United States Nuclear Regulatory Commission - Protecting People and the Environment

ACCESSION #: 9411160196
                       LICENSEE EVENT REPORT (LER)

FACILITY NAME:  River Bend Station                        PAGE: 1 OF 7

DOCKET NUMBER:  05000458

TITLE:  TGSCC of CRD Piping Due to Inadvertent Contamination with
        a Chloride Bearing Substance

EVENT DATE: 10/10/94    LER #: 94-027-00    REPORT DATE: 11/09/94

OTHER FACILITIES INVOLVED:                          DOCKET NO:  05000



NAME:  Timothy W. Gates,                    TELEPHONE:  (504) 381-4866
       Supervisor - Nuclear Licensing




On October 10, 1994 at approximately 0100, with the plant in Operational
Condition 4 (cold shutdown), a control rod drive (CRD) pipe was found to
be cracked and leaking.  This condition was identified by plant personnel
exhibiting a noteworthy level of attention to detail during a scheduled
walkdown/visual inspection of the drywell prior to plant startup.
Investigations were performed which determined that a total of eight CRD
pipes, and a section of the 'A' variable leg narrow range level pipe were
affected and required repairs.  Detailed analyses of this condition
concluded that the failure mode was chloride induced Transgranular Stress
Corrosion Cracking (TGSCC).  The event which created the opportunity for
the TGSCC is suspected to be a spill of high chloride bearing Therma-Cel
950 adhesive on the piping during the plant construction or early
refueling outages.

Immediate corrective actions were taken to replace those sections of
stainless steel pipe that exhibited crack indications.  The balance of
the plant equipment that could have been susceptible to this degradation
has been addressed.  To preclude recurrence, the chemicals used in the
power block will be evaluated and additional control measures will be
instituted, if appropriate.  This condition did not pose a significant
safety hazard.  A review of LERs at RBS did not reveal any similar


TEXT                                                          PAGE 2 OF 7


On October 10, 1994 at approximately 0100, with the plant in Operational
Condition 4 (cold shutdown), the CRD (*AA*) piping (*PSP*) on control rod
44-33 insert line was found to be cracked and leaking.  This condition
was identified during a scheduled walkdown of the drywell prior to plant
startup.  A visual inspection revealed an unknown brown hardened
substance on the affected piping around the crack.  When conditions
allowed, detailed investigations were performed which determined that a
total of eight insert or withdrawal CRD pipes, and a section of the 'A'
variable leg narrow range level pipe exhibited similar degradation.
Since this condition could potentially create a serious degradation of a
principle safety barrier, this condition is reported pursuant to 10 CFR


As stated above, the adverse condition associated with the CRD piping on
control rod 44-33 was identified by plant personnel during a scheduled
plant walkdown.  The individual who found the condition demonstrated a
noteworthy level of attention to detail because the tell-tale leakage was
very minimal.  Subsequent to this initial finding, further inspections of
the CRD insert and withdraw lines at azimuth 85 degrees and the
surrounding areas were performed on October 12, 1994.  A foreign material
was identified on the surface of the piping, grating and several cable
conduits in the area.  The foreign substance appeared reddish-brown in
color and was dried onto the surface.  It appeared initially that a
liquid had spilled from higher elevations in the drywell.  It had the
same consistency as dried paint and was difficult to remove from the
surface that it contacted.  The material path was traced up above the CRD
piping by the splatter trail.

On October 14, 1994, a general inspection of uninsulated stainless steel
piping in the Drywell was performed to determine if there was any other
piping having the "brownish solid deposit" that seemed to be the common
denominator of the corrosion/cracking phenomenon.  Three teams of three
persons each conducted the inspection.  As a result of these and
additional walkdowns in the containment, Radiation Monitoring System
(*IL*), Containment Atmosphere Monitoring System (*IK*), and Standby
Liquid Control System (*BR*) piping were examined by ultrasonic testing
(UT) and determined to be free of cracks.

Samples of the foreign material deposited on piping were analyzed for
chemical composition at commercial laboratories.  These analyses commonly
indicated high levels of chlorides and the presence of iron, copper, zinc
and other minor constituents.  The composition of these samples was
compared with potential candidate sources.

TEXT                                                          PAGE 3 OF 7

Based on the available chemistry results and locations of the affected
piping, the foreign material was determined to most likely be the
Therma-Cel 950 adhesive.  Other possible, but less probable, sources of
foreign material were also analyzed and ruled out in the investigation.

Therma-Cel 950 was approved for use on chilled water and service water
piping for anti-sweat insulation at River Bend Station during
construction.  The Chemical Permit for use of this adhesive was
discontinued on 2/01/90.  It was also determined that the production of
Therma-Cel 950 was discontinued in 1988 and that it had a shelf life of
one year.

A nondestructive investigation of the CRD lines was conducted using UT
methods.  The following pipes, with the characteristic brownish deposits,
were found to have outside diameter flaws:

1RDS-125-3233 insert
1RDS-125-3233 withdraw
1RDS-125-3633 insert
1RDS-125-3633 withdraw
1RDS-125-4033 insert
1RDS-125-4433 insert
1RDS-125-4833 insert
1RDS-125-5233 insert
1RCS-750-33-2 variable leg "A"

Initial UT testing was directed to piping with the same heat number
around the problem area.  Subsequently, additional lines were examined
to determine if other material heat numbers or deposits were a potential
root cause.  All of these additional lines were found to be free of

Axial cracks which allowed weepage to occur existed on only one insert
line of the CRDs.  This was determined by non-destructive UT.  These
cracks were further evaluated to establish the cause of the cracking.
The evaluation consisted of a detailed visual examination with the aid
of a Stereo Microscope, Scanning Electron Microscopy (SEM), analysis of
fracture surface corrosion products and deposits, Energy Dispersive
Spectroscopy (EDS), Metallography, and Optical Emmersion Spectroscopy
(OES) for base metal chemistry determination.  The results obtained from
these analytical evaluations form the basis for determination of the
cause.  The cause of the cracking was determined to be TGSCC initiating
on the outside diameter of the pipe and penetrating through the wall.
Testing of the brown colored deposit and the corrosion product on the
fracture surface showed the presence of chlorides.  Hence it is shown
that the cracking mechanism was chloride-induced TGSCC.

TEXT                                                          PAGE 4 OF 7

The conditions required to promote Stress Corrosion Cracking (SCC) were
also investigated for the purposes of bounding this condition.  For SCC
in chloride environments (> 10ppm) to occur, the temperature has to be
above a minimum threshold of 140 degrees F.  Therefore, below 140 degrees
F the likelihood of SCC occurring is very low.  The other controlling
factor is stress loading.  The threshold stress for 304 stainless steel
is conservatively estimated to be 10.0 ksi.  The pertinent loading for
axial flaws is from hoop stress.  The stress values associated with
various system's piping in conjunction with the expected temperature
conditions were analyzed to evaluate susceptibility of various system's
piping to SCC.


Stainless steel piping in the plant that could have had a potential for
exposure to chloride contamination was inspected.  Eleven pipes in
containment, four pipes in the fuel building, and no pipes in the
auxiliary building were identified as potentially having the same type of
deposit which contributed to chloride contamination on the CRD lines.  At
these locations, no cracks were found on the lines that had the material
per UT inspection.  The probable reason for this finding is that the
piping fell below the minimum threshold limits for temperature (140
degrees F) and sustained applied stress (10.0 ksi).

The list of susceptible pipe was developed using the line designation
tables and the above criteria.  The physical locations of these lines
were listed and all lines inside the Drywell and Containment were
eliminated based on previous walkdowns.  The final list of lines meeting
the criteria were eliminated by the completion of the auxiliary building
and fuel building walkdowns and the elimination of non-safety related
piping in the turbine building.

The contaminated piping found in the drywell experienced environmental
conditions which were conducive to TGSCC.  Other areas of the plant were
reviewed to determine if conditions existed which could be conducive to
SCC.  Fracture Mechanics Analyses were also performed which showed that
the affected piping contained sufficient margin to insure structural
integrity of piping for part through wall and through wall cracks.  Based
upon this analysis, extensive visual inspection, and exclusion criteria
stated above, we have concluded that a generic problem resulting in gross
failure of stainless steel piping due to TGSCC does not exist at River
Bend Station.


Event and causal factor analysis was utilized to determine root cause of
this event.  The failure mode was determined to be chloride induced
Transgranular Stress Corrosion Cracking (TGSCC).  The event which created
the opportunity for the TGSCC is suspected to be a spill of high chloride
bearing Therma-Cel 950 adhesive on the piping during the plant
construction or early refueling outages.

TEXT                                                          PAGE 5 OF 7

Contributing causes were the lack of a sufficiently comprehensive
chemical control program during the construction and early operational
phase of the plant, an apparent lack of personnel accountability
regarding the use of chemicals inside the containment, and the failure to
recognize the adverse conditions that could result from the splattering
of the Therma-Cel 950 during its application.

A review of LERs at RBS did not reveal any similar events.  Note,
however, that RICSIL-052 documents similar CRD insert and withdrawal line
cracking caused by chloride induced TGSCC at Fukushima, Brunswick and
Duane Arnold.  Sources of chlorides were different in each case and
ranged from sea water, cable insulation, and an unknown source.  The
known failure mechanisms described in this RICSIL were reviewed and
determined not to be applicable to RBS.  Generic actions to help identify
the potential for SCC due to unknown chloride contamination sources were
also evaluated.  RBS's review following receipt of the RICSIL concluded
that the existing plant programs (e.g., scheduled system walkdowns and
surveillances, the IST/ISI program, reactor system hydro test, etc.) were
adequate for identifying any degradation that could potentially occur.
Note that this condition was identified during a normally scheduled
pre-startup walkdown.  The RICSIL evaluation was reviewed as a result of
this event and found to be satisfactory given the indications available
at the time.


The following immediate corrective actions have been taken to correct and
bound the identified condition.

o    The eight CRD pipe sections and the one RCS pipe section which
     exhibited crack indications as a result of TGSCC have been replaced.

o    Area inspections were conducted to identify plant equipment that
     could have been exposed to the adhesive.

o    All CRD pipelines found bearing deposits of Therma-Cel 950 have been
     cleaned, inspected and evaluated.

To preclude recurrence, the following long-term corrective action is
being pursued.

o    Chemistry will re-evaluate all current chemical permits used in the
     power block to identify materials which contain chlorides.
     Additionally, these permits will be reviewed to ensure that
     appropriate restrictions exist to govern use of these materials.
     This action will be completed by January 18, 1995.

TEXT                                                          PAGE 6 OF 7

o    Lessons-learned training will be conducted on the event discussed in
     this LER.

o    EOI management has recognized the need to improve personnel
     accountability and to heighten the awareness of personnel to
     identify conditions which could have adverse consequences.  Generic
     actions being implemented in these areas and are described in RBS's
     Long Tenn Performance Improvement Plan.  Details of these
     programmatic improvements are provided in Section 9, "Problem
     Identification and Problem Solving;" Section 10, "Problem
     Identification and Root Cause Evaluation;" and Section 13, "Human
     Performance Effectiveness.


As discussed above, several CRD pipes and a variable leg pipe were found
with indications and cracks.  The degradation mechanism was determined to
be Transgranular Stress Corrosion Cracking (TGSCC) which was induced in
the stainless steel piping by the presence of chlorides in the adhesive.
This cracking was axial in alignment and was limited to an area directly
under a foreign substance which was located on the outside diameter
surface of the piping.

A detailed metallurgical examination of the worst-case pipe determined
that only a limited number of the axial cracks noted on the outside
diameter surface penetrated through the pipe wall.  The axial cracks on
the outside diameter were discontinuous with each individual crack being
short and discrete (i.e. intact ligaments existed between the cracks).
This evaluation concluded that the initiation and the propagation of the
TGSCC cracks occurred as a single event.  The driving mechanisms (i.e.,
free chlorides) of TGSCC is greatly reduced when the deposited material
dries; therefore, the pitting and etching associated with TGSCC cease.

No gross failures of the CRD piping have occurred as a result of this
mechanism at RBS.  Given the calculated CRD pipe stresses, an analysis
was performed to determine the critical crack length to assess the margin
of safety based on the observed crack lengths.  For the longest observed
crack length on the worst-case CRD insert pipe, there was a 30% margin on
pipe stress against gross pipe failure.

From a systems perspective, the function of the CRD system is to position
the control rods for the purpose of controlling the criticality of the
reactor.  The system's most significant safety function is the ability to
Scram the reactor when required.  The greatest challenge this condition
could impose on this system has been postulated to be a gross failure of
a CRD insert line.  However the system has been designed with the ability
to perform its Scram function with the failure of an insert line.  The
control rods are Scrammed by opening the insert portion of the drive
system to a volume of high pressure CRD water and opening the exhaust
(withdrawal) side to atmospheric pressure.  This differential pressure
quickly drives the control rods into the reactor core.  Each CRD
mechanism is provided with a ball check valve on the insert side which is

TEXT                                                          PAGE 7 OF 7

held closed against reactor pressure by the CRD drive water.  Upon the
loss of the system's ability to provide the required driving water to the
insert side of the CRD mechanism, this ball check valve would change
position and allow the high pressure reactor water to drive the control
rod into the reactor.  The water provided from the vessel will fully
Scram each affected rod, as required.

It had been shown that no gross failures of the CRD system or the reactor
pressure boundary occurred because of this condition.  Furthermore, it
has been shown that if a gross failure had occurred in the CRD system,
the system would maintain its ability to safely shut down the reactor.
Based on the above, it is concluded that this condition did not pose a
significant safety hazard.

Note: Energy Industry Identification System Codes are indicated in the
text as (*XX*)

ATTACHMENT TO 9411160196                                      PAGE 1 OF 2

                                        Entergy Operations, Inc.
                                        River Bend Station
                                        5485 U.S. Highway 61
                                        P. O. Box 220
ENTERGY                                 St. Francisville, LA 70775
                                        (504) 336-6225
                                        FAX (504) 635-5068

                                        JAMES J. FISICARO
                                        Nuclear Safety

November 9, 1994

U.S. Nuclear Regulatory Commission
Document Control Desk
Mail Stop P1-37
Washington, D.C. 20555

SUBJECT:       River Bend Station - Unit 1
               Docket No. 50-458
               License No. NPF-47
               Licensee Event Report 50-458/94-027
               File Nos. G9.5, G9.25.1.3

RBG- 41053


In accordance with 10CFR50.73, enclosed is the subject report.



ATTACHMENT TO 9411160196                                      PAGE 2 OF 2

Licensee Event Report 50-458/94-027
November 9 1994
RBG- 41053
Page 2 of 2

cc:  U.S. Nuclear Regulatory Commission
     611 Ryan Plaza Drive, Suite 400
     Arlington, TX 76011

     NRC Sr. Resident Inspector
     P.O. Box 1051
     St. Francisville, LA 70775

     INPO Records Center
     700 Galleria Parkway
     Atlanta, GA 30339-3064

     Mr. C. R. Oberg
     Public Utility Commission of Texas
     7800 Shoal Creek Blvd., Suite 400 North
     Austin, TX 78757

     Louisiana Department of Environmental Quality
     Radiation Protection Division
     P.O. Box 82135
     Baton Rouge, LA 70884-2135
     ATTN: Administrator


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