ML20235R342
| ML20235R342 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 01/25/1989 |
| From: | Haughney C, Konklin J, Vandenburgh C Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20235R333 | List: |
| References | |
| 50-324-88-200, 50-325-88-200, NUDOCS 8903030263 | |
| Download: ML20235R342 (35) | |
See also: IR 05000324/1988200
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U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
Division of Reactor Inspection and Safeguards
Report Nos.:
50-325/88-200 and 50-324/88-200
Docket Nos.:
50-325 and 50-324
Licensee:
Carolina Power and Light Company
P.O. Box 1551
Raleigh, NC 27602
Inspection At:
Brunswick Steam Electric Plant, Units 1 and 2
Inspection Dates:
September 26 through October 7, 1988
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Team Leader:
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C. A. VanDenburgh, Senior Operations
Date Signed
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Engineer, NRR
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Team Members:
G.T. Hopper, Region II
P.R. Farron, Nuclear Engineers and Consultants
D.H. Schultz, Comex Corporation
J.F. Hanek, EG&G Idaho, Incorporated
W.E. Gilmore, EG&G Idaho, Incorporated
Other NRC Personnel Attending Exit Meetings:
J. Konklin, Section Chief NRR;
C. Julian, Branch Chief, Region II; B. Buckley, Project Manager, NRR; and
W. Ruland, Senior Resident Inspector.
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Reviewed By:
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ames E. Konklin, Chief
Ddte Signed
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Special Team Support
& Integration Section, NRR
Approved By:
(164/4t(
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Unarles p. Haughney, Chief
Ddte Signed
Special inspection Branch, NRR
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8903030263 890223
ADOCK 03000324
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Scope:
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From September 26 through October 7,1988 an NRC inspection team conducted an
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inspection of the Emergency Operating Procedures (E0Ps) for the Brunswick Steam
Electric Plant (BSEP), Units 1 and 2.
BSEP Units 1 and 2 are General Electric
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BWR-4 plants with Mark I containments.
The objective of the inspection was to
determine if the E0Ps (1) were technically correct (2) could be physically
carried out in the plant, and (3) could be performed correctly by the
operators.
The inspection team compared Revision 4AF of the BWR Owner's Group (BWROG)
Emergency Procedure Guidelines (EPGs) to the Plant Specific Technical
Guidelines (PSTGs); compared the PSTGs to the E0Ps; reviewed the calculations
performed to develop the plant specific curves, values and setpoints utilized
in the E0Ps; performed a plant walkthrough of all the E0Ps and the Local
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Emergency Procedures (LEPs) and Supplemental Emergency Procedures (SEPs)
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referenced by the E0Ps; observed a simulation of four emergency scenarios using
the plant-specific simulator; performed a human factors review of the
procedures and plant operations; interviewed licensed and non-licensed
personnel who utilize the E0Ps; and reviewed the primary containment venting
procedures.
Results:
The inspection was based on a draft of the E0Ps which were in the final stages
of development and were expected to be implemented on December 15, 1988.
The
draft E0Ps incorporated Revision 4AF of the BWROG EPGs.
They corrected
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deficiencies which had been identified during an Operational Safety Assessment
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and a Probabilistic Risk Assessment based inspection [ Inspection Reports
50-325(324)/88-19 and 50-325(324)/88-11] performed by Region II to evaluate the
E0Ps presently in use.
The inspectors were impressed with the scope of the corrective actions taken in
response to the deficiencies identified during the previous inspections and
with the licensee's controls for the development of the E0Ps. All of the
previous deficiencies had been corrected, and the development process was well
documented and defined.
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The BSEP E0Ps were developed as post-trip recovery procedures and integrated
the post-trip operator actions with the required actions of the EPGs and the
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station blackout actions.
The E0Ps provided a high level of detail and
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prioritized the operators' actions based on the significance of the event. As
a result, however, the E0Ps had a significant potential to delay the required
accident mitigation actions as post-trip recovery actions were accomplished.
The inspection team concluded, based on the simulator scenarios, that the
required EPG actions could not be accomplished in a timely manner without the
direct involvement of both the shift foreman and the shift technical adviscr to
read and perform the E0P action steps. The active participation of both these
individuals was not in accordance with the licensee's administrative
instructions, but was considered by the team to be an adequate method of E0P
accomplishment.
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The inspection team determined that the draft E0Ps did not in every instance
represent an accurate incorporation of the BWROG EPGs and would not adequately
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assure the successful accomplishment of all specified actions because several
procedures had a low probability of success and several calculational errors
were identified.
Several of the inspection teams' concerns affected the E0P3
which were presently implemented. The licensee was requested to take innediate
action to evaluate and correct these operational concerns.
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TABLE OF CONTENTS
EMERGENCY OPEP.ATING PROCEDURE INSPECTION at
Brunswick Steam Electric Plant, Units 1 and 2
(Inspection Reports 50-325/88-200and50-324/88-200)
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1.0 INSPECTION 0BJECTIVE.........................................
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2.0
BACKGR0VND.......................................
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3.0 DETAILED INSPECTION
FINDINGS.................................
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3.1 Emergency Operation Procedure (E0P) Program Evaluation..
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3.1.1
E0P Development..................................
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3.1.2 Licensee Verification and Validation of E0Ps.....
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3.1.3
E0P Operator Training............................
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3.1.4 Maintenance of E0Ps..............................
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3.1.5 Quality Assurance Involvement in PSTG
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Maintenance......................................
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3.1.6 Licensee Response to IE Information Notice 86-64.
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3.2 E0P P rocedu re Ve ri fi ca t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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3.2.1
EPG/PSTG Comparison..............................
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3.2.2 PSTG/EOP Comparison..............................
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3.2.3 Calculation Review...............................
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3.2.4 Adequacy of Writer's
Guide.......................
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3.2.5 Writer's Guide Implementation....................
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3.3 E0P Validation Using Plant Walkthroughs.................
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3.3.1 Technical Adequacy of Procedures.................
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3.3.2 Availability of Special Tools and Equipment......
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3.3.3 Station Material
Condition.......................
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3.3.4 Reactor Building Accessibility...................
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3.4 C0P Validation Using Plant Simulator....................
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3.4.1
Scena rio Des c ri pti on. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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3.4.2 Limitations of the Plant-Specific Simulator......
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3.4.3 Observations and Conclusions.....................
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3.5 Operator Interviews.....................................
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3.5.1 Observations and Conclusions.....................
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3.6 Prima ry Contai nment Venting Provi sions. . . . . . . . . . . . . . . . . .
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4.0 MANAGEMENT EXIT MEETING......................................
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Appendix A - PERSONNEL C0NTACTED..................................
A-1
Appendix B - DOCUMENTS REVIEWED...................................
B-1
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1.0 INSPECTION OBJECTIVE
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A special team inspection reviewed the licensee's Emergency Operating
Procedures (E0Ps), operator training and plant systems in accordance with NRC
Temporary Instruction (TI) 2515/92 to accomplish the following objectives:
1)
Determine whether the E0Ps conformed to the BWP Owner's Group (BWROG)
Emergency Procedure Guidelines EPGs) and were technically correct for the
BrunswickSteamElectricPlantg{BSEP), Units 1and2.
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Assess whether the E0Ps could be physically carried out in the plant using
existing equipment, controls, and instrumentation, under the expected
environmental conditions.
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Evaluate whether the plant staff could correctly perform the E0P actions
in the time available.
2.0 BACKGROUND
Following the Three Mile Island (TMI) accident, the Office of Nuclear Reactor
Regulation (NRR) developed the "TMI Action Plan," (NUREG-0660 and NUREG-0737).
Item I.C.1 of this plan required licensees of operating plants to reanalyze
transients and accidents and to upgrade E0Ps.
In addition, Item I.C.9 of the
plan required the NRC staff to develop a long-term plan that integrated and
expanded efforts for the writing, reviewing, and monitoring of plant
procedures.
NUREG-0899, " Guidelines for the Preparation of Emergency Operating
and describes the use of a Procedures Generition Package (PGP) pgrading E0Ps,
Procedures," represents the NRC staff's long-term program for u
to prepare E0Ps.
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The licensees formed four vendor owners groups corresponding to the four major
reactor vendor types in the United States: Westinghouse, General Electric,
Babcock & Wilcox, and Combustion Engineering. Working with the vendor
companies and the NRC, the owner's groups developed generic procedures that set
forth the desired accident mitigation strategy.
For General Electric plants,
the generic guidelines are referred to as the BWR0G EPGs. These guidelines
were to be used by the licensees in developing their PGPs.
Generic Letter 82-33, " Supplement I to NUREG-0737 - Requirements for Emergency
Response Capability," required each licensee to submit to the NRC a PGP which
included, (1) Plant Specific Technical Guidelines (PSTGs) with justification
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for safety significant differences from the BWROG EPGs, (2) a Plant Specific
Writer's Guideline (PSWG), (3) a description of the program to be used for the
verification and validation of E0Ps, and (4) a description of the training
program for the upgraded E0Ps. The generic letter required the development of
plant-specific E0Ps which would provide the operators with directions to
mitigate the consequences of a broad range of initiating events and subsequent
multiple failures or operator errors.
In addition, the upgraded E0Ps were
required to be symptom-based procedures which would not require the operators
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to diagnose specific events.
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Although various circumstances caused long delays in achieving NRC approval of
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many of the PGPs, the licensees have all implemented their upgraded E0Ps.
To
determine the success of this implementation, a series of NRC inspections was
performed to examine the final product of the program - the E0Ps.
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Representative samples of each of the four vendor types were selected for
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review by four inspection teams from Regions I, II, III and IV.
An additional 13 inspections were identified at facilities with General
Electric Mark I type containments. These inspections were conducted by the
Office of Nuclear Reactor Regulation and included a detailed review of the
primary containment venting provisions of the E0Ps.
This inspection is the
final inspection in this series.
3.0 DETAILED INSPECTION FINDINGS
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3.1 Emergency Operating Procedure (EOP) Program Evaluation
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3.1.1
E0P Development
A Confirmatory Order dated February 22, 1984, identified that the licensee had
submitted a PGP on August 17, 1983, and implemented upgraded E0Ps.
The PSTG
submitted and the E0Ps currently implemented at the facility were based upon
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The inspection team reviewed a draft version of the E0Ps which were based upon
Revision 4AF of the BWROG EPGs.
This revision incorporated a revised accident
mitigation strategy and calculational methods which were approved by the NRC in
a generic safety evaluation report (SER) issued on September 12, 1988.
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inspection team reviewed the draft E0Ps because the licensee was in the final
stages of implementing this revision and had scheduled full implementation by
December 15, 1988.
Although the inspection was based upon the draft E0Ps, the
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inspection team verified whether identified deficiencies affected the approved
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ECPs.
Two operational concerns were identified and are discussed in Sections
3.2.1.1 and 3.2.1.2 of this report.
Both the currently implemented E0Ps and '.he draft E0Ps had been developed in
flowchart format with the post-trip recovery actions and the station blackout
actions integrated with the steps of the BWROG EPG accident mitigation
strategy. The post-trip recovery actions are event-based actions which are
normally provided in separate procedures and are not appropriate for the
symptom-based E0Ps.
The BWROG EPGs and the SER indicated that additional
auxiliary event-specific procedures intended for use in conjunction with the
symptomatic procedures must not contradict or subvert the symptomatic operator
actions specified in the BWROG EPGs.
The inspection team was concerned that the inclusion of the event-based actions
into the E0Ps delayed the accomplishment of the actions directed by the BWROG
EPGs, had the potential to result in incorrect event diagnosis, and affected
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the ability of the operators to implement the E0Ps and thereby respond to the
emergency in a timely manner. As discussed in Section 3.4.3.1, the simulator
scenarios demonstrated that the shift foreman could not implement the E0Ps, as
required by the licensee's administrative procedures, without the assistance of
the shif t technical advisor to directly monitor and control the specified E0P
actions involving primary containment and radiological release control.
Although operation in this manner was not in accordance with the administrative
procedures, the inspection team concluded that the operating crew could
implement the specified E0P actions to shutdown the reactor and return the
plant to a safe, stable condition. However, the inspection team identified
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several examples as a result of this method of implementation, in which
specified E0P actions were not accomplished or were misinterpreted because the
shift foreman and the STA were involved in separate areas of the E0Ps and did
not have the opportunity to consult and review each others actions.
The inspection team identified the following additional examples in which the
E0Ps included event-based actions not related to post-trip recovery actions.
1)
Path-2, steps 35, 60 and 170, precluded the use of the feedwater or
condensate system for reactor pressure vessel (RPV) injection if the
feedwater conductivity was greater than 0.3 mmhos. This was an
event-based action for condenser tube leakaoe which potentially delayed or
prevented recovery from a low RPV water level condition.
2)
Primary Containment Control Procedure, steps PC/P-19 through 22, were
event-based actions for recirculation pump seal failure which were not
related to primary containment control.
3)
In the Radiological Release Control Procedure, all the steps in the five
flowpaths below step RR-6 were event-based actions for identification and
mitigation of primary leakage. Although these steps were necessary in the
event of a primary leak, they wv.e not specified in the BWROG EPG for the
response to a radiological release.
Further licensee action is necessary to ensure that the E0Ps do not contain
event-based actions and to implement the E0Ps in a manner consistent with the
administrative procedures.
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In addition to including event-based actions in the E0Ps, the licensee
developed the E0Ps with a high level of detail and complexity.
The inspection
team was concerned that the additional detail and unnecessary complexity
represented by the following examples, had the potential to delay the
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operator's response to an actual emergency.
Further licensee action'is
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necessary to reduce the level of complexity of the E0Ps.
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1)
Primary Containment Control Procedure, step C.9.e (1), and section 1,
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included reference to the head spray system, which was no longer
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applicable because of a plant modification.
The reference should be
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deleted.
2)
Primary Containment Control Procedure, step PC/M-4, indicated that the
hydrogen monitor readings must be compensated for primary containment
conditions in accordance with operational procedure OP-24.
In practice,
as evidenced by the simulator scenarios, the operators did not consult
OP-24 to determine correction values and there was inadequate time to
perform these calculations.
3)
Path-2 and Path-3 provided multiple steps for initiating suppression pool
cooling. As demonstrated in the simulator exercises, the operators placed
suppression pool cooling into operation without working through each of
these steps.
By contrast, the SP/T path of primary containment control
for operating suppression pool cooling provided direction to the operator
using only a single step.
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4)
Path-2 was entered following a reactor scram from a condition where the
reactor mode switch was not in RUN. The power level at this condition is
anticipated to be less than approximately eight percent power.
Steps 12,
13 and 17 of this procedure represented actions for tripping the main
turbine, ensuring that turbine auxiliaries started, and tripping the
heater drain pumps. These actions were not appropriate for this power
level and diverted the operators attention from more important activities.
5)
Path-3, step 26, required the operator to set the reactor re irculation
pump speed controllers to minimum; however, this step was not required for
the pump logi: involved.
6)
Radiological Release Control Procedure, steps RR/PB-9 through 11,
identified core cooling systems which -ay be the source of a primary leak;
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however, these systems were not located in the turbine building and were
therefore not applicable.
7)
Path-3, steps 61 and 85, and Path-2, steps 61 and 85, provided redundant
action steps for RPV pressure control.
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Throughout the E0Ps, there were several examples in which multiple action
steps were used to accomplish a single action.
For example, in each leg
of the Primary Containment Control Procedure, the generic monitor and
control steps of the PSTG were restated in one step and the specific
direction on how to accomplish the referenced action was provided in the
subsequent step.
In addition, if a scram was required during the
performance of the Primary Containment Control Procedure, two action steps
were required. The first stated that a reactor scram was required and the
second executed the scram.
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Path-2, steps 80, 90, 91, 99 and 100, and Path-3, steps 79 through 84,
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provided detailed steps for the operation of the suppression pool cooling
system which were more appropriate for operational procedures.
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addition, these actions should have been covered in a single action step
as accomplished by procedure SP/T-3.
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3.1.2 Licensee Verification and Validation of E0Ps
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NUREG-0899, section 3.3.5, indicated that after E0Ps are written they must
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undergo a process of verification and validation. This process was used to
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establish the accuracy of information and instructions, to determine that the
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procedures could be carried out accurately and efficiently, and to demonstrate
that the procedures were adequate to mitigate transients and accidents.
Both
technical and human engineering adequacy were required to be addressed in the
review process.
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Administrative Instruction AI-95, " Verification and Validation Program for EPG,
Revision 4, based Emergency Operating Procedures," defined the program for
verification and validation of the E0Ps at BSEP.
BSEP administrative
procedures (Volume 1, Book 1, sectic' 5.7.4.1, paragraph A.III.c) required that
all E0P changes receive the review and approval of the E0P Review Committee.
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The membership of the committee included operations, quality assurance,
technical support, off-site nuclear safet.;, and the licensed training
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lhe verification and validation required for implementation of Revision 4AF of
the BWROG EPGs was identified in an untitled supplement to AI-95. The licensee
indicated that this methodology was reviewed and approved by the E0P Review
Committee on December 14, 1987.
The team was concerned that the specific
methodology for the verification and validation of the substantial changes
represented by the incorporation of Revision 4AF of the BWROG EPGs had not been
specifically identified and approved by the E0P Review Committee.
Further
licensee action is necessary to ensure that the verification and validation
program approved by the E0P Review Comittee is successfully completed prior to
the implementation of the draft E0Ps.
The inspection team's review of the verification and validation program
determined that a mechanism existed for ensuring that all portions of the E0Ps
could be validated using either the plant-specific simulator, plant
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walkthroughs, or desk top reviews. The preferred validation method was to
perform the E0Ps on the plant simulator.
In instances in which the E0P steps
exceeded the capability of the simulator, a combination plant walkthrough and
desk top review was employed.
In order to ensure that the full complement of
E0Ps were validated, a list of functional objectives to be accomplished by
performing the E0P was developed. The licensee defined the functional
objective of each E0P step and developed exercises to satisfy each functional
objective. The exercises were performed on the plant simulator or by some
combination of simulator exercises and plant walkthroughs.
Problems idantified
during the demonstration of the functional objectives were resolved by the E0P
revision process as described in Al-95.
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The inspection team was concerned that the identified verification and
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validation methodology did not indicate that appropriate consideration had been
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given to the necessity of performing all steps of the E0Ps on the plant
simulator or in table top exercises rather than evaluating them through plant
walkthroughs. Based on the inability of the simulator to accurately model RPV
level and decay heat (previously identified by the licensee and discussed in
Section 3.4.2), it is extremely important to ensure that all steps of the E0Ps
would be effective in fulfilling the actions intended by the BWROG EPGs.
Further licensee action is necessary to ensure that all E0P steps are validated
on a simulator or by an equally acceptable methodology.
3.1.3
E0P Operator Training
A review of the licensee's training program was conducted to determine the
adequacy of operator training prior to implementation of Revision 4 of the
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EWP0G EPGs.
The inspection team compared the requirements of NUREG-0899, the
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Procedures Generation Package (PGP), and the operator training program
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developed for Revision 4.
The PGP contained a detailed description of the initial operator training which
was conducted prior to the initial implementation of the upgraded E0Ps. The
extent of the initial operator training met the requirements of NUREG-0899,
section 3.4
Although the PGP did not specify the operator training require-
ments for revisions to the E0Ps, the licensee required all revisions to be
performed in accordance with Administrative Instruction Al-95, " Verification
and Validation Program for EPG, Revision 4, based Emergency Operating
Procedures." This procedure required that an E0P Review Comittee review
proposed E0P revisions and determine the implementation requirements.
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The inspection team was concerned that these instructions contained no guidance
concerning the scope of operator training required prior to implementation of
revisions to the E0Ps.
Nevertheless, the licensee developed and incorporated a
satisfactory training program into the E0P verification and validation process.
This program was outlined in an untitled supplement to AI-95. The licensee
recognized the need for ongoing operator training on the E0Ps and had
accomplished this goal with periodic licensed operator retraining and the
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Operator Real Time Training Program described in Operating Instruction 01-33.
This latter program served to complement the annual operator retraining by
accomplishing immediate training needs on a continuing basis.
Interviews with training supervisors indicated that two of the three phases of
training had been completed prior to the time of the inspection. Phase IA was
completed in April 1988 and consisted of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of classroom instruction on
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the content and use of the new E0Ps.
Phase IB was completed in June 1988 and
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consisted of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> of classroom instruction cambined with 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of
simulator training designed to exercise the major branching points within the
E0P flowcharts.
Phase 11 training was conducted in September 1988 and involved
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four hours of classroom instruction followed by four hours of simulator
exercises.
This brief session served to update operators on changes made to
the E0Ps since completion of Phase IB training.
The final phase of training
(Phase III) was accomplished in December 1988 and served as the final operator
training update prior to implementation of the revised E0Ps.
3.1.4 Maintenance of E0Ps
During the review of the PSTGs and the E0Ps, the team determined that the PSTGs
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and BWROG EPG Appendix C calculations were being maintained up-to-date as a
basis document ar.d were properly controlled as a plant record by the document
control center.
The E0P calculations based on Revision 2 of the BWROG EPGs
were reviewed and documented in a study entitled ENSA 84-038, "EOP Numerical
Limits and Graphs," and the PSTG was contained in Operating Instruction 01-37,
" Preparation and Review of the Plant Specific Technical Guideline for EPG
Revision 2."
The E0P calculations based on Revision 4 of the BWROG EPGs were
under review by the Nuclear Engineering Department and were scheduled to be
published and the PSTG documented in a similar manner.
3.1.5 Quality Assurance Involvement in PSTG Maintenance
NUREG-0899, section 4.4, indicated that as a primary basis of the E0Ps, the
PS1Gs should be subject to examination under the plants' overall quality
assurance (QA) program.
Because the licensee was responsible for ensuring that
the PSTGs were accurate and up-to-date, the review and control of the PSTGs
shculd be included in the established QA program.
The licensee indicated that QA surveillance 86-067 was performed in December
1986 as a result of E0P development deficiencies identified by the NRC in IE
Information Notice (IEN) 86-64.
In addition, QA Audit QAA/0021-88-05, was
performed in August 1988 on Revision 4 of the E0Ps and identified one follow-up
item concerning justification 'of BWROG EPG deviations.
Future audit schedules
included a site QA surveillance, similar in scope to surveillance 86-067,
scheduled for the first quarter of 1989 and annually thereafter.
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3.1.6 Licensee Response to IE Information Notice 86-64
IEN 86-64 was issued on August 14, 1986, followed by IEN 86-64, Supplement 1,
issued on April 20, 1987.
IEN 86-64 alerted the licensee to problems found in
review and audits of Procedure Generation Packages (PGPs) and E0Ps. The IEN
indicated that many utilities had not appropriately developed or implemented
upgraded E0Ps.
In addition, the IEN identified deficiencies in the development
and implementation of each of the four major aspects of the upgrade program.
These deficiencies included undocumented deviations from and inappropriate
adaptation of BWROG EPGs, failure to adhere to the PSWG and the verification
and validation programs, and deficient training programs.
Supplement 1 to IEN
86-64 alerted the licensee's to significant problems that were continuing with
plant E0Ps. Deficiencies were identified in all the major aspects of the E0P
upgrade program.
The licensee's were requested to review the information for
applicability to their facility and consider actions to correct or preclude
similar problems from occurring.
The licensee's evaluation process for IENs was performed in accordance with
Corporate huclear Safety Instruction CNSI-I and On-Site Nuclear Safety
Instruction ONSI-1.
The IENs were reviewed by the nuclear safety coordinator
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and assigned to responsible engineers for evaluation.
IEN 86-64 and Supplement
1 were evaluated by the coordinator and closed because a OA surveillance,
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discussed in Section 3.1.5, had already been initiated and had identified
similar deficiencies. The inspection team concluded that the licensee's
actions in response to IEN 86-64 were satisfactory.
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3.2 E0P Procedure Verification
This portion of the inspection was performed to determine whether the E0Ps had
been prepared in accordance with the BWROG EPGs, the PSTGs, and the PGP.
l
The inspection ccmpared Revision 4AF of the BWR0G EPGs to the PSTGs, and the
PSTGs to the E0Ps.
All differences were evaluated to ensure that safety
significant deviations were identified and that a documented basis existed for
all deviations. A review of selected calculations was performed to ensure that
plant-specific values utilized in the E0Ps were correct and had been performed
in accordance with a documented engineering analysis. Appendix B of this
report lists the procedures reviewed.
3.2.I
FPG/PSTG Comparison
Nine differences were identified between the BWROG EPGs and the PSTGs as
detailed below.
Based on these discrepancies, the inspection team concluded
that the draft PSTGs did not accurately incorporate the guidance of Revision
4AF of the BWROG EPGs. The inspection team identified technical concerns
relating to the measurement of RPV water level, which adversely affected the
I
operator's ability to perform the level / power control procedure, and technical
I
concerns relating to the measurement of primary containment drywell temperature,
which potentially raasked a valid entry condition.
These concerns affected both
the E0Ps which were currently implemented at the facility (Revision 2) and the
draft E0Ps.
In addition, numerous discrepancies were identified in the draft
i
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E0Ps in which the entry conditions of the PWROG EPGs were changed without
sufficient technical justification.
Further licensee action is necessary to
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evaluate and correct the E0Ps presently in use and to ensure that the draft
!
E0Ps accurately incorporate the technical guidance of the BWROG EPGs.
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1)
BWROG EPG Contingency No. 7 provided a methodology to control reactor
power following an anticipated transient without scram (ATWS).
This
methodology involved lowering the RPV water level to the top of active
fuel (TAF) or to the minimum steam cooling water level (MSCWL).
The
licensee implemented these actions in the Level / Power Control Procedure.
BWROG EPG Caution ho. 1 provided operator precautions related to the
nieasurement of RPV water level and the accuracy of various water level
instruments. The licensee implemented these precautions in Caution No. 1
of the User's Guide. The inspection team reviewed the methodology and
precautions for ATWS power level control implemented by the licensee and
identified several undocumented and unjustified deviations which adversely
affected the ability of the operators to control reactor power.
These
deviations involved (1) the equivalency between the instrument zero
indication and the TAF, (2) the restrictions on the use of the wide range
level instruments, and (3) the calibration of the fuel zone level
instrument.
These conditions, detailed in the following paragraphs,
affected the E0Ps which were presently in use at the facility.
a)
Instrument Zero - Based on the location of the instrument taps, the
wide range level instruments (N0-26A and NO-26B) indicate 0 inches
when the actual RPV water level is +8.44 inches above the top of
active fuel (TAF).
In an attempt to simplify the E0Ps, the licensee
,
used this instrument zero indication as the TAF; however, the
licensee did not document this deviation from the BWROG EPGs and did
not evaluate the difference to ensure that there were no adverse
effects on the Level / Power Control Procedure. This deviation was
significant because water levels higher than the TAF result in higher
reactor power levels during an ATWS condition.
Higher power levels
increase the amount of energy deposited in the primary containment
and reduce the time until primary containment venting is t equired.
In addition, a larger primary containment vent path may bt. required
to remove this excess energy. The inspection team also noted that
this condition affected the E0Ps which were presently in use at the
facility.
Further licensee action is necessary to ensure that the
higher power levels resulting from this deviation are technically
acceptable and appropriately documented for the approved and draft
E0Ps.
b)
Wide Range Level Instrument Restrictions - Caution No. 1 in the
User's Guide restricted the use of the wide range level instruments
(N0-26A and NO-268) as a function of level. The caution required
that the instruments not be used when the indicated water level was
below +10 inches (i.e., +18.44 inches actual) on both Units 1 and 2.
In addition, the caution precluded use of the Unit 2 instruments when
the water level was below +40 inches (i.e., +48.44 inches actual)
when conditions indicative of a high energy line break (HELB) were
present.
These restrictions were based upon the location of the
reference le.gs of the wide range instruments and the lack of
temperature compensation methods in the E0Ps.
The +40 inch
precaution was not applicable on Unit 1 because the reference legs
were in a different location.
The licensee had not developed a method to compensate the level
instruments when indication was below +10 inches and did not have a
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method to compensate the instruments during a HELB because
temperature instruments were not installed in the secondary
containment. The level instrument restrictions adversely affected
the performance of the Level / Power Control Procedure because the
operators did not have an accurate level instrument with which to
control the RPV level below an actual level of +18.44 inches or
+48.44 inches. This potentially degraded the control of reactor
power during an ATWS condition and, as such, was an undocumented and
unjustified deviation from the BWROG EPGs. The inspection team also
noted that these conditions affected the E0Ps which were presently in
use at the facility.
Further licensee action is necessary to
evaluate this deviation from the BWR0G EPGs and to provide an
accurate method to control reactor power by means of water level
during the ATWS condition for the approved and draft E0Ps.
c)
Fuel Zone Level Instruments Calibration - The fuel zone level
instruments (N0-36 and NO-37) were calibrated under cold conditions
of 212 degrees F in the reactor building and the drywell, and 0 psig
in the RPV. Under cold conditions, these instruments normally
indicate accurately from -150 to +150 inches. However, this cold
calibration resulted in a wide variance in actual versus indicated
level for the drywell temperatures, RPV pressure, and reactor
building temperature anticipated during an ATWS.
Because no
compensation method was available to the operators, the fuel zone
instruments would be grossly inaccurate under the conditions in which
they will be required to be used.
The following level deviations
would result if the fuel zone indicators were used at 1100 psig
during ATWS conditions in accordance with the Level / Power Control
Procedure. With actual RPV water level at the actual TAF (i.e.,
-8.44" indicated on the wide range instruments), RPV pressure,
reactor building temperature at 200 degrees F, and drywell
temperature in the area of the reference legs as indicated below, the
fuel zone instruments would indicate the following levels.
Drywell Temperature
Indicated Level
l
(degrees F)
(inches)
1
180
a,09
l
200
-61.45
250
57.06
300
-51.94
400
-39.60
500
-23.24
Since both units precluded the use of the wide range level
instruments below an indication of +10 inches, the fuel zone
indicators would be indicating approximately -42 inches below TAF at
the time when they became the only level indicators available.
The inspection team also noted that the E0Ps and associated cautions
did not preclude the use of the fuel zone instruments in preference
to the wide range instruments for water level control.
If the wide
range instruments were not available, the operators were required to
use the fuel zone instruments to control RPV water level. Under
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these conditions, and in the absence of compensation techniques, the
operators would control RPV water level to an indicativa of TAF
(i.e., an indication of 0 inches on the fuel zone instruments),
which would correspond to an actual RPV water level of approximately
+60 inches. Control of reactor power during an ATWS would not be
effective at these elevated levels.
The licensee's failure to provide a method of compensating the fuel
zone instruments for use in conditions other than their calibration
condition effectively prevented their use and had the potential to
adversely affect the performance of the Level / Power Control
Procedure.
This was a significant deviation from the BWROG EPGs
which was not documented or justified.
The inspection team also
noted that this condition affected the E0Ps which were presently in
use at the facility.
Further licensee action is necessary to provide
an effective method of controlling water level under the conditions
when use of the Level / Power Control Procedure is anticipated.
2)
The BWROG EPG drywell temperature entry condition was established at the
drywell technical. specification (TS) limiting condition for operation
(LCO) or the maximum normal operating temperature, whichever was higher.
The PSTG entry condition was set at the primary containment volumetric
average temperature LC0 of 135 degrees. The BSEP TS did not contain a LC0
for drywell temperature.
The PSTG justified this deviation based on the
assuinption that the values for drywell temperature LC0 and primary
containment temperature LC0 were equivalent even though the primary
containment volumetric average included the suppression pool air space in
addition to the drywell airspace.
Because the suppression pool air space
contributed 43 percent to the volumetric average of the primary contain-
ment, the potential existed for the relatively cool suppression pool air
temperature to mask a high temperature in the drywell.
In addition, the
PSTG justification indicated that the normal maximum operating temperature
was lower than 135 degrees; however, there were times throughout the year
when the maximum operating temperature exceeded 135 degrees.
The inssec-
tion team determined that this deficiency also affected the E0Ps whici
were presently in use at the facility.
Further licensee action is
necessary to correct this operational concern.
3)
The BWROG EPG entry conditions for the RPV control guideline were: (1) RPV
water level at the low level scram setpoint, (2) RPV pressure above the
scram setpoint, (3) drywell pressure above the scram setpoint, and (4)
reactor power above the average power range monitor (APRM) down scale trip
for any scram.
The entry conditions in the PSTG deviated from the BWROG
EPCs in that the PSTG entry condition was any plant condition requiring or
causing a scram.
The PSTG justification stated that this conservative
approach permitted execution of any of five scram recovery paths which
would lead the operator to the End Path Procedure where the entry
conditions of the BWR0G EPG would be assessed.
The inspection team was concerned that this methodology delayed essential
operator actions. The potential existed for plant parameters indicative
of an emergency (i.e., the BWROG EPG entry conditions), to remain
unmonitored and therefore uncontrolled pending completion of the post-trip
actions. These post-trip actions were event-based and are normally
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controlled as immediate, memorized actions' of the control room operators.
As discussed in Section 3.1.1, the inspection team was concerned that the
inclusion of these post-trip recovery actions into the E0Ps delayed the
accomplishment of the directed actions of the BWROG EPGs, had the
potential to result in incorrect event diagnosis, and affected the ability
of the operators to implement the E0Ps and thereby respond.to the
i
emergency in a timely manner. The licensee's method of satisfying the
1
BWROG EPG entry conditions and including event-based actions in the E0Ps
was a significant deviation from the BWROG EPGs and had the potential to
adversely affect the satisfactory performance of the E0Ps.
4)
The BWROG EPG entry condition for drywell pressure was the high drywell
pressure scram setpoint. The PSTG entry condition for drywell pressure
was established at the maximum pressure allowed by the plant technical
specifications of 2.0 psig, while the actual scram setpoint was 1.83 psig
+/- 0.076 psig. This deviation was not justified and was potentially
significant because a scram could occur at a high drywell pressure before
the Primary Containment Control Procedure entry conditions were satisfied.
5)
The BWROG EPG entry condition for the Radiological Release Control-
Procedure was limited to an ALERT condition from a radioactivity release
off-site. The PSTG entry conditions were more conservative than the BWROG
abnormal operating procedures (A0Fs) y conditions and actions for several
EPG entry conditions because the entr
were incorporated into the PSTG. As
discussed in Section 3.1.1, these additional actions diverted the
attention of the shift foreman during the simulator demonstration and
increased the complexity of the E0Ps.
6)
BWROG EPG, step C6-3, vented the RPV to permit flooding of primary
containment with a flow path through the RPV.
The specified vent paths
prevented pressurizing the primary containment during the Primary
Containment Flooding Procedure.
PSTG, step C6-2, improperly listed the
reactor head vent valves which vented to the floor of the primary
containment drywell. The vent lines did not accomplish the intent of the
BWROG EPGs because they were only 1/4 inch in diameter and were directed
inside primary containment. The same problem was noted at step C.7.a of
the Primary Containment Flooding Procedure.
7)
The BWR0G EPG entry condition for primary containment hydrogen
concentration was the high alarm setpoint for hydrogen concentration
(i.e., 2 percent). The PSTG entry condition was set at the minimum
detectable hydrogen concentration of 1 percent.
This value was
conservative with respect to the alarm, but relied on the operators to
monitor the concentration in order to identify the entry condition.
During an emergency this entry condition could be missed and could
potentially delay the operator actions required to mitigate the emergency.
8)
BWROG EPG, step C2-1.4, performed an emergency depressurization of the RPV
with other steam-driven equipment if the proper number of safety relief
valves (SRVs) could not be opened. The PSTG did not reference equipment,
such as the reactor feed pump turbines and steam jet air ejectors which
were also available at BSEP as additional steam loads capable of reducing
RPV pressure.
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9)
BWROG EPG, step RC-1, required a manual scran of the reactor if a reactor
scram has not been already initiated.
The corresponding PSTG step
deviated from the BWROG EPGs by deleting this conditional action.
In the
justification for the deviation, the licensee indicated that the
conditional statement was deleted because the flowcharts were entered for
the initial scram and were not re-entered for any subsequent scrams.
The
inspection team was concerned that re-entry into the flowcharts would be
required if plant conditions changed and a new entry condition occurred.
!
Under these conditions, re-insertion of a scram signal was undesirable and
could adversely affect ongoing recovery actions such as alternate rod
insertion techniques.
l
3.2.2 PSTG/EOP Comparison
Four differences were identified in which the PSTGs steps were not accurately
incorporated into the E0Ps and were therefore unjustified deviations from the
Further licensee action is necessary to accurately incorporate
these PSTG steps.
1)
Paths 1, 2, 3, 4, and 5 included conditional action steps which precluded
the use of the feedwater system in the event of high condensate
conductivity.
These actions were not included in either the BWROG EPGs or
the PSTGs. The effect of these steps was to prevent the use of an
available high pressure injection system during a low RPV water level
emergency.
In addition, Path 5 failed to consider the use of the
feedwater system as a high pressure injection source until after the high
pressurecoreinjection(HPCI)andreactorcoreisolationcooling(RCIC)
systems were attempted. The SWROG EPGs assumed that the feedwater system
would be the first and primary method of level restoration, regardless of
the condensate conductivity, until after the RPV water level emergency was
controlled. The prerequisites for use of the feedwater system and the
failure to attempt its use are considered to be significant deviations
2)
PSTG, step RC/P-2, contained a conditional action step which placed the
control switch for each SRV in the CLOSE or AUTO position if the
continuous SRV pneumatic supply became unavailable. The intent was to
reserve operating air for subsequent necessary cycles of the SRVs.
PSTG,
step RC/P-3, required emergency RPV depressurization with sustained
opening of the SRVs if one or more SRVs were being used to depressurize
the RPV and the continuous SRV pneumatic supply became unavailable. The
intent was to continue the cooldown by leaving the appropriate valves open
continuously to maintain the proper cooldown rate.
However, the E0Ps in
End Path Procedure, step 76, required using the SRVs for RPV pressure
control only when a continuous pneumatic supply was available to the SRVs.
This was a deviation from the BWROG EPGs, in that sustained opening of the
SRVs was not attempted before operating pressure of the emergency
depressurization system was no longer available.
3)
PSTG, step DW/T-1, directed the operators to operate all available drywell
cooling, defeating isolation interlocks if necessary.
However, the
Primary Containment Control Procedure, step DW/T6, prohibited operation of
the drywell coolers if drywell pressure was above 2.0 psig. The licensee
indicated that the operation of the drywell coolers was prohibited at 2.0
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psig because the fans had previously tripped on thennal overloads at this
pressure.
This rationalization did not justify the restriction on the
primary method available to mitigate the high drywell temperature
condition.
Further licensee action is necessary to investigate and
correct the drywell cooler fan problems in order to fully utilize the
drywell coolers for primary containment temperature control.
4)
PSTG, step RC/P-1, directed the operators to manually open the SRVs if any
SRVs were cycling, until reactor pressure dropped to 950 psig, the
pressure at which all turbine bypass valves would remain fully open.
However, E0P Path-1, step 12, required that the operators open SRVs to
stabilize reactor pressure while maintaining maximum possible steam flow
to the main condenser, and did not specify a pressure setpoint. The
inspection team was concerned that the E0P omitted the parameter to which
the RPV pressure should be lowered without justification.
3.2.3 Calculation Review
l
The inspection team reviewed the calculations for figures and setpoints used in
the E0Ps to determine if the values were correctly calculated based on the
plant specific differences and the guidance of the BWROG EPGs. At the time of
the inspection, the licensee's Nuclear Engineering Department (NED) was
completing an independent verification of all calculations used to support the
draft E0Ps in accordance with Special Procedure SP-87-079, Revision 001,
.
" Independent Review of BSEP E0P Numerical Limits and Graphs." Although several
l
calculations remained to be verified by the NED, the calculations reviewed by
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the inspection team had previously been completed by the NED. As evidenced by
1
the errors in the calculation of the hot shutdown boron weight discussed below,
the verification of the draft E0P calculations was not completely effective.
Further licensee action is necessary to ensure the accuracy of the calculations
and associated assumptions. The following deficiencies were noted.
1)
Worksheet WS-09 determined the maximum primary containment water level
limit that would not cover the highest primary containment vent capable of
rejecting all decay heat, and calculated the maximum primary containment
pressure capability.
In a report entitled " Calculation of Vent Flows for
the BSEP," dated July 29, 1988, the licensee reviewed four primary
containment vont flow paths and concluded that three of the four paths
would pass the anticipated design decay heat load.
Each of the three
acceptable paths vented the primary containment from the suppression
chamber. Although a vent path from an elevated location in the drywell
was not considered in the study, the licensee calculated the maximum
containment water level based on a vent path from the drywell (i.e.,
through valves V-9 ard V-10). The licensee indicated that the path was
equivalent to the suppression pool vent path and, therefore, was
technically adequate for not exceeding the maximum pressure limit;
however, a technical justification that the drywell vent path had
sufficient capacity to pass the decay heat load was not performed.
The calculated value for the maximum primary containment water level limit
was the elevation of the drywell vent elevation (i.e., 69.67 feet to the
center line of an 18-inch diameter vent pipe). A more conservative value
of 68.5 feet was used in the PSTG to ensure that water would not enter the
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vent piping and inhibit primary containment venting; however, this
conservatism was not included in the calculation.
The inspection team was concerned that the method of primary containment
water level measurement developed by the licensee did not have sufficient
accuracy to support controlling primary containment water level. The
Primary Containment Flooding Procedure, section 9, provided a method for
the operators to estimate the primary containment water level by using the
pressure instruments in the suppression chamber and at the bottom of the
drywell to trend the drywell pressure as a function of time during primary
containment flooding. Trending was required Secause the drywell pressure
instrument would be submerged at low primary containment water levels and
could not be used for measuring differential pressure and primary
containment watcr level. After adding the expected pressure head of the
water in the primary containment to the extrapolated pressure obtained
from trending, RPV injection was secured at the estimated total pressure
corresponding to the maximum primary containment water level. This
methodology was unreliable because it incorrectly assumed that the
pressure increase would be linear.
In addition, the inaccuracies involved
in this methodology would not support controlling primary containment
water level within an accuracy of 1.17 feet (i.e., the conservatism used
to prevent flooding the primary containment vent path).
The lack of primary containment water level instrumentation was noted
during the Detailed Control Room Design Review (DCRDR) in HED 206X-5093.
This deficiency will eventually be corrected by the installation of a
i
drywell pressure instrument above the maximum water level, thus supporting
i
accurate primary containment water level measurement.
Further licensee
I
action is necessary to revise the current procedures to ensure that the
1
primary containment water level measurement procedures can be implemented
l
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effectively by the operators.
In addition, the new pressure instrumentation
j
should be installed as soon as possible.
I
2)
Worksheets WS-15 and WS-16 and plant-specific data package PSD-17
calculated the cold and hot shutdown boron weights required to poison the
reactor in the event of an ATWS.
In PSD-17, the licensee erroneously
calculatad the concentration of boron required due to several errors in
the conversion of the reference values provided by the vendor. This
incorrect conversion resulted in a calculation of the hot shutdown boren
weight which was 14.46 pounds too low. This incorrect value adversely
affected the calculations for: (1) time to inject boron (100 seconds
longer), (2) volume of the standby) liquid control (SLC) tank corresponding
to hot shutdown (68.5 gallons more , (3) SLC tank level indication for hot
shutdown (0.43 percent lower), and (4) the amount of borax required for
hot shutdown (127.6 pounds more). Although these errors resulted in
!
non-conservative values for the hot shutdown boron weights, the difference
!
(i.e., less that 5 percent) was unlikely to prevent the emergency shutdown
of the reactor due to the conservatism of the calculation.
Nevertheless,
~
these errors were not identified by the licensee's verification of the
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calculation, including the independent verification by the NED. Further
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licensee action is necessary to correct this error and ensure that all the
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draft calculations are correct.
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3)
Worksheet WS-AC4 detailed the calculation of the plant specific value for
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drywell scram pressure. The numerical limit value was listed as 2.0 psig;
however, no calculation was provided to support the parameter. The basis
was listed as technical specifications 2.2.1-1 and 3.3-1 with an
amplifying comment that 2.0 psig was the scram setpoint for high drywell
pressure. As discussed in Section 3.3.1.1, the latter statement was
incorrect in that the high drywell pressure scram was set at 1.8 psig.
Further licensee action is necessary to ensure that the setpoint
documentation corresponds to values actually used.
4)
Worksheet WS-12 calculated the lowest suppression chamber pressure which
could occur when 95 percent of the non-condensables in the drywell had
been transferred to the suppression chamber.
A minor discrepancy was
identified in that the computed value was 13.07 psig, but the cover sheet
i
of the calculation indicated 13 psig without explanation.
PSTG, step
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PC/P-1, also incorporated the value of 13.0 psig.
The PSTG should reflect
the calculations and any differences between the PSTG and the calculations
should be explained in the PSTG deviation documentation.
5)
Worksheet WS-8 calculated the highest suppression chamber pressure as a
function of the primary containment water level that would permit the
primary containment to maintain its pressure suppression function while
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the RPV was at normal operating pressure.
Several administrative errors
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that did not affect the technical adequacy of the calculation were noted.
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Examples included differences between values which were transferred into
subsequent calculations.
l
3.2.4 Adequacy of Writer's Guide
A review of the PSWG was conducted to determine wbether it described acceptable
methods for accomplishing the objectives stated in NUREG-0899. The inspection
tet.m concluded that the PSWG was incomplete and should be supplemented with
detailed guidance in the following areas.
1)
Referencing Supporting Material - All figures, tables, and other
supporting materials that may be required in the performance of a
i
procedural step should be referenced explicitly in the E0P at the point at
!
which the information is needed.
For ex. ample, the "RPV Pressure Range for
System Operation Table," was not referenced or included in step 27 of the
End Path Procedure.
Similarily, although Primary Containment Control
Procedure, step PC/P-9, required controlling suppression chamber pressure
in the safe region of the pressure suppression pressure, no reference was
made in this step for the graph or figure to be used.
Guidance for
referencing supporting materials within the procedural steps should be
part of the PSWG.
2)
Referencing Other E0Ps - Several E0Ps directed the performance of a series
~Tsleps in accordance with other procedures.
In order to reduce
o
transition errors, the complete title of the procedure and its reference
,
number should be included in the procedural step.
In addition, a complete
technique that will aid the operator in making a correct identification of
these other procedures should be included in the PSWG.
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3)
Step Identification - The PSWG described a technique for identifying
critical action steps which required placing the symbol for a decision
block over the symbol of an action block.
This methodology was not an
effective method of identifying override requirements. As discussed in
Section 3.4.3.3, a critical step was overlooked during the simulator
exercise because the operator did not recognize that the critical step
represented an override condition. A more discernible shape coding
technique should be employed for deignating critical steps in the E0Ps.
4)
Operator Aids - Operating Instruction 01-41 discussed procedures and
methodologies for implementing operator aids at BSEP; however, this
instruction was not referenced by the PSWG.
Reference to this document,
including the basic criteria for design and control of operator aids,
should be incorporated into the PSWG.
The need for training operators on
the use of the operator aids should also be addressed.
5)
_ Color Coding - The PSWG contained no criteria for color coding the E0Ps;
however, the draft E0Ps employed a color coding scheme.
Guidelines and
direction on the uses of color should be included in the PSWG.
6)
Titles - The operators should be able to identify the basic scope of each
E0P by reading the title.
The E0P titles Path-1 through Path-5 failed to
indicate what the procedure was intended to accomplish.
Guidance for
constructing meaningful and unique titles for the E0Ps should be included
in the PSWG .
7)
Consistency of Step Numbering - Some steps within the E0P flow charts
applied the BWROG EPG convention for designating steps (i.e., PC/H-9),
while others employed a three digit system (i.e., 027).
A consistent
method for numbering the E0P steps should be incorporated and documented
in the PSWG.
3.2.5 Writer's Guide Implementation
The PSWG was independently verified to assess its implementation as a source
document for the preparation of the E0Ps. The verification process consisted
of comparing the E0P flowcharts and written procedures (e.g., LEPs, SEPs, etc.)
with the stated criteria and human factors guidance contained in the PSWG.
The
inspection team concluded that the PSWG was generally followed as a source
document for preparation of E0Ps; however, several minor deviations were
ider,ti fied.
Further licensee action is necessary to ensure that the criteria
and human factors guidance contained in the PSWG are reflected in the E0Ps.
1)
Instrument Accuracy - Some of the values referenced in the E0Ps could not
be obtained from the displays.
In Path-4 for example, the operators were
required to read the conductivity of the condensate booster pump to less
than 0.3 umhos. The instrument display, 1-00 CR-3075, did not support
this level of accuracy.
As demonstrated during the system walkthroughs,
the operators were unable to read the setpoint value of 0.3 mmhos from the
]
instrument scale. This deficiency was identified as a human engineering
deficiency (HED 20X5-5015) during the DCRDR; however, no corrective action
had been taken.
In addition, the resolution of the reactor building roof
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radiation level instrument, CAC-AQH-1264-3, was unsuitable for reading the
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E0P-specified setpoints of 3446 cpm (setpoint 1) and 4213 cpm (setpoint
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2). Also, the E0P directed the operator to read the turbine building vent
radiation levels on instrument D12-RM-23; however, no setpoints were
identified on the instrument.
2)
Instrument Labels - The E0Ps referenced different units than those
inoicated on the instrument displays.
For example, the E0P referenced the
radiation level for service water effluent in units of counts per minute;
however, the instrument in the control room (i.e., D12-K805) for obtaining
this information was displayed in counts per second.
In addition, the
digital readout for monitoring stack releases, located on the control room
back panels, was not labeled and no units were identified.
Only the
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value, 4.57E + 1, was displayed.
3)
location of Equipment - The E0Ps did not provide adequate location
information for specific equipment, controls, or displays.
For example,
the action steps to start the diesel fire pump, open all battery room exit
doors, or open emergency core cooling system (ECCS) pipe tunnel doors were
local operations.
The PSWG did not establish a standard method for
identifying the location of controls and displays external to the control
room.
4)
System Nomenclature - The E0Ps used inconsistent nomenclature for
equipment and systems.
For example, in the Level / Power Control Procedure,
steps 76 and 30, LPCI was used instead of RHR.
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5)
Step Content - The E0Ps contained both decision and action steps or
contained more than one action or subject.
For example, in Path-3, steps
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175 and 93, and Path-1, step 12, the decision step required several
actions on the part of the operator.
6)
Change Identification - There was no identification of the location of
recent changes in the written procedures. A change bar technique should
be used.
7)
Section Redundancy - PSWG, section 3.7, "Information/ Caution Steps," and
section 3.9, "Information Steps," appeared to be identical in content.
8)
Vocabulary - The E0Ps used verbs such as downrange, monitor, cycle, and
increase, which were not listed in Table 1 of the PSWG as approved verbs.
3.3 E0P Validation Using Plant Walkthroughs
In order to ensure that the E0Ps could be accomplished successfully, plant
walkthroughs for all the E0Ps and referenced operational procedures were
performed. The team verified that E0P instrument and control designations were
consistent with the installed equipment and that indicators, annunciators, and
controls referenced by the E0Ps were available to the operators. The
inspection team also verified the location and control of E0Ps-in the control
room. With the assistance of licensed operators, the team physically verified
that activities which would occur outside the control room during an accident
scenario could physically be accomplished and that tools, jumpers, and test
equipment were available to the operators.
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3.3.1 Technical Adequacy of Procedures __
The inspection team identified several deficiencies with respect to the
procedural completeness and technical adequacy of the E0Ps.
Although the
inspection team concluded that the operators could adequately perform the
procedures in spite of these deficiencies, further licensee action is necessary
'
to correct these deficiencies and perform an adequate verification and valida-
tion of the E0Ps.
1)
Path-1, steps 115 and 116, and Path-2, steps 165 and 166, directed the
operators to maximize the flow from the operating control rod drive (CRD)
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system pumps by operating at the optimum pressure on the pump tead curve
,
The intent of these steps was to maximize CRD flow.
However, the steps
!
failed to accomplish the desired action because the operator was directed
I
to throttle the pressure control valve to maintain pressure equal to or
greater than 1000 psig and was never directed to increase CRD flow to the
reactor.
The steps should have directed the operator to maintain pressure
equal to or greater than 1000 psig but as low as possible.
Further
licensee action is necessary te modify these steps to ensure that the
intended action is accomplished.
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2)
Primary Containment Flooding Procedure, section 7, step 3.d (2),
instructed the operators to lift wire number 25 from terminal 70, on
terminal board UU in control panel P601.
A note preceding the step stated
that the lead to be lifted was the lead entering from outside control
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panel P601. The operator could not detennine which wire entered from
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outside the panel because two wires with exactly the same number (i.e.,
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number 25) were on the tenninal and both wires entered the same wireway.
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This condition was noted at three other steps in the same section.
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3)
Primary Containment Flooding Procedure, sections 7 and 8, step C.3, failed
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to provide the operator with instructions concerning the level to which to
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fill the primary containment.
4)
Primary Containment Flooding Procedure, section 2, did not list in the
note for manpower required the radwaste operator required to take several
actions necessary to support the evolution.
5)
Primary Containment Control Procedure, step PC/P-4, directed the operators
to vent the primary containment drywell through the standby gas treatment
(SBGT) system in accordance with Operational Procedure OP-10.
This
procedure only permitted venting the SBGT through two 1/2-inch lines
(valves V8 and V9) when drywell pressure was above 0.7 psig.
In this mode
of operation, the SBGT system vent path would have little or no effect on
controlling primary containment pressure.
The licensee should use the
10-inch ventilation damper (F-BFV-RP.) for venting, at least until the
pressure in the SBGT train reaches the limiting operating pressure.
6)
Primary Containment Control Procedure, steps PC/P-6 and PC/P-8, directed
the operator to initiate suppression pool and drywell sprays; however,
during the walkthroughs the operators were confused as to whether or not
to secure suppression pool sprays prior to initiating drywell sprays.
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Augmented training or clarification in the E0P should be provided to
resolve this confusion.
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7)
Primary Containment Control Procedure, step SP/L-5.3, directed the
operator to drain the suppression pool to radwaste to control suppression
pool level.
This step did not provide alternate instructions if these
valves were interlocked closed from an isolation signal.
Further licensee
action is necessary to account for this possibility.
8)
Primary Containment Control Procedure, step SP/L-5.22 directed the
operators to maintain primary containment water level below 68.5 feet;
however, this step and subsequent steps did not reference the procedure to
accomplish this measurement.
9)
SEP-01, section 3, initiated primary containment venting before primary
containment pressure reached 70 psig by using preferentially listed vent
paths. After opening the proper valve, the subsequent action step
required continued venting of the primary containment if the initial
venting operation stabilized primary containment pressure below 70 psig.
The inspection team was concerned that the step provided inadequate
guidance to the operator concerning action required if the vent path was
more than adequate and primary containment pressure started to fall below
70 psig. The licensee should ensure that an approved PSWG action verb is
used which properly implements the intent of the BWROG EPG concerning
primary containment pressure control during venting.
10) SEP-04, steps 3 and 4, directed opening of reactor building inboard and
outboard ventilation isolation valves.
The terminology was incorrect in
that the procedure referred to the valves as reactor building inboard
(cutboard) isolation valve (s). The correct terminology was reactor
building vent inboard (outboard) isolation valve (s).
11) SEP-06, included entry conditions of drywell pressure which were below 2.0
psig.
The procedure was actually implemented when the shutdown cooling
interlocks were fulfilled at the corresponding drywell pressure of 1.8
'
psig. As discussed in Section 3.2.3.3, further licensee action is
necessary to ensure that procedural values are consistent with the plant
parameters used to initiate actions.
12) SEP-06 cautioned the operators concerning reactor power excursions when
the residual heat removal (RHR) system pumps were started in step C.48.
However, the correct reference for this precaution should have been a
subsequent action step which throttled open the injection valve. The
licensee should ensure that the caution correctly references the operator
action which actually affects reactor power level.
3.3.2 Availability of Special Tools and Equipment
The availability of special tools and equipment in the plant appeared to be
adequate to accomplish the activities required by the E0Ps. The team verified
that the plant equipment was accessible and available to perform the identified
task. A walkthrough was performed of the special tools and equipment used in
the E0Ps both in the control room and the plant.
Because the draft E0Ps had
not been implemented, not all equipment could be verified.
Nevertheless,
several specific examples were identified in which equipment or infonnation was
not available which could adversely affect the performance of the E0Ps and
their support procedures.
Based on the training and experience of the
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operations staff, the inspection team concluded that the E0P actions could be
accomplished satisfactorily. However, based on the need to provide procedures
which can be implemented correctly by a newly qualified operator, and on the
guidance of NUREG-0899, the inspection team concluded that there was a
potential for operator confusion or error which could affect the performance of
the procedures.
Further licensee action is required to provide the necessary
equipment or information to ensure that operator confusion will not exist
during the performance of the procedures.
i
1)
LEP-02 provided an alternate control rod insertion method involving local
venting of the hydraulic control units (HCus). The venting operation used
control rod drive (CRD) vent hoses located in the toolbox on the 20-foot
elevation of the reactor building.
The toolbox contained two sets of
hoses with different types of connectors, only one of which would fit the
HCU vent block. The licensee could not determine the purpose of the
second set of hoses in the toolbox.
The inspection team was concerned
that in an emergency the presence of the incorrect hoses could delay the
performance of alternate control rod insertion. The inspection team also
noted that the toolbox did not contain any protective eouipment and that
the procedure did not warn the operators that HCU venting was a
potentially hazardous operation which could release contaminated, hot
reactor water.
In addition, the licensee indicated that the venting
procedure was a two-man job requiring one operator to perform the venting
operation in the overhead while a second operator coordinated the
activities with the control room and verified that the correct hydraulic
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control unit was being vented from below.
However, the procedure only
required the resources of one operator to perform the venting operation.
2)
The Primary Containment Flooding Procedure required the use of several
electrical jumpers. Generic jumpers were available to the operators to
perform the E0P actions; however, these jumpers had closed-end
terminations. The use of closed-ended jumpers required the operator to
(
remove the terrrinal screw, install the additional terminal, recapture all
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terminals, and re-install the terminal screw. The inspection team was
concerned that this task was unnecessarily complex for emergency
conditions.
The use of open-ended terminations, which could be slipped
under a loosened screw, would simplify the task.
In addition, the
inspection team noted that the procedure lacked direction concerning
insulation of lifted leads, and that insulating materials were not readily
,
available.
The inspection team also observed that some electrical relays had wiring
diagrams posted adjacent to the relays to aid the operators in identifying
the terminal locations; however, not all relays used in the E0Ps were
identified in this manner.
Further licensee action is necessary to
provide installation specific jumpers for use in accomplishing the E0P
action steps and to provide consistent use of operator aids for the
identification of relay terminal locations.
,
3)
During the E0P simulations, the control room operators directed the
auxiliary operators to perform numerous actions in the plant.
For
example, steps 67 and 68 in Path-1, required opening battery room exit
doors and ECCS pipe tunnel doors. These actions were initiated by the
control room operator using the public address (PA) system and required
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the auxiliary operators to find a PA station to report the completion of
the directed actions.
Alternate communications techniques, such as
hand-held radios, were not available for communicating with the operators
perfonning local actions. The inspection team concluded that the licensee
should give further consideration to the use of hand-held radios to permit
reliable communication with the control room under emergency conditions.
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3.3.3 Station Material Condition
The inspection team reviewed the material condition of the station during the
plant walkthroughs and ensured that necessary equipment and components were
dCCessible and functional.
The overall material condition of the plant
appeared good. The team did not observe any interferences in the reactor
building which would adversely affect emergency actions. The inspection team
noted that significant amounts of non-combustible material were located in the
bottom of control panel P601; however, the licensee initiated corrective action
to clean the panel and inspected and cleaned other panels as required.
The
team verified that emergency lighting was available for E0P operator actions
and noted that lighting was available within electrical cabinets requiring
terminal manipulations.
However, during the walkthroughs, the operators would
not operate the switches to turn on the lights in the cabinets because the
switches were not labeled.
Further licensee action is necessary to correct
this deficiency.
3.3.4 Reactor Building Accessibility
The licensee performed a design review entitled, " Post-Accident Control of
Radiation in Systems Outside Containment of PWRs and BWRs," to meet the
requirements of paragraph 2.1.6 of NUREG-0578, "TMI-2 Lessons Learned Task
Force Status Report and Short Term Recommendations." The inspection team noted
that the extent of the design review fulfilled the additional requirements of
NUREG-0737, paragraph II.B.2, concerning the same subject.
The inspection team
evaluated the results of this design review and its impact on the ability of
operators to perform the emergency actions of the E0Ps.
The ability of the operators to perform the E0P actions successfully would be
dependent on access to the reactor and radwaste buildings. Access to the
reactor building was dependent on the specific accident scenario, and access to
the radwaste building was dependent on the location of primary system leakage.
Although the licensee's radiation protection procedures allowed operator entry
into high radiation level areas under the supervision of radiation protection
personnel, the E0P contingency actions could not be performed if radiation
levels prevented entry.
The design review was based upon the source terms
specified by Pegulatory Guides 1.3 and 1.4 and the accidents of Chapter 14 of
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the BSEP Final Safety Analysis Report (FSAR). The design review concluded that
entries into unprotected areas or areas with prohibitively high dose rates
would not be required for mitigation of the accidents. However, several areas
were identified which could require operator entry during recuvery operations.
The inspection team concluded that multiple methods of implementing the E0P
contingency actions had been adequately considered in the development of the
E0Ps. However, the inspection team identified two actions, during the
walkthrough of the plant, for which an alternative method of accomplishment had
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not been adequately considered.
Further licensee action is necessary to
correct these discrepancies.
1)
The LEP-01 and Primary Containment Flooding Procedure identified several
local operator actions to inject service water and demineralized water
into the RPV.
These actions included opening the residual heat removal
(RHR) loop cross tie valve, Ell F010, in the high pressure core injection
(HPCI)systemmezzaninearea.
This valve was a normally de-energized
motor-operated valve whose breaker was removed from its cubical to ensure
separation of the two trains of RHR.
A significant amount of time was
required to operate this valve manually in area in which radiation levels
could be as high as 20000 R/HR one hour into an accident.
Since this
valve had the potential to be operated remotely, further licensee
consideration should be given to reinstalling the valve breaker rather
than attempting manual operation.
2)
SEP-06, step C.24, required the operator to monitor the RHR heat exchanger
outlet conductivity at a local instrument in the south RHR room.
This
,
area would have extremely high radiation levels in the accident conditions
during which performance of the step would be required.
The inspection
team noted that control room panel alarm, A-03, tile 2-10, monitored the
desired location and alarmed at the value specified in the E0P (i.e., 10
umho/cm).
Further licensee action is necessary to ensure that remote
instrumentation is used where possible in lieu of local monitoring in high
radiation areas.
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3.4 E0P Validation Using Plant Simulator
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To ensure that the E0Ps could be implemented correctly under emergency
j
conditions, the inspection team developed and performed four accident scenarios
utilizing licensed operators. The accident scenarios determined whether the
)
E0Ps provided the operators with sufficient guidance and clearly outlined their
required actions during an emergency; verified whether the E0Ps caused the
operators to interfere physically with each other; verified that the procedures
did not duplicate operator actions unless required; and verified that
transitions from one E0P to another or to other procedures were accomplished
satisfactorily.
3.4.1
Scenario Description
The first scenario involved a rupture of the feedwater pump suction header from
100% power with a spurious group 1 isolation signal inserted at the time of the
reactor scram due to low RPV water level.
The SRVs opened on high RPV pressure
following the main steam isolation valve (MSIV) closure.
One safety relief
valve (SRV) stuck open and remained open throughout the scenario. One minute
after the scram and MSIV isolation, a small steam leak was initiated into the
drywell . The high pressure core injection (HPCI) system, pump B of the control
rod drive (CRD) system, and the loop B heat exchanger of the residual heat
removal (RHR) system were out of service throughout the event.
Following the
reactor scram, the operators performed Path-4 when RPV water level decreased
below +112 inches.
The operators exited Path-4 and performed steps RC/L and
RC/P of the End Path Procedure concurrently to restore RPV water level and
pressure. The operators performed the Primary Containment Control
Procedure to control suppression pool temperature and drywell pressure and
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temperature, and depressurized the RPV in accordance with the End Path
i
Procedure, when drywell temperature exceeded 300 degrees F.
The second scenario exercised the Level / Power Control Procedure with alternate
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boron injection. A spurious group 1 isolation signal initiated the event and
resulted in a failure of all control rods to scram.
Failure of the standby
liquid control (SBLC) system to inject along with both reactor water cleanup
(RWCU) system pumps being out of service required the use of the Alternate
Boron Injection Procedure using the CRD system. A small break loss of coolant
accident (LOCA) in the drywell required emergency depressurization when drywell
temperature exceeded 300 degrees F.
The scram condition required the
performance of Path-1 and eventually the Level / Power Control Procedure for the
l
ATWS condition. The Primary Containment Control Procedure was used to control
drywell and suppression pool temperature and pressure.
The third scenario exercised the Secondary Contairiment Control Procedure and
i
the Radioactive Release Control Procedure. A loss of feedwater resulted in a
reactor scram on low RPV water level coincident with a fuel element failure.
Maintenance. activities in the HPCI room required the reactor core isolation
cooling (RCIC) to HPCI room door to remain open to allow passage of hoses.
When the RCIC system started on low RPV water level a steam leak occurred at
the RCIC steam inlet valve (F0-45). The steam leak caused a RCIC system
isolation signal.
The RCIC steam supply containment isolation valves failed to
isolate and caused a HPCI isolation signal several minutes later due to the
open door between the two rooms. The scram coincident with an RPV level below
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+112 inches required performance of Path-4. The radioactive steam leak in
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secondary containment required performance of the Secondary Containment Control
Procedure.
Exceeding the reactor building roof vent annunciator setpoint
required performing the Radiological Release Control Procedure. When the
operators determined that more than one area had exceeded its maximum safe
operating radiation level, the End Path Procedure required emergency
depressurization.
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The fourth scenario required venting primary containment to control primary
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containment hydrogen concentrations.
RHR loop B was out of service throughout
l
emergency bus (E-3) ge break LOCA coincident with a failure of the 4160 vcit
the scenario. A lar
initiated a reactor scram and an ECCS actuation. The A
loop RHR injection valve failed to open, leaving only one core spray (CS) pump
available for injection.
The reactor core was uncovered, resulting in fuel
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damage and the release of hydrogen to the primary containment. The scram with
high drywell pressure required performance of Path-5 and the Primary
Containment Control Procedure.
The loss of power to emergency bus E-3
unexpectedly resulted in the inability of the operators to perform the primary
containment venting procedure because the torus purge exhaust valve, CAC V-8,
was powered from emergency bus E-3.
Further licensee action is necessary to
ensure that an alternate method is available to vent the primary containment
ouring a partial loss of power condition.
3.4.2 Limitations of the Plant-Specific Simulator
The plant-specific simulator located on-site was used for the E0P scenarios.
The simulator demonstrated extremely poor modeling with respect to decay heat
and RPV water level response.
For example, during scenarios in which all high
pressure injection had failed and with mass being removed by open SRVs or a
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small break LOCA, RPV water level would continue to increase.
Following
MSIV isolations from 100 percent power with end of life (COL) decay heat
loading and no steam being drawn off by the HPCI or RCIC systems, it was not
necessary to use the SRVs to control RPV pressure.
In fact, RPV pressure would
decrease with no external energy removal in progress. As a result, the RC/L
steps of Path-1 were not able to be simulated past the initial entry steps.
The inspection team concluded that the plant-specific simulator was not.an
effective tool for operator training on the Level / Power Control Procedure, E0P
Path-5, or any of the E0P steps requiring level control manipulations. As
previously discussed in Section 3.1.2, the simulator modeling deficiencies also
adversely affected the ability of the licensee to perform validation for any
E0P steps which required level manipulations.
3.4.3 Observations and Conclusions
The inspection team concluded that the operating crew could satisfactorily-
implement the E0Ps to shutdown the reactor and return the plant to a safe,
stable condition. Overall, the operators performed well and demonstrated a
good understanding of the E0Ps which was indicative of a high level of training
on the procedures. As discussed in Section 3.1.1, the inspection team
concluded that the timely implementation and execution of the E0Ps required the
active participation and assistance of the STA because the licensee included
the post-trip actions in the E0Ps and developed overly complex procedures. The
inspection team identified concerns in the following two areas.
1)
Control Room Responsibilities - During all four scenarios, the inspection
team observed that the shift foreman (SF) directly supervised the two
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control operators and directed the performance of the E0Ps and that the
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shift operating supervisor (SOS) monitored the emergency plan and
performed the required notifications.
The shift technical assistant (STA)
monitored the emergency response facility information system (ERFIS) and
available control room indications for key parameters and trends.
In
I
addition, the STA monitored changing plant conditions to identify E0P
J
entry conditions and to advise the SF regarding the required actions. The
inspection team also noted that the STA performed E0P steps in legs which
the SF did not have time to execute.
This was particularly evident in the
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third scenario involving the Secondary Containment Control Procedure.
1
The BSEP administrative instructions required the STA to provide an
overview of the plant conditions and ensure that all the required E0P
steps were completed.
In actual practice, the STA independently performed
portions of the E0Ps in order to provide more time for the SF to read and
complete the post-trip scram recovery actions of the E0Ps.
The inspection
team concluded that the level of detail of the BSEP E0Ps did not permit a
single individual sufficient time to direct the performance of all
required actions of the E0Ps.
The inspection team also observed that the SF was not able to perfom all
the parallel steps as required by the BWROG EPGs. This was clearly
demonstrated in the first scenario involving the performance of the
Primary Containment Control Procedure.
During the scenario, the SF
completed only two steps of the five required parallel flowpaths (i.e.,
DW/T and PC/P).
The remaining three flowpaths (i.e., SP/T, SP/L, and
PC/H) were not performed. Another example occurred in the third scenario
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involving the Secondary Containment Control Procedure.
During this
scenario, the SF completed only one of the three required parallel
flowpaths (i .e. , SC/R).
In this example, the SF directed the control
operator to obtain the area radiation levels from the back panel, but not
the area temperature and level readings. The failure to execute all legs
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of the E0Ps potentially prevents monitoring and control of all symptoms
indicative of an accident condition. As discussed in Section 3.1.1,
further licensee action is necessary to (1) accurately define and
implement the control room responsibilities of the STA and SF during E0P.
performance, (2) remove the event-based actions from the E0Ps, and (3)
reduce the level of complexity of the E0Ps.
2)
Critical Action Steps - Critical action step RR-5 in the Radioactive
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Release Control Procedure required the operators to execute the subsequent
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actions of the flowpath only if an ALERT was not declared as a result of a
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radioactive release. As discussed in Section 3.1.1, these actions were
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event-based and not appropriate for inclusion in the E0Ps. Durir.g the
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third scenario, the_ STA and SF performed these action steps after an ALERT
had been declared. Although in direct conflict with the procedural
requirement of step RR-5, the licensee's training staff indicated that it
was desirable to perform these action steps even after an ALERT had been
declared.
Further licensee action is required to correctly train and
implement the critical actlon of step RR-5.
During the third scenario, the operators incorrectly performed emergency
,
depressurization in accordance with the End Path Procedure because they
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missed critical action step 64 of the Level / Power Control Procedure. As a
result, the operators bypassed the cautions concerning power oscillations
during an ATWS contained in the procedure.
Although, the SF correctly
i
controlled injection flows and reactor power level, he subsequently
indicated that he did so as a result of his previous training and had
missed the precautions of the critical action step.
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The operators used a marker to maintain peacekeeping within the E0Ps and
to note critical action steps and, as a result, were able to explain
accurately where they were in each of the flowcharts.
However, the
scenarios demonstrated that they experienced difficulty in identifying and
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monitoring the override requirements of critical action steps.
Because
missing a critical action step has a significant potential to result in
.
severe core damage, the inspection team concluded that further licensee
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action is necessary to identify, train, and procedurally support a more
effective method for monitoring the critical action steps.
3.5 Operator Interviews
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The inspection team conducted interviews with three shift operating
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supervisors, four control operators, and one auxiliary operator. These
interviews developed information on the effectiveness of the E0Ps and did not
examine the qualifications of the operators.
Each interview lasted
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approximately one hour. The following observations summarize the comments
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volunteered by the operators.
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3.5.1 Observations and Conclusions
1)
Equi ament Design - The operators experienced difficulty in locating and
reacaing several valves outside the control room.
For example, the
operators suggested cutting a manhole in the grate that covered the
condensate header valve, C0-V304, to enhance the accessibility from above.
In addition, the operators also suggested implementing hardware
modifications to make the valve more easily accessible and labeling the
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RCIC CST suction valve, CO-V301, on a nearby wall to clarify its location.
Although the E0P provided location information, the operators indicated
)
that the use of signs would' aid performance of the E0Ps.
2)
Assignment of Duties - The E0Ps clearly defined the number and
qualifications of operations personnel required for executing the E0Ps.
Major tasks and duty assignments were clearly delineated and unambiguous.
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The operating instructions delineated the basic philosophy and established
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practices for personnel assignments.
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3)
0)erator Training - All SFs and C0s had received preliminary training on
tie use of the draft EOPs. Approximately two weeks of combined classroom
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and simulator training were devoted to the use of E0PS; however, formal
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training on the E0Ps for the A0s had not yet been accomplished.
The
operators indicated that additional training was scheduled before the
draft E0Ps would be implemented.
Ir general, the operators considered
their training on the E0Ps to be adequate; however, more training would be
beneficial. Some operators expresseii concern regarding the transfer of
training betweer. the new procedures end the old procedures.
4)
Validation and Verification of E0Ps - The verification and validation of
the E0Ps included a combination of system walkthroughs and simulator
exercises.
In addition, operator training accomplished portions of the
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verification and validation process.
For example, verification of the
technical adequacy for selected E0Ps was performed during classroom
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discussions.
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5)
System for Making Changes to E0Ps - A fonnal system existed for making
changes to the E0Ps.
The operators submitted changes to the E0Ps in
accordance with Operating Instruction 01-28.
6)
Calculations - The E0Ps required the operators to perform very few
calculations and did not require complex calculations.
7)
E0P Availability - All the E0Ps were located within the control room and
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were inraediately accessible by the operators. All of the operators
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reported that there were no problems in locating and retrieving the
required E0Ps needed to perform a spccific function.
Nevertheless, the
inspection team believed that further consideration should be given to
locating the E0Ps which would be required to be performed outside the
control rocm at a locally accessible area.
NVP.EG-0899 required that the
procedures be available at all locations in the plant where equipment is
to be manually operated under emergency conditions.
8)
Communications - The operators considered the communications inside the
control room to be adequate and reported no conditions where it was hard
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to hear or convey verbal instructions in the control room. All operators
expressed the need to keep the number of personnel in the control room to
a minimum during en emergency. The operators identified that communica-
tions would be difficult in the diesel building and the RHR pump room (-17
level) during an emergency. The inspection team noted that communications
from outside the control room were only available through the PA system
and that the availability of radios as an alternative mode for communica-
tions would be a valuable asset.
3.6 Primary Containment Venting Provisions
The inspection team reviewed the " Primary Containment Venting Procedure,"
E0P-01-SEP-01, to determine the adequacy of the procedure and the feasibility
of the vent paths.
The inspection team also reviewed the results of the
special Probabilistic Risk Assessment based operational safety inspection
cor. ducted by the NRC in March 1988. The inspection team performed a
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walkthrough of all primary containment vent paths which had not previously been
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examined during the earlier inspection, and verified that all necessary
equipment was available.
The Primary Containment Control Procedure initiated venting of the primary
containment, irrespective of the off-site release rate, for conditions of high
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pressure (i.e., 70 psig in step PC/P-12) and for conditions of high hydrogen or
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oxygen (i.e., 6 percent and 5 percent, respectively, in step PC/H-16). The
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shift foreman had the final authority for venting the primary containment under
these conditions.
4
The licensee had established hard pipe vent paths which were capable of
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removing the decay heat load required by Revision 4AF of the BWROG EPGs.
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E0P-01-SEP-01 preferentially listed the vent paths from the small bore pipe to
the large bore piping, to control the primary containment pressure. All the
vent paths were monitored release paths that permitted off-site dose
calculations to be performed. Although the vent paths used hard piping, low
pressure ducting was installed at transitions to the standby gas treatment
(SBGT) system and the reactor building purge exhaust system fans. A recent
study completed by the licensee concluded that the pressure at the fan duct
work could exceed acceptable limits and a further evaluation was in progress at
the time of inspection. This evaluation should be completed in a timely manner
by the licensee.
The inspection team was also concerned about the ability of the operators to
establish a vent path during reduced power capability or station blackout
conditions. As discussed in Section 3.4.1, the inspection team noted during
the simulator exercises that the operators were unable to establish a vent path
to remove simulated excessive hydrogen with the loss of one division of
essential power.
Contingency plans were under development by the licensee for
the conditions of loss of power, including containment venting provisions.
This effort should be completed expeditiously by the licensee.
4.0 MANAGEMENT EXIT MEETING
The inspection team conducted an exit meeting on October 7, 1988, with licensee
management.
During this meeting, the inspection team identified the inspection
findings and provided the licensee with an opportunity to question the
observations. The inspection team also detailed the scope of the inspection
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and informed the licensee of the conclusions identified in this report. Mr.
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Jim Konklin, Section Chief, Special Team Support and Integration Section,
Office of Nuclear Reactor Regulation, and Mr. Caudie Julian, Branch Chief,
Operations Branch, Region II, represented NRC management at the final exit
meeting. Appendix A identifies the licensee personnel who participated in this
meeting.
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APPENDIX A
PERSONNEL CONTACTED
A large number of people, including the following licensee personnel, were
contacted during the inspection.
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- J. Harness, Plant General Manager
- K. Enzor, Director, Regulatory Compliance
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- L. Jones, Director, Quality Assurance and Quality Control
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- C. Blackmon, Manager, Operations
A. Hegler, Superintendent, Operations
- W. Martin, Principal Engineer, On-site Nuclear Safety
- J. Titrington, Principal Engineer, Operations
- M. Sawtschenko, Operations
S. Reynolds, Operations
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M. Amato, Operations
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- M. Williams, Senior Specialist, Operations
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D. LaBelle, Shift Supervisor, Operations
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M. Schall, Shift Foreman, Operations
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E. Hutt, Shift Foreman, Operations
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K. Chism, Shift Foreman, Operations
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K. Horn, Shift Foreman, Operations
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R. Gibbs, Shift Technical Advisor, Operations
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H. Harrelson, Operations
R. Mullis, Operations
D. Best, Operations
B. Jones, Operations
D. Jenkins, Operations
R. Blair, Operations
R. Knight, Operations
R. Poulk, Regulatory Compliance
- T. Jones, Regulatory Compliance
- J. Moyer, Manager, Training
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E. Hawkins, Training
- M. Shealy, Project Specialist', Training
- B. Strickland, Project Specialist, Operations
- A. Schmich, Senior Specialist, Corporate Nuclear Licensing
- Denotes those personnel present at the exit meeting on October 7, 1988.
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APPENDIX B
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DOCUMENTS REVIEWED
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Emergency Procedure Guidelines (EPGs), Revision 4AF, March 1987
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Plant Specific Technical Guideline (PSTG) for EPG Revision 4, Draft D
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EPG/PSTG Step Documentation, Draft D
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Appendix A PSTG/EOP Step Documentation, Draft C
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Procedures Generation Package (PGP), August 17, 1983
Administrative Instruction AI-95, " Verification and Validation Program for
EPG, Revision 4, based Emergency Operating Procedures," Draft A
MST-RPS-26R, "Drywell Pressure Setpoint Calibration," Revision 2
Engineering Evaluation Report No. 85-0231, Revision 0
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General Area Personnel Dose Rates Versus Time (post-LOCA)
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Emergency Operating Procedures (E0Ps):
E0P-01-UG, " User's Guide," Draft B
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E0P-01-FP-1, " Path-1," Draft 0
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E0P-01-FP-2, " Path-2," Draft E
E0P-01-FP-3, " Path-3," Draft E
E0P-01-FP-4, " Path-4," Draft D
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E0P-01-FP-5, " Path-3," Draft D
E0P-0 rPP-5, "End Path Procedure," Draft H
E0P-01-LPC-1, " Level / Power Control Procedure," Draft E
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E0P-02-PCCF, " Primary Containment Contml Procedure," Draft F
'0P-03-SCCF, " Secondary Containment C
.rol Procedure," Draft G
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E0P-04-RRCP, " Radioactivity Release Co.. trol," Draft D
E0P-01-ALC, " Alternate Level Control," Revision E
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E0P-01-AEDP, " Alternate Emergency Depressurization Procedure,"
Revision D
E0P-01-StCP, " Steam Cooling Procedure," Revision A
E0P-01-FP, "RPV Flooding Procedure," Revision E
E0P-01-PCFP, " Primary Containment Flooding Procedure," Revision B
E0P-01-LEP-01, " Alternate Coolant Injection," Revision 005
E0P-01-LEP-02, " Alternate Control Rod Insertion," Revision 005
E0P-01-LEP-03, " Alternate Boron Injection," Revision 004
E0P-01-SEP-01, " Primary Containment Venting," Draft D
E0P-01-SEP-02, "Drywell Spray Procedure," Draft C
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E0P-01-SEP-03, " Suppression Pool Spray Procedure," Draft C
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E0P-01-SEP-04, " Reactor Building HVAC Restart Procedure," Draft C
E0P-01-SEP-05, " Primary Containment Purging," Draft C
E0P-01-SEP-06, " Shutdown Following Boron Injection," Draft B
E0P-01-SEP-07, " Bypassing RWCU Filter Domineralizers," Draft B
E0P-01-SEP-09, "CRD Flow Maximization," Draft B
Operating Instructions and Procedures:
01-28, " Appendix C Writer's Guide for Emergency Operating Procedures
(EOPs)," Revision 6
01-37, " Preparation and Review of the Plant-Specific Technical Guideline
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for EPG Revision 2,"
Revision 001
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PT-16.2, " Primary Containment Volumetric Average Temperature,"
Revision 20
CP-05, " Unit Shutdown," Revision 28
OP-10. " Standby Gas Treatnient System," Revision 32 (Unit 2)
OP-17, " Residual Heat Removal System," Revision 77 (Unit 2)
OP-24, " Containment Atmosphere Control," Revision 26 (Unit 1)
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