ML14178A079
| ML14178A079 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 02/01/1991 |
| From: | Christensen H, Garner L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14178A077 | List: |
| References | |
| 50-261-90-30, NUDOCS 9102130112 | |
| Download: ML14178A079 (16) | |
See also: IR 05000261/1990030
Text
t~kREGU'
UNITED STATES
NUCLEAR REGULATORY COMMISSION
0.,
REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/90-30
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Conducted: December 11, 1990 - January 10, 1991
Lead Inspector:
/
/
L.
. Ga
r, Senior
sid
Inspector
Ddte Sioned
Other Inspector:
K. R. Jury
Approved by:
.-
H. 0. Christensen, Section Chief
Date Signed
Reactor Projects Branch 1
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation,
refueling activities and action on previous inspection findings.
Results:
A violation was identified involving an inadequately established preventive
maintenance procedure for inspection of the residual heat removal system pump
discharge check valves (paragraph 4).
The ultrasonic surface reflectors on the A steam generator upper girth weld
were determined (by visual and fluorescent magnetic particle inspections) not
to be similar to those associated with rapid crack propagation occurring in
other utilities' steam generators (paragraph 6).
The actual 1990 radiological exposure of 437 Person-Roentgen Equivalent Man
(REM) was less than the 450 Person-REM goal established at the beginning of
1990 (paragraph 2).
9102130112 910201
ADOCK 05000261
G
2
The component cooling water piping to the residual heat removal pump seal
coolers ruptured during a hydrostatic test. The probable root cause was
attributed to rain or other external water intrusion between the piping and
thermal insulation, resulting in extensive external corrosion of the carbon
steel pipe (paragraph 2).
Extensive service water system inspection, repairs, and component
refurbishment/replacement were performed during the refueling outage
(paragraph 2).
Strong communications and interfacing was evident between Technical Support
and Nuclear Engineering Department on both the service water system efforts
and the A steam generator indications resolution (paragraphs 2 and 6).
Fourteen spent fuel assemblies have been shipped from the site to the Harris
Nuclear Facility in North Carolina (paragraph 6).
All control rod guide tube support pins have been replaced with a redesigned
pin which is less susceptible to intergranular stress corrosion cracking
(paragraph 6).
REPORT DETAILS
1. Persons Contacted
- R. Barnett, Manager, Outages and Modifications
C. Baucom, Shift Outage Manager, Outages and Modifications
J. Benjamin, Shift Outage Manager, Outages and Modifications
C. Bethea, Manager, Training
- W. Biggs, Manager, Nuclear Engineering Department Site Unit
S. Billings, Technical Aide, Regulatory Compliance
R. Chambers, Manager, Operations
- D. Crook, Senior Specialist, Regulatory Compliance
- J. Curley, Manager, Environmental and Radiation Control
- C. Dietz, Manager, Robinson Nuclear Project
D. Dixon, Manager, Control and Administration
J. Eaddy, Supervisor, Environmental and Radiation Support
S. Farmer, Supervisor -
Programs, Technical Support
R. Femal, Shift Foreman, Operations
- W. Gainey, Plant Support
E. Harris, Manager, Onsite Nuclear Safety
- J. Kloosterman, Director, Regulatory Compliance
D. Knight, Shift Foreman, Operations
E. Lee, Shift Outage Manager, Outages and Modifications
A. McCauley, Supervisor -
Electrical Systems, Technical Support
R. Moore, Shift Foreman, Operations
D. Nelson, Shift Outage Manager, Outages and Modifications
- M. Page, Manager, Technical Support
D. Seagle, Shift Foreman, Operations
- J. Sheppard, Plant General Manager
- R. Smith, Manager, Maintenance
R. Steele, Shift Foreman, Operations
D. Winters, Shift Foreman, Operations
- H. Young, Director, Quality Assurance/Quality Control
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and office personnel.
- Attended exit interview on January 15, 1991.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Operational Safety Verification (71707)
The inspectors evaluated licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory
requirements. These activities were confirmed by direct observation,
facility tours, interviews and discussions with licensee personnel and
2
management, verification of safety system status, and review of facility
records.
To verify equipment operability and compliance with TS, the inspectors
reviewed shift logs, Operations' records, data sheets, instrument traces,
and records of equipment malfunctions. Through work observations and
discussions with Operations staff members, the inspectors verified the
staff was knowledgeable of plant conditions, responded properly to
alarms, adhered to procedures and applicable administrative controls,
cognizant of in-process surveillance and maintenance activities, and
aware of inoperable equipment status. The inspectors performed channel
verifications and reviewed component status and safety-related parameters
to verify conformance with TS. Shift changes were observed, verifying
that system status continuity was maintained and that proper control room
staffing existed. Access to the control room was controlled and
operations personnel carried out their assigned duties in an effective
manner. Control room demeanor and communications continued to be
informal, yet effective.
Plant tours and perimeter walkdowns were conducted to verify equipment
operability, assess the general condition of plant equipment, and to
verify that radiological controls, fire protection controls, and physical
protection controls were properly implemented.
Source Range Monitors
In preparation for fuel reloading, I & C determined on December 4, 1990,
that both source range monitors (NI-31 and NI-32) were not operable and
could not be repaired. Moisture apparently had intruded into the cables
and/or connectors, and short circuited the detectors. A PNSC review of
potential alternatives to monitor the core during fuel reloading resulted
in a decision to replace both the NI-31 and NI-32 detectors. Replacement
detectors were installed, tested, and placed in service on December 15,
1990. At the end of the report period, the licensee was in the process
of replacing the source range and intermediate range monitor cables.
CCW Line Degradation
On December 13, 1990, during hydrostatic testing for modification M-1017,
Eliminate RHR Pump Common Mode Failure, the CCW return line from the A
RHR pump seal cooler ruptured. Subsequently, based upon a visual
inspection, engineering concluded that portions of the supply and return
lines into the RHR pit were so extensively damaged by external corrosion
that successful hydrostatic test completion appeared improbable.
Engineering recommended replacement of supply and return piping sections
from both A and B RHR pump seal coolers. The pipe replacement was
accomplished in accordance with WR/JO 90-ARIT1, 90-ARIW1, and 90-ARJK1.
The piping was subsequently successfully hydrostatically tested on
December 19, 1990, per SP-369, System Hydrostatic Pressure Testing of
Component Cooling Water System, and returned to service.
3
The affected piping consisted of approximately 20 feet of 1 and 2-inch,
schedule 40 carbon steel piping. Preliminary root cause analysis
indicated that water, most likely rain, had over a period of years
penetrated between the pipe and its thermal insulation, thereby wetting
the pipe OD and causing the external corrosion. The piping degradation
went undetected apparently due to the piping being insulated. The
replacement piping was painted with an epoxy type paint to reduce the
potential for external corrosion. The licensee has not determined what
monitoring or inspections, if any, are necessary to detect future or
additional external piping corrosion. This is an IFI:
Review Steps To
Detect And/Or Preclude Extensive External Corrosion Of Carbon Steel
Piping, 90-30-01.
Inspection Report 89-09 discussed a RHR system common mode failure in
which a leak in the RHR pit would not be isolable during the
recirculation phase of an accident due to high radiation fields. This
postulated scenario would eventually result in both RHR pump motors
shorting out (i.e., loss of all ECCS capability). The report describes
compensatory measures to isolate certain potential leak paths into the
RHR pit by closing certain valves before entering the recirculation phase
of an accident. The compensatory actions did not include isolation of
the CCW lines to the RHR pump seal coolers. The pump vendor indicated
that the RHR pump seals could operate indefinitely at the temperatures
anticipated during the recirculation phase of an accident; however, it
was considered prudent to have the seal coolers remain in service during
an accident. This decision was based in part on the determination that
leakage from these lines was a relatively small contributor to the
estimated core melt frequency for the assumed event. If an external
inspection had been performed of these lines at that time, it appears
that the low probability of failure would not have been assumed. The
inspectors discussed with management that -future JCO evaluations should
consider what measures, if any, need to be taken to establish confidence
that equipment relied upon for acceptable continued operation is not
degraded.
1990 Radiological Goals Status
The E & RC Manager provided the inspectors with the following actual
end-of-year status of selected radiological goals:
Actual
Goal
Exposure (Person-REM)
437
<450
Contamination Events
235
<300
Contaminated Area (sq. ft.)
5795
<2000
Radwaste Volume (cu. ft.)
2467
<4000
Prior to the outage (i.e., end of August 1990), the contaminated area YTD
value was 1220 sq. ft..
During the outage, the contaminated area has
typically varied between 5,000 and 6,000 sq. ft..
The licensee is
decontaminating areas such that the amount of contaminated space will be
4
reduced to levels similar to that existing prior to the outage. The
radwaste volume shipped is the lowest amount since 1973, the year in
which radwaste volume trending was initiated.
System Cleanliness
On January 3, 1991, the inspectors observed that CC-702A, the A CCW pump
discharge check valve, had been left open without anyone in the area. The
inspectors reported this condition to an operator so that appropriate
measures could be taken to preclude foreign materials from entering the
system. The inspectors visually verified that no foreign materials had
entered into the valve body at that time.
SW System Outage Activities
During RO-13, extensive inspections, repairs, refurbishment/replacements,
and modifications were performed on the SW system and its components.
These activities were performed as a result of various requirements (i.e.,
GLs 89-13 and 90-05), commitments, and licensee initiatives. The
inspection portion of the SW system efforts included visual and camera
inspections of the 30", 24", 20", 18", and 16" diameter, cement-lined
piping.
This inspection included both the buried north and south SW
supply headers which are discussed later in detail.
Key SW check valves
inspected include:
the A,B,C, and D SW pump discharge check valves,
SW-374, -376, -375, and -377, respectively; the north and south header
check valves, SW-541 and -545, respectively; and the A and B SWBP
discharge check valves, SW-561 and -560, respectively. These valves were
not disassembled due to replacement part unavailability; however, each
valve was inspected, cleaned, and mechanically stroked with the exception
of SW-561, which was replaced on November 8, 1989.
With the exception of the buried SW supply headers, most of the cement-lined
SW lines and joints inspected were relatively sound, with only localized
cement liner spalling evident. These localized areas, as well as the
header joints, were repaired with Speed Crete Blue Line, which is a
commercially prepared portland cement mortar. The acceptability of this
material was justified and approved by EE 90-100, Revision 0, Evaluation
of a Commercial Prepared Portland Cement Mortar for Repair of Cement
Lining of the RNP's Service Water Pipes. The repairs were performed
under SP-968, Cement Lining Repairs Using "Speed Crete Blue Line".
Additionally, a black "slime" was identified as covering the inside of
the large majority of the SW piping inspected. This foreign substance is
discussed in the following paragraph. In regard to the buried north and
south SW supply headers, the following paragraphs give a brief description
of the inspection/repairs that were performed on the subject piping.
The buried SW supply piping is a 31.375" OD by 0.188" nominal wall,
cement-lined pipe divided into two headers approximately 900 feet long
each. The piping was purchased and installed in 1968 under the AWWA
specifications.
Camera, visual, and UT inspections were performed inside
5
the pipe. The initial camera inspections, as well as visual walkdowns,
indicated the piping to be coated with a black "slime" with localized
areas of concrete lining missing. The inspections also identified that
the non-coated cross-sectional areas had experienced corrosion-induced
pipe thinning. Degradation was observed primarily in the bell and spigot
(mechanical slip-fit) joints with additional joints also exhibiting
corrosion. The black "slime" was determined to be manganese dioxide
hydroxide and iron dioxide hydroxide. Agitation and aeration of Lake
Robinson water which contains high levels of tanic acid caused these
chemicals to precipitate out of solution.
After the initial inspections revealed corrosion in the locations which
were not cement-lined, the licensee attempted to quantify the degree of
corrosion through interior UT examinations of selected north and south
header joints. This UT indicated that there were not any areas with a
minimum wall thickness less than the calculated required thickness.
Based upon both the interior UT and the visual examinations, the bell and
spigot joints in the north header were cleaned and covered with Speed
Crete. Subsequently, it was determined that the interior UT data was
invalid due to the UT probe being larger than the effective size of the
corroded areas being measured (i.e., some pit depth was measured as wall
thickness). Additional and more accurate UT was then performed on
selected joints from the piping's exterior. Based on the initial visual
determination that the south header was in worse shape and more
susceptible to corrosion (i.e., piping not as well fit-up with larger
joint gaps and contained more elbows), the additional examinations
focused on the joints determined to be the 12 worst south header joints.
Two "typical" (bell and spigot) joints in the south header, S-10 and
S-42, were determined to require repair. All other "typical" joints were
evaluated per calculations and formulas (calculation no. RNP-C/STRS-1114)
per ASME Code Case N-480 and were determined to be acceptable.
The four atypical (non-bell and spigot) joints in the north header were
repaired/replaced based on the corrosion severity on those joints. In
addition to south header joints S-10 and S-42, weld areas on joints S-6,
5-31, and a factory butt welded joint required repair. Joints S-10 and
S-42 utilized a butt strap repair/replacement technique, where S-6, S-31,
and the factory joint required weld repair. All repair/replacements were
performed in accordance with the original pipe design, ASA B31.1-1955
Edition, Code for Pressure Piping, and AWWA Standard, ANSI/AWWA C206-88,
Field Welding of Steel Water Pipe. Subsequent weld joint inspection was
performed per AWWA C206-88, Section 5.8. All repaired/replaced joints
were subsequently covered with Speed Crete.
Upon repair/replacement
completion, the system was hydrotested per ASME Section XI, IWA-5000,
1977 Edition, Summer 1978 Addenda. At the end of the report period, the
inspectors had not reviewed the calculations, inspections, and hydrotest
results; however, they were deemed acceptable by the licensee.
Also inspected during the outage were the smaller diameter SW lines, as
well as the SW intake structure and traveling screens.
The intake
structure and screen inspections did not identify significant structural
6
damage nor sediment/fouling buildup that could affect SW pump
performance. Smaller diameter SW piping lines (i.e., MDAFW and SDAFW Lube
Oil Coolers, ECCS Pump Room Coolers) were determined to have varying
degrees of fouling. The normal manual cleaning and flushing method was
supplemented by utilization of a foam plug or "pig".
The procedure
involved the forcing of the "pig" through the lines, thus swabbing the
pipe walls and loosening the fouling material.
The lines were
subsequently flushed. Some small diameter SW lines were only manually
cleaned and flushed.
During the outage, extensive refurbishment was performed on three SW
pumps and three motors, as well as the SWBPs and motors. The
refurbishment included, but was not limited to: shaft, impeller, and
bearing replacement; tolerance and clearance checks; shop testing; and
generation of pump specific head curves. The motor refurbishment (also
vendor performed) included cleaning, tolerance checks, electrical
testing, etc., as well as any necessary component repair/replacement.
At the end of the report period, A, B, and D SW pumps and motors had
been refurbished and installed with the original C pump and motor
installed as well.
The refurbished C motor (originally a spare) was
expected to arrive on site by January 18, 1991. An additional
refurbished (spare) pump was already on site. Upon delivery and outage
schedule permitting, the refurbished pump and motor will be installed.
Subsequent to this installation, the original C pump and motor will be
refurbished, with the pump's internals being upgraded. The refurbished
SWBP and motors have been reinstalled.
Prior to the outage, twenty-nine SW valves were scheduled to be replaced.
The valves were scheduled for replacement due to design changes, lack of
replacement parts, and in some cases due to degradation. Component
availability resulted in twenty-two of these valves being replaced, as
well as three others which were originally scheduled for repair. The
following is a list of the replaced valves:
Valve
Description
SW-20
CCW Hx A Cooling Water Supply
SW-21
CCW Hx B Cooling Water Supply
SW-23
SW Return from Auxiliary Building
SW-142
TCV-1650 Inlet
SW-143
TCV-1650 Outlet
V6-33 A,B,C,D,E,F
SWBP Supply to HVH Units
V6-34 A,B,C,D
HVH Cooling Water Return
Isolation
SW-24
South Header Supply to SWBP
SW-26
SWBP Suction Cross Connect
SW-27
SWBP Suction Cross Connect
SW-28
SWBP A Suction Valve
SW-29
SWBP B Suction Valve
SW-32
SW Pump A Discharge Valve
SW-33
SW Pump B Discharge Valve
7
SW-739
CCW Hx A Cooling Water Return
SW-740
CCW Hx B Cooling Water Return
SW-741
CCW Hx B and Auxiliary Building
Return Isolation
The seven SW valves which were not replaced included: V6-12A and D, the
South and North SW Supply Header Isolation valves, respectively; V6-12B,
and C, the SW Pump Discharge Cross Connect valves; V6-16 A and B, the
North and South SW Supply to Turbine Building, respectively; and V6-16C,
the Turbine Building Cooling Water Isolation valve. The V6-12 valves were
inspected and found to be in good condition (i.e., no repair or replace
ment was necessary). The V6-16 valves were inspected, cleaned, Belzona
covered, and received new seats. Valves SW-739, -740, and -741 which were
not originally scheduled for replacement were replaced due to significant
degradation. Additionally, significant pipe erosion downstream of these
latter valves was detected. The eroded pipe was replaced. Some erosion
had been anticipated; however, the amount of degradation found was
unexpected. The system engineer plans on initiating a PM Route to inspect
this piping on a regular interval.
This is an IFI: Establishment of PM
Route To Inspect SW Piping, 90-30-02.
While the SW buried piping corrosion issue/resolution was very complex
and time consuming, the communications and interfaces between Technical
Support and NED were effective, with the Technical Support system
engineer's coordination and oversight being particularly noteworthy.
Spent Fuel Shipments
On December 4, 1990, fourteen spent fuel assemblies were transported from
the HBR site to the spent fuel storage facility at SHNPP in North
'
Carolina. Future shipments are scheduled for 1991. The shipments will
allow sufficient room in the spent fuel pool for a full core off-load.
No violations or deviations were identified.
3. Monthly Surveillance Observation (61726)
The inspectors observed certain safety-related surveillance activities on
systems and components to ascertain that these activities were conducted
in accordance with license requirements. For the surveillance test-
procedures listed below, the inspectors determined that precautions and
LCOs were adhered to, the required administrative approvals and tagouts
were obtained prior to test initiation, testing was accomplished by
qualified personnel in accordance with an approved test procedure, test
instrumentation was properly calibrated, and that the tests conformed to
TS requirements. Upon test completion, the inspectors verified the
recorded test data was complete, accurate, and met TS requirements; test
8
discrepancies were properly documented and rectified; and that the
systems were properly returned to service. Specifically, the inspectors
witnessed/reviewed portions of the following test activities:
OST-401 (revision 25)
Emergency Diesels (Slow Speed Starts)
RHR Pump Flow Test
RHR Flow Test
On January 4, 1991, the inspectors observed performance of SP-1002, RHR
Pump Flow Test. While attempting to take flow and pressure data with the
A RHR pump operating in shutdown cooling, the flow rate appeared unstable
or oscillatory in nature. The procedure was discontinued after two sets
of data was taken. At the end of the report period the flow instability
cause(s) had not been determined and a revised test procedure was being
prepared utilizing another system configuration. The licensee plans to
perform this test and resolve the issue prior to startup. The inspectors
will review and document the resolution in IR 91-01.
No violations or deviations were identified.
4.
Monthly Maintenance Observation (62703)
)
The inspectors observed safety-related maintenance activities on systems
and components to ascertain that these activities were conducted in
accordance with TS and approved procedures.
The inspectors determined
that these activities did not violate LCOs and that required redundant
components were operable. The inspectors verified that required
administrative, testing, radiological, and fire prevention controls were
adhered to. In particular, the inspectors observed/reviewed the
following maintenance activities:
90-ALYE1
Snubber 30 Bracket Repair
91-ARRSI
Adjustment of A EDG Turbocharge Exhaust Nozzle
90-AKGE1
Votes Testing of FW-V2-6A
90-AKGF1
Votes Testing of FW-V2-6B
91-AAQH1
MCC Contractor Contacts Inspection
B RHR Pump Impeller
On November 26, 1990, the inspectors witnessed the technical support
inspection of the B RHR pump impeller. The impeller was considered to be
in good condition; however there was an eroded area, less than 1 sq. cm.,
observed on one discharge vane. Repair of this area was deemed not to be
currently necessary. At the end of this reporting period, the licensee
had not determined if periodic inspections of the eroded area need to be
conducted. This an IFI:
Review Periodic Inspection Frequency
Determination For B RHR Pump Impeller, 90-30-03.
9
A EDG Operating Temperatures
The A EDG, Fairbanks Morse model 38TD81/8, has historically operated
fully loaded with the exhaust temperature approximately 100 degrees
centigrade higher than that measured on the B EDG.
Individual cylinder
exhaust temperatures have been 50 to 75 degrees centigrade hotter on A
EDG than these experienced on the corresponding B EDG cylinders. The A
EDG turbocharger air inlet check valve has not operated in a manner
similar to the B EDG valve. Normal valve operation is as follows: At
less than 80 to 90 percent of full load (2500 KW) the valve is fully
closed. This allows the inlet air to be diverted through the scavenger
air blower prior to being routed under the valve and into the
turbochargers. As the load is increased, an increasing volume of air is
drawn into the engine and exhausted through the turbocharger exhaust
turbine blades. The increasing flow increases the turbocharger speed
(i.e., the inlet pressure decreases at the turbocharger suction and below
the air inlet check valve). The differential pressure across the valve
will result in the valve modulating open as load increases. Opening of
the air inlet check valve allows air to flow directly to the
turbocharger. The air flow, being increased above the scavenger air
blower's capacity, allows the cylinders to operate at a lower temperature
than that experienced with only the scavenger air blower air flow. The B
EDG valve works in this manner; however, the A EDG air inlet check valve
remains closed and/or open less than desired as load is increased to full
load. The ability to operate the A EDG at full load with operating
temperatures similar to B EDG has been demonstrated by manual valve
operation.
Actions taken to date have not corrected the A EDG's high temperature
condition. These actions included: replacement of both turbochargers,
adjustment of the turbocharger exhaust nozzles to increase turbocharger
rpm, and inlet check valve replacement. These actions have been
developed in conjunction with, and monitored by, a Colt Industries
technical representative, On January 8, 1990, air pressure data was
recorded with the A and B EDG engines operating at various loads.
This
information along with previously submitted data was being analyzed by
the vendor for other possible corrective actions. Correction of this
higher than normal temperature condition is considered to be desirable
(i.e., would improve reliability, but is not required for the A EDG to
perform its safety function).
The inspectors have discussed the above problems and corrective actions
with both the engineering staff and the vendor representative and
observed various associated corrective maintenance as it was performed.
RHR-753B Degradation
During the performance of OST-251, RHR Component Test, on December 24,
1990, valve RHR-753B, the B RHR pump discharge check valve, did not
close.
Inspection of the valve internals revealed that the clapper arm
10
was worn and the disc travel stop was deformed. The valve is a 10-inch
Aloyco swing disc check valve. Apparently, the disc stem had become
misaligned due to the worn arm and had stuck on the gouged stop.
According to the vendor, this is a known failure mode for this valve.
The stop was weld repaired in accordance with WR/JO 90-ARZT5, the valve
was reassembled, and proper operation was verified by the successful
completion of OST-251. The worn clapper arm will be replaced when a
replacement part is received in mid-January.
This valve had been inspected on November 24, 1990, per PM-300, Aloyco
Swing Check Valve Inspection, revision 0. Though PM-300, revisions 0 and
1, steps 7.2.1 and 7.3.10.1 required inspection and documentation of the
general condition of the valve body, no specific steps were provided to
address the travel stop. Though deformation of the travel stop was
observed on November 24, 1990, it was not documented on Attachment 8.4 of
PM-300. Failure to specifically require the condition of the stop to be
documented so that degradation can be detected is considered a VIO:
Procedure PM-300 Was Inadequate In That Condition of The Aloyco Check
Valve Travel Stop Was Not specifically Required To Be Evaluated and
Documented, 90-30-04.
The inspectors are concerned that the maintenance procedure upgrade
program failed to incorporate specific steps in the inspection procedure
to address a known failure mode.
One violation was identified.
5.
Refueling Activities (60710)
Movement of fuel into the reactor vessel was initiated on December 25 and
completed on December 29, 1990. The inspectors observed 12 fuel
assemblies being loaded on December 28. The inspectors verified that
activities were being conducted in accordance with FMP-019, Fuel and
Insert Shuffle and GP-010, Refueling. During refueling activities, the
inspectors verified that the requirements of TS 3.8.1 c, 3.8.1.d, 3.8.1.e,
3.8.1.g, 3.8.1.h, and 3.8.2.d were being met. On December 27 the
inspectors observed that refueling activities were suspended in accordance
with TS 3.8.2.d when the relative humidity of the air processed by the
refueling filter systems approached 70 percent. Fuel movement resumed
when the relative humidity decreased to less than 70 percent. Later that
night and the next day, fuel movement had to be suspended on two additional
occasions due to relative humidity restrictions. The condition was caused
by a combination of faulty duct heaters and rain and fog in the area.
Inspection Report 90-22 documented that cleanliness controls in the
reactor cavity area at the start of control rod unlatching was poor. The
inspectors observed that housekeeping was being maintained at an acceptable
level during fuel reloading.
6. Action on Previous Inspection Findings (92700, 92701, 92702, 71707)
Upper Internals Repair
During the September 1990 reactor vessel upper internals inspection, the
licensee observed crack indications in 38 control rod guide tube support
pins (split pins) and 13 guide tube removable inserts with less than the
necessary number of flexures.
See IR 90-22 and 90-24 for additional
description of these problems.
By December 12, 1990, the licensee had completed replacement of split
pins on all 53 guide tubes with a redesigned split pin. The replacement
split pins received a higher temperature heat treatment and have a larger
shank to collar radius than the original supplied split pins. The heat
treatment makes the material less susceptible to IGSCC and the radius
increase reduces the stresses at a location where IGSCC had occurred in
the previous designed type of split pins.
By December 12, 1990,
flexureless inserts had also been installed on the guide tubes such that
all 45 guide tubes which had removable inserts earlier now have flexureless
inserts. Eight guide tubes of the total 53 guide tubes did not have
flexures. These eight guides tubes were used previously with the no
longer installed partial length control rods. Based upon the
repair/replacement activities, the split pin and flexure failure issues
have been satisfactorily addressed.
S/G Girth Weld 5 ID Indications
Inspection Report 90-24 documented that preliminary in-process external UT
examination of A S/G weld 5 (upper girth weld) resulted in detection of
low amplitude ultrasonic reflectors at the vessel ID which ran circumfer
entially in the base metal adjacent to the wall edge. Subsequently,
indications have been found in the same general area of C S/G. Ultrasonic
examinations had previously recorded isolated indications on the B S/G
upper girth weld. The B S/G indications were not considered to be indica
tive of cracks. After reviewing available information, the licensee
decided to perform internal ID magnetic particle examination of the A S/G
weld 5. The A S/G was selected because its external UT examination had
been completed (i.e., C S/G was still being examined) and A S/G was more
readily accessible than C S/G due to outage activities in and around the
S/Gs.
Visual examination of the A S/G weld from the inside revealed no
indication of cracks. The visual inspection also revealed that the weld
on the inside was much wider, 3 to 4 inches in width, than shown on the
drawing. Thus, the UT indications were all in the weld area, not in the
base metal as originally thought. Ten linear feet of the weld,
encompassing the worst UT indications, was selected for fluorescent MT.
This confirmed that surface indications were present in the weld, and not
in the base metal.
Two indications were surface prepared before the MT.
These indications were found to be associated with weld porosity.
Preliminary analysis of the A and C S/G UT results by Structural Integrity
12
Associates indicates that it is acceptable to operate at least one cycle.
The UT and MT results were discussed with Region II and NRR personnel via
a conference call on December 14, 1990. The NRC has tentatively concurred
with the licensee's approach (i.e., it is acceptable to operate one cycle
without removing the indications). The licensee has agreed to submit to
NRR for further review the UT and MT examination results and the associated
engineering analysis prior to startup. In addition, the licensee indicated
a.willingness to perform external UT examinations of the affected S/G
areas should a forced outage of sufficient duration put the unit in cold
shutdown after mid-cycle. Such an examination would determine if the
character of the existing indications had changed. The licensee currently
plans to re-examine these indications during the next refueling outage,
scheduled for March 1992.
On December 18, 1990, the inspectors visually
inspected an accessible portion of the A S/G welds from the secondary
side. Comparison of the observed conditions with those depicted in
pictures from another site that had pitting which resulted in rapidly
propagating cracks, showed that such pitting did not exist in the area
viewed. These pictures were also viewed by the cognizant engineer who had
looked at the entire A S/G weld 5 area. The engineer also indicated that
pitting as shown in the other site's pictures did not occur in the A S/G.
On December 18, 1990, while removing work platforms from inside A S/G, an
internal ladder rung broke at its attachment weld and fell into the
annulus area. Subsequent underwater TV camera inspection located the
broken rung and the part was retrieved. Magnetic particle testing of the
other ladder rungs' attachment welds revealed no other defects.
The communications and interfaces among the groups (NED, HEEC and Technical
Support) involved in the resolution of the S/G indications were effective.
The support provided to the site by the offsite organizations was
especially noteworthy.
(Closed) VIO 89-18-01, 10 CFR 50 Appendix B Criterion XVI Failure To
Promptly Identify And Correct Conditions Associated With the AFW System
Potential Escalated.
Inspection Report 89-18 transmittal letter
identified that the subject item was under consideration for escalated
enforcement action and accordingly no NOV was being issued at that time.
On November 15, 1989, the NOV was issued with a proposed imposition of
civil penalty. Inspection of this item is being conducted under item
number 89-11-01. Thus, for administrative purposes, violation 89-18-01 is
considered closed.
No violations or deviations were identified.
13
7. Exit Interview (30703)
The inspection scope and findings were summarized on January 15, 1991,
with those persons indicated in paragraph 1. The inspectors described
the areas inspected and discussed in detail the inspection findings
listed below and in the summary. Dissenting comments were not received
from the licensee. Proprietary information is not contained in this
report.
Item Number
Description/Reference Paragraph
90-30-01
IFI - Review Steps To Detect And/Or
Preclude Extensive External Corrosion
Of Carbon Steel Piping, paragraph 2.
90-30-02
IFI - Establishment Of PM Route To
Inspect SW Piping, paragraph 2.
90-30-03
IFI - Review Periodic Inspection
Frequency Determination For B RHR Pump
Impeller, paragraph 4.
90-30-04
VIO - Procedure PM-300 Was Inadequate
In That Condition Of The Aloyco Check
Valve Travel Stop Was Not Specifically
Required To Be Evaluated And
Documented, paragraph 4.
8. List of Acronyms and Initialisms
ANSI
American National Standards Institute
American Society of Mechanical Engineers
AWWA
American Water Works Association
Component Cooling
Component Cooling Water
CFR
Code of Federal Regulations
cu. ft.
Cubic Feet
e.g.
For Example
E & RC
Environmental and Radiation Control
EE
Engineering Evaluation
Environmental Qualification
FMP
Fuel Management Procedure
GL
Generic Letter
General Procedure
HEEC
Harris Energy and Environmental Center
HVH
Heating, Ventilation Handling
14
Instrumentation & Control
ID
Inside Diameter
IFI
Inspector Followup Item
Intergranular Stress Corrosion Cracking
IR
Inspection Report
JCO
Justification For Continued Operation
KW
Kilowatt
LCO
Limiting Condition for Operation
Motor Control Center
Motor Driven Auxiliary Feed Water
Magnetic Particle Testing
NED
Nuclear Engineering Department
NI
Nuclear Instrumentation
Nuclear Reactor Regulation
Outside Diameter
OST
Operations Surveillance Test
Preventative Maintenance
PNSC
Plant Nuclear Safety Committee
Roentgen Equivalent Man
Robinson Nuclear Project
rpm
Revolutions Per Minute
Refueling Outage
Radwaste
System Driven Auxiliary Feedwater
S/G .
SHNPP
Shearon Harris Nuclear Power Plant
Special Procedure
Sq. Ft.
Square Feet
Sq. Cm.
Square Centimeters
SWBP
Service Water Booster Pump
TS
Technical Specification
TV
Television
Unresolved Item
Ultrasonic Test
Violation
WR/JO
Work Request/Job Order
YTD
Year To Date