addressed format / style c1anges.
l'.any of the human factor's discrepancies, which were identified by the team and documented in Section 7 and Appendix C of this report, should have been identified by an evaluation r ogram that required licensee personnel to address these types of concerns.
The tearr reviewed the involvement and oversight provided by QA in the cevelopment, implementation, and training on the E0Ps. A licensee representative stated, during the course of an interview, that QA had only minimal involvement in E0P development and implementation.
He stated that
QA had ellowed the E0Ps tu evolve and had only looked at selected E0Ps during the performance of emergency drills.
The licensee's QA manager comitted to review this issue and provide appropriate oversight of E0P development and implementation.
Thisisanopenitem(382/8818-08).
l The team also reviewed the activities of P0HC to determine the extent of their oversight over E0P development.
Revision 2 to the E0Ps was reviewed anc' discussed during PORC Meeting 87-08. As noted above, the review included an extensive briefing by the Administrative Supervisor.
The PORC also did a prior review and evaluation of the verification and validation results for the Revision 2 procedures.
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No violations or deviaties were identified in the review of this program
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7.
H_uman Factors Analysis of E0Ps (25592)
The human factors review covered a number of areas including the analysis of the procedures, observations of instruments in the control room required for E0Ps, observations of instruments outside the control room required for E0Ps, and environmental factors. The data uere obtained via several methods.
a.
Differences in_ Operator Interpretation _of E0P Implementat_ ion __
Through various methods, the E0P inspection team detennined that operators varied widely in their interpretation and execution of E0Ps. This was illustrated during a simulator scenario in which operators disagreed on how to interpret and utilize the charts in the SFRP, specifically, the Resource Assessment Trees. Operators'
attitudes toward the SFRP also varied, ranging from negative to accepting.
The high variability in operator interpretations, documented in Appendix C, support the inspectors' conclusion that E0P training needs to be improved.
If E0P training was better, the differences described in Appendix C may be reduced or eliminated.
b.
Manpower Allocation At W3, the minimum control room shift consists of two Nuclear Plant Operators (NPO), one Control Room Supervisor (CRS), one Shift Supervisor (SS), and one Shift Technical Advisor (STA).
In addition, some shifts have an administrative NPO. However, since this position is not required on all shifts, the administrative NPO may be absent from a given shift. As the E0Ps are presently written, the minimum shift can perform the E0Ps, but a shift's ability to perform the E0Ps is reduced when the administrative NPO is not present.
(NUREG-0899, Sections 5.8.1,6.2.3)
The operator roles were not well structured.
This conclusion was based on the observation that operators on several occassions omitted the performance of verifying the safety functicn checklist parameters section of the E0P and that they duplicated each others efforts. On several occasions both reactor operators provided the CRS with the sane parameter value when asked. A major factor that contril ted to the unstructured nature of operator roles was the task division between the primary and secondary board operators. The control panels consist of two main panels that are perpendicular with one center panel diagonally connecting the two.
The primary plant NPO is responsible for the center panel located in the center and adjacent panels on the two main panels.
The secondary operator operates the panels located at the two outer ends of the main panels.
(Oneofthesepanelsisthesafeguardspanel,usedduringemergencies.)
The secondary plant NPO is, therefore, required to move between
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opposite ends of.the control panels, a distance of approximately 20 feet.. Throughout simulator scenarios, the E0P inspectors observed the STA, CRS, SS, and primary plant NPO walk over to the safeguards panel (CP-8) to look at instrument indications.
The secondary plant NPO was observed several times asking the primary operator for pressurizer pressure, which was not indicated as such on the
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safeguards panel (CP-8). The layout of instrument panels and the assignment of operator tasks during E0Ps were not wholly compatible.
(NUREG-0/00, Section'6.1.1.la:and NUREG-0899, Sections 5.8.2 and 5.8.3)
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-In sumary, various. factors contributed to the problem of allocation
of manpower. - As noted above, the reactor operator roles were not well structured, thus. encouraging the observed operator task duplications as well as the operator's omissions of E0P actions.
Additionally, the absence of an extra operator (administrative NPO)
j in several simulator scenarios forced the shift supervisor to distribute E0P tasks among two operators instead of three, which exacerbated task allocation.
c.
Emergency Operating Prncedures Documentati_on Several deficiencies were identified in the E0Ps including the areas i
of fomat, clare and level of detail. The most significant format issue identifie.
the E0P inspection team was the licensee's use of a single-column 3,
aat, which is not recommended in CEh-152 Revision 3.
- nce W3 operators have been trained on the single-colut o format, the E0P inspectors understand the utility's hesitation to change the E0Ps to the reconrnended dual-column fomat.
From a human factors viewpoint, however, the utility should recognize that the single-column fomat requires operators, primarily the CRS,
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to skim through many contingencies that are not applicable.
Placekeeping also is a potential problem because more steps must be checked.
Those that do not apply should be somehow checked or crossed out. Also the CRS may become confused by mistakenly considering contingencies that do not apply.
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Sections 5.5.4,5.4.6)
l Portions of the E0Ps were not written clearly.
For example, some logic statements were too complex, including more than a single idea.
i (See Appendix C for specific examples of unclear steps.)
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The following items were identified in the Safety Function (
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The first pages of the procedure did not adequately explain how
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to use the procedure, l
i The Resource Assessment Tree lacked infonnation or contained
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misleading infonnation.
(NUREG-0899, Sections 5.6.1, 5.6.3,
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5.6.4,5.6.5)
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d.
Control Room Instrumentation Some instrument scales were found to be incompatible with some E0P requirements.
For example, most E0Ps, as well as the safety function status checklists, instructed the operator to read 0.378 x 108/bm/hr -
However, the instrument scales used for this parameter are not sufficiently detailed to allow the operator to see this value.
The licensee has agreed to round this number to 0.3 x 106 in the forthcoming Revision 3 of the E0Ps.
Other instances of inappropriate or incompatible instruments are listed in Appendix C.
(NUREG-0899, Sections 5.6.8 and 5.6.6)
Labeling of measurement units on instrument scales was found to be deficient in certain instances.
On resny scales, the units were written in very small characters, causing it to be clnost unnoticeable.
The containment pressure recorders located on the safeguards panel did not have, adequate measurement unit labeling.
In fact, two wide range containment pressure recorders exist on the safeguard panel about one foot apart.
Papr on one recorder reads
"PSIA," the other "PSIG"; these labeis are hard to read. When asked what the difference vetween the recorders was, operators were unable to provide an explanation.
It is still unclear why one recorder reads PSIG and the other PSIA.
If operators are required to read both, as distinct parameters, then the appropriate distinction between the respective units should be made.
(NUREG-0899, Sections 5.6.6, 5.6.7, 5.6.8)
The SG level instruments were not labeled as either wide range or narrow range.
Operators had to rely on training to discern which range was on each instrument.
To compound the problem, on panel CP-1, only a narrow range level existed.
Thus, th( operator could not compare it to wide range level on that panel.
On the safeguards panel (CP-8), both wide and narrow range levels were displayed but were not labeled as such.
Furthermore, both scales contained precisely the same scale, 0-100 percent.
This caused the scales to be even less differentiated.
The wide range scale on this panel was also not clearly labeled as being a SG parameter.
(NUREG-0899, Sections 5.6.6, 5.6.7, 5.6.8).
As stated earlier, a pressurizer pressure indication on the safeguards panel did not exist.
An additional control room issue identified
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during observation of scenarios was the operators' calculations of cooldown rate.
The STA spent a considerable amount of time calculating and recalculating cooldown rate, thus detracting from other tasks.
The team noted that the plant computer could be set up to perform cooldown rate calculations.
(NUREG-0899, Section 5.6.9, NUREG'0700, Section 6.3.2.1c)
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Local In-Plant Deficiencies A number of valves in the plant that must be manually operated'during E0Ps were inaccessible.
(These are. listed in Appendices C and 0).
J Some of the valves were located between 8 to 20 feet above ground, l
with no means of reaching them.- In one case, operators.had to locate-
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a large aluminum ladder and set it against-an overhead pipe.
This i
task would be precarious, at best.
Some valves were located about 15-20 feet above ground and behind other pipes and components.
For
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these valves, operators must climb.up and around the pipes.
(NUREG 0700, Sections.6.1.1.3, 6.6.'1.1)
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The labeling of some componeits requiredLin'the E0Ps were deficient.
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Some of the inaccessible valves was inadequately labeled; the identifications were a metal dog tag type label.
These labels cannot
be read from a distance.
They were small and could easily become
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dirty, eroded, or broken off.
(NUREG 0700, Section 6.6.1.1)
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No violations or deviations were identified in the review of this program e
area, i
8.
Exit Meetina (30703)
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On July 14, 1988, an exit meeting wac conducted with'the licensee:
representatives identified in Paragraph 1.
The inspectors summarized the i
inspection scope and findings as described in the Results section of this i
report.
The licensee acknowledged the inspection findings and noted that appropriate corrective actions would be implemented wheru warranted.
The licensee did not identify as proprietary any of the information provided to, or reviewed by, the inspectors during this inspection.
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APPENDIX A List of Procedures Reviewed 1.
Procedures Reviewed on Table-Top OP-902-000 Emergency Entry Procedure OP-901-001 Uncomplicated Reactor Trip Recovery Procedure OP-902-002 Loss,of Coolant Accident Recovery Procedure OP-902-003 Loss of Forced Flow. Recovery Procedure
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OP-902-004
. Excess Steam Demand Recovery Procedure OP-902-005 Degraded Electrical Distribution Recovery Procedure OP-902-006 Loss of the Main Feedwater Recovery Procedure OP-902-007 Steam Generator: Tube Rupture Recovery Procedure OP-902-008 Safety Function Recovery Procedure Note:
The inspection team also reviewed the Technical Guidelines for each procedure listed above.
2.
PGP Administrative and Validation and Verification Procedures UNT-01-012 Emergency Operating Procedure.
Development, Review and Approval, Revision, and Deletion 3.
E0? Training Material and Lesson Plans Reviewed 01-019-00 Operating Instructions:
Development of Operation Procedure Administration Group.
L581-507-30 Mitigating Core Damage Chapter 7-Gas L584-200-00 Introduction to Function Based E0Ps L584-203-30 Function Based E0Ps L584-302-10 FbEOPs/ Loss of Coolant Accident / Excess Steam Demand Recovery Procedure LS84-303-10 FBEOPs/ Loss of Main Feedwater Recovery Procedure LSS4-304-10 FBEOPs/ Uncomplicated Reactor Trip Recovery Procedure L584-401-00 FBEOPs/ Loss of RC Flow / Loss.of Offsite Power / Natural Circulation Demonstration Recovery Procedure L584-402-10 FBEOPs/ Degraded Electrical Distribution Recovery Procedure L584-403-10 FBEOPs/ Safety Function Recovery Procedure L585-203-10 FBEOPs/ Review and Revision-L586-501-10 FBEOPs/ Review and Revision 2 L587-207-00 FBEOPs/ Review I
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Operations Procedures Reviewed Which Were Referenced In E0Ps OP-1-002 Reactor Coolant Pump Operat. ions OP-3-003 Condensate-Feedwater Operations OP-3-010 Blowdown Operating Procedere OP-5-001 Auxiliary Boiler OP-8-006 Hydrogen Recombiner OP-8-010 Containment Hydrogen Analyzer OP-10-001 General Plant Operations s
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APPENDIX B Technical Review Questions and Answers The following are inspection team questions as a result of reviews of the W3 E0Ps.
In the following responses, the licensee either provided clarification for the deviations from CEN-152, or acknowledged that deficiencies identified by the inspection team and agreed to correct them in the next revision to the E0Ps.
Section 5 of the report provides further discussion regarding some of these items.
1.
OP-902-000, Emergency Entry Procedure Q1:
C.1.B., colons should be periods (generic to immediate acticns).
R1:
The next revision will follow the Writer's Guide and eliminate colons for steps with no substeps or with no list associated with the action.
Q2:
Containment Spray Pump flow should be checked in immediate actions (Step 14).
R2:
This comment will be incorporated in Revision 3.
Q3:
Concerning Steps 2b, 3c, and 4b of Attachment 1, which subcooling indication instruments from QSPDS are used to determine subcooling?
R3:
All available subcooling information should be looked at for comparison.
The training process will emphasize when the use of RVLMS subcooled margin indication would be appropriate.
Q4:
Why does the hierarchy in the entry procedure differ from EPGs?
R4:
In the next revision to the E0Ps, the Immediate Actions will be listed in the order of the related safety functions of CEN-152, 2.
OP-902-001, Uncomplicated Reactor Trip Recovery Procedure Q1:
Page four, Paragraph E.1 caution - No timeframe designated for completing one set of the SF Status Checklist.
"Continuously" is too vague a word.
Once per 10-15 minutes should be a goal and the completion time logged.
R1:
Operator training is used to determine the actions required for continuously monitoring safety functions.
Logging on a time interval is cumbersome for the operators.
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3.
OP-902-002, Loss of Coolant Accident Recovery Procedure
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0'. : b.Ny is Core Exit Temperatures'(CET) or Reactor Vessel Level Ho.)itoring System'(RVLMS). thermocouple TC not'used for Note.57 CET is considered for next note.
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R1:
CET temperature will be specified in Note 5 in the'next revision.
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Step-8 - Since~the purpose of Step 8 is to isolate the leak,'why initiate SIAS? Technical Guide does not explain this.
R2:
SIAS provides isolation functions.
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Q3:
Step 8 purpose is not clear.
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R3:
Step 8 will be reworded ~to include the purpose of the step.
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Q4:
Step-21c should identify whether CETs or RWLMS indications should be used.
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R4:
CETs will be spccified in the next revision.
Q5:
Step 17 is two sentences with one idea.
Should have one sentence
using "refer to."
R5: Will combine sentences in next revision.
Q6:
Step 21c and 52d should refer to CET.
Q7:
Step 57 - refer to CEN-152, Step 40A, Why was information in 40A
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omitted?
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R7: Will be addressed in Revision 3 of E0Ps.
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Q3:
Step 91 - H2 concentration of 3 percent is less conservative then
CEN-152 whici uses 2 percent.
Why wait 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to turn on Hydrogen recombiner? What is the basis for the difference in Hydrogen
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concentration and the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time?
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R8:
Reference FSAR, Section 6.2.5.3, for discussion of the system and the
3 percent criteria.
Two percent is a bracketed number in CEN-152, i
i.e., generic, whereas 3 percent is the Waterford 3 plant specific
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number.
Hydrogen recombiners will be started at Hydrogen i
concentration of 3 p.!rcent or 24-hours, whichever comes first.
i Twenty-four hours is more (Unservative that CEN-152 or 3 percent
criteria.
4.
OP-902-003, loss of Forced Flow Recovery Procedure
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Q1:
Step 9 of OP-902-003 should be moved to an approp?iate place.
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R1: 'Will be moved in.next revision of-EOPs.
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5.
-OP-902-004, Excess Steam Demand Recovery Procedure Q1:
Sampling activity S/Gs for' activity is not.early enough in'the procedure because it,will take Chemistry a while to'do this.-
OP-902-004 calls for this at Step 35, Page 15, while CEN-152 calls for it in Paragraph 3.
R1:
Substep 35c will be moved between Step 12 and 13 in next revision.
6.
OP-902-005,
Dear,
ded Elf:ctrical Distribution Recovery Procedure Q1:
Step 17 of OP-902-005 does not open PW 9017 A&B to~ supply potable water.
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R1: Will be incorporated in next revision of E0Ps.
7.
OP-902-006, Loss of Main Feedwater Recovery Procedure Q1:
Step 4 should be moved to' Step 8 to provide time to verify loss of MFW and trip RCP 1A and 2A before kick out to STRP.
R1:.Will be incorporated in next revision of E0Ps.
8.
OP-902-007, Steam Generator Tube Rupture Recovery Procedure Q1:
Need Plant specific curves for two RCP operation.
The procedu.e should address NPSH.
(comment is for all E0Ps that refer to RCP operation)
R1:
Plant Engineering to provide.
Q2:
Step 36 should reflect that combinations may be used-to cool SG U tubes for V tube voiding.
R2: Will incorporate in next revision of EUPs.
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i APPENDIX C
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Specific Examples of Human. Factor'sLDiscrepancies 1.
Differences in Operator's Interpretation of E0P Implementation Operators differed in their understanding and/or execiution of the E0Ps'in following ways:
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The importance of.EOP attachments relative to the body of the E0P.
What to do if items in the attachment lists are not verified.
- Placekeeping methods:
some operators used.the checkoff spaces, others did not.
- Order of executing E0P steps:
For example, if a step reqd red a certain parameter value that had not yet been attained, some operators skipped the steps and came back to it later; others waited for the parameter before continuing with the E0P.
- Interpretation of "refer to," "commence," and other references.
Some operators performed the referenced procedure in parallel with the current c0P; others temporarily exited the current E0P to perform the referenced orocedure.
- Interpretacion of orange dots on control room instrument labels.
2.
E0P Documenta @
a.
E0P 002, LOCA, Caution 13.d. "00 NOT rely solely on RVLMS when RCPs are operating, use more than one instrument to verify core is covered." Statement should be reversed, rewritten, or punctuated differently to highlight the recommendation in the second half, b.
All E0Ps.
Colons used to introduce the name of an attachment or procedure should be changed to commas or deleted as appropriate.
Commas should also follow the named attachment or procedure.
c.
E0P 002, LOCA, Step 21.
"IF NO RCPs are operating AND Reactor Coolant System Subcooling Margin i:28 F, THEN Check Two Phase Natural Circulation AND Break Heat Removal by the following":
This step identifies two antecedent conditions that must be satisfied and two consequent actions that must be taken.
It is a complex logic statement that presents more than a simple idea.
d.
E0P 004, ESDE, Step 47.
This step incluues a series of substeps that continue onto the subsequent page, beginning with an OR.
At the bottom of the first page, it is neither clear that the step continues l
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nor that the preceding substeps are to be used disjunctively (with
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forthcoming substeps),
t E0P 008, SFR, Page 5 of 176, Step 5.
This is an action step embedded
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within cautions, notes, and references to foldouts.
It is not clear why this step was placed in this location in the procedure.
It could easily be missed by operators.
f.
E0P 002, LOCA, Step 30.b.
Operators are required to maintain Emergency Feedwater (EFW) level between 68 percent and 71 percent wide range.
This difference can only be seen clearly on the QSPDS, which is not referenced in the E0P step, g.
E0P 002, LOCA, Step 14.
"If ALL Safety Injection (SI) termination criteria (Step 13) are satisfied, THEN. throttle OR stop SI FLOW one train at a time AND stop charging pumps as necessary to control pressurizer level 33 percent to 60 percent." This step is complex, consisting of more than one required action.
It also lacks sufficient detail because it does not state how flow should be stopped:
should the pumps be stopped, the valves closed on both or just one train? Further, "throttle" should probably be "reduce" in this step.
h.
E0P 002, LOCA, Step 15.
This step states to "reinitiate SI flow."
"Reinitiate" in this step means to start the pumps and open the valves; these should be specified in the step.
i.
E0P 004, ESDE, Step 47.b, t0P 002, LOCA, Step 58.b.
"Stop any depressurization." More detail should provide the necessary guidance on exactly how the depressurization should be stopped.
j.
E0P 004, ESDE, Note 5.
"...PRESSORIZER TEMPERATURE WATER" 5.
be changed to read "Pressurizer Water Temperature."
k.
E0P 001, Steps 8.a.2, 8.b.1. "Emergency Borated 190 ppm," and
"Emergency borated 321 ppm."
Both steps should include "an additional" betwecn horated and the numerical values to ensure operators do not erroneously borate only up to 190 ppm and 321 ppm.
1.
E0P 001, Step 21.1.
"Calculate and adjust Volume Control Tank blend rate." Additional detail should be provided regarding the blend rate.
m.
E0P 003, Attachment 1.
The Note at the top of the page begins with
"These valves..." implying that the Note is applicable to all listed valves, when it actually only applies to the last two.
3.
Control Room Deficiencies a.
E0P 00^, LOCA, Steps 40, 43, 44, and other E0Ps.
Operators are required to distinguish between containment pressures reading 17.1 psia vs. 17.7 psia.
This difference cannot be accurately
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I 3-perceived on the two scales (CP-7).
The scales display identical orange setpoint bands, both. marking 17.1 although the setpoints for
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the two parameters are'different:
17.1 vs. 17.7.
b.
E0P 004, SF Status Chec'klist, 6.b, and other' E0Ps.
The checklist instructs operators to verify that containment spray _ flow is i:1950 gpm. The illustrated setpoint on the Containment Flow instrument, however, is incorrectly set at 1850 gpm.
This indication appears on Cp-8'(safeguards panel).
c.
E0P 002, LOCA, Step 41.d.
The step directs operators to' place:
switches to the "NORMAL" position.
The actual' switch, however, does-not have a NORMAL position.
d.
OP-3-003, Condensate Feedwater, Page 45, Caution.
This procedure references a valve irethe control room, AFW-125, Pressure Relief Valve.
However, the valve controller indicator is not labeled in the control room (or simulator),
e.
E0P 002, LOCA. Step 10.a and other E0Ps.
The operator checks the Steam Bypass Controller, which consists of two adjacent scales.
The lef t scale is the parameter value, and the right one is the setpoint value.
The scales are not respectively labelled, so the operator must remember or deduce which scale is which.
f.
Recorders on the safeguard panel and other panels were difficult to read because:
Increments were not easily readable.
- Many were dual parameter recorders.
Arrows were too far from the pointed-to value.
- Pen lines sere thin.
- Pen lines could overiap, making them indiscernid h.
- Arrows could overlap, completely obscuring one another.
- Measurement units were not clearly labeled.
4.
Local In-Plant Deficiencies i
a.
E0P 002, LOCA, Step 33 b.1..The procedure directs operators to locally open the Auxiliary Boiler (AB) Steam Supply to MFW Pump A
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Isolation valve.
This valve is located approximately 15 feet above the scaffolding.
No ladder is readily available.
b.
E0P 002, LOCA, Step 33 c.1.
The procedure required operators to
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locally open the AB Steam Suppiy to MFW Pump B Isolation valve.
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valve is approximately 8 feet above the scaffolding.
Its label is completely obscured.
c.
E0P 005, Steps 24.a, b, and c.
The operator is instructed to locally open one of three Main Condenser Vacuum Breaker valves.
All three valves are totally inaccessible, located about 15 feet high and behind the feedwater heaters.
Operators must climb onto and around pipes to reach the valves.
d.
E0P 005, Step 23.b.
Operators are directed to locally verify that the Seal Oil System is operating.
During a walkdown, however, no local indications were found.
e.
E0P 003, Step 27.a.
Operators must locally open the Gland Steam Auxiliary Steam Supply valve, which is inaccessible and requires the operators to climb a ladder.
f.
E0P 003, Step 27.c.
"Verify Gland Steam Header Pressure 290 psig."
The value is not labeled as such.
It only had a label with the component number.
The valve indication reads in "PSI" rather than
"PSIG."
g.
E0P 003, Step 27.f.
Operators must verify that the MFW Pump Turbine Gland Seal Steam Pressure Controller "maintains 4 psig." The controller is not clearly labeled.
The unit is labeled "psi."
It is not possible to visually perceive exactly 4 on the scale.
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l APPENDIX 0 i
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Verification / Validation Review Comments f
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Specific comments on the cuntrol room walkdowns and the review of the l
validation programs are provided below.
The licensee committed to correct
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these weaknesses or review specific steps for potential changes.
Section 4 of this report provided further discussions regarding verification and validation.
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1.
General a.
Labeling (1) Motor control center A 3115 and B 3115 are referred to in i
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Step 78 of OP-902-007 as 311AS and 31185.
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(2) The tag for the blowdown demin air operated outlet dump valve to i'
regen waste tank (80512) is missing from.the local panel.
(3) Valve controller 1 indicator for AFW-125 is not labeled in the i
control room and the simulator.
i (4) Valve 803401 does not have an identification tag.
(5) Valve numbers are missing for Valves AFW 125 and BD 1038 in the
j simulator.
l (6) Valve IB (512268) is labeled 51266B in the simulator.
b.
Valves Hard to Reach The following valves referred to in the E0Ps that are high off the floor with no permanent ladder or platform available for an operator j
to stand on while operating the velves.
The licensee has agreed to review these locations and determine if ladders are stored close i
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enough to the valve location or whether ladders should be moved into the area.
(1) OP-902-007, Step 46.b.
Main Steam to Gland Steam Isolation MS 148.
(2) OP-902-002, Step 47.b.1.
AB Steam supply to MFW Pump A l
Isolation ABS 3144A.
(3) OP-902-002, Step 33.b.2.
Main Steam to MFW Pump A Stop Valve MS215A.
(4) OP-902-008, Step E3.5.a and b (page 42) A and Charging Header to Hot Leg Injection Headers.
B Isolation Valves SI 504 and SI 505.
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OP-902-002, LOCA
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Steps 69a and 83a.
The condensate storage pool 1make up valve No. C-
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MU141 is missing from the procedure.
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OP-902-007, SGTR
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Step 43A refers the operator to OP 3-010 Blowdown Operation..
Step 6.10.12.2 of OP-3-010 has to operator p'sition the blowdown
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j denim acid and caustic pump control switcher.to "0FF."
This system is not in use and consideration should:be given to removing the controls from the panel and the step from the procedure.
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b.
Step 45 has the operator start the AB and refers to Procedure OP-5-001.
Presently, the licensee is installing a new temporary AB which will be used while the permanent AB is being retubed.
The licensee is reviewing OP-5-001 and may issue a temporary procedure for the new boiler.
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Step 46c instructs the operator to check gland steam pressure between 1-5 to 3 psig.
This pressure appears lower than is presently being
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APPENDIX E List of Abbreviations AB Auxiliary Boiler AFW Auxiliary.Feedwater (not emergency)
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CEN-152 Combustion' Engineering Emergency Procedure Guidelines CET Core Exit Thermocouple CP Control Panel CRS Control Room Supervisor EFW Emergency Feedwater E0P imergency Operating Procedure EPG Emergency Procedure Guidelines ESDE Excess Steam Demand Event LOCA Loss of Coolant Accident MFW Main Feedwater NPO Nuclear Plant Operator NPSH Net Positive Suction Head ORP Optimum Recovery Procedure.(Event Based)
PORC Plant Operations Review Committee QSPDS Qualified Safety Parameter Display System RCP Reactor Coolant Pump RVLMS Reactor Vessel Level Monitoring System SFRP Safety Function Recovery Procedure SF Safety Function SG Steam Generator SI Safety Injection SIAS Safety Injection Actuation System SS Shift Supervisor STA Shift Technical Advisor W3 Waterford 3