ML20235R342: Difference between revisions

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{{Adams
#REDIRECT [[IR 05000324/1988200]]
| number = ML20235R342
| issue date = 01/25/1989
| title = Insp Repts 50-324/88-200 & 50-325/88-200 on 880926-1007. Technical Inaccuracies Noted.Major Areas Inspected:Emergency Operating Procedures,Procedures & Plant Operations Re Human Factors & Primary Containment Venting Procedures
| author name = Haughney C, Konklin J, Vandenburgh C
| author affiliation = NRC OFFICE OF NUCLEAR REACTOR REGULATION (NRR)
| addressee name =
| addressee affiliation =
| docket = 05000324, 05000325
| license number =
| contact person =
| document report number = 50-324-88-200, 50-325-88-200, NUDOCS 8903030263
| package number = ML20235R333
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 35
}}
See also: [[see also::IR 05000324/1988200]]
 
=Text=
{{#Wiki_filter:_ _ .
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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
                                                                                                                          l
                                        -        ~ b' ^-                    l -T5- @
        Team Leader:
,
                        C. A. VanDenburgh, Senior Operations                Date Signed                                    .
I                      Engineer, NRR                                                                                      l
        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.
l
        Reviewed By:      w                          '
                                                        /                  //ET//f'(
                          ames E. Konklin, Chief                            Ddte Signed
                        Special Team Support
                        & Integration Section, NRR
        Approved By:            (164/4t(                                    //2Md7
                        Unarles p. Haughney, Chief                          Ddte Signed
                        Special inspection Branch, NRR
i
              8903030263 890223
              PDR
              O
                    ADOCK 03000324
                                PDC
                                                                                _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _      -
 
            .                -
          '
                                                ,
                                              ~
          .
                                  Scope:
                                                                                                                  1
                                  From September 26 through October 7,1988 an NRC inspection team conducted an    '
                                  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  i
                                  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        l
                                                                                                                  '
                                  Emergency Procedures (LEPs) and Supplemental Emergency Procedures (SEPs)
                                  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
i
                                  draft E0Ps incorporated Revision 4AF of the BWROG EPGs. They corrected
l                                deficiencies which had been identified during an Operational Safety Assessment
                                  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.
l                                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
l                                station blackout actions. The E0Ps provided a high level of detail and
l                                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.
l                                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
1
m___._______________.___.__..______________._    _ _ _ _ _ _ _ _ _
 
. .
'
                                                                                            .
                                          .
.
        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.
                                                                                                                                                                                                                      I
                                                                                                                                                                                                                      J
                                                                                                                                                                                                                      l
                                                                                                                                                                                                                      l
                                                                                                                                                                                                                      I
                                                                                                                                                                                                                      l
    - _ _ _ . _ . - _ _ . - _ _ _ _ - _ _ _ . . _ _ _ _ _ _ _ _ _ - - _ - _ _ _ _ _ _ . _ _ - - . . _ . - - ,-. -_- _ _ . - , . - _ . . . , - - _ - - _ - . . . . - _ . , - - _ - - - - . - _ - - , . . - _ - - _ . -
 
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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)
                                                                                                                  Page
        1.0 INSPECTION 0BJECTIVE.........................................                                          1
        2.0    BACKGR0VND.......................................                            4 ..........          1
        3.0 DETAILED INSPECTION FINDINGS.................................                                          3
              3.1 Emergency Operation Procedure (E0P) Program Evaluation..                                        3
                    3.1.1 E0P Development..................................                                      3
                    3.1.2 Licensee Verification and Validation of E0Ps.....                                      4    i
                    3.1.3 E0P Operator Training............................                                      5    1
                    3.1.4 Maintenance of E0Ps..............................                                      6
                    3.1.5 Quality Assurance Involvement in PSTG                                                        l
                                                                                                                        1
                            Maintenance......................................                                    6
                    3.1.6 Licensee Response to IE Information Notice 86-64.                                      7
              3.2 E0P P rocedu re Ve ri fi ca t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  7    !
                    3.2.1  EPG/PSTG Comparison..............................                                    7  I
                    3.2.2 PSTG/EOP Comparison..............................                                      12
                    3.2.3 Calculation      Review...............................                                13
                    3.2.4 Adequacy of Writer's Guide.......................                                      15
                    3.2.5 Writer's Guide Implementation....................                                      16
              3.3 E0P Validation Using Plant Walkthroughs.................                                      17  j
                    3.3.1 Technical Adequacy of Procedures.................                                      18
                    3.3.2 Availability of Special Tools and Equipment......                                      19
                    3.3.3 Station Material Condition.......................                                      21
                    3.3.4 Reactor Building Accessibility...................                                      21
l
              3.4 C0P Validation Using Plant            Simulator....................                            22
,
                    3.4.1  Scena rio Des c ri pti on. . . . . . . . . . . . . . . . . . . . . . . . . . . . .  22
'
                    3.4.2 Limitations of the Plant-Specific Simulator......                                      23
                    3.4.3 Observations and Conclusions.....................                                      24
                                                                                                                        '
              3.5 Operator Interviews.....................................                                      25
                    3.5.1 Observations and Conclusions.....................                                      26
              3.6 Prima ry Contai nment Venting Provi sions. . . . . . . . . . . . . . . . . .                  27
        4.0 MANAGEMENT EXIT MEETING......................................                                        27
        Appendix A - PERSONNEL C0NTACTED..................................                                        A-1
        Appendix B - DOCUMENTS REVIEWED...................................                                        B-1
 
    _ _ .                                          --                          .
                                                                                                - . . .
          -
  .                                                                                                    !
  '
                        .
  .
                  .
            1.0 INSPECTION OBJECTIVE
l
            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.
,
            2)    Assess whether the E0Ps could be physically carried out in the plant using
                    existing equipment, controls, and instrumentation, under the expected
                    environmental conditions.
            3)    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
            Procedures," represents the NRC staff's long-term program for u
            and describes the use of a Procedures Generition Package to          (PGP)  pgrading
                                                                                    prepare E0Ps. E0Ps,
l
            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
            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              j
            to diagnose specific events.                                                                I
            Although various circumstances caused long delays in achieving NRC approval of              J
            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.
                                                                                                        !
                                                                                                        i
                                                      1                                                !
 
  .
              .
  -
                                                                                            l
                                                                                            l
    Representative samples of each of the four vendor types were selected for                j
    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                                                        j
                                                                                            I
    3.1 Emergency Operating Procedure (EOP) Program Evaluation                              l
    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
l  Revision 2 of the BWROG EPGs.
l
l
    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. The
    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            l
    inspection team verified whether identified deficiencies affected the approved
                                                                                              '
    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
l
    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
    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
                                            2
                                                                                  _ _ _ - _-
 
                                                            _ - _ _ _ _ - _            . _ _ - _ _ _ - _ _ _ _ .
    .
  .
                .
          -
  .
      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.
      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                                      i
      operator's response to an actual emergency. Further licensee action'is                                    I
      necessary to reduce the level of complexity of the E0Ps.                                                  l
                                                                                                                l
      1)    Primary Containment Control Procedure, step C.9.e (1), and section 1,                              !
'
            included reference to the head spray system, which was no longer
'
            applicable because of a plant modification. The reference should be
            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.
                                                3
 
  '
.
'
                ,
          .
.
    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;    ,
            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.
    P)    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.                                                ,
                                                                                      l
    9)    Path-2, steps 80, 90, 91, 99 and 100, and Path-3, steps 79 through 84,    j
            provided detailed steps for the operation of the suppression pool cooling
            system which were more appropriate for operational procedures. In            ,
            addition, these actions should have been covered in a single action step  !
            as accomplished by procedure SP/T-3.                                        .
                                                                                      !
    3.1.2 Licensee Verification and Validation of E0Ps                                i
                                                                                        l
    NUREG-0899, section 3.3.5, indicated that after E0Ps are written they must        i
    undergo a process of verification and validation. This process was used to        l'
    establish the accuracy of information and instructions, to determine that the
    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.                                                                  ;
                                                                                      i
    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.      i
    The membership of the committee included operations, quality assurance,
    technical support, off-site nuclear safet.;, and the licensed training            !
    departments.
                                                4                                      !
                                                                                      !
 
                  '
  .
                              .
  4                                                                                                  j
                    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
l
                    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.
l                    The inspection team was concerned that the identified verification and
I                    validation methodology did not indicate that appropriate consideration had been
l                    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
.
                    EWP0G EPGs.    The inspection team compared the requirements of NUREG-0899, the
l
                    Procedures Generation Package (PGP), and the operator training program
l                    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.
                                                                5
    ___- _ _ _ _ -
 
      _____-
            '
  .
  '
                        .
    .
              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          ,
              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 hours of classroom instruction on      i
              the content and use of the new E0Ps. Phase IB was completed in June 1988 and      l
              consisted of 16 hours of classroom instruction cambined with 20 hours of
              simulator training designed to exercise the major branching points within the
              E0P flowcharts.  Phase 11 training was conducted in September 1988 and involved
l              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    j
              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.
                                                      6
                                                                                _    ___ _ -  -
 
                                                                                          _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
  '
.
'
              .
        .
.
    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                                              ,
    and assigned to responsible engineers for evaluation. IEN 86-64 and Supplement                                            l
    1 were evaluated by the coordinator and closed because a OA surveillance,
                                                                                                                                '
    discussed in Section 3.1.5, had already been initiated and had identified
    similar deficiencies. The inspection team concluded that the licensee's                                                    i
    actions in response to IEN 86-64 were satisfactory.                                                                        l
                                                                                                                              .
    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
                                                                                                                              '
    E0Ps in which the entry conditions of the PWROG EPGs were changed without
    sufficient technical justification.      Further licensee action is necessary to                                        l
    evaluate and correct the E0Ps presently in use and to ensure that the draft                                              !
    E0Ps accurately incorporate the technical guidance of the BWROG EPGs.
                                              7
                                                                                      . _ _ - - _ _ _ _                  ___
 
                                              _
                                                                                    ,
  '
.
            S
      -
.
                                                                                      l
    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          i
        indication and the TAF, (2) the restrictions on the use of the wide range    l
        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    i
              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          I
              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
                                            8
 
    '
  .
  '
            .
      +
  .
              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
I
                                            9
                                                                        _ - _  _ _ _ -
 
                                                                                                                                                                        1
                                *                                                                                                                                        j
          a
          '
                                                                              .
                                                        -
            .
                                                                                    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
                                                                                                                    10
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _                                                    _        _          _ _ _ _ .
                                                                                                                                                                        ,
 
  '
o
.
                                                                                              4
        -
.
          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            I
          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
          EPG entry conditions because the entr
          abnormal operating procedures (A0Fs)  were yincorporated
                                                        conditions into
                                                                    andthe
                                                                        actions
                                                                            PSTG.forAsseveral
          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.
                                              11
 
                                                                                                            -
    '
  .
  '
                .
          *
  .
      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
      BWROG EPGs.    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
            from the BWROG EPGs.
      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
                                                  12
                                                                      _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - -
 
    *
.
'
                .
          '
  .
            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    '
      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,    i
      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
                                                13
 
                                                                                        -                            _ _ - _ _ _ _ _
      *
    .
  '
                  .
          '
    .
            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
l            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
              to hot shutdown    (68.5ofgallons
                                          the standby)  liquid
                                                more , (3) SLCcontrol
                                                                tank level          (SLC)      tank corresponding
                                                                                      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                                                  i
              calculation, including the independent verification by the NED. Further                                                ;
                                                                                                                                      '
i            licensee action is necessary to correct this error and ensure that all the
I
              draft calculations are correct.
I
                                                  14
                                      _              ._          . _ _ _ _ _ _ - -        _ _ _ _ _ _____ - -
 
                              '
          .
          ,
                                                  .
                                            -
            .
                                    3)        Worksheet WS-AC4 detailed the calculation of the plant specific value for    i
                                              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
                                                                                                                          '
                                              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      l
.
                                              the RPV was at normal operating pressure. Several administrative errors      I
l                                            that did not affect the technical adequacy of the calculation were noted.    '
                                              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
                                              o        in accordance with other procedures. In order to reduce
                                              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.
                                                                                                                          l
                                                                                                                          !
                                                                                                                          I
                                                                                15
  - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _
 
    *
,
'
                .
          *
  ,
      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  l
            had been taken.    In addition, the resolution of the reactor building roof j
            radiation level instrument, CAC-AQH-1264-3, was unsuitable for reading the  i
            E0P-specified setpoints of 3446 cpm (setpoint 1) and 4213 cpm (setpoint
                                                16
 
                                                                              - _ ___ _ _ _ _ _
    '
.
'
              ,
        '
  .
          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                  !
                                                                                                I
          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.
                                                                                                .
      5)  Step Content - The E0Ps contained both decision and action steps or                    l
          contained more than one action or subject. For example, in Path-3, steps            !
          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.
                                              17
 
                                                          - __              _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - _ - - - - . - .
                                                                                                                                              ,
      '
  .
  ,
                  e
            *
    .
                                                                                                                                                l
        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)
              system pumps by operating at the optimum pressure on the pump tead curve                                                          l
                                                                                                                                                ,
              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.
l      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
l            panel P601. The operator could not detennine which wire entered from                                                              l
              outside the panel because two wires with exactly the same number (i.e.,                                                            l
              number 25) were on the tenninal and both wires entered the same wireway.                                                          l
              This condition was noted at three other steps in the same section.                                                                l
                                                                                                                                                l
                                                                                                                                                '
        3)    Primary Containment Flooding Procedure, sections 7 and 8, step C.3, failed
              to provide the operator with instructions concerning the level to which to                                                        l
              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.
I
              Augmented training or clarification in the E0P should be provided to
              resolve this confusion.
                                                  18
                                                                                                      _ ____ _____-___ _                    -
 
f    ,
) .'
                .
          '
  .
      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      i
            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
                                                19
 
  '
                                        .
                                    '
  .
                                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  i
                                      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 i
                                      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
                                                                        20
    - _ _ - _ - - _ . _ - - _ -
 
  '
,
              .
        '
.
          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.
                                                                                                      i
    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                      l
    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                        I
    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                      I
    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                          l
    specified by Pegulatory Guides 1.3 and 1.4 and the accidents of Chapter 14 of                      '
    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
                                                                                                      l
                                            21
                                                                          _-_  - _ _ _ _ _ _ _ - _ _ -
 
    _- -
        .
t
                      .
              -
.
          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.                                          !
                                                                                            l
          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    I
                  team noted that control room panel alarm, A-03, tile 2-10, monitored the  i
                  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.                                                          ;
                                                                                            i
          3.4 E0P Validation Using Plant Simulator                                          j
                                                                                            i
          To ensure that the E0Ps could be implemented correctly under emergency            j
          conditions, the inspection team developed and performed four accident scenarios    l
          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
                                                      22
  _                  ___    _______________ _-
 
                                                                              --                __
      *
    .-
                .
  4                                                                                                i
        temperature, and depressurized the RPV in accordance with the End Path                    i
        Procedure, when drywell temperature exceeded 300 degrees F.
                                                                                                    l
        The second scenario exercised the Level / Power Control Procedure with alternate
        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
l        +112 inches required performance of Path-4. The radioactive steam leak in
        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.
l
        The fourth scenario required venting primary containment to control primary
.
        containment hydrogen concentrations. RHR loop B was out of service throughout
l
        the scenario. A lar
        emergency bus (E-3)      ge break
                              initiated      LOCA
                                        a reactor  coincident
                                                  scram  and an with
                                                                  ECCSa failure
                                                                        actuation.of the
                                                                                      The4160
                                                                                          A vcit
        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
        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
                                                  23                                              1
 
                                                                                                                                                                                              '
                    ,, .                                                                                                                                                                        f
                                                                              .
                                                                        *
.
                                                                    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                                                  ,
                                                                          control operators and directed the performance of the E0Ps and that the                                                l
                                                                          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                                              <
                                                                          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
                                                                                                                          24
- _ _ _ - - _ _ _ _ _ _ _ - - _ - _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ -                                        _ _ _ _ _ ______ _ __                -_      _ _ - _ _ - _ _ _ - _ _ _ - _ - _ _
 
      *
    ,,
                  .
            *
  .
                                                                                                +
              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
              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
                                                                    -                                  ,
              Release Control Procedure required the operators to execute the subsequent              )
              actions of the flowpath only if an ALERT was not declared as a result of a              i
              radioactive release. As discussed in Section 3.1.1, these actions were                  l
l            event-based and not appropriate for inclusion in the E0Ps. Durir.g the                    l
              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
              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.
'
              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                '
              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                l
              action is necessary to identify, train, and procedurally support a more
              effective method for monitoring the critical action steps.
        3.5 Operator Interviews
                                                                                                      i
        The inspection team conducted interviews with three shift operating                          '
                                                                                                      -
        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                          !
        approximately one hour. The following observations summarize the comments                    i
        volunteered by the operators.
                                                  25
                                                      __- _ _ - _ - _ _ _- __-_ _ ____-__ _ ___  ___
 
      *
    ..
                  *
                .
  e                        .                .
        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      .
              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.  j
              The operating instructions delineated the basic philosophy and established  i
              practices for personnel assignments.                                        l
        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  l
              and simulator training were devoted to the use of E0PS; however, formal    !
              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
l            verification and validation process.    For example, verification of the
              technical adequacy for selected E0Ps was performed during classroom        .
                                                                                          '
              discussions.
        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
i              were inraediately accessible by the operators. All of the operators
              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
,
                                                  26
l
 
                                                                                          _
      *
    .i
  ,
                  *
                .
            '
  .
              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
l        walkthrough of all primary containment vent paths which had not previously been
l        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      l
        pressure (i.e., 70 psig in step PC/P-12) and for conditions of high hydrogen or      i
        oxygen (i.e., 6 percent and 5 percent, respectively, in step PC/H-16). The          i
        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            l
        removing the decay heat load required by Revision 4AF of the BWROG EPGs.            I
        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
                                                  27
                                                                                            I
 
f.,*
,
  '          *
          ,,
        '
  e
    and informed the licensee of the conclusions identified in this report. Mr.                            l
    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.
l                                                                                                          l
1
                                                                                                            l
l                                          28
                                                                      _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ -
 
                                        '
        .'
  ,
                                                                '
  '
                                                            .,
                                                          '
  e
                                                                                            APPENDIX A
                                                                                        PERSONNEL CONTACTED
                                                      A large number of people, including the following licensee personnel, were
                                                      contacted during the inspection.                                            I
                                                                                                                                    :
                                                            *J. Harness, Plant General Manager
                                                            *K. Enzor, Director, Regulatory Compliance                              ,
                                                            *L. Jones, Director, Quality Assurance and Quality Control              i
                                                            *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                                              J
                                                              M. Amato, Operations                                                l
                                                            *M.  Williams, Senior Specialist, Operations
l                                                              D. LaBelle, Shift Supervisor, Operations
l                                                              M. Schall, Shift Foreman, Operations
l
                                                              E. Hutt, Shift Foreman, Operations                                  l
l
                                                              K. Chism, Shift Foreman, Operations                                  i
'
                                                              K. Horn, Shift Foreman, Operations
                                                              R. Gibbs, Shift Technical Advisor, Operations
l                                                              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                                            l
                                                              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.
I
                                                                                                A-1
                                                                                                                                  ,
h    _ . _ . _ _ _ . _ _ _ _ _ _ _ _ _ - . _ . . _ _ _
 
      *
  &*.
                                                                                                                  .
                                                                                                                  I
  a
                *
            ,,
          '
  e
                                            APPENDIX B                                                            l
                                        DOCUMENTS REVIEWED
                                                                                                                  l
                                                                                                                  l
        Emergency Procedure Guidelines (EPGs), Revision 4AF, March 1987                                          l
        Plant Specific Technical Guideline (PSTG) for EPG Revision 4, Draft D                                    i
        EPG/PSTG Step Documentation, Draft D                                                                      l
        Appendix A PSTG/EOP Step Documentation, Draft C                                                          l
        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                                                    l
        General Area Personnel Dose Rates Versus Time (post-LOCA)                                                l
        Emergency Operating Procedures (E0Ps):
            E0P-01-UG, " User's Guide," Draft B                                                                  l
            E0P-01-FP-1, " Path-1," Draft 0                                                                      l
            E0P-01-FP-2, " Path-2," Draft E
            E0P-01-FP-3, " Path-3," Draft E
            E0P-01-FP-4, " Path-4," Draft D                                                                      l
            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                                            I
            E0P-02-PCCF, " Primary Containment Contml Procedure," Draft F
,            '0P-03-SCCF, " Secondary Containment C  .rol Procedure," Draft G                                  l'
l
            E0P-04-RRCP, " Radioactivity Release Co.. trol," Draft D
            E0P-01-ALC, " Alternate Level Control," Revision E                                                  i
            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                                                  .
                                                                                                                '
            E0P-01-SEP-03, " Suppression Pool Spray Procedure," Draft C
            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
i                  for EPG Revision 2," Revision 001
                                                B-1
'
                                                                                _ _ _ _ _ _ _ _ _ - _ _ _ _-_ -
 
l
                                                                                1
        ,
  g,*
  *              *
                ,,
              '
  a
                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)
i
,
)
                                                    B-2
L-______-____-_________________-    _ _ _ _ _ _
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