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{{Adams
#REDIRECT [[IR 05000289/1987011]]
| number = ML20237H879
| issue date = 08/10/1987
| title = Insp Rept 50-289/87-11 on 870529-0709.No Violations & Five Unresolved Items Noted.Major Areas Inspected:Power Operations & Transition Into & Out of Letdown Cooler Replacement Outage,Focusing on Operator Performance
| author name = Baunack W, Conte R, Johnson D
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| addressee name =
| addressee affiliation =
| docket = 05000289
| license number =
| contact person =
| document report number = 50-289-87-11, NUDOCS 8708170394
| package number = ML20237H859
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 33
}}
See also: [[see also::IR 05000289/1987011]]
 
=Text=
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v  .
                                  U. S. NUCLEAR REGULATORY COMMISSION
                                                                                                                            k
                                                REGION I
l          -Docket / Report No. 50-289/87-11                      License: DRP-50
            . Licensee:      GPU Nuclear Corporation                                                                        ,
                              P. O. Box 480
                              Middletown, Pennsylvania 17057                                                              ..
              Facility:      Three Mile. Island Nuclear Station, Unit 1
              Location:      Middletown, Pennsylvania
              Dates:          May 29 - July 9, 1987
              Inspectors:    D. Coe, License Examiner, Region I (RI)
                              R. Conte, Senior Resident Inspector (TMI-1)
                              D. Johnson, Resident Inspector (TMI-1)
                              S. Peleschak, Reactor Engineer, RI
              Reporting        jj j
              Inspector:      Mft      .MV                                                                        g,7
  >
                              D.~ Johns n, Re ident Inspector
              Reviewed by                      v>v-  -
                                                                                                                  1/7/J7
                              R. Conte // enior Resident Inspector                                                  Date
              Approvedbh:          ),    u  (L4ws-                                                                /8/O
                              W. Baunack,- Acting Chief                                                            Da'te
                              Reactor Section No. 1A
4
                              Division of Reactor Projects
              Inspection Summary:
            The NRC resident staff conducted safety inspections (210 hours) of power
              operations and the transition into and out of the letdown cooler replace-
              ment outage, focusing on operator performance, including-event response.
              The following events were reviewed: letdown pre-filter noble gas
              release; reactor trip of June 12, 1987; and, reactor protection system
              (RPS) actuation during reactor startup. Items reviewed in the plant
              operations area were: reactor coolant system leak rate, reactor shutdown
              for letdown heat exchanger replacement, letdown heat exchanger problems,
              and plant shutdown and startup. With respect to system operability, the
              following items were reviewed: nuclear service river pump 1A overhaul
              and spurious actuations of the control building chlorine detection
              system. Licensee action on past inspection findings was also reviewed.
              A review of the implementation of the fire protection program was also
              conducted.
        8708170394 870811
        PDR
        0        ADOCK 05000289
      -
                            ppg
                                                                            . _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _
 
- _ _ _ _ _ _ .      _ _ - .          _ _ - - _  __ _ _ _ _ _ _ _ _ _ _ .    _ _ _ _    _
                                                                                                .
        .
        .
                                                                            la
                Inspection Results:
                No violations were identified; five. items reviewed in the course of the
                inspection remain unresolved. One item concerned problems associated with the
                high chloride levels in the reactor coolant system (RCS) identified during the
                outage. This will require NRC staff review of licensee's evaluation of addi-
                tional chemistry samples. The second item concerns the review and approval of
                Technical Specifications Change Request (TSCR) No.172 for the reorganization
                of the licensee corporate organization. The third item concerns the repeated
                spurious actuations of the new chlorine detection system which actuates pro-
                tective actions for the control building ventilation system. A licensee-
                identified violation discussed during review of the fire hazards analysis will
                require additional lice.isee action to get the appropriate Fire Hazards Analysis
                Report (FHAR) exemptions.        The last item concerns the operability of NI-9, a
                source range detector for the remote shutdown panel.                  Corrective actions to
                repair this detector and establish requirements for its operability are yet to
                be determined.
                The transitions into and out of the letdown cooler replacement outage went
                relatively smoothly with no major equipment problems. Operator performance
                problems appear to be isolated cases and are being dealt with by licensee
                management.
                                                                                                                                        !
                                                                                                                                        !
                                                                                                                                        i
                                                                                                                                        ;
                                                                                                                                        1
                                                                                                  _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
                                                                                                                                        J
 
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                                                                            _ _ _ _ - _ - . - - - _ _ - _ _ _
.
  .
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                                _ TABLE OF CONTENTS
                                                                                    Page
    1. Introduction and Overview. . . . . . .    ...........                                      2
    2. Plant Operations . . . . . . . . . . . . . . . . . . . . . .                                2
    3. Maintenance / Surveillance - Operability Review. . . . . . .                        10
    4. Event Review . . . . . . . . . . . . . . . . . . . . . . .                          13
    5. Fire Protection Annual Review. ..............19
    6. Licensee Action on Previous Inspection Findings. . . . . .                        24
    7. Exit' Interview . . . . . . . . . . . . . . . . . .. . . . .                      27
    8. Attachment 1 - Activities Reviewed
                                                                                                                                                !
                                                                                                              _ - _ - _ _ _ _ _ - _ _ _ _ _ _ -
 
- _ __      -      _-      ___-
      .
                                                  DETAILS
        1.0 Introduction and Overview
              1.1 NRC Staff Activities
              The overall purpose of this inspection was to assess licensee activities
              during the power operations and cold shutdown modes as they related to
              reactor safety and radiation protection. Within each area, the inspectors
              documented the specific purpose of the area ~under review, acceptance
              criteria and scope of inspections, along with appropriate findings / con-
              clusions. The inspector made this assessment by reviewing information on
              a sampling basis through actual observation of licensee activities,
              interviews with licensee personnel, measurement of radiation levels, or
              independent calculation and selective review of listed applicable docu-
              ments.
              On June 19, 1987, a resident inspector also participated in a licensee
              meeting with NRC: Region I staff to discuss licensee's tentative plans to
              shift to a site emergency plan instead of one for each unit.                                The licensee
              explained that plant conditions at TMI-2 do not warrant a specific plan.
              For an event at TMI-2, the combined (site) plan would be oriented toward
              technical problems being resolved by TMI-2 personnel, while TMI-1 would be
              responsible for overall emergency plan implementation such as off-site
              notification or recall of plant personnel. A separate meeting summary
              will be documented by NRC staff.
              1.2 Licensee Activities
              During this period, the licensee operated the plant at full power, except
              for a two-week shutdown to replace the letdown heat exchangers. The
              reactor was shut down on Friday, June 11, 1987; and, during the shutdown
              at approximately 11 percent power, the reactor tripped due to reactor
              coolant system (RCS) high pressure (see section 4). The plant was
              restarted on Friday, June 26, 1987, and ended the period at full power.
              The problem with Once-Through Steam Generator (OTSG) tube fouling was not
              as evident as prior to the shutdown.      OTSG 1evels wer- somewhat lower
              after startup, especially in the "B" 0TSG. Details concerning the letdown
              heat exchanger leaks are discussed in paragraph 2.2.1.
        2.0 Plant Operations
              2.1 Criteria / Scope of Review
              The resident inspectors periodically inspected the facility to
              determine the licensee's compliance with the general operating
              requirements of Section 6 of the Technical Specifications (TS) in
              the following areas:
              --
                      review of selected plant parameters for abnormal trends;                                          '
                                                                    ______. _____ -____________ ____ __-_ _ -
 
  . _ . ._ - _
                    - ___ _-              _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ - _ _  _ _ _ _ _ - _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _
.
                                                                                                                                                                                  '
.
                                                                                        3
              --
                      plant status from a maintenance / modification viewpoint, includ-
                      ing plant housekeeping and fire protection measures;
              --
                      control of ongoing and special evolutions, including control                                                                                                i
                      room personnel awareness of these evolutions;
              --
                      control of documents, including logkeeping practices;
              --
                      implementation of radiological controls; and,
              --
                      implementation of the security plan, including access control,
                      boundary integrity, and badging practices.
              The inspectors focused on the specific areas listed in Attachment 1.
              As a result of this review, the inspectors reviewed specific evolu-
              tions in more detail as noted below.
              2.2 Findings / Conclusions
              2.2.1          Letdown Heat Exchanger Leakage
              On June 3, 1987, the licensee was operating at full power with
              letdown through the "1B" letdown heat exchanger (HX) MU-C-18. The
              "A" letdown heat exchanger MU-C-1A was isolated due to the identifi-
              cation of a leak on May 14, 1987. This leak (in the "A" HX) had
              been of sufficient magnitude (estimated at 0.5 gpm) to render the
                intermediate closed cooling (ICC) system radiation monitor RM-L-9
              inoperable due to the meter reading being at full scale (10 E6
              counts per minute (cpm)). On June 1,1987, the licensee again
              experienced a leak of similar magnitude from the "B" HX, which also
              produced a RM-L-9 reading of greater than 10 E6 cpm. The leak
                increased during the next two days to approximately 3.3 gpm. Then, on
              June 3, 1987, the leak rate abruptly increased to an estimated 30 grm.
              Technical specifications prohibit operation for more than 24 hours
              with known (identified) RCS leakage greater than 10 gpm. The
                licensee shifted letdown flow back to the "A" HX and considered a
              plant shutdown if the "A" HX did not show a significantly lower leak
                rate. The "A" HX leak rate was subsequently measured at approxi-
              mately 0.4 gpm and remained that way until June 12, 1987, when
                leakage abruptly increased to 0.8 gpm. At this time, the decision
              was made to shut down the plant to accomplish repairs.
              During the period of time that the "B" letdown HX was in service and
                leaking to the ICC system, the excess level generated in the ICC
                system surge tank was being drained to the auxiliary building sump
                (at approximately 3 hour intervals) via vent valves on the ICC
                system cooler in the 265 foot elevation of the auxiliary building.
              A vent on the surge tank located in the fuel handling building was
                temporarily directed to an opening in the ventilation system, which
                                                                                                                                                      _ _ _ _ _ _ _ _ _ _ - _ _ -
 
                    __ - _ __ - ____-_    - __- -_-_-            _ - - _ _ _ _ _ - _ -  _ - _ _ _ - _ - _ _-
(
                  .
                  .                                          4
                          exhausts through carbon.and particulate filters and is monitored by
                          RM-A-8. The RM-A-8 gas' channel indicated a slight increase during
                        .the time frame June 1-3, 1987, and it was-estimated that approximately 101
l
                          curies, mostly Xenon 133 and Xenon 135, were released during this two-day
                          period. This release was coming mostly from the ICC system surge tank
.                        vent as'the,RCS was partially degassing through the leak into the surge.
                          tank.
                                                                                                                I
                        ,The in'spector_ conducted independent radiation surveys of the areas
                          of-.the auxiliary building which contain ICC piping to confirm
                          licensee information. These surveys showed some readings (e.g., ICC
                          surge tank) to be garoximately 80 mrem /hr. Maximum readings were
                          30 mrem / hour on some. portions of the ICC system piping. This piping
                          would normally be reading less than'1.0 mrem / hour. Licensee sam-
                          pling of:the ICC system indicated.that total gamma activity was-
                          approximately 0.25 micro curies per millimeter (micro-Ci/ml). The
                          RCS activity was approximately 2.8 micro-Ci/ml during this period.
                          The inspectors discussed these changing radiological prameters for
                          the ICC system and the release that was occurring from the ICC
                          system surge tank with appropriate radiological control personnel.
                          Licensee radiological control personnel had evaluated these condi-
                          tions and concluded that they did not present a significant problem as
                          long-as leakage did not increase substantially. The noble gas .
                          release was'a small percentage of technical specification quarterly
                          limits. The increase in general area radiation levels in the
                          affected auxiliary building and fuel handling building areas was not
                          in areas normally traversed by personnel, except'for routine auxil-
                          iary operator-(AO) tours and surveys and, therefore, ALARA (as low
                          as' reasonably achievable) principles were not a concern. The
                          inspector concluded that, although this leak' rate (approximately 3.3                ,
                          gpm during June- 1-3,1987) was not desirable, the licensee was not
                          violating technical specifications and no substantial exposures would
                          likely result from the release or increased radiation levels.
                          Subsequent to the shifting of heat exchangers from the "B" to the
  '.
                          "A'! on June 3,1987, the total release indicated on RM-A-8 and the
                          radiation levels and activity levels in the ICC system all showed
                          marked decreases. Although only one heat exchanger was available,
                          the licensee continued to operate while making contingency plans to
                          shutdown.
                          The licensee issued Special Temporery Procedure (STP) 1-87-029,
                          " Guidelines for Shutdown /Cooldown with Letdown Isolated," on June 5,
                          1987. This procedure provided guidance to the operators in the
                          event that leakage from the "1A" letdown heat exchanger became
                          unmanageable (a limit of 2 gpm was set) and both heat exchangers
                          were required to be isolated. The inspector reviewed this procedure
                          and discussed its implications with operations personnel. Although
    _ _ _ _ _ _ -                -
                                                                                                                \
 
                          - _ _ _ _ - _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ .__
                      .
                      .                                                                        5
                                                                                                                                                                                !
  !                      shutdown without letdown is not desirable, a simulation of this
                          event was done on the plant simulator and showed that pressurizer
                          'evel would not reach high level limits during a rapid controlled                                                                                    !
                          shutdown, followed by plant cooldown.                                                                      The inspector concluded again              I
                          that even though this was not a desirable condition, it could be
                          managed by licensee personnel.
                          2.2.2                                  heactor Shutdown /Cooldown for Heat Exchangers Replacement
                          On June 12, 1987, the decision was made by licensee personnel to
                          shut down the plant to cold shutdown conditions to replace both
                          letdown heat exchangers, MU-C-1A/18. Leakage had increased abruptly
                          on the morning of June 12, 1987. The licensee evaluated the situa-
                          tion and concluded that the leak could be expected to get larger. There-
                          fore, since shutdown without the availability of the letdown system was
                          not advisable, plant shutdown for repair was the conservative
                          option.
                          The licensee employed an extra shift of personnel to assist normal
                          plant operations staff in conducting the shutdown. This has been
                          standard practice for major evolutions conducted at TMI-1. Plant
                          power reduction was commenced at approximately 9:15 p.m.                                                                                          The
                          inspector verified that the shutdown was being conducted in accor-
                          dance with Operating Procedure (0P) 1102-10, Revision 39, dated
                          March 20, 1987. A reactor building purge was ia progress at the
                          time and the inspector verified consistent and acceptable radiation
                          monitor reading on RM-A-2, reactor building monitor, and RM-A-9,
                          reactor building purge exhaust stack monitor. QA monitoring person-
                          nel were also present for the shutdown. The reactor shutdown was
                          controlled properly with no problems until just after the turbine
                          generator was tripped. At this time, reactor power was approximate-
                          ly 10-12 percent and was being controlled by the turbine bypass
                          valves. The feed pumps were being controlled in manual and the
                          operator did not maintain the proper flow to the OTSG's. The
                          resultant lowering of OTSG levels resulted in a high RCS pressure
                          condition and subsequent reactor trip (see section 4).
                          Overall, the cooldown was properly controlled. Based on a sampling
                            review, the cooloown procedure was properly followed. Operators
                          were particularly plotting reactor coolant system (RCS) pressure (P)
                          and temperature (T) within the P-T curve limits and cooldown rate
                            (temperature vs. time) was also plotted. The inspector noted that
                          the cooldown curve used was not that specified in the licensee's
'
,
                          cooldown procedure, but it was a suitable equivalent.
                            2.2.3                                Plant Heatup/ Reactor Startup
                          On Ju'e 25,1987, the licensee commenced plant heatup to 525 F,
                            after the completion of the letdown cooler replacement. The inspec-
                            tor witnessed portions of the plant heatup over a two-shift period
                            on June 25, 1987. Initial heat up operations with three RCP's in
    _ - _ _ - _ _ - _  _                  _                                  _              . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ - _ - _ - _ -
 
                                .. -            -        _ _ _ _ - _ ____ _ -__ _ _
  "'
(I
  .'                                        6
        service were conducted smoothly with few problems. The inspector
        verified proper licensee tracking-of RCS heatup rates as plant
        heatup is limited to 100 F/hr. During:the heatup, the licensee
        identified a high chloride (C1) concentration. in the RCS. The
        chloride sample indicated approximately 0.45 ppm (p' arts per million).
        The technical specification limit for critical operation is
      '0.15 ppm. ' The heatup was stopped at approximately 375 F in order to
                  .
      . clean up the RCS. Maximum letdown flow of 120 gpm was established
        and, 'using the installed. letdown demineralized and filtering sys-
        tems, chloride concentration was lowered to approximately 0.129 ppm
I'      by 5:00 a.m. on' June 26, 1987.. Plant heatup was recommenced and hot
        shutdown was reached at 9:00 a.m.
        Licensee representatives could not positively identify the chloride
        source. One plausible explanation was related to the fact that, earlier
        in the outage, high chloride concentration was detected in the "A" decay
        heat (DH) loop when the plant was in cold shutdown. Residual chlorides
        that remained in the system could have leached-out of RCS metal crevices
        during the heatup. The licensee established some data which'showed
        that lithium eJditions for pH control would temporarily cause the
        chloride concentration to increase. The source of the chloride
      . intrusion.into the decay. heat system was also unknown.
        The leaching-out process is'a plausible explanation for the chloride
        increases when heatup commenced and proper chemistry was being
        established. Final chloride concentration was reduced to less than 0.1
        ppm. The licensee chemistry department is still studying the problem and
        has sent several RCS samples off site to an independent lab for
        analysis. The licensee intends to report the results of the inves-
        tigation when completed. The inspectors will review the results of
        that investigation in future inspections.    This item is unresolved
      .(289/87-11-01).
        Just prior to heatup, the licensee conducted a special test, Special
        Temporary Procedure, STP 1-87-033, to adjust the intermediate closed          j
        cooling system flow in preparation for changing to a parallel cooler          '
        arrangement for the letdown heat exchangers. Parallel cooler
        operation, in addition to modifications in the control circuitry for          ,
        the cooler outlet isolation valves, MU-V-2A/B, were the changes made          j
        in an effort'to reduce the failures that were observed in the
        letdown coolers. MU-V-2A/B now will only close approximately 10
        percent during Engineering Safeguards Actuation System (ESAS)
        testing and during the testing of the interlock for radiation monitor
        RM-L-1.    Previously, these valves would shut during the quarterly testing
        of these valves. MU-V-2A/B function as the inside containment isola-
        tion valves for the letdown line. The inspector reviewed the
        changes to OP 1104-8, Revision 27, dated January 26, 1987, "Interme-
        diate Cooling System," and OP 1104-2, Revision 61, dated January 6,
        1987, " Makeup and Purification System," to verify that proper safety
        evaluations were made.
 
                                                                    _ _ - _ _ _ _ - _ _ _ _ - _ _ __
  .
                                        7
l  The inspector reviewed the modification package, Safety Evaluation
    (SE) No. 128965-001, to verify that proper consideration was given
    to technical specification and Final Safety Analysis Report (FSAR)
    requirements concerning the operation of MU-V-2A/B. This modifica-
    tion was similar to the controls provided for other containment
    isolation valves such as IC-V-2 and NS-V-35. The inspector verified
    that the licensee was granted an exemption from the quarterly
    cycling requirements of Section XI of the ASME (American Society of
    Mechnical Engineers), B&PV (Boiler and Pressure Vessel) Code, for
    MU-V-2A/B. This was a previously granted exemption as a result of
    NRR evaluation of the licensee's submittal of their second ten year
    inservice testing (IST) program.
    The inspector also reviewed the completed test procedures TP 455-1
    and 455-2 that verified propar operability of the modification. The
    valves will still close on a valid ESAS signal as long as the new
    test switches are in the normal position.    The position of the
    switches is administrative 1y controlled by procedure.
    Also, during the heatup, an RPS actuation occurred when in shutdown
    bypass conditions and the event is detailed in paragraph 4.4.
    Overall, the licensee appears to have taken proper corrective action
    to correct the problem with the leak development in the letdown heat
    exchangers.
    2.2.4  Early Criticality
    At 4:35 a.m. on June 24, 1987, the licensee identified that the reactor
    was critical below the specified range for estimated critical rod posi-
    tion. The reactor was declared critical with Group 6 at 31 percent with
    the maximum estimated critical position (ECP) at 65 percent on Group 7 and
    minimum position at 54 percent on Croup 6. In accordance with facility
    procedures, operators immediately inserted control rods to assure the
    reactor was sufficiently shut down (1% delta K/K). Apparently, " excess
    fuel reactivity" was underestimated due to depletion of lumped burnable
    poison in the reactor core. Nuclear engineers processed a procedure
    change to the applicable reactivity curve and reevaluated the ECP. Then
    reactor startup continued without similar incident.
    With the new calculation of ECP at 58 percent withdrawn on Group 6,
    the minimum rod position for criticality was calculated to be 14
    percent withdrawn on Group 6 and maximum was 30 percent on Group 7.
    The actual critical rod position was 31 percent on Group 6.                                      '
    The resident inspectors first learned of the problem from a log
    review during backshift inspections later that weekend.      Initial
    inspector review of the Temporary Change Notice (TCN) (No.
    1-87-0143) on June 28, 1987, generated additional questions. The
    TCN safety evaluation (on file in the control room) was very brief
 
                                            _ _ _ _ _ _ - _ _ _    _ _ _ ___      _- . _ - -        _ _ _ _ _ _
  .
  .                                    8
    (handwritten with one of four lines illegible due to copying of the
    original TCN) and it provided little obvious technical basis for
    correcting the fuel excess reactivity term by 0.25 percent delta
    K/K. During later discussions with the licensee's nuclear engineer,
    it became clearer as to the basis for the above-noted change. These
    discussions occurred through the week of June 27, 1987, and in a
    conference call between NRR staff, Region I staff, and the licensee
    on July 6, 1987. A summary of these discussions is presented below.
    The licensee has been tracking the all rods out (AR0) boron concen-
    tration as being consistently high above target since the beginning
    of reactor core life for this cycle of operation.              For the startup
    on June 27, 1987, core life was seventy effective full power days
    (EFPD) and the ARO boron concentration was approximately 920 ppm
    (parts per million) with the target at 870 ppm.              The ARO boron
    concentration is a measure of the excess fuel reactivity, since the
    measurement is made essentially with all rods cut o' the core and
    with compensation for other reactivity terms such is " power doppler
    defect" and equilibrium xenon. Surveillance Procedure (SP)
    1301-9.5, Revision 22, effective March 11, 1987, " Reactivity Anomaly,"
    makes the measurement and, on a sampling basis, the inspector determined
    it to be technically adequate to meet TS 4.10. Similarly, the inspector
    determined the technical adequacy of the ECP Procedure 1103-15B, Revision
    6, effective March 13, 1987, " Estimated Critical Conditions."
    These results indicated that the core is more reactive than that
    reflected by the target ARO boron concentration. The target curve
    is provided by the Nuclear Steam Supplier (Babcock and Wilcox (B&W))
    with a target band. The above-noted results were within that band
    (for 70 EFPD the band is 750 ppm to 970 ppm).              Licensee representa-
    tives provided two reasons for the ARO boron concentration being off
    target.
    There appears to be a modeling problem with lumped burnable poison
    (LBP) burnout rate. The LBP is placed in a fuel assembly designed
    to " burn out" during reactor operation to provide extended core life
    (12 to 18 months). It has been determined at other B&W plants with
    extended core life that, la % in core life, the ARO boron concentra-
    tion approaches the target s ave, thus the reason for not adding a
    correction factor to all tFe appropriate reactivity curves.                The                                  j
    other reason provided by the licensee representatives is the buildup                                            ;
    of Plutonium (Pu-239), which adds fuel reactivity of approximately                                              l
    .26 percent delta K/K, which is not factored into the reactivity                                                !
    curves for this cycle of operation. The licensee representatives                                                i
    pointed out that incorporating this factor into the ECP would have                                              I
    resulted in achieving criticality in the calculated target band.
    The inspector noted that a brief explanation of this phenomenon was                                              l
    provided on a one page SE written by the lead nuclear engineer and                                              J
    attached to a copy of the ECP calculation. The forms provided by
l  the licensee's technical and safety review process procedure were
,                                                                                            _ _ _ _            _D
 
                              _ _ _ _ _ _ _ _ _  __
                                                      _ _ _ _ _ _ _ _ _ - _ _ _ _      ____-_    _ - _ _ _ - _
                                                                                                                          _-
  .
  .                                              9
    not.directly used in this instance, but the SE appeared to be
    technically sound. The inspector expressed concern that the infor-
    mation was not consolidated into clear and concise presentation,
    using appropriate administrative control forms, as justification to
    proceed with startup. The licensee acknowledged this comment.                              During
    the confe*ence call of July 6,1987, the licensee committed
    to sending a letter to NRC staff within two weeks of that date
    explaining the above in a clear and concise manner for NRR staff
    review, along with appropriate corrective actions. The inspector
    had no additional comments on this matter.
    2.2.5  Licensee Reorganization
    Dn Friday, May 29, 1987, licensee representatives announced a
    reorgani::ation of GPU Nuclear, effective June 1,1987. Nine divi-
    sions under the Office of the President remain; but, five of the six
    corporate-based divisions changed functional responsibilities.                              No
    changes were made to the Communications Division or the site operat-
    ing divisions: TMI-1, Oyster Creek, and TMI-2.
    The divisions with new functional responsibilities are as described
    below. (1) A new Division of Planning and Nuclear Sefety is headed
    by Dr. Robert Long, formerly Director of Nuclear Assurance Division
    (NAD), a disbanded division. This new division also has the Licens-
    ing Department, .formerly under the Division of Technical Functions.
    (2) The Division of Administration is headed by Mr. F. Manganaro,
    formerly Director of the Division of Maintenance, Construction and
    Facilities. This division picks up, in part, the Training and
    Educaticn Department, formerly under NAD.                (3) The Division of
    Maintenance, Construction and Facilities is headed by Mr. R. Heward,
    formerly Director of Radiological and Environmental Controls.                              (4)
    Another new division is the Division of Quality and Radiological
    Controls and it is headed by Mr. M. Roche. This division picks up
    the Quality Control function, formerly under NAD.                            (5) The Division
    of Technical Functions (remains under Mr. R. Wilson), which essen-
    tially remains in tact, except for the removal of its licensing
    responsibilities as noted above.
    The inspector noted that the reorganization was inconsistent with
    that specified in Technical Specifications (TS) Section 6, Figure
    6-1. L;censee representatives acknowledged that fact and indicated
    that this change was not substantial in that the responsibilities did
    not change management level positions and the operating divisions were
    unaffected. Apparently no 10 CFR 50.59 safety eveluation was conducted
    for this change prior to June 1, 1987, to assess whether or not a tech-
    nical specification clarification was needed on a pre-implementation
    basis. However, both GPUN licensing management and the GPUN President
    discussed these changes with NRC Region I management on May 29. The
    licensee committed to submitting a Technical Specification change by June
    19. To clarify the technical specification, on June 19, 1987, the
                                                                                                                              i
r                                                                                                                - - - _ -
 
  -- _.  _ _ _ _ - -      . _ _ _.  - - _ _ _ _ _ _ - _ _ __ . _ _ _ _ _ _ _ _ _ _ _ _    _- _ _ _ _ _
                                                                                                          .)
                                                                                                            i
.
                                                                                                          .)
,                                                                                      10
                                                                                                            I
              licensee submitted Technical Specification Change Request (TSCR) No.172                        ]
            to make the TS Figure 6-1 more in line with the current reorganization                          j
                                                                                                              '
            and the question on significant safety hazard is addressed by that letter.
            This area is unresolved pending NRC staff review and approval of-
            TSCR No. 172(289/87-11-02).
            2.3 Plant Operations Summary
              Licensee management and the quality assurance department continued
            their detailed attention to and involvement in plant operations.
            Generally, operations were carried out formally and in accordance
            with licensee procedures. The errors made by personnel resulting in
            the reactor trip on June 12, 1987, and the RPS actuation on June 23,
              1987, were isolated incidents of individuals not using appropriate
            judgement in the conduct of their particular function at the time.
            Operator action to recover from these incidents was performed
            adequately.
            Activities requiring safety review could have beer, enhanced with the
            better use of the consolide:ed corporate policy in this area.
      3.    Maintenance / Surveillance - Operability Review
            3.1 General Criteria / Scope of Review
            The inspector reviewed activities to verify proper implementation of
            the applicable portions of the maintenance and surveillance pro-
            grams. This was a spontaneous review to capture ongoing activities
              in the plant spaces as they occurred. The inspector used the
            general criteria listed under the plant operations section of this
              report. Specific areas of review are listed in Attachment 1.                              A
            more detailed review of equipment operability was also addressed
            below.
            3.2 Selected Equipment Operability Review
            The inspector reviewed licensee maintenance (preventive and corrective)
            and surveillance activities to assure nuclear service river water pump
            operability. Specifically, the inspector was to verify that:
            --
                      equipment was appropriately tagged out of service;
            --
                      procedures were being followed by maintenance personnel and the
                      procedures were current;
            --
                      test equipment was calibrated;
            --
                      replacement parts were appropriately noted and certified; and,
                                                                                                            l
                                                                                                          -
 
                                                                - _ _ _ - - _ - _ _ _ _ _ _ _ _ _ _ _ _ _
t  !
      .
      .                                        11-
  l
          --
                -the maintenance history for the nuclear river water system
                indicated no. major problems.
          The inspector reviewed the maintenance and surveillance that was conducted
          on the "1A" nuclear services river water pump (NR-P-1A). The pump was
          observed by.the licensee' to.have brass filings emitting from the' packing-
        - gland and this indicated ~ some problem with the bearings on the pump :, haft
          and housing. The pump motor also indicated high vibration readings.
                                                                                                          ~
          NR-P-1A'is a' deep shaft-type pump used to supply river water to the
          nuclear service closed cooling system heat exchangers. The licensee
          replaced the majority of pump components during this maintenance, inclu-
          ding the submersible bowl, impeller, shaft, shaft to support column
        . bearings,- and packing.
          The inspector reviewed the conduct of the work as it was being accompl-
        'ished, discussed the -various aspects of the repair with licensee
          personnel, anrl< reviewed the following documentation associated with the
          repair and testing.
          --
                Job. Ticket (JT) CM-855.for NR-P-1A overhaul
          --
                Corrective Maintenance'(CM) Procedure 1410-P-14, deep' shaft
                pump (RR, NR, SR, RB) yearly overhaul.
          --
                SP 1300-3I A/B, Revision 25, completed June 13, 1987,'"NSRW
                Pump Functional Test and Valve Operability Test."
          3.3 Findings / Conclusions,
          3.3.1 Nuclear Service River Water pump
          Generally, maintenance personnel involved in the repair evolution
          were knowledgeable of the equipment that was being repaired.- The
        -inspector observed portions of the pump impeller-t bowl clearance
          adjustment. This involved applying a pre-load to the shaft using a
          "dillon load cell" and chain fall arrangement. The amount of
          pre-load force that the maintenance personnel used was as specified
          in CM Procedure 1410-P14. The inspector observed initial pump
          operation and packing adjustment after the repair was completed.
          Maintenance personnel used appropriate caution to ensure that the
          packing was well lubricated-and that sufficient water flow was
          available to prevent the packing from overheating. The evolution
        .was coordinated well with operations personnel. The pump was
          allowed to run for several shifts to ensure proper operation prior
          to performance of the surveillance test.
        .The inspector also observed the post-overhaul inservice inspection
          (ISI) of the pump impeller that was replaced. Some portions of the
          impeller were worn substantially and portions of the shaft'also
          exhibited evidence of some wear. The post-overhaul ISI examination
          of the worn parts is a licensee initiative in addition to the normal
 
p
t -
                                                                                                a
    .
    .-                                      12
l
        corrective maintenance program review. This is, intended to ensure that
        adverse or unexpected pump degradation'due to the harsh conditions to
        which this pump is subjected will be appropriately identified and tracked
        for corrective action.
        Post-maintenance surveillance test results were reviewed by~the
        inspector and data was verified to be within acceptable tolerances.
        The inspector concluded that this maintenance evolution was conduct-
        ed in accordance with appropriate maintenance and surveillance
        procedures. Persennel involved were knowledgeable of the work being
        done. The inspector had no safety concerns with this evolution.
                                              ~
        3.3.2 Core Flooding System Valve Operability
        The inspector witnessed the performance of SP 1303-11.21, Revision
        7, dated December'23,1983, " Core Flooding System sives Operability
        Test." Subsequently, the inspector reviewed.the i ucedure for
        technical adequacy to meet the requirements of TS 4.5.2.3 for check
        valve CF-V4A/B and isolation valve operability. This test also
        satisfies ASME inservice testing for these valves (partial stroke
        testing) as required by TS 4.2.2.
        On a sampling basis, the inspector verified that the operators
        properly implemented the procedure during the cooldown sequence.
      . Appropriate data was recorded and it was within test acceptance
        criteria.
        Subsequent to the test, the inspector reviewed the procedure for
        technical adequacy. The procedure met the intent of the applicable
        TS.
        3.3.3  Control Building Ventilation Chlorine Detector
        For Cycle 6 startup, the licensee installed safety grade chlorine
        (C1) detectors at the river water screenhouse (channels CE 776-1 and
        777-1) and the air intake tunnel (channels CE 776-2 and 777-2). At
        5 ppm (parts per million), they actuate to place the control
        building (which includes the control room) ventilation system (CRVS)
        into a recirculation mode to prohibit outside C1 from entering the
        control room environment. Since that startup, there has been
        periodic actuation of the CRVS into the recirculation mode due to
        spurious high Cl detector response.
        Licensee representatives similarly noticed the problem and requested
        a solution from plant engineering. Cognizant plant engineers
        explained that the detector is sensitive to certain environmental
        conditions. Direct sunlight and heavy rainfall apparently promote
        drying and saturation conditions on the probe. Chlorine detection
                                                                                ___ ___________
 
                                                                          - - _ - _ _
.
                                        13
    is based on a conductivity measurement based on how much chlorine is
    absorbed into the probe. Currently plant engineering is working on
    a solution under Change Modification Request (CMR) No. 0820M.
    During the above discussion, the inspector determined that the
    licensee had instituted weekly preventive maintenance for these
    problems, 10-145, " Intake Chlorine Monitor Probe Maintenance." This
    is apparently ineffective in keeping up with the changing environ-
    mental conditions.
    The inspector did not question the operability of the system.
                                                      ~
                                                                      In
    fact, it appears to be too sensitive to changing environmental
    conditions. He expressed concern for the reliability of the system
    under such circumstances and when spurious actuations on a real
    chlorine leak event have occurred. He also questioned operator
    conditioning to the spurious actuations. This area is unresolved
    pending NRC: Region I review of the licensee solution for CMR No.
    0820M (289/87-11-03).
    3.4 Operability Summary
    Licensee maintenance management and the quality assurance department
    were also involved in this area.    In general, safety-related equip-
    ment was operable and kept in good working order. However, the
    licensee needs to resolve the problem with the Cl detection probes.
  4. Event Review
    4.1  Introduction and General Scope of NRC Staff Review
    During this inspection period, there were several events that the
    NRC staff reviewed in Lore detail. They were:      the letdown
    pre-filter noble gas release of May 28, 1987; the reactor trip of
    June 12, 1987; and, reactor protection system actuation of June 24,
    1987. In general, the following aspects were considered for each of
    these events:
    --
          details regarding the cause of the event and event chronology;
    --
          functioning of safety systems as required by plant conditions;
    --
          consistency of licensee actions with licensee requirements,
          approved procedures, and the nature of the event;
    --
          radiological consequences (on site or off site) and personnel
          exposure, if any;
    --
          proposed licensee actions to correct the causes of the event;
                                                                                      ,
                                                                                      I
 
                                          _          _      -      ._- _ __ _ _ - _ _ - -
L
  .
  .                                          14
        --
              verification that plant and system performance are within the
              limits of analyses described in the Final Safety Analysis
              Report (FSAR); and,
l
        --
              proper notification of the NRC was made in accordance with 10
              CFR 50.72.
        For each of these events, the inspector provided a chronological /
        factual summary and a specific scope of NRC staff review, licensee
        findings and NRC staff findings. An overall conclusion on licensee
l
    ,  performance is also provided.
        4.2 Letdown Pre-filter Noble Gas Release
        At the close of the' previous inspection period, the licensee experi-
        enced a small release of noble gas from the auxiliary building
        during the changeout of a letdown pre-filter cartridge. This
        occurred on May 29,-1987, and was noted in Inspection Report No.
        50-289/87-10, but details ~ were not available at the time to allow a
        proper discussion in that report.
        Subsequent' investigation by the licensee'and the inspectors revealed
        that a drain valve for the filter housing was left open and this
        allowed water to drain to the auxiliary building sump during the
      : filter changeout. Since the water was coming from the reactor
        coolant system (RCS),. noble gas was released to the auxiliary
                                -
        building and to the atmosphere via-the monitored filtered building
        exhaust fans.    RM-A-8 showed a-slight increase which was calculated
        to be 0.0994 curies.      This represents a very small fraction of the
        quarterly release limits for noble gas.
        The drain valve'is operated via a reach rod through the shield wall
        that protects personnel from the high radiation levels present at
        the filter housings. Binding in the reach rod mechanism allowed the
        valve to remain partially'open when it was supposed to be shut.
        This condition was corrected by licensee maintenance personnel and
        the valve subsequently tested satisfactorily. The licensee has
      . subsequently completed several filter changeouts with no recurrent
        problems.
        The inspector concluded that licensee corrective action for this
        problem was adequate. The inspector had no safety concerns for this
        item. The licensee is presently in the process of evaluating
        ventilation flow paths and flow rates from the auxiliary building in
      'an attempt to prevent any noble gas releases from spreading through
        the auxiliary building when they occur.
                                                                      _ _ _ _ - _ - _ _ _ _ - _ _ - _ _ -
 
-  _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _                  ._.  _ _ . -_          _. _ __            _ _ _ _ _ _ _
                                                                                                                                            i
  .
                                                                          15
                                        4.3 Reactor Trip
                                        4.3.1  Event Chronology
                                        At 9:20 p.m. on June 12, 1987, the licensee started a normal plant
                                        shutdown for the letdown cooler replacement outage. At 9:42 p.m.,
                                        operators experienced minor feedwater oscillations. At 9:51 p.m.,
                                        the low steam level emergency feedwater (EFW) initiation function
                                        was defeated as permitted by technical specification for this cycle
                                        of operation when reactor power is less than 30 percent for a normal
                                        shutdown. At 9:56 p.m., operators manually tripped the main tur-
                                        bine. Between 9:51 p.m. and 9:57 p.m., while in manual operator
                                        control, main feedwater flow started large oscillations and it was
                                        eventually lost with reactor power at 10-12 percent. This resulted
                                        in RCS high pressure and a reactor trip occurred at 9:57 p.m. when
                                        only two-of-four reactor protection system (RPS) channels for RCS
                                        pressure reached 2300 psig.
                                        Once-through Steam Generator (OTSG) levels reached approximately 11
                                        inches on the "A" 0TSG and 2 inches on the "B" OTSG. The EFW pump
                                        start occurs at 10 inches, normally; but, since the initiation
                                        system was in defeat, no EFW actuation occurred. Operators restored
                                        levels in the OTSG to low level limits of 30 inches using the main
                                        feedwater system.
                                        Because of operator response to the low level in the OTSG's, the
                                        startup regulating valves were opened excessively and a large amount
                                        of feedwater was injected into the steam generators. The operato'
                                        quickly responded to prevent an excessive cooldown rate in the RLS.
                                        Since the reactor was already shutdown by the trip, the licensee
                                        decided to proceed with the plant cooldown for outage preparations
                                        and they conducted a post-trip review on June 13, 1987.
                                        The inspectors attended that post-trip review in addition to wit-                                    {
                                        nessing the reactor trip, since they were on backshift coverage                                      1
                                        during that weekend.                                                                                  )
                                        4.3.2  Specific Scope of NRC Staff Review for the R, ;ctor Trip                                      J
                                        Specific to the reactor trip event noted above, the inspector
                                        verified the below-listed items:
                                        --
                                              initial proper response of the plant to the post-trip window on
                                              the pressure-temperature (P-T) plot;
                                                                                                                                              l
                                        --
                                              personnel properly implemented ATOG procedures and prudently                                    '
                                              acted o, unusual conditions;
                                                                                                                                              1
                                                                                                                                              !
                                                                                                                                              I
                                                                                                                  __--_________--_----_-__J
 
  _ _ _ _ -
    *
i
,
    .
                                                  16
l
l
            --
                  identification of the sequential proximate causes for the trip
l
                  along with a reasonable determination of the root cause;
            --
                  post-trip review was conducted in accordance with Administra-
                  tive Procedure (AP) 1063, " Reactor Review Process;" and,
            --
                  no unreviewed safety issues identified in post-trip review
                  date.
            In addition to discussions with cognizant licensee personnel, the
            inspector:
            --
                  made an independent assessment of post-trip parameter response
                  based on visible strip charts and indicators in the control
                  room shortly after the events;
            --
                  attended the licensee's post-trip review;
            --
                  reviewed the complete post-trip review package ( O . 87-03);
                  and,
            --
                  reviewed AP 1063, " Reactor Trip Review Process" for adequacy.
            4.3.3    Licensee Findings / Conclusions
            For the reactor trip, listed below is a summary of the licensee-
            identified problems / findings along with licensee resolutions:
            (1) The cause of the trip was operator inattention to differential
                  pressure indicator in the main feedwater system while operating
                  a main feedwater pump in manual speed control. This differen-
                  tial pressure assures enough driving head for water to be                                                        ;
                  injected into the OTSG. This cause was also noted for a trip                                                    ;
                  in 1986.                                                                                                        >
                  At the post-trip review, operations department decided to
                  re-review operator training for the period of low power opera-
                  tion with main feedwater in manual control.
                  The licensee operations department also issued a memorandum to
                  all shift supervisors stressing the need for closer cooperation
                  among all shif t operations personnel during these types of
                  plant transients to assist in preventing abnormal occurrences.
            (2) One channel of source range instrumentation (NI-1) acted
                  erratically and sometimes failed.    Based on past trips, the
                  problem had been traced to a faulty cable.
                  The outage list had replacement of new cables for both NI-1 and
                  NI-2. This was accomplished during the letdown cooler outage.
                                                                            _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _
 
                                                                _ _ _ - __--                  _
  +
                                            17
      (3) Minimum pressure in a steam generator went below 925 psig (at
              815 psis). By the licensee's post-trip administrative control,
              this abnormality was to be independently reviewed.
            The post-trip group concluded that the minimum pressure-was due
              to overfeeding the 0TSG's because of operator response to the
              low. level situation. It was also concluded that operator
              response was good to take control of the overfeed situation and
              prevent an excessive cooldown. rate'on the'RCS.
            The independent review was conducted June 16, 1987, by the
              Plant Review Group (PRG), which concluded that no unreviewed
              safety question existed.
      (4) Other minur. equipment problems were noted and they were placed
              on the outage work list for corrective action.
      '4.3.4    NU Findings / Conclusions
      The inspector independently confirmed the licensee findings /conclu-
      sions as noted above. Plant response was essentially as expected
      with minor problems noted. The licensee adequately identified these
      problems _and planned appropriate and reasonable action for immediate
      correction and to prevent racurrence. The AP 1063 was adequate to
      identify / confirm the root cause of the reactor trip and the
      post-trip review was. reasonably thorough to identify appropriate
      corrective actions before:startup.
      Operator response to the trip and off-normal. conditions were essen-
      tially consistent with facility operating and emergency procedures.
      It appeared that they were conscious of and they oriented' their
    " actions toward. confirming reactor shutdown. conditions and adequate
      decay heat removal. Licensee action-to recover from the reactor
      trip'was adequate. The memorandum noted above to enhance shift
      awareness of the feedwater pump control at lower power level was
      adequate. The Plant Operations Director (POD) indicated.that sufficient                  ,
      training and procedure guidance existed to have precluded the event.                      '
      The inspector also reviewed the procedural guidance for this evolu-
      tion. The feedwater system startup procedure addresses the problem
      explicitly with cautionary notes, etc.      However,'the shutdown
      section provides little guidance in this regard.      Nonetheless, the
      operators do train on this evolution frequently and they should know
      what is expected of them during such evolutions. The POD acknowl-
r-    edged that the feedwater pump procedure may be enhanced in the next
      periodic review of that procedure.
      Cont'rol of the feed pumps in manual is a somewhat difficult evolu-
      tion that demands attentiveness on the part of the operator. This
                                                                                                !
                                                                              .----------- _ _
 
  .
  *                                                    1B
                                                                                                                            !
                    type of control problem has resulted in a previous reactor trip.
                    The inspector. concluded that this type of problem can occur based on
                  -the variation in individual operator skill level and it is not
                    considered a serious training deficiency.
                    The inspector pursued another apparent problem not specifically
                    identified as such by the licensee.    The post-trip review identified
                    that one or two OTSG safety valves lifted.' The inspector initially
                    thought that to be unexpected since the initial plant power.just
                    prior to the reactor trip was 10-12 percent, well within the capacity
                    of the turbine bypass valves and the atmospheric dun'p valves.
                    On a reactor trip, the turbine bypss valves open at 1010 psig while
                    the atmospheric dump valves start opening at'1026 psig and the first
                    set of safety valves open at 1030-1050 psig. For this trip, the
                    turbine bypass valves (initially open with turbine header pressure
                    at approximately 875 psig) went closed on reactor trip with the
                    automatic change in setpoint to 1010 psig. In response to the trip,
                    OTSG pressure rapidly increased to the 1010 psig turbine bypass
                    valve setting (for trip condition). The' licensee representative
                    stated that actual valve response was apparently too slow to turn
                              ~
                    the OTSG pressure increase and prevent overshoot into the range of
                    safety valve'setpoints.
                    The licensee representative indicated that the licensee was
                    re-reviewing the coordination of the valve setpoints in conjunction
                    with the B&W Owners Group Reassessment on OTSG safety valve chal.-
                    1enges (previous unresolved item No. 289/85-26-05). The inspector
                    had no additional' comments on this matter.
                    The' pre-startup RPS calibration checks showed that the two high
                    pressure ' channels that did not trip were in proper calibration.
                    Licensee representatives explained that the plant was almost recov-
                    ered from the feedwater oscillation that occurred just prior to the
                    trip. The inspector had no additional comments on the matter.                                            )
                                                                                                                            2
                                                                                                                              i
                    4.4 Reactor Protection System (RPS)-Actuation                                                            i
                    During the heatup, as pressure was being increased to 1700 psig, the
                    operators were procedurally required to drive four safety rod groups to
                    the bottom of the core during shifting of the reactor protection system
                  -(RPS) out of the shutdown bypass condition. In this condition, the RPS
                    has reduced high pressure trip setpoints of 1720 psig vice the normal 2300
                    psig setpoint.    In order to prevent a reactor trip, the rods must be
                    inserted prior to reaching this reduced setpoint, then the shift made tg.
.,  .
      . ... - . g) .RP3 "'setpoint~s. ' The' safet~ ' groups
                                                      y      ~can' then be re-withdrawn af ter
                    pressure is increased above 1800 psig. The low pressure trip setpoint is                                !
                    bypassed when the RPS is in the shutdown bypass mode.                                                    '
                                                                                                                            !
                                                                                                                            '
                                                                                                                          '!
                                                                                            _ _ _ . _ _ _ _ _ _ _ _ _ _ _
 
            ,
  .
, ,                                          19
        The. operators were in the process of ' driving the last group of
        safety rods (Group -1) to the bottom of ~ the core when pressure was
        allowed to: increase close to the 1720 psig setpoint. As result,.the
        reactor tripped on the reduced RCS high pressure trip setpoint.
        Operators had been monitoring RCS pressure using the digital pressure
        indication, which is not the instrument used to generate the RPS. trip
        setpoints. This instrument indicated approximately-1685 psig at the
        time of the trip. The relatively large disparity between pressure
        indications was due to the uneven reactor coolant pump combination
        -- one pump in one loop with two pumps in the other loop. It
        appears that the operators had allowed pressure to increase close to
        the: lower tolerance-band of the RPS pressure instrument while-
        monitoring another instrument.
        The licensee made the required NRC notifications-for RPS actuations
        per 10 CFR 50, Part 73, and the inspector will review the resultant
        Licensee Event' Report (LER) when it is submitted by the licensee.
        The inspectors concluded that no particular safety concern was
        generated by this RPS actuation. The licensee did not conduct a
        post-trip review as their Administrative Procedure (AP).1038 only
        requires a review if the reactor trip occurred at power. It appears-
        that more operator attention to detail is required when conducting
        this evolution. No previous startups have resulted in this type of
        problem and the inspectors. concluded that this was' apparent 1,v an
        isolated incident.
        4.5 Event Summary
        Overall, operator response to off-normal events were oriented toward
        safety and in accordance with facility' procedures.
        Licensee management and quality assurance department provided
        substantial attention and involvement in the reactor trip and
        post-trip review.    Post-event reviews were reasonably thorough with.
        corrective action appropriately identified, documented, and evaluat-
        ed for impact on plant operations.
        Plant response was as' expected. When required, safety systems
        functioned appropriately. There were no challenges to the emergency
        core cooling systems.
    5.0 Fire Protection
        5.1 Fire Protection Annua'l Review
        The inspector conducted a review of the licensee's fire protection
        program to verify that proper measures have been established and are
        .being maintained to prevent, detect, and control fires at the site.
        The. licensee's fire protection program is described in AP 1038,
        Revision 13, dated January 12,1987, " Fire Protectica Program."
                                                                                _ - ______ -
 
                                              -        . _ _ _ _ _ . . - - _ _ _ - _ _ _ _                __
  .
  .                                    20
    Also, the requirements for operability / surveillance of fire detec-
    tion and control equipment are delineated in Technical Specifica-
    tions (TS) Section 3.18 and 4.18. The requirements for fire protec-
    tion audits are contained in Section 6.5.3.1g and 6.5.3.2a/b. The
    inspector reviewed these procedures and requirements to verify
    proper licensee implementation of the fire protection program.
    5.1.1 Audits
    The inspector reviewed audits completed during the period since the
    last annual review. The bi-annual audit of the fire protection
    program and implementing procedure, S-TMI-86-03, required by TS
    6.5.3.lg was completed on April 24, 1986. No major problems were
    noted, except that the local fire company did not participate in an
    on-site drill during 1985,    The inspector questioned the lead fire
    protection engineer as to the cause of the problem and if a problem
    existed in gaining support of the local fire company. The licensee
    responded that scheduling of local fire company personnel, who are
    all volunteers, was difficult that year.    Since that time, the local
    company has participated in on-site drills. It was also noted that
    the local company personnel do use the on-site facilities for their
    own training and are, therefore, familiar with site practices and
    configurations. This was not a concern to the inspector as on-site
    participation has taken place.
    The inspector reviewed the latest annual fire protection audit
    0-TMI-86-09 completed October 27, 1986, which is required by TS
    6.5.3.2a. Several minor discrepancies were noted but were satisfac-
    torily resolved by on-site licensee personnel and documented in a
    memorandum to file from the lead fire protection engineer. The
    inspector had no other concerns on the completion of these audits.
    5.1.2 Fire protection System Walkdowns
    The inspector examined visible portions of the fire protection water
    system to verify that valves were lined up in accordance with
    approved system lineup procedures. Surveillance Procedure (SP)
    3301-M1, Revision 28, dated April 24, 1987, " Fire System Valve
    Lineup Verification," was used as a guide. No discrepancies were
    noted, except that FS-V-399, the shutoff valve for the auxiliary
    building 281 foot area deluge system was noted as closed when the
    valve is open as the deluge station is now automatically actuated.
    It was previously a manual station. An Exception and Deficiency
    (E&D) sheet was properly noted and dispositioned. A Procedure
    Change Request (PCR) is required to update the procedure.
    The fire pump rooms were examined, along with selected post-Indicator
    valves, hydrants, deluge stations, and sprinkler stations.                            No problems
    were noted.  The inspector also observed proper installation of fire
1
                                                                                                      _ _ _ - _ _ - _ _ _ _ _ _ _ _ -
 
    _
  .
  .                                      21
      barrier penetration seals, fire detection systems, and alarms and fire
;    doors. Fire extinguishers that were checked all had proper inspection
      tags that indicated monthly checks were completed.
      The inspector questioned the lead fire protection engineer on an
      apparent discrepancy in the fire barrier penetration seal design. A
      large area containing several pipes and electrical conduits was
      visible in the ceiling of the 281 foot elevation of the fuel han-
      dling building or the " chiller room."    It appeared that this area
      should have been sealed to separate the two levels of the fuel
      handling building 281 foot and 305 foot areas. The licensee re-
      sponded that the Fire Hazards Analysis Report (FHAR) considered
      these two' locations as one fire zone and that they were protected
      accordingly as described in the FHAR.
      The inspector reviewed the completed surveillance file for surveillance
      required by TS 4.18. The E&D sheets that were generated for the surveil-
      lances were limited in number and were resolved satisfactorily. No
      discrepancies in the surveillance program were noted.
      The 5spector did question the licensee maintenance personnel
      concerning ongoing evaluation of fire pump discharge check valves
      that are being considered for inclusion in some type of preventive
      maintenance program.    This is a residual concern following the
      damage done to the FS-P-3 building when check valve FS-V-27 failed
      open (previous inspection finding 289/86-10-02).
      The licensee personnel stated that they are currently evaluating
      several commercially available non-destructive examination systems
      that will allow check valve performance / operability determination
      without disassembly. A decision on the implementation of this type
      of system would probably be made within the next three to four
      months.    The inspector will continue to track licensee effort in
      this area (289/86-10-02).
      Fire brigade training and performance was not evaluated (normally a
      yearly review) as extensive review of this area was accomplished
      during closecut of residual items from the previous fire protection
      program inspection (see NRC Inspection Report No. 50-289/87-06).
      Further, a 10 CFR 50, Appendix R review was conducted by NRC staff
      as documented in NRC Inspection Report No. 50-289/86-23. Accordingly,
      these areas were not revisited, except as noted below.
      5.2 Protection of Equipment
      Within the last three months, the licensee identified certain
      apparent failures to meet the technical requirements of 10 CFR 50
      Appendix R for which an NRC staff exemption was not granted. The 10
      CFR 50 Appendix R, Section III.G.2 requires, in part, that the
      equipment (cables, pumps, valves, etc.) necessary to achieve hot
 
.
                                      22
  shutdown conditions be protected and remain free of fire damage by
  several options specified in III.G.2 a through f (except as provided
  in III.G.3). The staf f's safety evaluation, dated March 19, 1987,
  for the licensee' exemption request to these. requirements, specifically
  exempted certain equipment (which was not adequately protected) with
  specific compensatory measures to achieve the same level of safety. For
  equipment that needed to be operated manually in less than thirty minutes,
  a roving fire watch was to assure timely identification and response to a
  fire in areas that had unprotected equipment.
  In particular, one group of exempted components was to assure RCP
  seal integrity (seal injection / cooling). Normal action for fires in
  CB-FA-28 and 2F) includes tripping of the RCP. An additional
  commitment for this function on fire in CB-FA-2B and 2F was the
  upgrading of the fire emergency procedure to dispatch an operator to
  the RSP to restore seal injection or trip the RCP's locally in the        ,
  turbine building. On April 24 and May 1, 1987, and in a letter
  dated May 7, 1987, to NRC staff, the licensee identified that
  unprotected cables (as defined by III.G.2) for RCP seal injec-
  tion / cooling were also in CB-FA-1 and that area was not under a
  roving patrol, nor did the fire emergency procedure for a fire in
  CB-FA-1 specifically address the additional commitments on operator
  action. The licensee pointed out that other emergency procedures
  would require those actions for RCP seal integrity anyway. The
  letter noted that the RSP provides an alternative capability for
  restoration of RCP seal cooling independent of CB-FA-1, including
  fire protection and detection capability and that the requirement of
  III.G 3 is met. Therefore, no exemption was required.
  However, the letter requested that fire area CB-FA-1 be included in
  the NRC staff's updated safety evaluation to ensure compliance with
  10 CFR 50 Appendix R. The NRC staff will review the licensee's
  (final) Fire Hazards Analysis Report, Revision 9, to be submitted
  October 31, 1987. The NRC staff will review this matter for techni-
  cal adequacy.
  On June 25, 1987, the licensee identified to the NRC staff that
  certain equipment for safe shutdown was unprotected for which no
  exemption was granted by NRC staff. The equipment was in area
  FB-FZ-1 (281 foot elevation, Fuel Handling Building) and it was
  cabling for a local ventilation fan AH-E-ISB, which services the
  nuclear services pump area in the auxiliary building (AB-FZ-7). The
  licensee identified that the problem was noted during re-review of a
  need for modification to adequately protect equipment associated
  with the RCP seal injection / cooling issue.
  The NRR staff informed the licensee a letter was needed to describe        I
  the technical solution or provide an exemption request to 10 CFR 50
  Appendix R.
                                                                            !
                                                                            i
 
- _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ - - _ _ - - _ _ - - _ _ _ _ _ - _
                                      .
                                                                                                        23
                                                                    The licensee added the FH-FZ-1 area to the roving fire watch patrol.
                                                                    The licensee will be sending letter by July 27, 1987, to address
                                                                    this item. The inspector expressed concern that the technical
                                                                    shortcomings noted above poorly reflects on the licensee Appendix R
                                                                    review as a whole unless they are indeed isolated cases.                          It was
                                                                    noteworthy that these items were being identified by the
                                                                    licensee / vendor and are being reported to NRC staff. The licensee
                                                                    acknowledged the above and stated that their letter of July 1987 may
                                                                    address whether or not these problems are indeed isolated cases.
                                                                                                                                                            -
                                                                    The above items are unresolved pending completion of licensee action
                                                                    as noted above and subsequent NRC staff review for technical adequacy
                                                                    and/or appropriate enforcement action (289/87-11-04).
                                                                    5.3 Remote Shutdown Panel Source Range Indication
                                                                    For the startup after the letdown cooler outage, the licensee
                                                                    decided that it was safe to proceed with the source range channel                        -__
                                                                    (NI-9) at the remote shutdown panel (RSP) inoperable. There are no
                                                                    technical specifications for the system and proposed technical
                                                                    specification indicated that while the RSP is inoperable or any
                                                                    portion thereof, a written report would be made to NRC to identify
                                                                    the problem along with taken/ planned action.
                                                                    On July 8, 1987, the inspector determined that the licensee could
                                                                    not immediately repair NI-9 because of a faulty detector. The plant
                                                                    would have to be shutdown for such repairs.
                                                                    Further discussions revealed that the control building roving fire
                                                                    watch was instructed to pay attention to the cables for NI-1/2
                                                                    (other source range channels indicated in the control room) cable on
                                                                    tours. The inspector questioned if that was an equivalent fire
                                                                    protection measure.    Further, the 'icensee plans to submit a letter
                                                                    outlining corrective actions by July 31, 1987. Tentatively, it
                                                                    appears that, if a shutdown in excess of 24 hours were to occur, the
                                                                    licensee would plan to replace the ill-9 detector.
                                                                    The operability of NI-9 is unresolved pending NRC staff review of
                                                                    the above noted letter to the NRC staff (289/87-11-05).
                                                                    5.4 Fire Protection Summary
                                                                    Generally, the fire protection program at TMI-1 continues to be
                                                                    properly implemented. Housekeeping is acceptable and control of
                                                                    transient combustibles is generally not a problem.    The inspector
                                                                    reviewed several recently completed fire protection engineer weekly
                                                                    walkdowns of the plant spaces. These walkdowns identified some
                                                                    minor discrepancies but they were promptly corrected. The inspector
                                                                    noted sufficient evidence of the proper implementation of this
                                                                    program. This inspector had no other safety concerns on the fire
                                                                    protection program.
    - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _                                                                  . _ . _ _ _ _ _ _ _ _ _ _
 
                                                                                  _ _ _ - _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
        .
                                                                                                                                            i
          .                                                          24
                                  The problems being identified for Appendix R work show signs of weak
                                  technical support. Further review by the licensee and NRC staff is
                                  needed.
                              6.  Licensee Actions on Previous Inspection Findings
                                  6.1 (Closed) Unresolved Item (25-00-16): NRC Temporary Instruc
                                  tion, " Seismic Interaction for Incore Nuclear Instrumentation"
                                  The NRC staff's Temporary Instruction (TI) 2500/16 was issued to
                                  provide inspection guidance concerning IE Information Notice 85-45,
                                  " Potential Seismic Interaction Involving the Moveable Incore Flux
                                  Mapping System at Westinghouse (W) Plants."
                                  The configuration that exists at TMI-1 on Babcock and Wilcox (B&W)-
                                  designed plants is not similar to the W-designed plants in that the
                                  incore flux detectors are permanently installed in the core at B&W.
                                  The inspector considered the issue of TI 2500/16 applicable to
                                  TM1-1; namely, the adequacy of non-seismic equipment over
                                  seismically-installed equipment. The seal table exists on the
                                  operating floor of the reactor building, but no equipment or machin-
                                  ery for detector movement is required. The flux detectors are
                                  removed from the core during refueling evolutions by using an
                                  overhead jib crane mounted on the wall of tLe "D-ring" adjacent to
                                  the incore seal table. During plant operati3n, this jib crane is
                                  not located over the seal table and is secured in position on the
                                  D-ring by cables and turn buckles to prevent it from falling onto
                                  the seal table during a seismic event.
                                  General Maintenance Procedure (MP) 1401-18, Revision 2, " Equipment
                                  Storage in Class I buildings," was reviewed by the inspector. This
                                  procedure specifies the requirements and methods to secure this
                                  crane to prevent its movement during normal plant operations. The
                                  inspector also verified after the latest outage that the jib crane
                                  was properly secured and stored.
                                  The licensee was aware of the concerns in Information Notice 85-45
                                  and had evaluated the situation as not being applicable to TMI-1.
                                  The reason was that TMI-1 is not a W-designed plant.
                                  The inspector concluded that, based on the type of arrangement used                                    .
                                  for the incore instrumentation at TMI-1, no concern of the type                                        '
                                  identified in IN 85-45 exists at TMI-1. Adequate actions have been
                                  taken to prevent damage to the incore seal table so as to preclude
                                  any damage during a seismic event at TMI-1.    The inspector had no
                                  other concerns and this temporary instruction is considered closed
                                  for TMI-1. Additional work on seismic interaction throughout the
                                  plant will occur related to Generic Letter 87-02.
_ _ _ - _ _ _ _ _ _ - _ _ _ _    .
 
    - _-__ _      - _ _ _ - __-    _ _ _ _ - _ _ _ _ - - - . _ _ _ _ - -    _. _.
..
                                                                                                                                  ,
  ,                                                                      25
              6.2- (Closed) Unresolved Item (289/85-24-01. Training Feedback
              An Atomic Safety and Licensing Board (ASLB) Partial Initial Decision
            '(PID), dated May 3, 1985, required the licensee-to develop a method
              to provide supervisors with a means to.give feedback to training                                                  ,
              programs by licensed operators directly evaluating the effect of
              training on the actual job performance of trainees under their
              supervision (performance based training evaluation). At the time of                                                i
            'NRC Inspection No. 50-289/85-24, a licensee-developed procedure to                                                  ;
              accomplish this objective.had not been implemented for licensed
              operators and the item was-left unresolved.
            . Subsequent review of this item was reported in NRC Inspection Report
              No.'50-289/87-09 during which the inspector identified one remaining
              concern. The method by which the licensee was documenting the
              supervisors feedback allowed for the use of this process'by the
              operators themselves to voice concerns or suggest improvements in
                                                                                    ~
              training.        However, separate mechanisms existed for operator / trainee
              feedback,' which were intended to be distinct from-that for supervi-
              sors. The supervisors own evaluation was not directly required.
            'The inspector reviewed the licensee's memora'nda and the supervisor
              feedback forms for the evaluations which covered the one year period
              ending in March 1987. Licensee training staff. representatives met
              one-on-one with each supervisor to' explain the objective of the
              evaluation and to ensure the proper level of analysis and suggested
              improvement were taking place. Based on this and the previous
              review, the inspector. concluded that the licensee's procedure now
              adequately addresses the original concern.
              Furthermore, the inspector noted that this feedback input is only
              one of several that the licensee uses for improving training. Other
              inputs ~ include requalification. examination results, simulator
              evaluations, TMI and industry operational events, operations depart-
              ment inputs, NRC/INP0/ internal audits. These changes are comprehen-
              sive, well documented, and exceed minimum regulatory requirements.
              6.3 (Closed) Inspector Follow Item (289/86-03-15): Licensee
              Review / Modify Maintenance Procedure for Limitorque Motor-Operated
              Valves
              Two maintenance procedures, Corrective Maintenance Procedure                                                        l
                                                                                                                                  '
              1420-LTQ-2, Revision 8, and Preventive Maintenance Procedure E-131,
              Revision 12, for Limitorque motor-operated valves were identified as                                                l
              having various weaknesses concerning adjustments to the limit                                                      '
              switches 'or in specifying valve operation. The inspector reviewed
              current revisions to the subject procedures, Revision 10 to
              1420-LTQ-2 and revision 13 to E-13 and he verified that the previous
              concerns had been addressed.
                                                                                            . - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _
 
    -                    - _ _ _ _ - _ _ _ _ _ _ _ _ _ _
  .
                                                          26
      Procedure 1420-LTQ-2 now specifies that a more precise valve open
      position (6 percent of total handwheel turn) be maintained when
      setting the open limit switch.                    Previous guidance was that the valve
      be open "a slight amount." This change was considered satisfactory
      by the inspector to correct any doubt as to what valve position is
      required to set the open limit switch.
      The second concern was that the torque bypass switch could have been
      set such that unseating forces would not be overcome before torque
      switch trip at the previously specified 3-10 percent open position.
      The procedure now specifies that 10 percent (+4 - 2) of valve stroke
      time be attained for setting the opening of the torque bypass
      switch. The inspector concluded that this was acceptable. Previous
      guidance has determined that 8-14 percent of valve travel be allowed
      prior to bypass switch actuation.
      Procedure E-13 was modified to delete reference to " jogging" the
      valve to verify proper motor rotation. The procedure now correctly
      specifies how to operate the valve to check correct motor rotation.
      The inspector concluded that the above-noted procedure enhancements
      were adequate to address the previously-noted concerns and this item
      is closed.
      6.4 [0 pen)UnresolvedItem(289/85-25-05): Steam Generator Safety
      Valve Performance
      Additional information on this item was obtained during a post-trip
      review (see paragraph 4.3.4).
      6.5 (0 pen) Unresolved Item (289/87-02-01):                    NRC to Review Licensee
      Investigation of Drug Abuse
      During this inspection period, the licensee concluded another
      investigation of drug abuse by its employees and/or contractor
      personnel.
      Since May 19, 1987, the licensee has frequently briefed NRC staff on
      their investigation. On June 15, 1987, the licensee concluded their
      review and issued a press release on their investigation. The
l
      licensee confirmed positive drug test results have been received on
      ten employees. Of the ten employees, one has resigned, one was
      fired for failing to cooperate with the investigation, and eight
      have been suspended without pay. One additional employee refused to
      undergo testing and was discharged.                    There are no positive test
      results (or test refusals) involving licensed operators or manage-
      ment personnel.
                                                              _          _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - - __
 
.
                                        27
    The eight suspended employees were given the opportunity to regain
    their jobs after thirty days if they successfulD completed a
    rehabilitation program and subsequent evaluation by a GPU Nuclear
    psychologist. A licensee representative reported that all eight
    employees accepted the licensee's offer and terms which included
    periodic and random testing for drug misuse.
    The licensee indicated that, similar to a previous investigation, an
    internal investigation report would be issued. This area continues
    to be unresolved pending NRC staff specialist review of the
    licensee's internal reports on these matters.
    6.6 {0 pen)InspectorFollowItem(289/87-07-01):        Individual
    Documentation of Operator Performance during Simulator Evaluations
    The licensee committed to document individual performance, as well
    as team performance during simulator evaluations. This area will be
    reviewed again by NRC staff after the licensee's next annual simala-
    tor examinations in March 1988.
    6.7 (0 pen) Inspector Follow Item (289/87-07-02):    Senior Licensed
    Operators Not Evaluated During Simulator and Oral Examinations at
    the Senior License Level
    The licensee has added a statement to a proposed revision to their
    corporate requalification program description clearly specifying
    that senior reactor operators (SR0's) will be evaluated in SRO
    positions during simulator examinations. Two senior operators who
    did not' receive this type of evaluation (apparently because they
    normally stand reactor operator watch) during the licensee's March
    1937 simulator examinations will be given additional simulator
    evaluations by the licensee during July 1987. This item can be
    closed out following notification by the licensee that the
    requalification program description is approved as drafted and the
    additional simulator examinations scheduled for July 1987 are
    complete.
    6.8 Past Inspection Findings Summary
    Overall, the licensee was responsive to address previous inspection
    issues / concerns.
  7. Exit Interview
                                                                                            I
    The inspectors discussed the inspection scope and findings with                        )
    licensee management at a final exit interview conducted July 9,                        4
    1987. Senior licensee personnel attending the final exit meeting                      l
    included the following:
    C. Incorvati, Audits Supervisor, TMI-1
    M. Ross, Director, Plant Operations, TMI-1
    C. Smyth, Licensing Manager, TMI-1                                                    ;
                                                                          .______-_______-__
 
_ - _ _ _ _ _      - _    -    . _ _ - _ _ _ _ - _ _ _ _ _    __ _ __        -                    ._ _ _ _ _
                                                            28
              The inspection results as discussed at the meeting are summarized in
              the cover page of the inspection report. Licensee representatives
              indicated that none of the subjects discussed contained proprietary
              or safeguards information.
              Unresolved Items are matters about which more information is re-
              quired in order to ascertain whether they are acceptable, viola-
              tions, or deviations. Unresolved items discussed during the exit
              -meeting are addressed in paragraphs 2.2.3, 2.2.5, 3.3.3, 5.2, 5.3,
              and Section 6.
              Inspector Follow Items are significant open issues warranting
              follow-up by the inspector at a later time to determine if it i's
              acceptable, unresolved, a violation, or a deviation. An inspector
              follow item discussed during the exit meeting is addressed in
              paragraph 6.3 of this report.
                                                                                                                l
                                                                                  .________-_-__-_-_w
 
                                                    . - - _ _ - _
                                                                  - _ _ _ - _ - _ _ _ - _ - ,
,
  .
      '
    .
                                  NRC INSPECTION REPORT
                      i
''
                                      NO. 50-289/87-11
                                        ATTACHMENT'l
                                    ACTIVITIES REVIEWE0
        Plant Operations
        --
            Control room operations during regular and backshift hours, including
            frequent observation of activities in process'and periodic reviews of
            selected sections of the shift foreman's log and control room. operator's,
            ~1og and selected sections of'other control room daily logs
        --
            Areas outside the control room
        --
            Letdown' cooler shift due to high leak rate from "1B" heat exchanger
            on June 3, 1987-
        --
            Unplanned reactor trip, Emergency Procedure 1210-1 on June 12,'1987
                              -
        --
            Operating Procedure (OP) 1102-11,- Revision 68, dated March 15, 1987,
            " Plant Cooldown," on June 12-13, 1987
        --
            OP'-1102-2, Revision 80, dated May 15, 1987, " Plant Startup," includ-
            ing the license heatup/startup prerequisite list and related activi-
            ties on June 25-26,L1987                                                                                                        1
        --
            OP 1104-8, Revision 27, dated January 26,.1987, "ICCS System Operation,"
            (TCN 1-87-138) on June 24, 1987
        During this inspection period, the inspectors conducted direct inspections
        during the following backshift hours:
                  '6/01/87        8:00 p.m. to 10:30 p.m.
                  6/02/87        6:00 a.m. to 7:00 a.m.
                                  3:00 p.m. to 5:00 p.m.
                  6/06/87-      9:00 a.m. to 10:30 a.m.
                  6/12/87-      7:00 p.m. to 10:30 p.m
                  6/13/87        9:00 a.m. to 1:00 p.m.
                  6/24/87        5:00 p.m. to 8:00 p.m.
                  6/25/87        4:00 p.m. to 8:30 p.m.
                  6/27/87        8:00 a.m. to 10:00 a.m.
                  6/18/87        8:45 p.m. to 10:15 p.m.
                  7/09/87        5:00 a.m. to 7:00 a.m.
        Maintenance
        --
            NR-P-1A Overhaul per Job Ticket (JT) CM-855
        --
            Corrective Maintenance Procedure 1410-P-14
                                                                                            _ - _ _ _ _ _ - _ _ _ _ - - _ _ _ _ - _ - _ - _ A
 
                                                                    -_ _ _______ _ _ _ _ _ -
.
  Surveillance
  --
        Surveillance Procedure (SP) 11.21, Revision 7, dated December 3,
        193, " Core Flood Valve Operability Test," on June 13, 1987
  --
        SP 1303-4.16, Revision 29, dated June 23, 1987, " Emergency Power
      ' System for Diesel Generator B," on June 24, 1987
  --
        SP 1303-5.1, Revision 22, dated March 4, 1987, " Reactor Building
        Cooling and Isolation System Logic Channel and Component Test," week
        of July 6-9, 1987
  --
        SP 1303-5.2, Revision 24, dated March 10, 1987, " Load Sequence and
        Component Test," week of July 6-9, 1987
  --
        SP 1300-3I, NR-P-1A Post-Maintenance Test (records review)
  Reactor Coolant System (RCS) Leak Rate.
  The inspector selectively reviewed RCS leak rate data for the past inspection
  period. The inspector independently calculated certain RCS leak rate data
  reviewed using licensee input data and a generic NRC " BASIC" computer program
  "RCSLK9" as specified in NUREG 1107.      Licensee (L) and NRC (N) data are
  tabulated below.
                                        TABLE
                                RCS LEAK RATE DATA
                                  (All Values GpM)
  DATE/ TIME                              (NUREG 1107)    CORRECTED
  DURATION        Lg        Ng              Ng            Ng              L
                                                                                U
  6/1/87        2.1863      2.19            0.12          0.22    0.2236
  3:41 p.m.
  2 Hours
  6/2/87        3.2235      3.23          -0.04          0.06    0.0401
  10:34 a.m.
  2 Hours
  6/2/87        3.5089      3.50            0.13          0.23    0.2435
  8:27 a.m.
  2 Hours
 
i. -
L
l
l    DATE/ TIME                          (NUREG 1107)  CORRECTED
    DURATION        Lg        Ng              N
                                                g          Ng            L
                                                                            U
    7/8/87      0.0924'    O.09          0.12        -0.02      -0.0127
    11:49 p.m.
    2 Hours
    G = Identified gross leakage        U = Unidentified leakage
    L = Licensee calculated            N = NRC calculated
    Columns 2 and 3; 5 and 6 correlate 1 0.2 gpm in accordance with NUREG
    1107. (N is corrected by adding 0.1044 gpm to the NUREG 1101 N due to
                u                                                      u
l    total purge flow through the No. 3 seal from RCP's.
l
r
l
l
l
l
l
,                                                                            - - _ _
}}

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