ML14181B010
| ML14181B010 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 06/08/1998 |
| From: | Ernstes M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181B008 | List: |
| References | |
| 50-261-98-05, 50-261-98-5, NUDOCS 9806160186 | |
| Download: ML14181B010 (25) | |
See also: IR 05000261/1998005
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No:
50-261
License No:
Report No:
50-261/98-05
Licensee:
Carolina Power & Light (CP&L)
Facility:
H. B. Robinson Unit 2
Location:
3581 West Entrance Road
Hartsville, SC 29550
Dates:
March 29 - May 9, 1998
Inspectors:
B. Desai, Senior Resident Inspector
A. Hutto, Resident Inspector
F. Wright, Region II Inspector
G. MacDonald, Region II Project Engineer
Approved by:
M. Ernstes, Acting Chief, Projects
Branch 4
Division of Reactor Projects
0
Enclosure 2
9806160186 980608
ADOCK 05000261
G
EXECUTIVE SUMMARY
H. B. Robinson Power Plant, Unit 2
NRC Integrated Inspection Report 50-261/98-05
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of resident inspection; in addition, it includes the results of
inspections by Region II based inspectors.
Operations
The conduct of operations was professional, risk informed, and safety
conscious (Section 01.1).
A non-cited violation involving inadequate testing of refueling
equipment was identified. There were no direct safety consequences of
the fuel assembly drop incident. Had an irradiated assembly been
subject to a similar drop, any release of radioactivity would have been
contained, due to containment closure requirements during fuel movement.
Licensee follow up to this, event was appropriate (Section 01.2).
The inspector observed portions of startup related activities and
concluded that management decision to suspend startup to verify
potential affects of the seismic event were conservative. The inspector
did not note any affect to the plant as a result of the seismic event.
Operator performance during startup was considered good (Section 01.3).
Reactor operator response to the failed closed turbine control valve was
incorrect. Licensee plans to review this event to enhance future
training activities. Overall plant response was appropriate. Reactor
startup activities following the trip were uneventful (Section 02.1).
A violation for failure to perform a required surveillance test on the
containment personnel air lock test was identified (Section 04.1).
Nuclear Assessment Section and Plant Nuclear $afety Committee continued
to provide strong oversight, including during refueling outage 18
(Section 07.1).
Maintenance
Maintenance and surveillance activities were performed satisfactorily.
The inspector noted good controls of housekeeping and good supervisor
oversight of work activities (Section M1.1).
The repairs on the service water (SW) header were appropriately
completed. Management oversight of this problem was considered good
(Section M2.1).
The "A"
motor driven auxiliary feedwater (MDAFW) pump was deadheaded
during a test configuration. This did not cause damage to the pump.
Licensee actions to determine the root cause, including formation of an
event review team (ERT), were appropriate.
2
Two orifices on the MDAFW recirculation lines that had been worked on
during the outage were installed backwards due to inattention to detail
on the part of the mechanic. This issue was identified as a non-cited
violation. The incorrectly installed orifices did not contribute to the
pump deadheading (Section M4.1).
Engineering
Modification packages reviewed were acceptable. Modification 97-382
implemented corrective action to restore the damper control scheme for
the Containment Recirculation Cooling System units (Section E1.1).
The environmental qualification (EQ) components inside containment which
were inspected were being maintained with qualified seals in accordance
with EQ program requirements. The EQ data packages reviewed were being
updated in accordance with procedure EGR-NGGC-156, Environmental
Qualification Of Electrical Equipment Important To Safety. No backlog
of unincorporated engineering service requests (ESRs) was noted (Section
E2.1).
The licensee was conservative in evaluating a Westinghouse BF relay
failure during RFO-18 testing. The relay testing discrepancies were
being dispositioned in accordance with corrective action program
requirements (Section E2.2).
In response to the licensee's letter of April 4, 1998, several examples
of cauculational deficiencies identified in Notice of Violation dated
March 4, 1998, have been withdrawn and will be tracked as an Unresolved
Item (Section E8.1).
Plant Support
Housekeeping and cleanliness within the radiation control area were
acceptable (Section R1.1).
Overall, the inspectors observed good radiological controls and
radiation worker compliance throughout the inspection (Section R1.1).
A Non-Cited Violation was identified for radiation worker's failure to
comply with radiation protection procedures (Section R1.1).
The effectiveness of the licensee's dose reduction efforts in non-outage
periods during 1997 were very good and had resulted in the site'-s lowest
annual collective dose. The 1997 collective dose was 13 person-rem
(Section R1.2).
Overall, as-low-as-reasonably-achievable (ALARA) planning efforts were
appropriate and were effectively implemented for most outage work
activities. Unanticipated problems and poor planning resulted in excess
dose of 13 person-rem for three of the thirty-one planned projects
(Section R1.2).
3
Overall licensee contamination control measures were effective in
containing radioactive byproduct contamination and minimizing radiation
exposures to the contamination (Section R1.3).
Personnel contaminations were down from previous outages. The licensee
was evaluating the events to identify their causes and was taking
corrective actions to reduce the number of personnel contaminations.
The 14 Personnel Contamination Events (PCEs) documented in 1997 were the
site's lowest (Section R1.3).
Licensee use of self assessments in the radiation protection program
area was good (Section R7.1).
Report Details
Summary of Plant Status
Robinson Unit 2 was in Refueling Outage (RFO) 18 at the beginning of the
report period. Plant startup activities were initiated on April 10, 1998 and
the unit entered Mode 1 on April 10. Full power was reached on April 18. On
April 25, the unit experienced an automatic reactor trip from 100 percent
power due to low Steam Generator (SG) level.
The unit was started up on April
26 and returned to full power on April 27. The unit operated at 100 percent
for the remaining portion of the report period.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
The inspector conducted frequent control room tours to verify proper
staffing, operator attentiveness and communications, and adherence to
approved procedures. The.inspectors.attended daily operation turnovers,
management reviews, and plan-of-the-day meetings to maintain awareness
of overall plant operations. Operator logs were reviewed to verify
operational safety and compliance with TSs. Instrumentation, computer
indications, and safety.system lineups were periodically reviewed from
the Control Room to assess operability. Frequent plant tours were
conducted to observe equipment status and housekeeping. Condition
Reports (CRs) were routinely reviewed to assure that potential safety
concerns and equipment problems were reported and resolved. Good plant
equipment material conditions and housekeeping continued to be observed
throughout the report period.
In general, the conduct of operations was risk informed, professional,
and safety conscious.
01.2 Refueling Activities
a. Inspection Scope (71707)
The inspector monitored refueling activities during RFO-18, including
those related to the failure of the reactor building side upender
lifting cable.
b. Observations and Findings
Core reload activities were started on March 27, 1998, in accordance
with procedure FHP-006, Fuel Assembly And Insert Handling During Core
Loading, revision 8. Twenty-one assemblies were transferred to the
reactor vessel from the spent fuel pool without incident. On March 28,
at approximately 4:27 a.m., while upending new fuel assembly, AA16, with
the reactor side upender, the lifting cable associated with the upender
failed, while the upender was in the vertical position. The upender and
the transfer basket (with the fuel assembly) pivoted back (gravity fall
2
with water resistance) to the horizontal position on to the fuel
transfer cart. The licensee immediately stopped fuel movement
activities. No change in radiological conditions was noted as monitored
by the area monitors as well as in samples drawn from the cavity water.
The li-censee formed an ERT and initiated condition report CR 98-00736.
The investigation revealed that the shaft that coupled the hoist (motor)
drive to the programmable limit switch (resolver) had sheared. The
hoist/resolver shaft was a two-piece shaft pinned together. The failure
caused the resolver to also fail, resulting in the upender "FRAME-UP"
and "UP OVERTRAVEL" limits to not come in. This resulted in the hoist
continuing to run, pulling the upender cable past its intended position.
The tension on the cable increased as the hoist continued to run beyond
the "UP OVERTRAVEL" limit, causing the #2 sheave/pulley, mounted on the
refueling cavity wall, to be partially pulled off its support plate.
This rotation of the sheave caused the cable to contact the keeper,
which increased the stress on the cable, resulting in the snapping of
the cable. The upender and the transfer cart (with the new fuel
assembly) pivoted back to the horizontal position with 51 inches of the
cable attached. The hoist continued to reel the cable onto the drum.
The ERT was not conclusively able to determine what stopped the motor.
However, the ERT did conclude that a diverse means of stopping the hoist
motor did not function as intended. This means was through a proximity
switch which actuates when a ball mounted on the upender cable comes in
proximity to the switch. This diverse means of stopping the hoist did
not function as the ball was positioned such that it fell short in
actuating the sensing proximity switch. A modification had been
performed in December, 1993 which had replaced the ball and the
associate proximity switch. Post modification testing from this
modification did not adequately demonstrate that the proximity switch
would limit the upper travel of the hoist. Additionally, Engineering
Surveillance Test, EST-030, Fuel Handling Equipment Interlock and
Operation Test, was performed prior to operation of the upender. This
EST includes testing of protective features provided by the resolver and
the proximity switch. However, the correct position of the ball
relative to the proximity sensor was not verified, nor was a functional
test performed for the ball limit stop for the upender. 10 CFR 50:
Appendix B, Design Control requires that measures shall provide for
verifying or checking the adequacy of design. Further, 10 CFR 50, Appendix B, Inspection, Procedures, and Drawings requires that
procedures include appropriate quantitative Or qualitative acceptance
criteria for determining that important activities have been
satisfactorily accomplished. Contrary to these requirements, the post
modification procedure as well as the surveillance procedure associated
with Fuel Handling Equipment did not verify the correct position of the
ball relative to the proximity sensor. This resulted in the proximity
switch not appropriately stopping hoist movement following the failure
of the limit switch. This self identified , corrected, and non
repetitive violation is treated as an NCV, consistent with Section
VII.B.1 of the NRC enforcement policy. This issue is documented as NCV
50-261/98-05-01: Upender Failure during RFO 18.
3
Licensee corrective actions included replacement of the sheared shaft
with a newer design, replacement of the #2 sheave/pulley and cable,
inspection of the spent fuel side hoist/resolver shaft, and
repositioning and functional testing of the proximity sensor to correct
distance from the magnetic ball. The licensee also inspected portions of
the refuel movement apparatus on the spent fuel pool side. The
ball/limit on the spent fuel side did not need any adjustment. The
licensee also has plans to further enhance EST-30 prior to the next
planned use of fuel handling equipment.
Following completion of repair and testing, refueling activities were
commenced and completed without any incidents. A new fuel assembly was
procured as a replacement. Assembly AA16, was transferred back to the
spent fuel pool and current plans are to send it back to the
manufacturer (Siemens).
c. Conclusions
A NCV involving inadequate testing of refueling equipment was
identified. The direct safety consequences of the fuel assembly drop
were none. Had an irradiated assembly been subject to a similar drop,
any release of radioactivity would have been contained, due to
containment closure requirements during fuel movement. Licensee follow
up to this event was appropriate.
01.3 Plant Startup From Refueling
a. Inspection Scope (71707)
The inspector monitored startup activities for RFO-18.
b. Observations and Findings
On April 13, plant startup activities were in.progress in accordance
with procedure GP-003, Normal Plant Startup form Hot Shutdown to
Critical.
At approximately 5:56 a.m., tremors were felt in the plant.
A 3.9 (Richter Scale) seismic event was recorded at a location
approximately 25 miles from the plant. The site seismic recorder did
not register any seismic activity as it was below the trigger value.
The licensee entered Abnormal Operating Procedure 21, Seismic
Disturbances, as a result of the tremor. Startup activities were
suspended and a general inspection of the plant was conducted to
ascertain any consequences. After confirming no effect on the plant,
startup activities were recommenced. The plant reached Mode 2 at 2:10 pm
and Mode 1 at 6:31 pm on April 13. The unit reached 100 percent power on
April 18.
c. Conclusion
The inspector concluded that the management decision to suspend startup
to verify potential effects of the seismic event were conservative. The
4
inspector did not note any affect to the plant as a result of the
seismic event. Operator performance during startup was considered good.
02
Operational Status of Facilities and Equipment
02.1 Reactor Trip and Subsequent Unit Startup
a. Inspection Scope (71707)
Robinson Unit 2 experienced an automatic reactor trip from 100% power on
April 25, 1998 at approximately 1:34 p.m. The resident inspector
responded to the site.
b. Observations and Findings
The first out annunciator was low-low (16%) "A"
level. A review of Emergency Response Facility Information System
(ERFIS) data archived after the trip indicated that the initiating event
was the closing of the turbine governor valves. This led to a shrink in
all the SGs caused by reduced steam flow and resultant higher steam
pressure. The shrink was enough to reduce the SG levels to below the
low-low SG level reactor trip set point.
Control room operators initially noticed SG level deviation alarms,
concurrent with control rods inserting rapidly. Reactor Coolant System
(RCS) Tref. as well as first stage impulse pressure were also noted to
be dropping rapidly. The operators' initial diagnosis was that a first
stage pressure channel had failed low. Thus, they reacted by placing
control rods -in
manual.
All four governor valves were then noted shut
and the control room shift supervisor (CRSS) directed manually tripping
the reactor. Just prior to manually tripping the reactor, the reactor
automatically tripped on low-low SG level.
An Event Review Team (ERT) was formed to investigate the reactor trip.
Following extensive troubleshooting, the licensee was not able to
positively identify the root cause. However, during troubleshooting of
the Electro Hydraulic Control (EHC) system, it was revealed that a 35
psi change in impulse pressure output (PT-1359), when the governor
valves are open 90%, will cause the governor valves to close. The
licensee did not identify a cause for the 35 psi change in impulse
pressure nor were they able to confirm that any change in impulse
pressure or PT-1359 had actually occurred. The above scenario was
thought of as the most likely scenario for the unexpected closing of the
governor valves. A Westinghouse representative assisted the licensee in
the troubleshooting process.
Post trip plant response was as expected. A Power Operated Relief Valve
(PORV) opened momentarily to relieve RCS pressure. Reactor operator
response to the initiating event was incorrect. The RO reacted thinking
the turbine first stage pressure channel had failed low. He did not
incorporate the sharp decline in the generated megawatts in his
5
decision. This led him to place the rods in
manual, thus stopping
inward rod motion.
This incorrect response did not have any overall
impact on the plant as the reactor tripped shortly thereafter. However,
the licensee plans to include this scenario during future operator
training activities.
As corrective action, the licensee replaced impulse pressure transmitter
PT-1359. Further, the licensee started and operated the plant in the
"impulse pressure out" Mode. The EHC system was instrumented to capture
any additional anomalies. No anomalies in EHC operation were noted
during start-up and for the remainder of this inspection period.
c.
Conclusion
Reactor operator response to the failed closed turbine overnor valves
was incorrect. Licensee plans to review this event to enhance future
training activities.. Overall plant response was appropriate. Reactor
startup activities following the trip were uneventful.
04
Operator Knowledge and Performance
04.1 Missed Technical Specification Surveillance (61726. 71707)
a. Inspection Scope
The inspector reviewed circumstances related to a missed TS
surveillance. The missed surveillance, OST-014, Local Leak Rate Testing
(LLRT) of Personnel Air Lock Door Seals, placed the unit in TS 3.0.3.
This condition was identified by the control room shift supervisor
(CRSS).
b. Observations and Findings
OST-14 was successfully performed on April 10, 1998, as a prerequisite
for entering Mode 4. OST-14 ensures containment air lock operability
per TS 3.6.2. Further. TS 5.5.16, Containment Leakage Testing Program,
requires implementation of a containment leak rate testing program in
accordance with 10 CFR 50. Appendix J. 10 CFR 50, Appendix J. Section
D.2.ii and iii requires that air locks opened during periods when
containment integrity is required by TS shall be tested within three
days after being opened; and for air lock doors opened more frequently
than once every three days, the air lock shall be tested at least once
every three days during the period of frequent openings.
The unit entered Mode 4 at approximately 8:16 p.m. on April 10. at which
time the operability requirement, for the containment air lock became
effective. Further with the air lock door utilized for personnel
entry/exit, the three day testing requirements were effective in
accordance with 10 CFR 50 Appendix J. The next performance was due to
be performed by 4:45 a.m. on April 13. This was written and tracked on
the white board above the CRSS desk in
the control room.
6
On April 13 at approximately 9:32 -a.m., upon noticing the note on the
white board, a CRSS questioned it. At this time it was recognized that
OST-14 had not been performed as required between April 10 and April 13.
Upon identification, the plant entered TS 3.0.3 and immediately
requested performance of OST-14, which was successfully completed at
11:15 a.m. on April 13.
The licensee initiated CR 98-00890 which concluded that the primary
cause for the missed surveillance was inadequate administrative controls
to ensure event based surveillance requirements. The term "event based"
implies surveillances that are not scheduled through the Surveillance
Tracking System.
As corrective action, the licensee plans to revise OMM-007 to track
similar surveillances in the Equipment Inoperable Record (EIR) logs.
This would allow a positive tracking control, rather than a note on the
board. The inspector will review operator performance in this area to
determine similarity and effectiveness of corrective actions. NCV 97
12-01: Failure to Log TS Surveillance Completion in accordance with OST
20 was reviewed. This NCV was attributed to inattention to detail and
log keeping accuracy on the part of the operator when the control rod.
insertion limit monitor (RILM) was inoperable. NCV 97-12-02: Failure to
Verify Dose Equivalent 1-131 in accordance with GP-005, involved a
missed TS surveillance, also due to lack of operator attention to detail
and inadequate supervisory oversight during periods of high control room
activities. The inspector determined that the recent failure to perform
OST-14 was partially attributable to inattention to detail on the part
of the operating crew. This failure to perform the required
surveillance in accordance with 10 CFR 50, Appendix J is identified as
violation 50-261/98-05-02: Failure to Perform Personnel Air Lock Test.
c. Conclusion
A violation for failure to perform a required surveillance test on the
containment personnel air lock was identified..
07
Quality Assurance In Operations
07.1 Plant Nuclear Safety Committee and Nuclear Assessment Section Oversight
a. Inspection Scope (40500)
The inspector evaluated certain activities of the Plant Nuclear Safety
Committee (PNSC) and Nuclear Assessment Section (NAS) to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements.
7
b. Observations and Findings
The inspector periodically attended PNSC meetings during the report
period. The presentations were thorough and the presenters readily
responded to all questions. The committee members asked probing
questions and were well prepared. The committee members displayed
understanding of the issues and potential risks. Further, the inspector
reviewed NAS audits and concluded that they were appropriately focused
to identify and enhance safety.
c. Conclusions
The inspector concluded that the onsite review functions of the PNSC
were conducted in accordance with TSs. The PNSC meetings attended by
the inspector were well coordinated and meetings topics were thoroughly
discussed and evaluated. NAS continued to provide strong oversight of
licensee activities.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments' (62707,61726)
The inspector reviewed/observed all or portions of the following
maintenance and/or surveillances and reviewed the associated
documentation:
OST 401-2, Emergency Diesel Generator Slow Start
OST 402-2, Emergency Diesel Fuel Oil Flow Test
OST 302-1, Service Water System Component Test
Service Water Leak Repair Activities
Maintenance and surveillance activities observed were performed
satisfactorily. The inspector noted good controls of housekeeping and
good supervisor oversight of work activities.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Service Water System Leak Repairs (62707)
a. Inspection Scope
The inspector reviewed and observed licensee actions related to a leak
in the service water (SW) system. The SW system is a safety related
system. The discharge flow to the plant from the four SW pumps is
through two headers, the North and South header. These two headers
constitute the two redundant trains. This leak was in the North header
and was approximated to be 10 gpm.
8
b. Observations and Findings
A leak in the SW system was suspected when a water puddle near the
vicinity of the radwaste system was noted on March 27, 1998. A portion
of the SW header is located underground in the vicinity of the radwaste
Building. The licensee confirmed that the leak was in the SW system by
chlorinating the SW headers and sampling the leaked water. Following
extensive excavation, the licensee located the leak.
The leak was repaired by a welding a "cap assembly" over the section of
the small hole. The welding repair activities were conducted through
ESR 98-00202. The ESR documented the 10 CFR 50.59 evaluation associated
with the repair. The repair was successfully completed in accordance
with ANSI B31.1-1980. The root cause of the leak was determined to be
general corrosion, not particularly attributed to any single mechanism.
c. Conclusions
The repairs on the SW header were appropriately completed. Management
oversight of this problem was considered good.
M4
Maintenance Staff Knowledge and Performance
M4.1 Motor Driven Auxiliary Feedwater Pump 'A'
Trip During Testing (61726.
62707)
a. Inspection Scope
The inspector reviewed circumstances related to the tripping of the "A"
Motor Driven Auxiliary Feedwater Pump (MDAFW) during performance of
Operations Surveillance Test (OST)-163, Safety Injection Test and
Emergency Diesel Generator Autostart on Loss of Power and Safety
Injection.
b. Observations and Findings
During performance of OST-163. both the MDAFW pumps auto started as
designed. The valve configuration during the test precluded flow to the
SG. For the purpose of the test, the manual valves on the discharge
lines were maintained CLOSED.
Approximately 11 minutes into the OST, the "A"
MDAFW pump tripped on low
discharge pressure. Subsequently, the "A"
MDAFW pump was restarted.
Four minutes following the restart, the "A"
MDAFW pump tripped again on
low discharge pressure. OST-163 was continued by adding a component
cooling water pump to provide the compensating electrical load to
complete the OST.
Following completion of the OST, the licensee formed an Event Review
Team (ERT) to determine cause of the "A"
MDAFW pump trip. The ERT noted
that the "A"
MDAFW pump casing temperature was approximately 189 degrees
F one hour after the trip, indicative of liquid flashing to steam within
9
the pump.
During an-initial system walkdown, the system engineer
determined by visual inspection that the recirculation line flow
restriction orifices (RO-1400A and RO-1400B) on the "A"
and "B"
pumps were installed backwards. Although the orifice plates were
reversed, the system engineer did not expect that this was the cause of
the trip, since the flow through the orifice was not changed
significantly by the reverse installation. The insignificant change in
flow was based on the flow orifice design.
The ERT subsequently developed an action plan to determine the nature of
the event, a problem definition, and an investigation process to gather
any other data from the event. During this investigation, the ERT
determined that the during the OST, the "B"
MDAFW pump started first as
designed, since the E-1 bus had to be energized by EDG-A before the A
train sequencer could sequence loads on. The E-2 bus remained on off
site power for this part of the test. The "B"
MDAFW pump developed full
pressure in a few seconds. Since the cross connects were open and the
isolations valves to the steam generators were closed, this pressure
transmitted to the discharge side of the "A"
AFW pump check valve. This
caused the check valve to not open or to partially come off the seat.,
thus reducing flow from the "A"
MDAFW pump. This was further
substantiated by ERFIS data. This data indicated the presence of flow
in the pump discharge headers downstream of the recirculation lines.
This was consistent with flow from the "B"
AFW pump, to the cross
connect header, to the "A"
AFW pump-recirculation line. This
"deadheaded" the "A"
AFW pump resulting in insufficient flow from the
pump.
The ERT concluded that the AFW pump had insufficient flow resulting in
increased temperatures until the liquid in the "A"
MDAFW pump casing
flashed. This resulted in heating of the casing and reduction in
pressure until the pump tripped. The cause of the loss of flow was
concluded to be the effect of deadheading the "A"
MDAFW pump by "B"
pump pressure, preventing opening of the discharge check valve. The ERT
also concluded that the system was not susceptible to a similar problem
during normal operation and when the MDAFW pumps are required to be
operable because of a different valve configuration. The "A"
MDAFW pump
was externally inspected for any possible damage and none was found.
Further, the vendor was contacted with the data gathered. Per the
vendor recommendations, the pump was successfully started and no changes
in vibration and temperatures were noted. The pump was subsequently
declared operable.
With regard to the restricting orifices installed backwards, the
licensee determined that during RFO-18, the two orifices were
disassembled to perform an inspection. Following the inspection, the
orifices were re-installed backwards. The inspection and installation
activities were conducted under a work request(WR). The WR did not
specify any particular orifice orientation, however, the orifices were
clearly stamped identifying the inlet orientation. This job was
performed by a shared resources maintenance mechanic from the Brunswick
plant. The work was considered within the skill of the craft.
10
Notwithstanding, procedure MMM-001, Maintenance Administration Program,
section 3.1.1 required the craftsmen to restore an area to its design
condition following completion of maintenance activities! Further,
section 2.4.1 of MMM-001 required the mechanic to "THINK" and "APPLY" a
healthy skepticism to review each step of the job before doing to
prevent errors. Contrary to the requirements of MMM-001, absent clear
written instructions, the mechanic did not appropriately conduct the
skill of the craft maintenance activities involving orifice
installation. This resulted in the backward installation of two
orifices on the auxiliary feedwater system. The backward installed
orifices did not negatively impact system performance and thus the
overall significance of the condition was minor. The inspector
determined that failure to follow MMM-001 was a violation. This
licensee identified, corrected, and non-.repetitive violation is treated
as an NCV, consistent with Section VII.B.1 of the NRC enforcement
policy. This issue is documented as NCV 50-261/98-05-03: Backward
Orifice Installation on MDAFW system.
c. Conclusions
The "A"
MDAFW pump was deadheaded during a test configuration. This did
not cause damage to the pump. Licensee actions to determine root cause,
including formation of an ERT, were appropriate. Two orifices on the
MDAFW pump recirculation lines that had been worked on during the outage
were installed backwards due to inattention to detail on part of the
mechanic. This did not contribute to the pump deadheading.
III. Engineering
El
Conduct of Engineering
E1.1 Review of Modifications
a. Inspection Scope (37551)
The inspectors reviewed portions of modifications97-469 and 97-382.
b. Observations and Findings
During Refueling Outage 17 (RFO-17) the Containment Air Recirculation
Cooling system (HVH) unit damper control scheme was changed to have the
normal damper closed and the emergency damper open with no safeguards
signal damper repositioning required post accident. This configuration
reduced the performance of the containment coolers. NRC violation 50
261/97-12-04 was issued regarding the post maintenance testing of this
modification. The licensee's January 21, 1998, violation response
indicated that the pre-RFO-17 configuration would be restored for the
HVH unit dampers. Modification 97-382 was implemented to complete the
restoration. This modification changed the HVH unit damper
configuration to normal damper open and emergency damper open with the
normal damper closing on safeguards signal. The inspector noted that
the modification did not address the impact of the new HVH unit damper
configuration scheme on the HVH unit fan motor current.
Modification 97-469 was an EQ related modification which replaced the
cable to solenoid valve SVA33 for the normal damper of HVH unit HVH-1
with an environmentally qualified cable. The inspectors reviewed the
modification package and verified the package adequately addressed
technical and environmental qualification requirements for the
replacement cable.
The inspectors performed a walkdown and verified
that hardware and equipment were installed in accordance with
modification requirements.
c. Conclusions
Modification packages reviewed were acceptable. Modification 97-382
implemented corrective action.to restore the damper control scheme for
the Containment Recirculation Cooling system units.
E2
Engineering Support of Facilities and Equipment
E2.1 Review of Environmental Qualification Program
a. Inspection Scope (37551)
The inspector performed a walkdown of selected inside containment
Environmental Qualification (EQ) Program components and reviewed several
of the associated EQ Data Packages (EQDPs).
b. Observations and Findings
Selected EQ components were inspected to verify their EQ sealing
requirements were met. Twenty eight transmitters with Patel conduit
seals and twenty one solenoid valves with Patel conduit seals were
inspected. The inspectors determined that the equipment sealing for the
components inspected met-the requirements of TMM-019, List of
Environmentally Qualified Electric Equipment, revision 29, CM-310.
Installation of Patel Conduit Seals, revision 10, and EQDP 21.0, Patel
Conduit Seals. Additionally, eight limit Switches with Namco EC210
conduit seals were inspected. The inspectors determined that the
equipment sealing for the components inspected met the requirements of
TMM-019, List of Environmentally Qualified Electric Equipment, TMM-036.
Environmentally Qualified Electric Equipment Required Maintenance, and
EQDP 25.0, Namco Limit Switches.
12
The following EQDPs were reviewed.
EQDP 3.0 - Rockbestos Cabling
EQDP 21.0 - Patel Conduit Seals
EQDP 11.2 - Kerite Cabling
EQDP 28.0 - Brand Rex Cabling
EQDP 25.0 - Namco Limit Switches
EQDP 40.0 - Ram-Q Cable Connector Assemblies
The inspectors reviewed the Nuclear Records Control System (NRCS)
database to determine all ESRs which were posted against the above
listed EQDPs. All ESRs posted against the listed EQDPs had been
incorporated into the EQDPs except for current RFO-18 open outage ESRs.
No backlog of unincorporated ESRs was noted.
c. Conclusions
The EQ components inside containment which were inspected were being
maintained with qualified seals in accordance with EQ program
requirements. The EQDPs reviewed were being updated in accordance with
procedure EGR-NGGC-156, Environmental Qualification Of Electrical
Equipment Important To Safety. No backlog of unincorporated ESRs was
noted.
E2.2 Westinghouse BF Relays
a., Inspection Scope (37551)
The inspectors reviewed the licensee's activities related to resolution
of Westinghouse BF relay performance discrepancies.
b. Observations and Findings
In January 1997, BF relay 412C1 failed during surveillance testing. The
relay actuated correctly when denergized but experienced a delay during
re-energization. The relay was a normally energized relay used in a
Reactor Protection System (RPS) Overpower/Overtemperature (OP/OT)
Delta T application. Significant Condition Report (CR) 9700092 was
initiated for resolution and root cause evaluation. The relay was sent
to the Harris Energy and Environmental Center (HEEC) for failure
analysis. The analysis concluded that the energization delay was due to
the relay armature pin contacting the internal surface of the relay
casing.
A 1979 vendor technical bulletin documented a problem with BFD (DC)
relays experiencing armature pin binding. No problem was identified
with BF (AC) relays. The vendor evaluation indicated that this was an
isolated case but instituted a relay improvement to epoxy the armature
pin to prevent movement.
Relay 412C1 was one of 46 relays replaced in 1988 due to relay contact
deterioration. The replacement relays did not have epoxy on the
13
armature pin to restrict pin movement. The corrective actions developed
in CR 9700092 consisted of pro-active measures to replace the relays.
During RFO-18 twenty percent of the BF relays in RPS and Safeguards
System were scheduled to be replaced with nuclear qualified relays.
Additionally the licensee will analyze and evaluate the BF relays
removed in RFO-18 and determine if additional BF relay replacements are
necessary.
During BF relay testing during RFO-18, relay TC-432B1-XB failed to go to
the energized position, The relay would denergize and drop out but was
erratic in its pull in times when energized. Upon disassembly, the
armature pin was found binding on the side of the relay internal
surface. This relay was also an OP/OT Delta T relay which had been
replaced in 1988. A significant CR (98-751) was initiated for
resolution. The common factors between the failures in January 1997,
and March 1998, were that both relays were BF relays from the same 1988
procurement and both relays were used in RPS OP/DT Delta T input relay
applications which received more frequent cycling due to more frequent
testing than the other RPS and Safeguards BF relays.
The inspectors reviewed procurement records and verified that the failed
relays were from the same procurement purchase and installed on the same
work orders in 1988. The inspectors reviewed the procurement issue
history and determined that the licensee had relays during 1988 without
epoxy on the armature pin. The licensee developed an action plan for
relay replacement to address relays from the same procurement batch and
those with higher cycling rate and those which were energized to
complete the safety function. Forty one BF relays were scheduled to be
replaced in the RPS and 15 relays in Safeguards System during RFO-18 to
implement the corrective actions of CR 9700092. Based on the second
failure of a BF relay, an additional group of relays was replaced to
address the relays from the 1988 procurement activity. The new
replacement relays were purchased nuclear grade. Samples of the new
relays were inspected and none were noted without the epoxy on the
armature pin.
c. Conclusions
The licensee was conservative in evaluating a BF relay failure during
RFO-18 testing and accelerating relay replacements. The relay testing
discrepancies were being dispositioned in accordance with corrective
action program requirements.
E7.1 Special UFSAR Review (37551)
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special
focused review that compares plant practices, procedures and/or
parameters to the UFSAR descriptions. While performing the inspections
discussed in this report, the inspector reviewed the applicable portions
of the UFSAR related to the areas inspected. The inspector verified
that for the select portions.of the UFSAR reviewed, the UFSAR wording
14
was consistent with the observed plant practices, procedures and/or
parameters.
E8
Miscellaneous Engineering Issues
E8.1
(Open) Unresolved Item 50-261/98-05-05: Questions on Design Calculations
NRC Inspection Report 50-261/98-03, dated February 6, 1998, included an
apparent violation for a number of calculational deficiencies identified
in the NRC Design Inspection. A Notice of Violation was issued on
March 4, 1998, for these calculational deficiencies. The licensee
response of April 3, 1998, to the Notice of Violation, stated that
examples 4,6,12,13, and 14.of violation B and example 1 of violation D
were not violations of NRC requirements. These violation examples are
withdrawn and will be tracked as Unresolved item 50-261/98-05-05,
Questions on Design Calculations, pending further NRC review of the
information provided in the April 3, 1998 violation response.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1 Conduct of Radiological Protection Controls (83750)
a. Inspection Scope
Radiological controls associated with RFO-18 were reviewed to verify
that the licensee was effectively implementing the radiation protection
program and meeting 10 CFR Part 20, Standards for Protection Against
Radiation. requirements. In particular, the inspectors reviewed and
evaluated the adequacy of general housekeeping, radiological controls,
area radiological postings, radiation worker compliance with radiation
protection procedures, and controls of radioactive materials.
b. Observations and Findings
Overall, the inspector noted appropriate levels of housekeeping and
cleanliness within the observed work areas and radioactive material
storage areas. Housekeeping practices within the Containment Building
(CB) were considered acceptable. However, the inspector did find loose
debris and standing water on portions of the first floor of the CB.
The inspector made independent radiation surveys of areas, equipment,
and containers within the Radiation Control Area (RCA). The licensee's
radiation survey results compared well with the inspector's surveys.
Licensee radiological area postings met posting requirements for the
areas surveyed by the inspector and were consistent. Vacuum cleaners,
portable air filtration systems, and containers of radioactive materials
within the RCA were properly labeled. Observed radiological controls
met licensee and NRC requirements and were good overall.
During the tours within the RCA, the inspector found all portable
radiation survey meters and air sampling equipment in use possessed
valid calibration stickers. Radiation and contamination monitoring
equipment had recent response checks.
The inspector observed radiation workers performing various tasks in the
Unit 2 CB, Fuel Building, ReactorAuxiliary Building and yard areas
wi.thin the primary RCA. The inspector discussed radiological work
controls with Health Physics (HP) staff. Radiological controls for the
various tasks were appropriate for the radiological conditions.
Observed radiation worker and HP interactions were good.
On March 14, 1998, an employee working in the CB failed to immediately
exit a radiation area when his Electronic Personal Dosimeter (EPD)
alarmed. The EPD was designed to give an audible alarm for the user
when either a dose rate was too high or a predetermined dose limit was
reached. The worker's dosimeter was set to alarm at a dose rate of 200
mrem/hr and a dose of 100 mrem. The alarm showed the worker had
exceeded an authorized radiation dose for the job he was working. After
the EPD alarmed, the worker remained in the radiation area approximately
10 additional minutes to complete his assigned task with his dosimetry
in continuous alarm. The worker exceeded the authorized dose for the
job by approximately ten mrem. While the employee's actions did not
result in exceeding any regulatory limits, the employee failed to follow
guidance provided in the licensee's radiation protection training and
procedures. Specifically, the incident was a violation of paragraph 12
of Attachment 3 to licensee procedure DOS-NGGC-0016, Electronic Personal
Dosimeter System Operation, Rev 2. As stated in the licensee's
procedures, upon activation of the dose alarm workers should exit the
area immediately and report to radiation control.
The licensee documented the event as a significant condition in CR 98
00572. The licensee investigated and took immediate corrective actions.
Corrective actions to prevent recurrence were also made. The inspectors
found the licensee's corrective measures were.very good. This non
repetitive, licensee-identified, and corrected violation is being
treated as a Non-Cited Violation (NCV), consistent with Section VII.B.1
of the NRC Enforcement Policy. NCV 50-261/98-05-04, Radiation Worker's
Failure to Comply with Radiation Protection Procedures
c. Conclusions
Housekeeping and cleanliness within the RCA were acceptable.
Overall, the inspector observed good radiological controls and radiation
worker compliance with those controls throughout the inspection.
A Non-Cited Violation was identified for radiation worker's failure to
comply with radiation protection procedures.
16
R1.2 As Low As Reasonability Achievable (ALARA)(83750)
a. Inspection Scope
.The licensee's goals, plans, and implementation of the site ALARA
program was reviewed.
b. Observations and Findings
The 1997 collective dose goal was established at 22 person-rem. That
goal included a contingency exposure budget of 3.619 person-rem.
However, the licensee did not need the contingency as the plant was
operational for approximately 360 days in 1997. The licensee ended 1997
with an annual collective dose of approximately 13 person-rem. That was
the lowest annual exposure ever at the H. B. Robinson site. The 1997
annual collective dose was also the lowest for any Carolina Power and
Light (CP&L) nuclear facility. The licensee attributed the record to
detailed planning, ALARA culture, excellent operational performance, and
good plant chemistry.
Annual and RFO collective dose goals for 1998 were set at 165 and 155
person-rem respectively. When the inspection began, most of the outage
work had been completed and the licensee was approximately 10 person-rem
above the dose the licensee had projected for that day in the outage.
The inspectors reviewed the status of jobs resulting in significant
collective radiation exposures. Most tasks were being completed with
collective doses well within budget. However, three tasks had
significantly contributed to the increased collective dose. The
licensee had not planned to repair a main flange gasket on the "C"
reactor coolant pump that resulted in approximately eight person-rem.
Actual person-hours for sludge lancing and Steam Generator (SG) eddy
current activities were approximately three and two times projected
hours for those projects respectively. As a result, sludge lancing
exceeded the projected dose of eight person-rem by eight person-rem and
the eddy current projected dose of 6.6 person.-rem was exceeded by
approximately 2.4 person-rem. A new vendor was used for the sludge
lancing activities with unanticipated work and poor planning
contributing to the dose over run. Steam generators were empty longer
than expected and higher dose rates adversely affected the eddy current
project. Through the end of inspection, the licensee had closed the gap
between the actual and projected outage dose.' Outage collective doses
were approximately two person-rem above the projected dose.
The licensee continued to improve the process for accurately assigning
doses to very specific tasks. The licensee began the process of
assigning dose to specific work request and job orders in 1996 and was
continuing to improve its use. The process had not been fully
implemented and the implementation progress had been slow. The process
when fully carried out could be a valuable tool for the ALARA and plant
management staffs. With full implementation the licensee would have
0
more accurate time and dose information for planning activities.
17
Management support of the ALARA program was evidenced in the increased
staffing levels of the outage ALARA group, increased use of remote
monitoring equipment, visibility of ALARA goals, application of shutdown
chemistry controls, and activities of the Robinson ALARA Committee.
c. Conclusions
The effectiveness of the licensee's dose reduction efforts in non-outage
periods during 1997 were very good and had resulted in the site's lowest
annual collective dose. The 1997 collective dose was 13 person-rem.
Overall, ALARA planning efforts were appropriate and were effectively
implemented for most outage work activities. Unanticipated problems and
poor planning resulted in excess dose of 13 person-rem for three of the
thirty-one planned projects.
R1.3 Personnel Contamination Controls (83750)
a. Inspection Scope
Work activities in the licensee contaminated areas were observed by the
inspectors to verify the licensee was implementing appropriate personnel
contamination controls. Personnel contamination reports were reviewed
to determine the frequency of Personnel Contamination Events (PCEs) and
the adequacy of the licensee's response to the events.
b. Observations and Findings
Good contamination control measures were observed during the inspection.
Inspectors found the contamination controls appropriate for the .
contamination levels and the work being performed. Radiation workers
were properly wearing anti-contamination clothing as specified on
Radiation Work Permits (RWPs). Good use of containments and engineering
controls to reduce transport of radioactive contamination were also
observed.
The licensee documented PCEs for all contaminations having radioactivity
greater than 100 corrected counts per minute. The number of.PCEs
documented by the licensee in 1994, 1995, 1996. and 1997 were 54, 129,
207, and 14 respectively. The frequency of PCEs increased during outage
periods. The PCE goal for 1997 was 50.
Plant operability was very good
in 1997 and there were only a few outage days. The fourteen PCEs for
were the lowest in the site's history.
The annual and RFO goals for
1998 were 90 and 70 respectively. As of April 2, 1998. the numbers of
PCEs documented were 60 and 53.
The inspectors found the Environmental and Radiation Control.(E&RC)
Manager was reviewing all PCEs and had sorted and characterized the PCEs
looking for trends and causes.
Inspectors also reviewed the PCE reports
and found approximately half involved discrete radioactive particles.
The inspectors determined the licensee had taken measures to control the
dispersion of the particles.
No other PCE cause categories were
18
distinguishing. The radioactivity of the particles were all low and
only a few had resulted in skin doses.
c. Conclusions
Overall licensee contamination control measures were effective in
containing radioactive byproduct contamination and minimizing radiation
exposures to the contamination.
Personnel contaminations were down from previous outages. The licensee
evaluated the events to identify their causes and was took corrective
actions to reduce the number of personnel contaminations.
The number
of PCE's documented in 1997 were the site's lowest.
R7
Quality Assurance in RPC Activities
R7.1 Radiological Protection Program Self Assessments (83750)
a. Inspection Scope
Self Assessments of the radiation protection program.were reviewed to
verify the licensee-was identifying and correcting radiation protection
program problems.
b. Observations and Findings
The inspectors reviewed several self assessments of various radiation
protection programs completed in 1997. The inspectors found the .
licensee's self assessments of radiation protection programs were
critical and findings were being identified. All findings were
documented in a corrective action program and the staff was doing a good
job of tracking and trending problems identified in the process.
c. Conclusions
Licensee use of self assessments in the radiation protection program
area was good.
S1 -
Conduct of Security and Safeguards Activities
S1.1 General Comments (71750)
During the period, the inspector toured the protected area and noted
that the perimeter fence was intact and not compromised by erosion or
disrepair. Isolation zones were maintained on both sides of the barrier
and were free of objects which could shield or conceal an individual.
The inspector periodically observed personnel, packages, and vehicles
entering the protected area and verified that necessary searches,
visitor escorting, and special purpose detectors were used as applicable
prior to entry. Lighting of the perimeter and of the protected area was
acceptable and met illumination requirements:
19
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on May 19, 1998. No
proprietary information was identified.
20
PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. Boska, Manager, Operations
H. Chernoff, Supervisor, Licensing/Regulatory Programs
T. Cleary, Manager, Maintenance
J. Clements, Manager, Site Support Services
J. Keenan, Vice President, Robinson Nuclear Plant
R. Duncan, Manager, Robinson EngineeringSupport Services
R. Moore, Manager, Outage Management
J. Moyer, Manager, Robinson Plant
D. Stoddard, Manager, Operating Experience Assessment
R. Warden, Manager, Nuclear Assessment Section
T. Wilkerson, Manager, Regulatory Affairs
D. Young, Director, Site Operations
NRC
B. Desai, Senior Resident Inspector
M. Ernstes, Acting Branch Chief, Region II
21
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 83750:
Occupational Radiation Exposure used
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Type Item Number
Status
Description and Reference
98-05-01
Open
Upender Failure during RFO 18 (Section
01.2).
98-05-02
Open
Failure to Perform Personnel Air Lock
(Section 04.1).
98-05-03
Open
Backward Orifice Installation on MDAFW
system (Section M4.1).
98-05-04
Open
Radiation Worker's Failure to Comply with
Radiation Protection Procedures
(Section R1.1)
98-05-05
Open
Questions on Design Calculations (Section
E8.1)
Closed
Ixpe Item Number
Status
Descri tion and Reference
98-05-01
Closed
Upender Failure during RFO 18 (Section
01.2).
98-05-03
Closed
Backward Orifice Installation on MDAFW
system (Section M4.1).
98-05-04
Closed
Radiation Worker's Failure to Comply with
Radiation Protection Procedures
(Section R1.1)