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{{Adams
#REDIRECT [[IR 05000219/1985023]]
| number = ML20133H402
| issue date = 10/07/1985
| title = Insp Rept 50-219/85-23 on 850701-0818.Violations Noted: Improper Closure of Containment Isolation Valve & Failure to Follow Procedures While Inerting Drywell
| author name = Bateman W, Baunack W, Kister H, Reynolds S, Wechselberger
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| addressee name =
| addressee affiliation =
| docket = 05000219
| license number =
| contact person =
| document report number = 50-219-85-23, NUDOCS 8510170153
| package number = ML20133H397
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 18
}}
See also: [[see also::IR 05000701/2008018]]
 
=Text=
{{#Wiki_filter:_ _ ~  . - - . _ = _ - . . . _
                                                                                                                                            . _ - _ _ - .        .  _ _ . _
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                                                  .
                                                                                            O                                                    O
                                                                                                                                                                                  L
                                                                                                                                                                                  i
                                                                                                                                                                                  !
                                                                                              U. S. NUCLEAR REGULATORY COMMISSION                                                !
                                                                                                                REGION I
                                                                                                                                                                                  !
                                                                                                                                                                                  '
                                    Report No.                                      50-219/85-23
                                  Docket No.                                        50-219
                                    License No.                                      DPR-16            Priority                                  Category _C
                                    Licensee:                                        GEJ Nuclear Corporation
                                                                                    100 Interpace Parkway                                                                        ;
                                                                                    Parsippany. New Jersey 07054                                                                l
                                                                                                                                                                                  t
                                  Facility Name: Oyster Creek Nuclear Generating Station                                                                                        r
                                    Inspection At: Forked River, New Jersey
                                  Inspection Conducted:                                          July 1 - August 18. 1985
                                                                                                                                                                                  ,
                                  Inspectors:
                                                                              C
                                                                                      9%''$&  ~
                                                                                    W.'H. Batefan, Senior Resident Inspector                                l0/1
                                                                                                                                                              F te rr
                                                                                                                                                                                  i
                                                                                                                                                                                  l
                                                                                    sagn
                                                                                    J. F. Wedihhrfberger, Resident Inspector
                                                                                                                                                            w 'DJte
                                                                                                                                                                                  (
                                                                                        umu
                                                                                ^ S. D. Reinoids, Lead Reactor Engineer                                    ea-T te
                                                                                                                                                                                  '
                                                                                        Yb
                                                                                  . W. H. Bauna
                                                                                                      /5
                                                                                                      Project Engineer
                                                                                                                                                                Y 's
                                                                                                                                                            ~ 6 ate
                              Approved by:
                                                                                                    & k
                                                                                      . 6'. Kis'te4 Acting Chief,
                                                                                                                                                            h50 ae
                                                                                    Reactor Projects Section 1A
                                Inspection Summaryl                                                                                                                              ;
                              Routine and special onsite inspections were conducted by the resident
                                inspectors and two region based inspectors (216 hours) of activities in                                                                          :
                              progress including plant operations, physical security, radiation control,
                              housekeeping, chemistry, and hanger inspections.                                                          The inspectors also followed
                              up the events leading to two reactor trips, observed repair activities of the                                                                      .
                              EfW piping, and routinely toured the control room and the power block.                                                                              '
                                                                                                                                                                                  :
                                                          Eu 'I8&N 8M8PJi,
                                                          O                                PDR
        _-_-____ ___-__-__--___-_--_ __ _ _ _ -__ _ ___ _ _ ____ -_ _ _ _____                                                                                                _-
 
                            _          -                                            . _ .
      -
  , ,
                                                                                          ,
l
l
l
      Results:
l
      Two violations were ident!ffed. The first involved improper closure of a
,
      containment isolation valve (discussed in paragraph 1) and the second involved
i
      failure to follow procedures while inerting the drywell (discussed in
l    paragraph 2).
                                                                                          t
                                                                                          ,
                                                                                          m
                                                                                          !
                                                                                          >
                                                                                          P
I
l
,
l
.
l
 
                                            . _ - - . _                    -
          . .
                  .
                                      O                                      O
                                                        DETAILS
              1.    Licensee Event Report Review:
                    Licensee Event Report 85-002 which reported two inoperable containment
                    isolation valves in a single penetration was reviewed in detail.        The LER
                    identified a problem that occurred during a planned shutdown on February
                    2,1985, when a reactor water cleanup (RWCU) system containment isolation
                    valve, V-16-1, was required to be unbackseated. Standing Order No. 33,
                    "Backwating/Unbackseating of Valves," and Station Procedure 700.2.014,
                    "Backseating and Unbackseating Valves V-14-36 V-14-37, and V-16-1 (Elec-
                    trically)," provided the operators with the procedural directions. The
                    control room operators, however, rather than using the prescribed unback-
                    seating procedures, elected to unbackseat the valve by stationing an
                    electrician at the motor control center supplying the valve and have him
                    engage the closing contactor. To prevent full closure of the valve due to
                    a seal-in closing signal, after two seconds of valve operation, the valve
                    breaker was manually tripped.      This breaker trip resulted in an inadver-
                    tent isolation of the RWCU system. A second isolation valve failed to
                    fully close when the isolation signal was received, resulting in two
                    inoperable containment isolation valves in the same line. The second
                    isolation valve failed to close due to binding of the valve stem. The
                    valve was subsequently repaired and tested,
                    procedure 700.2.014 for unbackseating this valve was reviewed and it was
                    determined that had this procedure been used, tne automatic containment
                    isolation function of V-16-1 would not have been inoperable. (This is
                    true for all backseating and unbackseating procedures.) This complies
                    with the Technical Specification requirement that all automatic contain-
,'                  ment isolation valves be either operable or secured in the closed post-
                    tion. The operators, in not following the prescribed procedure, made a
                    containment isolation valve inoperable while in the open position.
                    In summary, although this event was licensee identhtd and reported in
                    accordance with 10 CFR 50.73, the inspector's review of the report noted
                    that it did not fully address the fact that this event occurred as a result
                    of using an incorrect method for unbackseating a valve. This is particu-
                    larly bothersome since an approved procedure was available to perform the
                    operation correctly. This is considered a serious matter and was not
                    really dealt with as part of the licensee's documented corrective action.
                    Also, it appears that the licensee's review process failed to note this
                    condition and correct it. Since appropriate corrective action appears not
                    to have been taken, this item has been classified as a violation.
                    (219/85-23-01)
                    The LER will remain open pending review of a supplemental report which
                    documents further corrective action regarding this matter.
  _ _ _ _                        _    .-              . -    . - - - - -  - - .        -        .-_
 
                                                                                                                                                                                                                                                                                _. _ ._ . _
                            ,
                                                                                                -
                                , ,
                                                                                                                                                                                                                                                                              3
                                                                                    2.                                    Containment Nitrogen Inertig
l                                                                                                                        A special revi s was conducted of the circumstances associated with the
                                                                                                                          containment inerting evolution which took place during the startup on
                                                                                                                          August 4, 1985. The inspection was conducted to review licensee noncom-
                                                                                                                          pliance with requirements to calibrate the drywell and torus oxygen
                                                                                                                          analyzers when, during the inerting process, oxygen concentration
                                                                                                                          decreases to less than 4%.
                                                                                                                  ,The following material associated with the event was reviewed. Also,
                                                                                    P                                    additional information was obtained during discussions with licensee
                                                                                                                          personnel.
.
'
                                                                                                                          --
                                                                                                                                                                Station Procedures 201.2, Plant Heatup to Hot Standby; 312, Reactor
                                                ,                                                                                                              Containment Integrity and Atmosphere Control; 312.7, Drywell/ Torus
                                                                                                                                                                Oxygen Analyzer Operation; 604.3.019, Drywell and Torus Oxygen
                                                                                                                                                              Analyzer Calibration; and 107, Procedure Control
                                                                                                                          --
                                                                                                                                                                Control Room Log (August 4 to August 6,1985)
j                                                                                                                        --
                                                                                                                                                              Group Shift Supervisor Log (August 4 to August 6, 1985)
                                                                                                                        --
                                                                                                                                                              Oxygen Analyzer Calibration Data for calibrations performed August 4
                                                                                                                                                                and August 6, 1985
                                                                                                                        --
                                                                                                                                                              Nitrogen tank level records
                                                                                                                        The findings from the above review show that the facility procedures
                                                                                                                        associated with inerting the containment clearly specify the actions which
                                                                                                                        are required to achieve Technical Spectfication requirements. The review
,
                                                                                                                        also showed that Station Procedure 312 was,not fully adhered to during the
l                                                                                                                        inerting evolution.
                                                                                                                        Procedural requirements which were not fully implemented were:
                                                                                                                        --
                                                                                                                                                              A prerequisite to containment inerting, which required the oxygen
                                                                                                                                                              analyzers to be calibrated in accordance with a surveillance
                                                                                                                                                              procedure, was not performed until inerting was in progress.
                                                                                                                        --
                                                                                                                                                              The requirement to use 150" of nitrogen from the nitrogen storage
                                                                                                                                                              tank to achieve less than 4*.' oxygen concentration was not fully
                                                                                                                                                              accomplished in that only 139" - 144" were added.
                                                                                                                        --
                                                                                                                                                              The procedural step which states, " Ignore the oxygen analyzer reading
,                                                                                                                                                            until stopt 4.3.19 and 4.3.23 are completed," was not adhered to.
!                                                                                                                                                            (Steps 4.3.19 and 4.3.23 required drywell and torus oxygen analyzers
                                                                                                                                                              be calibrated at less than 4% containment oxygen concentration.)
i
l
g                                                                                                                                                                                                  #
!
                                                                                                                                                                                                        '
                            ,
  - _ - - - - _ _ . - - _ . - - - _ - - - - . - - - - - _ _ _ _ _ . - _ _ _ _ . _ - . . - _ _ - . _ . _ _ - _ - - - _ - - _ . _ _ . - - _ . _ _ . - . - - - . . _ . _ . _ _ - _ _ _ - _ . . _ . - _ . . . _ . - - - _ . _ _ - _ _ - . _ . - _ - - . _ _ _ . . _ _ _ _ _ _ _ _
 
  .
    . .
              -
                                      O                                O
                                                        4
                    --
                          The required calibration of the drywell and torus oxygen analyzers
                          was not performed when oxygen concentrations were less than 4%.
                          (This was not accomplished due to depletion of a necessary
                          calibration gas.)
                    --
                          The note in the precedure which requires inerting until both the
                          torus and drywell are less than 3% oxygen concentration was not
                          adhered to.
                    --
                          The requirement to reduce the containment atmosphere to less than 4%
                          oxygen was not achieved due to reliance on analyzers which had not
                          been calibrated as required. A subsequent oxygen analyzer
                          calibration performed on August 6, .1985, after calibration gas was
                          obtained, showed a .4% nonconservative error existed in the drywell
                          oxygen analyzer readout. As a result of this error, operation was
                          being conducted at 4% drywell oxygen concentration as opposed to the
                          Technical Specification requirement of less than 4%.
                  Analysis of findings show the required prerequisite oxygen analyzer
                    calibrations were in fact performed during inerting with no procedure
                  change request having been prepared. No reason could be determined for
                  adding less than 150" of nitrogen from the storage tank. At the point in
                    the procedure where the drywell and torus oxygen analyzer calibrations
                  were required to be performed, it was determined no calibration gas, which
                  was needed to perform the calibration, existed on site. At this
                  point, a number of options were available to shift personnel; these
                    included the use of PASS for drywell and torus oxygen analyses, use of the
                    installed accident monitoring analyzer for drywell oxygen concentration,
                  addition of a more significant amount of nitrogen which was available,
                  expediting acquisition of calibration gas within the 24 hours allowed by
                  the Technical Specifications, or not placing the Mode Switch into RUN and
                  thereby avoiding having to reduce the oxygen concentration to less than 4%
                  within 24 hours. These options were apparently not considered. Instead,
                  believing the calibration performed during startup was sufficient,
                  operations personnel continued plant startup. When calibration gas was
                  eventually received, the subsequent calibration showed a .4% error in the
                  oxygen reading. This verified that operation at 4% oxygen versus the
                  Technical Specification required less than 4% oxygen had occurred. The
                  failure to adhere to Station Procedures is a violation. (219/85-23-02)
                  The failure of shift personnel (which included two SR0s and a STA on
                  watch) to consider the use of other methods to draw oxygen samples is a
                  matter that should be further evaluated. The entire event could have been
                  avoided had an available option been selected and an appropriate procedure
                  change prepared.
                  The licensee's procedure for the procurement of the calibration gas, which
                  is required for the oxygen analyzer calibration, was briefly discussed
                  with licensee personnel. Calibration gas has been maintained as a " stock
                  item" since March 1984 with a maximum of 4 bottles and a minimum of 2
4
        . - -  --
                          _.            .      -                            - - , ,
 
.
  . .
        -
                              O                                O
                                                5
          bottles specified (each bottle provides gas for approximately three
          calibrations). A three week delivery is normal. The amount specified was
          based on 1984 usage. During 1984 the plant was shutdown and calibrations
          were not required or performed. The date could not be determined, but I&C
          technicians stated the storeroom was notified when the next to the last
          bottle was taken from the storeroom. A purchase requisition was prepared
          for additional gas on June 28, 1985 and no further action was taken until
          a purchase order (P0) was phoned to the supplier on July 30, 1985.    After
          running out, gas was picked up at the suppliers by the licensee on August
          6, 1985. Steps have been taken to increase the specified amount of gas to
          be maintained on site.
      3.  Operational Safety Verification
          3.1 Control Room Observation
                Routinely throughout the inspection period, the inspector
                independently verified plant parameters and engineered safeguard
                equipment availability. The following items were observed:
                --
                      Proper Control Room manning and access control;
                --
                    ' Adherence to approved procedures for ongoing activities;
                -- -Proper safety systems and emergency power sources valve and
                      breaker alignment; and
                --
                      Shift turnover.
                duringareviewofcontrolroommanningrequirements,itwas
                identified that there is a conflict between the Regulations and the
                Technical Specification and Station Procedure 106, " Conduct of
                Operations," regarding the number of Senior Reactor Operators
                (SR0s) required per shift. Specifically, paragraph 50.54 of 10 CFR
                50 requires two SR0s per shift,'whereas the Technical Specifications    i
                and Station Procedure 106 require one SRO per shift. The licensee
                responded to this concsrn by stating they do require two SR0s per
                shift and will change the Technical Specifications and Procedure 106
                to be consistent with the Regulations. Routine NRC inspections have
                confirmed two SR0s per shift staffing. The inconsistency between the
                Regulations and the Technical Specifications and Procedure 106 is an
                unresolved item pending revisions to the Technical Specifications and
                Procedure 106 to reflect the requirements of the Regulations.
                (219/85-23-03)
          3.2 Review of Logs and Operating Records
                The inspector reviewed, on a sampling basis, the following logs and
                instructions for the period July 1 to August 18, 1985:
                                                                                    _
 
,
  ,
    . .
            -
                                O                                O
                                                  6
                    --
                          Control Room and Group Shift Supervisor's Logs;
                    --
                          Control Room and Shift Supervisor's Turnover Check Lists;
                    --
                          Reactor and Turbine Building Tour Sheets;
                    --
                          Equipment Control Logs;
                    --
                          Standing Orders; and
                    --
                          Operational Memos and Directives.
                    The logs and instructions were reviewed to:
                    --
                          Obtain information on plant problems and operations;
                    --
                          Detect changes and trends in performance;
                    --
                          Detect possible conflicts with Technical Specifications or
                          regulatory requirements;
                    --
                        Assess the effectiveness of the communications provided by the
                          logs and instructions; and
                    --
                        Determine that the reporting requirements of Technical
                        Specifications are met.
                    The reviews indicated the logs and operating records were generally
                    complete. No inspector concerns were identified.
        4.  Observation of Physical Security
              During daily entry and egress from the protected area, the inspectors
              verified that access controls were in accordance with the security plan
              and that security posts were properly manned. During facility tours, the
              inspectors verified that protected area gates were locked or guarded and
              that isolation zones were free of obstructions. The inspectors examined
              vital area access points to verify that they were properly locked or
              guarded and that access control was in accordance with the security plan.
              A moderate loss of physical security was reported by the licensee. It
              involved loss of power to the security computer for approximately two
              hours during an early morning thunder and lightening storm. During the
              time the computer was disabled, vital area access was adequately
              controlled, however, all elements of the Security Plan were not
              implemented as regards a small portion of the protected area adjacent to
              the main security building. The actions taken to compensate for this
              section of the protected area did, however, offer reasonable assurance
              that the area was not trespassed. A subsequent search of the plant
              confirmed no unauthorized entries were made during the period of time the
              computer was disabled.
<
 
      _                    .      . ..                      ..  .
                _                              _ __                      _    _ - _ . _                  .                  ._ _
  . .
            .
                                        O                                                O
i                                                                7                                                                    )
                                                                                                                                      i
          5.    Plant Tours
i
                During the inspection period, the inspectors made frequent tours of plant
                areas to make an independent assessment of equipment conditions, safety,
              ' and adherence to regulatory requirements. The following areas were among
                those inspected:
e                                                                                                                                    <
                        Turbine Building
                                                                                                                                      '
4              --
,
                --
                        Vital Switchgear Rooms
              --
                        Cable Spreading Room
i              --
                      Diesel Generator Building
i                                                                                                                                    !
,
              --
                        Reactor Building
              The following items were observed or verified.
              5.1 Fire Protection
                      --
                              Randomly selected fire extinguishers were accessible and
                                inspected on schedule.
i
-                      --
                              Fire doors were unobstructed and in their proper position.
                      --
                              Ignition sources and combustible materials were controlled in
.
                              accordance with the licensee's approved procedures.
l
'
                      --
                              Appropriate fire watches or fire patrols were stationed when
:                              equipment was out of service.
1
              5.2 Equipment Controls
                      -- . Jumper and equipment mark-ups did not conflict with Technical                                            '
                              Specification requirements.
<
                      --
                              Conditions requiring the use of jumpers received prompt licensee
                              attention.
l
                      --
                              Administrative controls for'the use of jumpers and equipment
                              mark-ups were properly implemented.
              5.3 ' Vital Instrumentation
4
                      --
                              Selected instruments appeared functional and demonstrated
'                              parameters within Technical Specification Limiting Conditions
                              for Operation.
i
!
                                                                                                                                    ,
      , -          --                      --.--.,.,.-,..amn,        e.-.--.m.  -,,v.----.w,---.w,,-- ..,,,-,,--nar,,.,,,,-,n,
 
    .-    - _                    . .      .    .      _                                                                        ~ -
      . .
                  -
                                                O                                      O
                                                                    8
                          5.4 Radioactive Waste System Controls
                                --
                                      Gaseous releases were monitored and recorded.                                                      i
<
;
                                --
                                      No unexpected gaseous releases occurred.
'
                        5.5 Housekeeping
;
,
                                --
                                      Plant housekeeping and cleanliness were in accordance with
3
                                      approved licensee programs.
!
              6.        Radiation Protection
                        During entry to and exit from the radiologically controlled area (RCA),
                        the inspectors verified that proper warning signs were posted, personnel
                        entering were wearing proper dosimetry, personnel and materials leaving
                        were properly monitored for radioactive contamination, and monitoring
1                        instruments were functional and in calibration. Posted extended Radiation
                        Work Permits (RWPs) and survey status boards were reviewed to verify that                                        ,
                        they were current and accurate. The inspector observed activities in the
                        RCA to verify that personnel complied with the requirements of applicable
                        RWPs and that workers were aware of the radiological conditions in the
                        area.
                        During this report period, ten individuals were slightly contaminated in
                        the New Radwaste (NRW) Building when a damper in the building's HVAC
                        system that isolates the building's HVAC-system from the main plant
                        discharge stack inadvertently opened while undergoing repairs. When the
                        damper opened, backflow from the plant stack into the NRW Building
                        resulted in airborne contamination that contaminated the ten individuals.
                        All individuals were decontaminated and whole body counted. No problems
                        were identified.
4
            7.          Return of Spent Fuel From West Valley
                        During this report period, the last shipments of spent fuel were received
                        onsite from West Valley, New York.            The resident and region based
                        inspectors observed final spent fuel receipt at Oyster Creek and the
i                      handling and unloading of spent fuel from the TN-9 spent fuel shipping
                        cask. Radiation Control personnel were observed to be knowledgeable and
                        in control of radcon related activities. Once reaching the refueling
                      . floor, the TN-9 casks were moved and unloaded and spent fuel stored in the
'
                        spent fuel pool in accordance with controlling procedures. The overall
                        spent fuel shipping effort was conducted without a major incident.
            8.          Pipe Hanger Inspections
                        During this report period, pipe and pipe support inspections continued.
                      Also, efforts were initiated to repair deficiencies that were determined
                        by Technical Functions not to be acceptable as is. The overall scope of
  f
            .      .. . a              ,,  a    w      g-~-, , -  w  s - -  ,e ,            e-m -,v ,,---..e-em-m -
                                                                                                                        w~ ,, n.  gre m-
 
                                            . -    - _ . - .
    ,
                -
      , ,
                                                              9
                  the inspection continued to increase and stood at 504 at the end of this
                  report period, 454 of which were inspected. Some of the more significant
                  problems identified during this report period were with supports on the
                  Core Spray System II full flow test line. The most significant of these
                  problems involved a cracked pipe clamp and cracked attachment welds used
                  to attach the pipe clamp to the pipe associated with snubber 411R11.
                  Other supports en the test line also had deficiencies, although not as
                  serious. Engineering evaluation of the problems determined the damage to
                  have resulted from water hammer in the piping prior to incorporation of a
                  " keep full" system installed nearly five years ago. The " keep full"
                  system eliminated the water hammer, but the damage to the supports was not
'
                  identified until this inspection. Prompt repairs were made to affected.                                      *
                  supports.
              9.  ContainmentSprayEmergencyServiceWaterSystem(CSESWSJ
.
'
I
                  During routine surveillance testing of the ESW pumps, problems involving
                  differential pressure (DP) changes across the ESW side of the 1-3
                  Containment Spray heat exchanger (HX) were identified. Additionally, ESW
:
                  pump 52 C' was determined to have a loose impellor. As part of the
                  investigation of the DP changes in 1-3 HX, the HX head was removed and an
j                  inspection of the ESW side of the HX was performed. This inspection
4                revealed a meterial suspected to be "bitumastic" or a coal tar enamel
                  coating applied to the inside of the ESW system piping for corrosion
!                protection. A sample was sent out for analysis to confirm suspicions.
                  Meanwhile, additional flushing of ESW System II (2 pumps and 2
'
                  heatexchangers are contained in ESW System I and ESW System II) was
                  resumed. While this flushing was in progress, a routine surveillance of
'
.
                  System I indicated inadequate pump performance thus requiring a plant
                  shutdown as System II was still considered inoperable because of the 52
                    C' pump. At this point discussions ensued between licensee and NRC
                  management as to whether or not at least one train of the ESW system could
                  be considered operable. The licensee suggested that if they could verify,
                  by use of other than normally used instrumentation, that the ESW pumps                                        l
                  were putting out equal to or greater than minimum flow, then ESW System I                                    '
;
                  or II could be considered operable. The NRC' suggested that the
                  operability of both loops was in question based on the presence of the
                  coal tar enamel in the 1-3 HX and increasing DP's in the other HX's
                  indicating a possible generic problem. The NRC and the licensee reached
                  an agreement that if adequate flow could be demonstrated in ESW System I
                  and a 24 hour run completed without encountering further problems, then
!
                  System I could be considered operable. However, System II would not be
                  considered operable until resolution of the problem of the foreign
                  material blocking flow to the HX's and, thereby affecting the ability of
                  the HX's to perform their design function. Less than 24 hours into the
                  run of System I, the DP across the HX's increased to the allowable limit.
;_                At this point, the licensee declared the ESW system inoperable, shut the
t
                  plant down, and commenced a major effort to resolve the problem.
4
  .      _~            _ . .        _        _  _s          . . . . _ . . . . _ _ , , _ . . - , . , - - _ . _ . . _ , _ . .
 
        .-  -                  --              - - ~ _ . . . _ .        -                                  --  -_
    . .
              .
                                        O                                                            O
:
                                                                      10
)                      Resident and region based inspectors reviewed the licensee's activities in
                        investigating the cause of the loss of bonding of the internal coating on
                        the ESW piping. The pipe lines affected were the redundant System I and
                      System II Emergency Service Water Inlets to Containment Spray Heat
4                      Exchangers 1-1, 1-2, 1-3, and.1-4. These lines appear on special GPUN
                        isometric sketches SK-1, SK-2, and SK-3 which reference the original
!                    construction piping drawings. System I connects ESW pumps #1 and #2 to a
                      common line which supplies CSHX 1-1 and 1-2. System II connects ESW pumps
                      #3 and #4 to a common line which supplies CSHX 1-3 and 1-4. The piping
                      from the pump to the common line is 10" in diameter and the common line
                      pipe itself is 14". At approximately 102. feet from the pumps on System I
                      and 73 feet from the pumps on System II the cooling water is chlorinated.                                      '
                    The total pipe length from pump to HX is approximately 780 feet in
                      System I and approximately 40 feet less than this for System II (estimated
                    by inspector). Investigation of the pipe by the licensee (utilizing a TV                                        '
                    optics system) of roughly 215 feet of System I and 280 feet of System II,
                      showed the coating problem to be limited to that portion of pipe between
                      the pumps' discharge and the point of chlorination.
                    The ESW piping system from the pumps to the CSHX consists of flanged pipe
:                  and elbows of carbon steel which were purchased as spool pieces then sent
                    to a coating application vendor. The licensee indicated they have not
                    been able to retrieve the purchasing information indicating the pipe
                    procurement and coating, however, licensee specifications called for the
                    coatings to meet American Water Works Association (AWWA) C 203-73 Type II
                      internal pipe coating system requirements. This coating system consists
l
'
                    of cleaning and blasting the pipe ID followed by application of a cold
                    primer coat of a coal tar pitch cut with a coal tar oil to a liquid
                    consistency which can be applied by brush or spray. Upon completion of
                    the primer coat, a hot coal tar enamel (pitch) containing inert mineral
                    fillers is cast in the pipe and a " pig" is drawn through the pipe to
'
                    produce a thick pliable coating in the order of 1/8-1/4" thick on the pipe
                  wall. The hot coal tar pitch coating is similar to a hot pitch roof,
                    however, the roof pitch does not contain the mineral fillers. The coating                                        1
                  does not extend around the radius of the flange attachment to the flange
                    face, but is given a guillotine cut in the same plane as the flange face
                    to produce an abutting (square butt) joint with adjacent spool pieces.
                  The coating continuity is, therefore, a function of the tightness of the
,                  square butt joint. Disassembly of the spool pieces near the pumps
!                  indicated that the worst area of coating de-bonding was in the first few
                    spool pieces.
                  The piping system immediately adjacent to the pumps consists of a short
<
                  horizontal straight pump extension piece (A), elbow (B), flow restrictor
                  (C), horizontal straight spool piece (D), elbow (E), vertical straight
                  spool piece (F), elbow (G), and a tee to the 14" common flow line.
                  Disassembly of the spool pieces near the pump indicated the worst
                  de-bonding of the coating was in the four horizontal straight spool pieces
1
  -
                  (D). These pieces and two elbows (E) were removed and replaced. One of
'
                  these was cut up for evaluation by GPUN Reading Material Engineering
                  Laboratory and one left intact for visual examination. The inspector
.
    ,      -  _ _ - -      -                    -..              ~    _  _ ~ _ _ . . - _ . , - - . . , . .    .    ~ __,._.,, _y
 
        .  .        _ . .    . .. _    . _ . _        _ _ - - _ _ _ - - - - _                                    _ _ _ - . . .    - - _ .  - _ __
  ,
          -
    . .
;                                                                                                                                                                      .
.
                                                                        11
,
'
                visually inspected one section from the cut-up elbow and also inspected
;                the other intact elbow. Marine life (barnacles, etc.) was attached to the
!              coating. The coating thickness varied from approximately 1/8 to 1/4 " or
.
                greater. There were " mud cracks" on the surface, but these cracks didn't                                                                              i
!              appear to go through the coating. On the elbow which was intact, the
!
*
                coating was not present on portions of the elbow adjacent to the flange
                face at the exposed edge (abutting edge area). On the elbow which was                                                                                  '
I
                sectioned, the coating attachment was good except for the apex of the
                " pie" cut section (introdos of elbow) where the cutting may have
                                                                                                                                                                        ,
,
                                                                                                                                                                        l
                mechanically loosened the coating (even though efforts were made to keep                                                                                i
                the saw cut cold).
                Discussions with a representative of the GPUN Materials Engineering                                                                                    !
1              Laboratory indicated the following results of examination of the sectioned                                                                              ,
j              elbow:
1                                                                                                                                                                      !
]
                --
                      " Mud cracking" pattern observed on surface                                                                                                      -
1
!              --
                      Undercutting at exposed coating edges observed (substrate corrosion
i                      causing loosening of coating).
!
j              The laboratory had technical discussions with three people (representing
i              field, laboratory, and technical area) of the Koppers Company on service
;
              experience problems with AWA C203 coal tar enamels.                                                Koppers indicated
                that if the-coating is permitted to dry out and concurrently subjected to
              ambient thermal cycles, it will produce " mud cracks." They also indicated
f              that if the coating is dry and subject to. low temperatures in the order of
!              O F, it will crack. A portion of the sectioned elbow was sent to Koppers                                                                                ;
j              for their analysis. The inspector requested copies of the GPUN Material
                                                                                    ~
                                                                                                                                                                        -
j              Laboratory Report and the Koppers Co. report when available. The portion
}              of pipe with the worst coating de-bonding was the horizontal run above the
i              concrete mat which could have seen either of the two conditions described
i              above. In addition this portion of the pipe line had severe barnacle
!              attachment and is subject to mechanical loading forces due to pump
j              starting and pump shut off.
1
!              The licensee hydrolased the coating off the pipe in System I for                                                                                          !
i
              approximately 60 feet from the pump and 75 feet from the pump (toward the
:            chlorination point) in System II. Subsequent flushing was performed to
i-            ensure removal of loose material.
I
:'
              The inspector reviewed the following documents:
                                                                                                                                                                        i
i
              --
                      AWA C203-73 " Coal Tar Protective Coatings and Linings for Steel
                      Water Pipelines - Enamel and Tape - Hot Applied" (specified by the
j                    A . E ._ )
.
'              --
                      GPU Nuclear OCNGSP No. 607.4.001 Rev. IB (DP acceptance criteria -
i                    para.-8.1.5 and .6)
                                                                                                                                                                        ;
i
                                                                                                                                                                        t
,
                                                                                                                                                                          ,
                            ,-        -,  -.    - - . .
                                                            , - - , - , .        -n,  , , - , - , . - . , . - . -                w,.  ,m-..-        - ,.,.,-- , -- ,,
 
  .  -    .      . . -            --                  . - -                      . -. --- -  - - - - _ - - -                -
.
    ,. ,
          -
                                        O                                                      O
'
                                                                                  12
                --
                        GPU Nuclear 0CNGSP No. 607.4.003 Rev. 7 (requires check of CSHX tube
                        side pressures at various HX stages - Data Sheet 6.9)
                --
                        LER 50-219/82-64/032 (HX DP problem caused by marine fouling)
I
              Discussions with the licensee indicated the following additional
                information on subject piping system:
,
              --
                        In the area where there was coating de-bonding, the insulation had
                        been removed from the pipe for a long period of time.
              --
                        The nominal cooling water conditions during operation are 4000 GPM
                        flow at ambient temperature with a pressure of 65 psig at the HX.
              --
                      There has been no previous history of coating de-bonding. LER 064 in
;                      1982 concerning marine biofouling was solved by chlorination.
-
,
              --
                        Frequent periodic examination and cleaning of the water boxes on the
                        reactor building closed cooling water HXs required by biofouling
l                      problems has indicated the coal tar enamel coating in the plant
,                      Service Water system is intact. (The lined piping used in this
'
                        system is similar to that used in the ESW System.)
              --
                      GPUN Engineering estimates a corrosion rate of 14 - 15 mils per year
                      (including pitting reactions) on the bare carbon steel piping.
1
              --
                      TV optics examination of other portions of ESW system I and II where                                        ,
                                                                                                                                    '
                      coating was not removed from the pump to the chlorination point,
;                      indicates coating to be intact with no significant surface defects.
              --
                      The nominal pipe wall thickness is 1/2" with a minimum design wall
                      (including 0.088" corrosion allowance) of 0.150".
i
              --
                      Monthly ESW pump operability tests to 607.4.001 and 607.4.003 will
                      provide sufficient information on any tube blockage by DP readings.
              --
                      The Perfex four pass Containment Spray HXs were originally tubed with
                      aluminum brass which had reasonable service, then retubed with 90-10
                      CU-NI, which failed in a relatively short time apparently due to wet
;
                      layup (static) pitting beneath surface films, and finally retubed
                      with unalloyed titanium tubes. The current tubes have great
!
                      resistance to partially blocked tube erosion problems. The water
1                      boxes and tube sheets are CU-NI, but there is no evidence of galvanic
1
                      attack of the tube sheet.
>
              --
                      No final engineering decision has been made by the licensee on the
                      long term plans regarding the uncoated ESW piping. Base line UT
!                      readings have been taken for monitoring purposes in the event it is
!
                      later determined that monitoring is necessary. The next refueling
                      outage is April 1986. The pipe line will.be run with no coating in
1
:
                            . .  . . .  -.,-_.,-,,-.,,__,~,-,,,,-,.--,~.m,-'r,m_                                - , - . . . , . -
 
  ..
    . .
          .
                                O                                O
                                                  13
                    the pipe upstream of the chlorination point at least until April
                    1986. Replacement or recoating of the piping is being considered.
                    Estimated corrosion rates, if correct, would give long term (multiple
                    refueling cycle) satisfactory service with bare pipe.
              --
                    The exact initiating mechanism of the coating de-bonding is not
                    known. The final reports from the GPUN Reading Lab and Koppers will
                    be supplied to the NRC when available.
              --
                    No special surveillance requirements of the pipe corrosion rates (and
                    coating in the remainder of the pipe) are contemplated at this time.
              The NRC considers the issues discussed above as unresolved pending the
              licensee providing the following information for NRC review:
              --
                    Koppers Company failure analysis report.
              --
                    GPUN R(ading Materials Laborato y failure analysis report.
              --
                    Final engineering decision and the long term solution to the coating
                    de-bonding problem.
              --
                    Engineering justification for changes in pump operability tests which
                    will increase DP limits and possibly change testing time to ensure
                    sufficient transport time for loose coating to collect on HX tube
                    sheets. (219/85-23-04)
              No violations were identified.
        10. Followup of Operational Events
              10.1 In NRC Inspection Report 85-19, a problem concerning drywell bulk
                    temperature was discussed. During this report period, the
                    calculation to arrive at drywell bulk temperature was revised to
                    factor in the gas contained in the large spherical volume at the
                    bottom of the drywell. This dropped the calculated bulk temperature
                    by several degrees from that value arrived at by the orevious
                    calculation.
                    As regards the concern of the deviation between the FSAR and plant
                    procedures as to the assumed drywell bulk temperature at the start of
                    a design basis accident and the failure of the licensee to notify NRC
                    licensing of this change, the licensee submitted LER 85-017. This
                    LER described the problem and stated their plans for corrective
                    action. The corrective action stated in the LER addresses the NRC
                    concerns regarding this issue, therefore, final resolution will be
                    tracked as part of closeout of LER 85-017.
i
 
                                                                              -            _
    ,
      . .
          .
                              O                                  O
                                                14
            10.2 A scram from full power operation due to low condenser vacuum
                occurred on July 8, 1985. The inspectors responded immediately and
                particulary noted that no problems with the scram discharge volume
                drain valves recurred. The scram resulted when the steam jet air
                ejector drain pumps malfunctioned and ultimately affected the steam
                jet air ejectors (SJAEs). With erratic SJAE operation, condenser
                vacuum dropped to the setpoint of the low condenser vacuum scram.
                Plant response and recovery was considered normal. However, operator
                action to restore reactor vessel water level resulted in a high level
                condition which has been a problem in previous recoveries from
                various events. The licensee intends to address this issue in future
                training activities.
            10.3 In NRC Inspection Report 85-19, the MSIV closure scram from full
                power was discussed. In this discussion, some abnormal and normal
                equipment responses that raised concerns were presented. These
                included two series scram discharge volume drain valves leaking,
                inability to reset the scram until reactor pressure decreased to less
                than 600 psig, and potentially inoperable safety-related
                equipment due to initiation of a plant deluge system. Further
                discussion of these concerns follows:
                10.3.1    The licensee conducted an investigation into the cause of
                            the leaky scram discharge volume (SDV) drain valves. The
                            investigation disclosed that, on one of the valves
                            (V-15-121), the stroke was improperly adjusted such that
                            the valve did not fully close and, on the other valve
                            (V-15-134), the closing springs were undersized thus
                            failing to hold the valve closed against reactor coolant
                            system pressure. The stroke on V-15-121 was properly
                            adjusted and the proper size closing springs were installed
  .
                            in V-15-134. A licensee self-critique of the undersized
                            sorings identified a multitude of problems and situations
                            tnat contributed to the installation of V-15-134 during the      ,
                            last outage. Action has been taken to address the                '
                            identified concerns. A concern remaining, however, that
                            did not appear to be addressed was that V-15-134 was
                            installed such that reactor pressure tended to open the
                            valve rather than to help seat it. A second concern was
                            raised in NRC Inspection Report 84-09. In particular,
                            Unresolved Item 219/84-09-08 questioned why the SDV vent
,
                            and drain valves were not included as part of the
                            containment pressure boundary and, therefore, tested in
                            accordance with the requirements of 10 CFR 50 Appendix J.
                            These two concerns are unresolved pending licensee
                            justification for the installed position of V-15-134
                            (219/85-23-05) and a response to address why the SDV vent
                            and drain valves are not considered containment isolation
                            valves and, therefore, tested in accordance with the
                                                    .                              .  _._
 
                                                    -                =      - ._ -
,
  . .
      .
                    O                                  O
                                    15
                  requirements of 10 CFR 50 Appendix J.    (219/85-23-06)
                  (Note: Urresolved Item 219/84-09-08 is closed as it will
                  now be tracked as Unresolved Item 219/85-23-06.)
        10.3.2  Another concern raised as result of the MSIV closure scram
                  on June 12, 1985 was the inability to reset the scram until
                  the reactor was depressurized to 600 psig. This became
                  significant as a result of the failure of the Scram
                Discharge Volume drain valves to seat properly.
                A Technical Specification amendment changed the MSIV
                closure and low condenser vacuum scram bypass from 600 psig
                to 800 psia. The actual plant setpoint, however, remains
                at 600 psig as a result of some concerns the licensee
                developed as a result of the Intermediate Range Monitoring
                (IRM) nuclear instrumentation system Range 10 modification.
                The particular concern involved a reactivity addition
                accident (excessive feedwater addition; idle recirculation
                loop startup) and subsequent power excursion event from IRM
                range 9. The hypothesized event would have the operator
                erroneously responding to resulting power excursion by
                upranging from IRM range 9 to 10. This would replace the
                IRM range 9 scram setpoint of 12% with the IRM range 10
                scram setpoint of 38.4%. If the resultant reactor scram
                occurred due to the 38.4% trip point, the 25% safety limit
                associated with the GEXL correlation would be violated.
                The 25% safety limit associated with GEXL correlation is
                provided to limit core power when reactor pressure is less
                than 800 psia and core flow is less than 10*. to protect the
                fuel cladding
                integrity safety limit. This event theorizes that the
                neutronic trip of 38.4". would be reached prior to the MSIV
                closure and low condenser vacuum scram being unbypassed as
                pressure increases to the bypass setpoint.
                Based on this and similar hypothesized accident scenarios,
                the licensee elected to leave the MSIV closure and low
                condenser vacuum scram bypass setpoint at 600 psig instead
                of increasing the setpoint to the amended 800 psia point.
                This provides additional margin, possibly to insure the 25%
                core thermal power limit is not exceeded. The licensee is
                contemplating hardware and software modification (s) to
                eliminate the reliance on the 600 psig setpoint for core
              , protection. The inspector will review the licensee's
                analysis to support these modifications and the Technical
                Specification basis change to 800 psia in a future
                inspection report. (219/85-23-07)
                                                                -  .-              . .
 
          ..        .      _ _  . _ - _      _ _ _
                                                      - .        - - _ . - -                        . _ _ _ _. -.      _ - - - - -
,
    ..
              -
                                            O                                            O
                                                                                                                                        l
;                                                                        16
                                                                                                                                      >
.
                          10.3.3        An Unusual Event was declared when a fire protection
;                                        deluge system initiated and wetted down safety-related
                                          equipment thereby rendering operability status
                                          questionable. The fire protection system performed as
  ,                                      designed but did have a potential impact on the operability                                  i
*
                                          of safety-related equipment. This conflict in safety                                        i
!                                        system objectives, that apparently was only partially
1                                        addressed when spray shields were installed, is unresolved
!                                        pending licensee corrective action to address the conflict.                                  i
:                                        (219/85-23-08)
i
*
            11. 480 Volt Unit Substation Transformers-Low 011 Level
                                                                                                                                      i
                  The licensee shutdown the plant to perform an oil filling operation on
                  vital transformers 1A2 and 182 on August 9, 1985. The shutdown resulted
                  when the licensee determined, using a thermographic process, that the
  ,
                  vital transformers might not be able to perform their design function.
                  Using a thermographic photography process, the oil (ASKAREL) in the IA2
1                and 182 transformers was determined to be low and not flowing in some of
j                the cooling fins. This situation could be significant during a LOCA
-
                  coupled with a single-failure of one of the transformers. A single
4
                  transformer failure would result in both transformer LOCA loads being
!                supplied through one vital transformer. (LER 85-009 provides further
                  discussion of this area.) Under these conditions the vital transformer
                  may not be able to perform its design function with a degraded cooling
                  capability.
.
]                The licensee's investigation into the low level concern determined that                                              '
4
                  approximately five quarts of oil samples could have been taken since the
i
i
                  transformer installation. It could not be determined if any routine
'
                  sampling of these transformers was conducted or spectfied on any                                                    l
                  preventative maintenance schedule. As a result of the filling operation
;                and load / cooling tests performed on the vital transformers, the licensee                                          ,
                  determined that the oil level in the transformer cooling header was not
                  sufficient to fill all the cooling fins protruding into the headers.
                  During the filling operation the licensee established a new oil level
i                approximately l" higher than the specified nameplate data required. This
:
i
                  was done to insure all the cooling fins would be filled with oil and thus
                  restore full cooling capability to the transformers. The 1A2 and 182
:                transformers required 16 and 12 gallons, respectively, to establish this
:                new oil level. The IA2 transformer may have required more oil to
!
'
                  establish the new level as a result of the transformer being slightly out
'                of level. The licensee calculated the cold (25 C) as found oil level to
                  be slightly less than specified by the nameplate data. A General Electric
                  representative was present during the filling operation. Upon completion
                  of the filling operation, the licensee verified that all cooling fins had
                  proper oil flow using thermographic photography,
i
i
-
l
                      .--
      ---                      .                    - - - - - -            .- . . . - . - - - _ -              - - -            .
 
I
      *
  . ,
                                              17
            Some problems with instrumentation were discovered during the licensee's
            investigation. The liquid temperature indicator did not give an accurate
            reading of the oil temperature. The temperature indicator is installed in
            a cooling fin and to display an accurate liquid temperature reading its
            sensor must be submerged in the transformer oil. This particular cooling
            fin was one of the cooling fins that did not receive any oil flow as a
            result of the low oil level. During licensee testing of the vital
            transformer, a portable pyrometer was used to measure the oil temperature.
          Once oil flow in the cooling fin with the installed temperature device was
          established, the pyrometer and installed temperature sensor compared
            favorably. Another instrument problem was the liquid-level gage. The
          accuracy of the level gage required to sense small level changes in the
            transformer cooling headers is critical. The present level gage may not
          have the required accuracy to indicate these small level changes in the
          cooling header to the extent that an operator could determine the onset of
          cooling degradation.
          The licensee's immediate corrective action was to shut down and fill the
          transformers to the newly established oil level which is higher than the
          manufacturer's (GE) recommended level stated on the transformers.    The
          long term corrective action has not been finalized. A number of action
          items are being considered including:
          --
                A thermographic testing program
          --
                Transformer replacement
          --
                Issue filling and sampling procedures and requirements
          --
                Instrumentation upgrading
          In addition the licensee is planning to request General Electric to review
          the vital transformer cooling problem. The cooling capability of the
          vital transformers in regard to the oil level in the transformers has the
          potential to be a generic issue. This will remain an Inspector Followup
          Item pending final resolution of long term corrective action and analysis.
          (219/85-23-09)
      12. Exit Interview
          At periodic intervals during the course of this inspection, meetings were
          held with senior facility management to discuss the inspection scope and
          findings. A summary of findings was presented to the licensee at the end
          of this inspection. The licensee stated that, of the subjects discussed
          at the exit interview, no proprietary information was included.
}}

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