ML14181A855
| ML14181A855 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 12/16/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A853 | List: |
| References | |
| 50-261-96-12, NUDOCS 9612230323 | |
| Download: ML14181A855 (60) | |
See also: IR 05000261/1996012
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No:
50-261
License No:
Report No:
50-261/96-12
Licensee:
Carolina Power & Light (CP&L)
Facility:
H. B. Robinson Unit 2
Location:
2112 Old Camden Rd.
Hartsville, SC 29550
Dates:
September 28 - November 16, 1996
Inspectors:
J. Zeiler, Acting Senior Resident Inspector
P. Byron, Resident Inspector, Surry
J. Coley, Reactor Inspector, RII (Section M1.3)
E. Girard, Reactor Inspector, RII (Section E1.1)
M. Miller, Reactor Inspector, RII (Section M1.2)
W. Rankin, Reactor Inspector, RII (Sections R1
and R8)
G. Wiseman, Project Engineer, RII (Sections Fl,
F2, F3, F5, F7, and F8)
Accompanying Personnel: M. Holbrook, Consultant, Idaho National
Engineering Laboratory (INEL)
R. Hall, Intern, NRC Office of Nuclear
Reactor Regulation (NRR)
T. Scarbrough, NRR
Approved by:
M. Shymlock, Chief, Projects Branch 4
Division of Reactor Projects
Enclosure 2
9612230323 961216
PDR ADOCK 05000261
G
EXECUTIVE SUMMARY
H. B. Robinson Power Plant, Unit 2
NRC Inspection Report No. 50-261/96-12
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of inspection; in addition, it includes the results of an Inservice
Inspection conducted by a regional inspector, Generic Letter 89-10 program
implementation inspection by regional and headquarters inspectors,
radiological inspection by a regional inspector, and a fire protection
inspection by a regional projects engineer.
Operations
Containment integrity was not assured during core reload activities.
Operations procedures and controls were not adequate to ensure
containment integrity was established and maintained during refueling
operations. Contributing to this was inadequate oversight and
coordination of work activities affecting containment integrity status.
This issue was the subject of a Non-Cited Violation (Section 01.2).
Communication errors resulted in delays in the investigation of a water
hammer in the Safety Injection (SI) cold leg injection lines.
Engineering walkdowns and investigations adequately identified and
corrected damage resulting from the transient. The water hammer
resulted from the failure of operators to ensure that a loop seal was
configured in test apparatus hose connected. This was identified as a
violation for an inadequate surveillance procedure (Section 01.3).
Plant and operator response to an automatic reactor trip was
satisfactory. However, several minor operator training enhancements
were identified (Section 01.4).
An effective program was developed and implemented to protect plant
systems and equipment from cold weather (Section 01.5).
While a formal process for conducting containment coating repairs were
implemented, it was evident that coating upkeep in the past had not
received the appropriate level of attention. Overall progress toward
improving the condition of containment coatings has been slow, and not
consistent with good upgrades that have been implemented in the
Auxiliary and Turbine Buildings over the past year (Section 08.1).
Maintenance
Maintenance and surveillance activities observed were performed
satisfactorily (Section M1.1).
A thorough and detailed program to train and control contractor
personnel during Refueling Outage 17 was implemented. The Maintenance
Department continues to expedite and place emphasis on identifying and
resolving problems through the use of Condition Reports and self
assessment (Section M1.2).
2
Inservice Inspection (ISI) activities conducted during the current
refueling outage were found to have been performed and documented
satisfactorily. New personnel assigned to the ISI program prior to the
outage had conducted their assigned responsibilities effectively.
Problems continued in the area of updating isometric drawings after
welding or component modifications (Section M1.3).
Engineering
Satisfactory implementation of Generic Letter (GL) 89-10 "Safety-Related
Motor-Operated Valve Testing and Surveillance" had not been
accomplished. Several violations were identified involving: (1)
inadequate evaluation of test data, and, (2) inadequate design controls.
Additionally, the licensee's torque seating of butterfly valves was
considered a weakness, as this practice was contrary to the
recommendations of the vendor. Extensive efforts to dynamically test
all motor-operated valves practicable was considered a strength (Section
E1.1).
Engineering walkdowns identified ECCS containment sump deficiencies
which had been created by lack of adequate controls over previous sump
alterations and repairs. A 1988 engineering evaluation of a containment
reflood level error failed to adequately address the impact on the ECCS
sump filtration design (Section E8.5).
Plant Support
The radiological controls program was being effectively implemented and
good occupational exposure controls during outage conditions was
demonstrated.
Good radiological control performance was apparent in the
occupational exposure activities observed. An upgrade in radiation area
posting throughout the facility was evident. Continued emphasis on
procedural adherence to radiation control procedures remains a
challenge. A Non-Cited Violation was identified for failure of a
radiation worker to wear an appropriate monitoring device within the RCA
as required by procedure (Section R1.1).
A high level of personnel contamination events were noted during the
outage which represents a continuing challenge in the licensee's
radiological control program. However, no deficiencies were identified
with respect to adequacy of followup on individual personnel
contaminations or controls for contaminated areas. Although personnel
contaminated events remain relatively high and a challenge area in
radiological controls overall, actions with respect to improving
personnel contamination controls were determined to be appropriate
(Section R1.2).
Overall, the ALARA program was effectively controlling collective site
dose and the total site dose was on a favorable reducing trend (Section
R8.1).
3
Fire protection activities were acceptable. Good compliance with plant
fire prevention procedures was observed. The general housekeeping and
control of combustibles was satisfactory. The control of combustible
and flammable materials was effective (Section F1.1).
Good compliance with plant fire prevention procedures has resulted in a
low incident of fires within the plant protected area (Section F1.2).
When fire protection systems are found degraded or inoperable a high
priority is assigned to promptly return these systems to service. With
one exception, all fire protection features inspected were operational
and appeared to be well maintained. Minor configuration discrepancies
were noted with the pyrocrete fire barriers walls for the Charging Pump
Room (Section F2.1).
Implementation of the fire protection and prevention procedures was
satisfactory. A fire protection program weakness was identified in that
there was no overall plant administrative procedure that documented the
program positions, responsibilities, authorities, or the Fire Hazards
Analysis/Safe Shutdown Analysis and 10 CFR 50, Appendix R exemptions.
Engineering responsibilities for fire protection related activities were
not well defined. A recent 1996 Nuclear Assessment Section audit of the
fire protection program identified several similar weaknesses with fire
protection procedures (Section F3.1).
The performance of the fire brigade during a drill was marginally
satisfactory and did not appear to be up to the standards previously
demonstrated by the plant fire brigade. The fire brigade drill
performance was not as intense as it could have been and guidance to the
off-site fire department personnel was minimal (Section F5.1).
Audits and assessments of the facility's fire protection program were
thorough and appropriate corrective actions were being taken to resolve
the identified issues (Section F7.1).
Report Details
Summary of Plant Status
Unit 2 began the report period in day 21 of a scheduled 39 day refueling
outage (RFO-17).
Fuel reload was completed October 4. The unit was returned
to power operation on October 20 after completing a 42 day outage. That same
day, during power ascension, an automatic reactor trip occurred from 20
percent power due to a turbine trip on steam generator high level.
The unit
was placed back on-line October 21 and operated the remainder of the report
period at essentially full power.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper
staffing, operator attentiveness and communications, and adherence to
approved procedures. The inspectors attended operations turnover, and
management review meetings to maintain awareness of overall plant
operations. Operator logs were reviewed to verify operational safety
and compliance with Technical Specifications (TSs).
Instrumentation,
computer indications, and safety system lineups were periodically
reviewed from the Control Room to assess operability. Plant tours were
conducted to observe equipment status and housekeeping. Condition
Reports (CRs) were reviewed to assure that potential safety concerns and
equipment problems were reported and resolved. Specific events and
noteworthy observations are detailed in the sections below.
01.2 Failure to Maintain Containment Integrity during Refueling Operations
a. Inspection Scope (71707)
The inspectors reviewed the events surrounding the licensee's
determination that containment integrity was not maintained during
refueling operations. This event was documented in CR 96-02595 and by
Licensee Event Report 50-261/96-06-00, dated November 4, 1996.
b. Observations and Findings
On October 3, 1996, reactor core fuel reload activities were in
progress. At 3:40 p.m., a maintenance contractor inside containment
performing welding to replace the bellows for Containment Penetration
Sleeve S-5, noted that air flow was coming into containment from the
opening in the bellows sleeve that was being welded. Readings obtained
with a hand held oxygen sensor indicated that the flow was air and not
argon gas as might have been expected. The individual expected to find
argon gas in the sample since an argon gas purge rig had been installed
on the auxiliary building side of the penetration to aid in the welding.
However, this rig had previously been isolated by the contractor to weld
the remaining small opening around the sleeve.
2
The control room was notified of the condition, and immediate actions
were taken to determine the source of the inleakage and if a potential
path from containment atmosphere to the outside existed. At the time,
fuel movement had already been placed on hold for an unrelated problem.
During the initial investigation, operations and engineering personnel
became aware that the gas purge rig had been connected to penetration
vent valve PP-58C which was an integral part of the penetration sleeve
boundary. It was noted that this gas rig also contained a vent valve
used by the welders to bleed off the argon gas upon completion of
purging. The position of the gas rig vent valve was checked and it was
discovered to have been open approximately 1/4 turn. The gas rig was
subsequently removed and a leak check of the penetration sleeve was
performed verifying that there was no leakage. Using valve lineup
procedures, operations conducted a verification of the status of all
other mechanical penetrations valves to ensure that no other potential
containment integrity problem existed. In addition, a detailed review
of outstanding clearances was performed to assure that no other
conditions affecting containment integrity existed.
The licensee determined that the most likely path of air flow was
through the gas rig vent valve that was found partially open. Since the
containment purge system was in operation during the welding activity,
the negative pressure created in containment would have drawn air into
containment from the open area in the sleeve that was still being
welded,-and then through this partially open vent valve. The inspectors
noted that during the period that containment integrity was not
maintained, the containment purge system was in operation and capable of
maintaining the containment at a negative pressure in relation to the
outside atmosphere, therefore, the actual safety consequences of this
event were minimal. The inspectors reviewed subsequent leak rate test
results for penetration sleeve S-5 to verify that leakage rates met TS
acceptance limits for plant startup.
The licensee's investigation of the event determined that there had been
inadequate oversight and coordination of the penetration sleeve work and
operations personnel had not adequately verified that containment
integrity was assured prior to refueling operations. Work activities
associated with the sleeve replacement were being performed in
accordance with modification ESR 94-00731. It was recognized that work
had the potential of affecting containment integrity and was supposed to
have been coordinated by working on one side or the other while
maintaining containment integrity of the side not being worked.
However, adequate oversight and coordination of work activities was not
maintained resulting in allowing contract welders to conduct activities
inside containment while the clearance boundary still allowed the
penetration sleeve vent valve on the auxiliary side to be open. The
inspectors reviewed General Procedure (GP)-10, Refueling, Revision 33.
Step 5.3.17.8 provided instructions for establishing refueling integrity
which included the completion of an attachment used to verify the status
of valves in certain penetrations. This attachment did not include all
containment penetration valves; the majority of the penetrations listed
were associated with containment air systems. GP-10 also required an
3
assessment of the status of containment penetrations via review of
outstanding clearances. While operations personnel performed this
action prior to initiating refueling activities on September 30, they
failed to identify that clearances for penetration sleeve 5 jeopardized
containment integrity.
The inspectors agreed with licensee's conclusions that the main cause of
the event was lack of adequate instructions and controls to assure that
refueling integrity was established and maintained prior to commencing
refueling operations. The licensee planned to revise GP-10 prior to the
next refueling outage to include provisions for more positive tracking
controls for all penetration valves during refueling operations.
Similar controls are already in place for conditions prior to refueling
operations such as for reduced inventory.
The failure to maintain containment integrity during refueling
operations was identified as a violation of TS 3.8.1.a. This 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. This issue was documented as NCV 50-261/96-12-01:
Failure to
Maintain Containment Integrity During Refueling.
c.
Conclusions
Procedures and controls for assuring containment integrity during
refueling operations were inadequate resulting in an open pathway
through a mechanical penetration. Contributing to this was inadequate
oversight and coordination of work activities affecting penetration
status. The licensee conducted a thorough investigation of the event
and initiated or planned suitable corrective actions. Therefore the
failure to maintain containment integrity during refueling operations
was identified as a NCV.
01.3 Water Hammer Event During RCS Check Valve Testing
a. Inspections Scope (71707, 61726)
On October 16, 1996, a water hammer occurred in the Safety Injection
(SI) cold leg injection lines while the licensee was conducting
backleakage testing of SI pressure isolation check valves connected to
the reactor coolant system (RCS).
As a result of the water hammer, a
seismic restraint support was damaged immediately downstream of where
the SI Accumulator A line discharged to the SI cold leg injection line.
The inspectors reviewed the licensee's assessment of the impact of the
water hammer on the piping and their investigation into the cause of the
incident. In addition, the inspectors performed an independent walkdown
of the piping affected by the water hammer.
b. Observations and Findings
On October 16, 1996, operations personnel were restoring the SI
Accumulator piping to its normal alignment after performing backleakage
4
testing of SI check valves that provide RCS pressure isolation. Testing
was conducted while the unit was still in cold shutdown in accordance
with Operations Surveillance Test (OST) procedure OST-160, Pressure
Isolation Check Valve Back Leakage Test, Revision 23. When the SI
Accumulator Discharge Valves (SI-865A, -865B, and -865C) were opened in
accordance with OST-160, water was admitted at 600 psig to partially
voided lines downstream in the SI cold leg injection lines. As a result
of the voided conditions, water hammers occurred in the lines.
Operations personnel in containment recognized from the noise that water
hammers had occurred and an engineering walkdown of the piping was
requested by operations management. Due to communication errors between
operations and engineering, piping in the charging system was examined
instead of the SI system. This error was recognized the following day
and engineering was directed to inspect the SI accumulator and cold leg
injection piping for potential damage.
Engineering inspections identified major damage to one seismic restraint
support, as well as other minor problems such as spalled concrete and a
loose restraint support nut. Damage to the seismic restraint supports
were repaired. Following these repairs, the inspectors conducted a
walkdown of the piping potentially affected by the transient. Repairs
to the restraint support were adequate and no other signs of piping,
insulation, or piping support damage was identified.
On October 18, the water hammer event and engineering findings were
discussed in a conference call between the licensee, NRC Region II, and
NRR management. At the request of NRC management, the licensee agreed
to conduct further inspections of a welded pipe attachment on the SI
piping that had not been visually examined for degradation in the
original scope of the walkdowns. This was accomplished that same day
and no damage was identified.
The inspectors reviewed OST-160 and CR 96-02754, which documented the
licensee's investigation of the transient. OST-160 involved
depressurizing piping upstream of check valves being tested and
pressurizing the downstream piping using a hydro pump. Leakage was then
measured by opening drain valves in the piping upstream of the check
valves. Sections 7.3, 7.5, and 7.7 of OST-160 provided instructions for
testing, among others, the first check valve connected to each SI cold
leg injection line from the Residual Heat Removal (RHR) system. In
order to test these check valves (SI-876A, -876B, -876C), drain valve
SI-876D, which was common to the upstream piping for each of the RHR
check valves, was opened to depressurize the piping. To prevent
draining the piping upstream of these check valves when SI-876D was
opened, a test apparatus was supposed to have been installed to the end
of SI-876D with a loop seal configured and the end of the test apparatus
hose routed to a floor drain. However, explicit instructions for
configuring this loop seal were not included in previous sections of the
procedure (step 7.1.13) which installed the test apparatus. A NOTE was
provided several steps prior to opening SI-876D in Section 7.3 to alert
the operators to route test apparatus hoses over the high point of the
line from which they drain to form a loop seal preventing excessive
5
draining. Similar notes were included in Sections 7.5 and 7.7 for
testing the RHR check valves for the remaining two SI cold leg injection
lines. The operators failed to follow these notes and it was not
recognized that the loop seal from SI-876D was not configured. Further,
the need for a loop seal was again not recognized after it was
identified that it took over four hours to allow SI-876D to depressurize
and drain when the valve was initially opened in Section 7.3 for testing
the RHR check valve to SI cold leg injection line 1. Opening SI-876D
without the loop seal allowed a drainage path for all three SI cold leg
injection lines due to backleakage through the RHR check valves. SI
876D was left open until completing Section 7.7 for SI cold leg loop 3.
Upon opening the SI Accumulator discharge valves at the completion of
testing, water hammers resulted due to the rapid pressurization of the
partially drained SI cold leg piping.
The inspectors concluded that OST-160 did not provide clear instructions
for ensuring that a proper test configuration was established for
testing the check valves. Operations personnel involved with the test
coordination and performance demonstrated a lack of test understanding
and attention to procedural detail in not resolving anomalous draining
problems encountered and recognizing procedural notes that would have
identified the improper loop seal configuration. This issue was
considered a violation of TS 6.5.1.1.1 for inadequate surveillance test
procedure. This item was identified as Violation 50-261/96-12-02:
Inadequate Safety Injection Check Valve Testing.
c. Conclusions
Communication errors resulted in delays in the investigation of water
hammers in the SI cold leg injection lines. Engineering walkdowns and
investigations were considered satisfactory for identifying and
correcting damage resulting from the transient. The water hammer
resulted from the failure of operators to ensure that a loop seal was
installed for certain test apparatus used. This was identified as a
violation for failure to follow surveillance procedures.
01.4 Automatic Reactor Trip due to Feedwater Control Malfunction
a. Inspection Scope (71707, 93702 and 40500)
On October 20, 1996, while restarting from RFO-17, an automatic reactor trip occurred from 20% power. The reactor tripped following a turbine
trip on high steam generator level which resulted when the B Feedwater
Regulating Valve (FRV) started to go full open unexpectedly. The
inspectors responded to the site following the trip and observed
operator actions to stabilize the plant. The inspectors evaluated plant
and operator response to the trip, reviewed the licensee's reactor trip
report and corrective actions to address the cause of the trip.
6
b. Observations and Findings
Upon arrival in the Control Room, the inspectors reviewed control board
indications and determined that the plant had been adequately stabilized
at zero percent power and hot shutdown conditions. The inspectors
reviewed plant trip data and determined that all plant safety systems
responded as designed. The loss of both main feedwater pumps resulted
in the start of both motor driven Auxiliary Feedwater pumps as expected.
The inspectors verified that a 4-hour notification was completed as
required by 10 CFR 50.72. The inspectors reviewed initial operator
response to the trip and determined that applicable emergency procedures
were entered and followed appropriately.
The inspectors reviewed the trip data and the licensee's preliminary
trip report. The following sequence of events were reconstructed from
interviews with the operators, trip data, and preliminary trip report.
At 12:36 p.m. on October 20, the unit was placed online following
reactor startup from RFO-17. During the time the reactor was placed
online until approximately 12% power, the FRVs were controlled in manual
using the bypass valves. As the demand for feedwater was increased,
control was transferred from the bypass valves to the FRVs and their
auto-manual control station placed in automatic. Reactor power was
increased to approximately 20%. At this low power, the FRVs were in the
minimum open position which created inherent instabilities. During this
transient time period, oscillations in the B Steam Generator (SG)
level/feedwater flow occurred. The feedwater control stations for all
three SGs were in automatic for approximately 30 minutes when the
control board operator observed a rapid increase in demand for the B
FRV. The B FRV auto-manual control station was placed in manual and the
close pushbutton depressed to drive the FRV to the close position to
prevent overfeed of the B SG. Even though the closed pushbutton was
depressed the operator observed the demand to increase. After matching
indicated feed flow with steam flow, the operator stopped closing the
valve. As a result of the swell from the amount of relatively cold
incoming feedwater, level in the B steam generator reached the high
level turbine trip setpoint of 75%.
The inspectors determined that operator actions prior to the trip were
adequate. Good control board monitoring was evident by the immediate
observation of the rapid FRV demand change. However, several potential
training enhancements were considered appropriate. For example, the
oscillations in feedwater flow and level observed were not considered
excessive due to experience that the feedwater control system was
instable at low power. However, it was not clear to the inspectors that
this phenomenon was clearly understood by operations personnel with
regard to the magnitude of the oscillations expected. Additionally, the
control board operator stopped closing the B FRV momentarily after
matching feedwater flow to steam flow. This indicated a lack of
understanding regarding the magnitude of the potential swell that was to
be expected after overfeeding the generator. The inspectors did not
consider these items indicative of a major training or knowledge
deficiency.
7
A team was formed to investigate the cause of the unexpected opening of
the B FRV. As a result of this investigation, failure of the B FRV
auto-manual control station was determined to be the most likely cause.
The control station was replaced and the unit was placed back online
October 21. No further problems were experienced with the feedwater
controls during the subsequent power ascension. Details of the
licensee's investigation of the auto-manual control station are
discussed further in Section M1.2 of this report.
c. Conclusions
The inspectors determined that the plant and operator response to the
reactor trip were satisfactory. However, several minor operator
training enhancements were identified. While conclusive evidence could
not be ascertained as to the root cause of the unexpected opening of the
B FRV, failure of the B auto-manual control station was considered the
most likely cause.
01.5 Cold Weather Preparations Review
a. Inspection Scope (71707, 71714)
The inspectors reviewed the licensee's procedures and controls to
determine whether the licensee had effectively implemented a program to
protect plant equipment against extreme cold weather. This included a
review of Administrative Procedure (AP)-008, Cold Weather Preparations,
Revision 1, and Operating Procedure (OP)-925, Cold Weather Operation,
Revision 9. The inspectors performed walkdowns to verify that cold
weather preparations had been implemented and that freeze protection
equipment was operating properly. In addition, the inspectors reviewed
CRs from the previous year involving freeze protection problems to
ensure that appropriate corrective actions had been completed.
b. Observations and Findings
The inspectors determined that AP-008 adequately established the overall
plant organizational responsibilities and guidance for implementing cold
weather activities. The procedure included requirements for checking
the proper operation of freeze protection equipment such as Freeze
Protection Circuits, Steam Unit Heaters and space heaters, well in
advance of the onset of freezing weather. Between November 1 and April
1, weekly checks of Freeze Protection Circuits are conducted by
maintenance personnel to ensure continued operability. The inspectors
reviewed completed Work Requests to verify that these checks were being
completed.
The majority of the responsibility for monitoring and protecting plant
equipment from cold weather lies with operations in the implementation
of OP-925. This procedure provided instructions for preparing the plant
for cold weather and for implementing periodic precautionary measures as
the outside temperature decreases. Periodic cold weather measures are
implemented when outside temperatures below 420F are imminent. OP-925
8
is considered to be "in
effect" at that time. Further precautionary
measures are implemented as the outside temperature decreases below
350F, 220F, and 180F. Major precautionary measures conducted when OP 925 is in effect include: running idle equipment susceptible to
freezing, verifying outside doors and air louvers are closed, and
verifying proper operation of Freeze Protection Circuits. The
inspectors determined that OP-925 provided comprehensive actions for
protecting plant equipment from cold weather conditions.
Based on plant walkdowns, review of operator log entries, and completed
copies of OP-925, the inspectors verified that preparations for cold
weather in accordance with AP-008 and OP-925 had been completed and
periodic precautionary measures were being implemented as outside
temperatures decreased below 42 and 35F.
The inspectors identified one action described in OP-925 and AP-008 that
was not performed adequately. This action involved the erection of
temporary enclosures to protect risk significant areas located outside.
Areas where enclosures were to be installed included: turbine first
stage pressure transmitters, main steam pressure transmitter enclosure,
condenser hotwell level controls, turbine Electro-Hydraulic skid area,
primary air compressor area, and the screen wash and fire pumps at the
service water intake structure. All of the enclosures had been erected
except the last items for the service water intake structure. Based on
discussions with operations personnel and management, there had been a
conscious decision not to erect this enclosure due to the opinion that
it was no longer needed. Apparently, there had been freezing problems
in the past associated with the fire pumps. As a result of those
problems, AP-008 and OP-925 were revised to add the service water areas
to the enclosure erection list. Following this, the freeze protection
equipment at the service water intake was upgraded which resolved the
earlier deficiencies resulting in freezing problems. Based on
confirmation with engineering personnel that problems with the freeze
protection equipment had been corrected, the inspectors agreed with
operation's determination that the enclosure was not necessary.
However, deviating from the procedure should have been documented and/or
a procedure revision implemented. The licensee indicated that AP-008
and OP-925 would be revised to remove the action for erecting this
enclosure.
On November 11, with the outside temperature near freezing, the
inspectors conducted a walkdown of various Freeze Protection Panels to
verify that Freeze Protection Circuits were energized. The inspectors
identified that the power status lights for four circuits in the turbine
building were extinguished. The inspectors alerted operations personnel
about the problems. Work Requests were initiated to investigate and
repair the circuits.
The inspectors reviewed CRs 96-00269 and 96-00270 which were initiated
during the past winter for several plant items that froze. CR 96-00269
involved the freezing of pressure instrumentation lines for the steam
driven auxiliary feedwater pump due to lack of insulation on a small
9
section of the instrument tubing. The inspectors walked down this and
other pump instrumentation to verify that exposed tubing was properly
insulated. Freezing of the unloader valves associated with the primary
air compressor was one of the more significant items identified in CR
96-00270. Corrective actions included revising AP-008 for erecting an
enclosure around the compressors in order to block wind drafts in the
area. As previously discussed, the inspectors verified that the
procedure revision had been implemented and that the enclosure was
installed.
c. Conclusions
The inspectors concluded that the licensee had effectively established
and implemented a program to protect plant systems and equipment from
cold weather. A decision not to erect a cold weather protection
enclosure at the service water intake was justified, but was not
documented properly.
08
Miscellaneous Operational Issues (92901)
08.1 (Closed) Escalated Enforcement Item (EEI) 50-261/94-23-01, Failure to
Properly Establish Containment Integrity: This incident involved two
separate issues that were cited in separate violations as follows:
Violation A - TS Containment Integrity Violation:
A violation of TS containment integrity requirements occurred as a
result of operators failing to position six main steam line drain
containment isolation valves in their required closed position. Due to
operator confusion, procedures were signed off indicating that the
valves were closed when in fact they had been throttled for RCS
temperature control.
Contributing to the event was the lack of adequate
documentation and configuration control of main steam line drain valves
when being manipulated for reactor coolant system temperature control
during hot shutdown conditions.
The licensee responded to the violation by letter dated December 27,
1994. Corrective actions included disciplinary action for the operator
who erroneously signed off procedures indicating that the valves were
closed. In addition, expectations for documenting equipment
manipulations conducted in the field were reinforced with operations
personnel via Real Time Training, RTT-94-004, completed November 29,
1994. To ensure that plant configuration is properly maintained when
using the valves for temperature control, the licensee developed new
instructions for controlling the process. OP-405, Main and Reheat Steam
System, was revised to add these instructions. The inspectors reviewed
Revision 29 of OP-405 and determined that the new instructions were
detailed and adequately controlled RCS temperature and the configuration
of the main steam drain valves. In addition, the inspectors reviewed
OP-923, Containment Integrity, Revision 18, to ensure that the valves
were added to the containment integrity checklists. The inspectors
determined that adequate corrective actions had been implemented.
10
Violation B - Inadequate Corrective Action:
This issue involved the licensee's failure to promptly revise plant
documents after a non-validated Generic Issue Document (GID) review on
the Containment Isolation System identified that certain valves needed
to be reclassified as containment isolation valves. Included among
these valves were the main steam isolation drain valves. Plant
procedures and documents were not updated to reflect the valve status
change due to the lack of a formal process for reviewing and accepting
non-validated GIDs and Design Basis Documents (DBDs).
Licensee corrective actions included revising OP-923 to identify the
main steam isolation drain line valves as containment isolation valves.
As previously discussed, the inspectors verified that the valves were
added to the procedure. As part of the corrective actions to address
the problem with the non-validated GID review, the licensee stated that
they would implement a procedure to perform formal reviews of the non
validated DBDs and GIDs for possible impact upon other plant
documentation. The inspectors noted that only one non-validated DBD
(Main Steam System) was reviewed under a pilot evaluation. This
evaluation was completed December 5, 1995, and documented in CR 94
01294. Based on no significant findings being identified from this
pilot evaluation, the licensee decided not to perform similar
evaluations of the remaining non-validated DBDs (Feedwater, Condensate,
and Radiation Monitoring Systems) and 11 non-validated GIDs. The
inspectors determined that further NRC review was needed to determine
whether there was adequate justification for not completing these
reviews. This aspect of Violation B will remain open pending completion
of this review. This was identified as Inspector Followup Item (IFI)
50-261/96-12-03: Review Licensee Justification for not Completing Non
Validated DBD and GID Evaluations.
08.2 (Closed) Licensee Event Reports (LER) 50-261/94-20-00, Condition Outside
Design Basis Due to Mispositioned Valves:
and,
(Closed) LER 50-261/94-20-01, Technical Specification Violation Due to
Mispositioned Valves:
The above LERs documented a violation of TS containment integrity
requirements as a result of operator errors in failing to position six
main steam line drain containment isolation valves in their required
closed position. This issue was the subject of NRC Violation A for EEI
50-261/94-23-01 which was discussed in Section 08.1 above. The
licensee's corrective actions addressed in the LERs were reviewed as
part of the inspector's review of the violation. Therefore, based on
these previous reviews, these LERs were closed.
08.3 (Closed) VIO 50-261/95-12-01, Operations Failure To Follow Procedure
During OST-254: This violation contained two examples of failure to
follow procedures. On April 11. 1995, the licensee performed
Operations Surveillance Test (OST)-254, Residual Heat Removal (RHR)
System and RHR Loop Sampling System Leak Test. During the performance
of the OST, the operators detected an unidentified reactor coolant leak
of 24.8 gallons per minute (gpm). The operators terminated the test and
closed valve HCV-142 which reduced leakage to 15.6 gpm. The leakage was
terminated by closing manual isolation valve CVC-205B. The licensee
declared an Unusual Event due to reactor coolant leakage exceeding 10
gpm approximately 45 minutes after detecting the excessive leakage and
it was terminated 33 minutes later after confirmatory tests. This event
is described in more detail in Section 3.b of Inspection Report 50
261/95-12. The licensee issued CR 95-00942 to follow the issue.
On April 12, an Event Review Team (ERT) was formed to evaluate: the root
cause of the event; the surveillance procedure and determine its
adequacy; and the declaration of the Unusual Event and actions taken by
the crew. The ERT was unable to determine the exact leak path and as a
result were unable to determine a root cause. The licensee's
investigation identified that an operator was able to shut valve RHR
757D an additional 1/4 turn. OST-254 requires verification that the RHR
system is aligned in accordance with Operating Procedure (OP)-201,
Residual Heat Removal System, Revision 28, Section 6.2.2.1, which
requires that valve RHR-757D be locked shut. This was the first example
of the violation.
OST-254 is an infrequently performed evolution and a pre-job brief was
required to be given by a Management Designated Monitor (MDM) in
accordance with Plant Programs (PLP) Procedure-037,Conduct of
Infrequently Performed Tests or Evolutions. The ERT determined that the
MDM performed a pre-job brief for all individuals involved in the
evolution except the onshift operations crew. Nor did he specify in
writing the duties, authority, and responsibilities of the extra
personnel or discuss a similar licensee event which had occurred within
the previous 14 months. This was contrary to the requirements of PLP
037 and was the second example of the violation.
The ERT's investigation revealed that the test should not be performed
at power. OST-254 was required to be performed annually. They
determined that the test was originally performed during refueling
outages which were on a 12 month cycle. The licensee extended the
refueling interval to 18 months but failed to change the frequency of
the RHR leak test to coincide with refueling outages. The licensee
requested relief from the annual test. The NRC granted the requested
relief in Amendment 163 to the TS, Section 4.4.3 which permits Post
Accident RHR system leakage testing on a refueling basis rather than
annually.
The inspectors reviewed CR 95-00942 which contained the ERT report. The
ERT drew the following conclusions:
OST-254 was technically accurate but did not provide specific
guidance to address a potential reactor coolant leak.
12
The performance of the PLP-037 was deficient.
The operation of HCV-142 had been erratic and previous corrective
actions to repair the valve had not been effective.
Performance of OST-254 was not recommended.
The operating crew demonstrated conservative decision making and
performed as expected.
No human performance errors were apparent.
The inspectors concluded that the ERT report was thorough and went into
great depth in attempting to determine the cause of the event.
Performing OST-254 during refueling outages appears to have been an
adequate corrective action and this item is closed.
08.4 (Closed) VIO 50-261/95-14-03, OST-156 Valve Lineup Improperly
Established:
On May 8, 1995, the inspectors questioned the valve lineup
for OST-156, Safety Injection and Containment Spray Systems Suction
Lines Leak Test, after observing that valve SI-887, the RHR Pump
Discharge to Safety Injection (SI) and CV Spray Suction valve was
closed. The inspectors concluded that with SI-887 shut, test pressure
could not be applied between it and the SI-863A and B valves. OST-156
was revised and the surveillance was reperformed.
On May 15 while conducting a post test review, the inspectors detected
another deficiency in OST-156. The valve lineup requires that valve SI
862A, Refueling Water Storage Tank to RHR, be closed. In that
configuration, the piping between valves SI-862A and SI-862B would not
be tested. However, End Path Procedure (EPP)-9, Transfer to Cold Leg
Recirculation, permits the operators to close either SI-862A or SI-862B
while establishing the long term recirculation line-up. The inspectors
were concerned that OST-156 as conducted, did not test all portions of
the piping within the test boundaries. CR 95-01104 was issued to follow
this issue.
The licensee's investigation determined that OST-156 verified the valve
positions of the boundary valves but failed to verify the valve
positions within the test boundaries. OST-156 was a new procedure and
the procedure writer assumed that the system was in a normal lineup.
The surveillance was performed with the unit in cold shutdown during
RFO-16 and as such valve line ups were not normal.
The deficiency associated with the section of piping between valves SI
862A and SI-862B resulted from the failure of the procedure writer to
account for a single active failure of Emergency Core Cooling System
(ECCS) components. Existing cold shutdown OSTs for leakage testing of
ECCS piping and components did not account for a single active failure.
A deficiency in the procedure development process combined with a lack
of knowledge on the part of the procedure writer and the reviewers
13
resulted in the failure to test the section of piping between valves SI
862A and SI-862B.
The licensee revised OST-156 and successfully reperformed the
surveillance. Operations personnel reviewed ten OST procedures related
to ECCS leakage testing. Enhancements were made to one OST and three
were revised to assure correct system alignment inside test boundaries
and assure that single active failures are accounted for in the
determination of test boundaries. This event was incorporated into the
operator's training.
The inspectors reviewed CR 95-01104 and considered it to be adequate.
They reviewed training records and verified that training was given.
OST-155, Revision 14; OST-156, Revision 4; OST-355, Revision 10; and
OST-355, Revision 16 were reviewed and the inspectors verified that the
proposed changes included in the corrective actions of CR 95-01104 were
added to the last three OSTs. This item is closed.
08.5 (Closed) VIO 50-261/95-19-01, Operations Configuration Control Events
Concerning RHR Pump Flow Path, Valve SI-883R, Steam Driven Auxiliary
Feedwater, and The Containment ventilation Unit:
This violation was
comprised of six separate examples. Each example will be addressed
separately.
1.
Clearance Procedure Error
On May 26, 1995, the licensee experienced difficulty filling the safety
injection accumulators. Investigation determined that valve SI-883R was
shut with a clearance tag (No.20) attached which was from Local
Clearance and Test Request (LCTR 95-F0013) that had been cleared 24 days
earlier. CR 95-01352 was written to address the issue. The licensee
determined that an auxiliary operator and an independent verifier
initialed LCTR 95-F0013 that clearance tag number 20 had been removed
and the valve opened. A Senior Reactor Operator (SRO) also signed the
clearance to indicate that he had verified that all tags removed from
this clearance.
Licensee procedure Operations Management Manual (OMM)-005, Clearance and
Test Request, requires that pulled tags be delivered to the Work Control
Center (WCC) for verification. Operators are required to notify the WCC
to update the clearance before destroying any potentially contaminated
tags. The operators did not manipulate the valve as the valve had
additional tags attached to it which required the valve to be closed nor
did they remove the tag. In addition, the operators destroyed the tags
without notifying the WCC from the Containment Vessel (CV). They
departed the CV and reported to the WCC to update the master copy of the
clearance from memory. They initialed the master clearance that they
had removed the tag and opened the valve.
The licensee determined that the operators failure to follow OMM-005 was
the root cause of the event and inadequate guidance in the procedure was
14
a contributing factor. The operators were counselled and OMM-005 was
revised.
The inspectors reviewed OMM-005, Revision 33 and verified that Section
5.2.19 addresses the proper method to account for contaminated tags.
They also reviewed the completed CR 95-01352 package and considered that
the licensee addressed all the issues.
2.
Containment Fan Operated With Flow Paths Isolated
On May 26, 1995, during a tour of containment the inspectors noted an
abnormal noise emanating from containment recirculation fan, HVH-2.
They observed that both the inlet damper and inlet butterfly valve were
closed with the unit operating. The control room was notified and the
unit was shut down. CR 95-01354 was written to address the issue.
The inspectors determined that LCTR 95-FO476 was in effect at the time
of the observation. The clearance isolated the instrument air supply to
the damper activator which caused the damper to be failed. Neither the
butterfly valve or its air supply were affected by the clearance which
specified that a Clearance Information Tag (CIT) be affixed to the HVH-2
RTGB control switch. There was no CIT attached to the RTGB switch nor
did the clearance reflect that one had been affixed.
The SRO who prepared the clearance was unaware that the butterfly valve
was supplied by a separate air supply and assumed it would fail open
with the loss of air. Assuming that a flow path existed, the SRO did
not believe a CIT was required to be placed on the RTGB switch. However
one was prepared but not placed on the switch.
The licensee's review of Operations Surveillance Test (OST)-902,
Containment Fan Coolers Component Test (Monthly), and the Heating and
Air Conditioning drawing identified the butterfly valve as V12-2A.
Neither the Containment Air Handling Operating Procedure, OP-921, nor
OP-905, Instrument and Station Air System, identified V12-2A as the HVH
2 butterfly valve. The licensee concluded that it was not apparent
using controlled documents that V12-2A had an independent instrument air
header. They concluded both reviewers failed to identify the need to
place a CIT on the control switch.
The SRO was counselled and a CIT was added to the clearance. Additional
corrective actions included revising OMM-005 to add a CIT sign off and
OP-905 was revised to identify the instrument air supplies.
The inspectors reviewed OP-905, Revision 47 and noted that page 30 of
Attachment 9.1 lists separate instrument air supplies for the HVH-2
damper and V12-2A. OP-921, Revision 23, Section 8.4.2.1 identified V12
2A as the butterfly valve. OST-902, Revision 22, Section 6.5 addresses
V12-2A as the butterfly valve. The inspectors review of OMM-005,
Revision 33 did not identify any CIT signoffs. Their review of CR 95
01354 verified that the issues had been adequately addressed.
15
3.
RHR Pump Operated with No Flow
On June 3, 1995, the licensee was preparing to restart the unit
following a refueling outage. The control room operators were
performing steps to depressurize and cooldown the "A" RHR train in
accordance with GP-002, Cold Shutdown To Hot Subcritical At No Load
Tavg. This is accomplished by recirculating the isolated train through
its associated heat exchanger until it has cooled to 150 0F.
Approximately 15 minutes into the evolution the operators had not
observed the expected temperature decrease. The control room operators
increased cooling water to the heat exchanger and then checked on the
position of valve RHR-743 which is in the recirculation flow path.
Finally the control room operators had an AO check the local flow
indicator, as RHR recirculation flow is not read in the control room.
The local indicator indicated no flow and the operators secured the "A"
RHR pump.
The "A" RHR pump had run for approximately 66 minutes with
essentially no flow. The pump was declared inoperable.
The licensee
issued CR 95-01474 to address the issue.
The licensee disassembled the "A" RHR pump and found no damage to the
pump. The licensee's investigation revealed that valve RHR-743 had been
operated with a reach rod. The AO stated that he attempted to open the
valve but it did not move and assumed that it was open.
The licensee's corrective action was to change the makeup of the crew to
strengthen leadership. Operations Management Manual (OMM)-001,
Operations-Conduct of Operations, was revised to provide additional
instructions on how to verify the position of manual valves that have
reach rods. Procedure GP-002 was revised to provide a step to verify
that valve RHR-743 is open prior to isolating the RHR system and verify
recirculation flow immediately after isolating the system. Engineering
Service Request (ESR) 95-00640 was issued to remove the reach rod on
RHR-743 and was accomplished by Work Request 95-AHWE1.
The inspectors reviewed OMM-01-8, Revision 01, Section 5.4.2.2.12 and
verified that additional instructions had been provided to verify the
position of manual valves with reach rods. Their review of GP-002,
Revision 67, Section 5.4.2.1 verified that a verification step had been
provided to ensure valve RHR-743 was open prior to isolating the RHR
system and verify recirculation flow immediately after system isolation.
The inspectors review of CR 95-01474 verified that the license had
adequately addressed the issues.
4.
RHR Pump Operated With No Flow
On June 9, 1995, the control room operators were aligning the "A"
pump to place it in service in accordance with Operating Procedure (OP)
201, RHR System, following its reassembly. The "B" RHR pump was
operating in a configuration which bypassed its heat exchanger. In this
configuration the common discharge valve (HCV-758) for the heat
exchangers for both RHR heat exchangers was closed. The "A" pump was
started and the "B" pump secured. The operators observed decaying RHR
16
flow and restored the pumps to their original condition. The operators
determined that the "A"
RHR pump had been started without a flow path.
The cross connect valve (RHR-757C) was opened to provide a flow path and
the pump was successfully started. The pump was operated for
approximately two minutes with minimal flow as HCV-758 leaked by. This
was the second time in six days that the operators ran the "A" RHR pump
with inadequate flow. The inspectors concluded that OP-201 was
inadequate in that it did not align the system to provide a flow path.
The licensee's corrective actions were to revise OP-201 and again
restructure the crew.
The inspectors reviewed OP-201, Revision 28, Section 6.1.2.3 and
verified that a flow path was provided by requiring that valve RHR-757C
be open prior to starting RHR pumps. The inspectors also reviewed
nonsignificant CR 95-01510 and determined that it adequately addressed
the issue.
5.
Auxiliary Feed Water (AFW) Pump Auto Start During Steam Generator
(SG) Draindown
On June 14, 1995, both AFW pumps started and the SG blowdown isolation
valves on all three SGs shut due to a low-low level in the "B" SG. The
operators responded by defeating the AFW pump auto-start logic, stopped
the pumps, and opened the blow down isolation valves. Draining the SGs
was accomplished in accordance with Operating Procedure (OP)-406, Steam
Generator Blowdown/Wet Layup System. Section 4.1 requires four key
switches be taken to the "defeat" position prior to draining the SGs.
This action blocks the SG low and low-low level signals from the AFW
autostart circuit during draindown. The licensee issued CR 95-01566 to
track this event.
The key switches were found in the "normal" position. Investigation
revealed that the AO had initialed OP-406 as having verified that the
key switches were in the "defeat" position. The AO stated that he had
called the control room SRO to verify that the switches were in the
"defeat" position. He initialed the procedural step after receiving
confirmation from the SRO. The SRO did not visually verify that the key
switches were in the proper position but was based on the illuminated
Train A and Train B AFW Auto Initiation Defeated warning lights.
However, these lights can be illuminated without the four key switches
being in the defeated position.
The licensee disciplined the operator and all crews were counselled. In
addition, during Licensed Operator Requalification (LOR) the licensee
reinforced the OMM-001 requirements concerning individual accountability
for signoffs.
The inspectors reviewed OP-406, Revision 34, Section 4.1 and verified
the requirement to place the four key switches in "defeat" prior to
draining to draining the SGs. A review of CR 95-01566 indicated that
the licensee's actions were adequate.
17
6.
Inadequate Clearance For Work On Valve V1-8A
On April 17, 1995, the licensee attempted to perform lubrication
preventive maintenance on valve V1-8A, one of three steam valves to the
steam driven AFW pump turbine. The turbine commenced to roll when valve
V1-8A was opened. Investigation revealed that valve MS-20 which is
immediately upstream of valve V1-8A was in the open position.
The clearance (LCTR 95-00748) for the V1-8A preventative maintenance did
not address valve MS-20. OMM-005, Section 5.1.31 requires that all
valves necessary to protect personnel and equipment are properly closed
or open as necessary. The inspectors considered LCTR 95-00748 to be
inadequate in that it did not address valve MS-20 which would have
protected the turbine.
The licensee's corrective action was to add MS-20 to the LCTR and the
corrected LCTR was added as a standard to the history file in the LCTR
database for valves V1-8A, B, and C.
The inspectors reviewed OMM-005, Revision 33, Section 5.1.31 and
verified that it contained requirements to position valves and switches
to protect personnel and equipment. They also reviewed two non
significant CRs (95-00961 and 95-00962) which were written to address
this issue. Neither CR addressed the adequacy of LCTR 95-00748 or its
review. The inspectors considered that the main steam line valve (MS
20) upstream of V1-8A should have been included in the LCTR as required
by OMM-005. They consider that this deficiency should have been
identified during the LCTR review. When questioned by the inspectors
the licensee's response was that the maintenance had always been
performed during an outage and this was the first time it had been
performed on line. When asked why a steam valve was not isolated to
protect the down stream equipment, the licensee responded that they
didn't believe that the available steam was sufficient to rotate the AFW
turbine. The inspectors considered that the evaluation of CRs95-961
and 95-962 were inadequate in that they did not address the human
performance issues.
The inspectors discussed their concern with the licensee who
acknowledged that the CR review was inadequate. Discussions with the
licensee revealed that they had revisited this issue and incorporated it
into a roll up multiple personnel issues. In addition, the licensee
previously scheduled a corrective action self-assessment for
December 1996. The adequacy of CR reviews will be part of the
assessment.
The licensee issued CR 95-01816 to address all six issues encompassed in
the violation as a common problem and represented a serious management
concern. The inspectors reviewed this CR and noted that it incorporated
all the above discussion. In addition, it addressed the human
performance issue involved with item 6. above. The inspectors consider
that the issues were adequately addressed and were raised to a
sufficient level of management. The corrective actions were to be
18
adequate and were verified to have been completed by the inspectors.
This item is closed.
08.6 (Closed) Unresolved Item (URI) 50-261/95-19-02, Safety Injection Pump
Breaker Racked-In with LTOP in Service:
This issue involved a licensing
basis question regarding TS 3.3.1.3 which requires the SI pump power
supply breakers to be racked out when the RCS is below 3500F and the RCS
is not vented to containment atmosphere. On May 30, 1995, the licensee
identified that the A SI pump motor breaker was racked in for
approximately five minutes to fill the SI Accumulators without an RCS
vent path established via an open Pressurizer Power-Operated Relief
Valve.
The inspectors reviewed the basis of TSs 3.3.1.3, 3.1.2, Amendment 42 to
the TSs and associated NRC Safety Evaluation Report (SER) which
evaluated the licensee's addition of the Low Temperature Overpressure
Protection (LTOP) System, and CR 95-01355 which documented the
licensee's evaluation of this incident. The inspectors determined from
review of the chronology of the event that during the short period that
the SI pump motor was racked in and the PORVs were closed, LTOP was
armed and capable of performing its overpressure protection function.
Design basis analyses support the capability of LTOP to perform its
intended function of relieving RCS overpressurization from the
inadvertent actuation of an SI pump. Further, the NRC SER recognized
the possibility that an SI pump may be racked in under LTOP conditions
for periodic or post-maintenance operational testing. The inspectors
concluded that the licensee had not operated outside of TSs as a result
of racking in the SI pump since LTOP had been operable. Based on this
review, this URI was closed.
08.7 (Closed) URI 50-261/95-19-03, Loose Paint in Containment: This issue
involved concerns over the amount of loose paint identified by NRC
inspectors during containment walkdowns in the previous refueling outage
(RFO-16). The main areas where loose or peeling paint was identified
was on the high traffic area of the floor of the first level of
containment. Other less affected areas included the containment fan
cooling units, operating deck, and polar crane.
The inspectors reviewed CR 95-01506 which was initiated by the licensee
to address the loose paint concerns. Prior to startup the licensee
performed inspections of containment and corrected areas needing
immediate repairs. The licensee determined that the normally expected
walkdown of containment by engineering personnel to identify and correct
coating problems was not performed. To ensure walkdowns were completed
during subsequent RFOs, a preventive maintenance work request was
developed to require the inspections during every RFO.
During RFO-17, the inspectors determined that WR/JO AHWU was performed
to inspect the condition of containment coatings. The inspectors also
accompanied engineering personnel on coating inspections of containment.
The purpose of the inspections by engineering were to determine areas
needing immediate repairs to remove loose or peeling paint and areas
19
that needed to be scheduled for repair in the next RFO. Based on the
large number of items identified needing repairs, it was evident that
coating upkeep in the past had not received the appropriate level of
attention by the licensee. During containment closeout walkdowns, the
inspectors verified that repairs had been completed for areas
representing immediate concerns. While the inspectors noted that
several small floor areas of the first level of the containment and some
equipment were repainted during the outage as part of preventive coating
upgrades, progress toward improving the overall degraded conditions of
containment coatings was progressing slowly. This was inconsistent with
the good upgrades in coating repairs that the licensee had implemented
in the Auxiliary and Turbine Buildings over the past year. This issue
was considered a licensee weakness. Engineering personnel indicated
that more aggressive coating upgrades were planned for the next RFO.
Based on the licensee's implementation of a more formal process for
inspecting the condition of containment coatings and efforts to address
long term coating improvements, this item was closed.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (61726 and 62707)
The inspectors observed all or portions of the following maintenance
related WRs/JOs and surveillances and reviewed the associated
documentation:
WR/JO 95-ALTE1, Reactor Coolant Pump A Seal Inspection, Repair,
and Reinstallation
WR/JO 96-ADIF1, Replace Mechanical Seal on Emergency Diesel
Generator (EDG) A Standby Circulating Pump
WR/JO 96-ABKG1, Replace Oil Seals on Control Shaft of EDG A
Governor
OST-163, Safety Injection Test and Emergency Diesel Generator Auto
Start on Loss of Power and Safety Injection, Revision 27
b. Observations and Findings
The inspectors observed that these activities were performed by
personnel who were experienced and knowledgeable of their assigned
tasks. Work and surveillance procedures were present at the work
location and being adhered to. Procedures provided sufficient detail
and guidance for the intended activities. Activities were properly
authorized and coordinated with operations prior to start. Test
equipment in use was calibrated, procedure prerequisites were met,
20
system restoration was completed, and surveillance acceptance criteria
were met.
c. Conclusions
The inspectors concluded that maintenance and surveillance activities
were performed satisfactorily.
M1.2 Maintenance Related Outage Activities
a. Inspection Scope (62700)
The inspectors reviewed documentation for maintenance activities
performed for the refueling outage to determine if the activities met
regulatory requirements and were performed in accordance with approved
procedures and appropriate maintenance standards. The inspectors
reviewed outage maintenance related CRs and the maintenance outage
contractor training program. The inspectors observed a post maintenance
lessons learned critique. In addition, the circumstances associated
with the October 20 reactor trip were reviewed to determine if the root
cause was identified.
b. Observations and Findings
Contractor Craft Maintenance Program - The inspectors reviewed the
maintenance program for using contractor personnel from Becon
Construction Company for work during RFO-17. The program included the
requirements for the craft certification process; the training
department and staffing plan; the Desk Top Guide; training categories;
and lessons plans. The "Desk Top Guide For Training Becon Personnel
Hired To Perform Outage And Maintenance Work At The Robinson Nuclear
Plant" described the requirements for training and the responsibilities
for all Becon personnel for RFO-17 work. Detailed training requirements
and lessons plans were specified for each category of workers. The
categories included: 1) Civil Trades, 2) Mechanical Trades including
welders, 3) Electrical Trades, and 4) Maintenance Workers. The
inspectors reviewed the training lessons and training matrix to verify
all 195 contractor personnel had received the appropriate and required
training. The program was considered very thorough and detailed.
Maintenance Condition Reports - The inspectors reviewed the "Maintenance
Condition Report Status Report" dated October 24, 1996, to evaluate the
status of outstanding CRs. In the group of CRs categorized as
"Significant," there were five open evaluations and one open corrective
action. These numbers were down from an average of 30 open evaluations
and 212 open corrective actions. In the group of "Non-Significant" CRs,
the open evaluations were up from an average of 17 to 39; and the open
corrective actions were down from an average of 83 to 31. In the group
of "Improvement" CRs, the open evaluations were down from an average of
29 to 3; and the open corrective actions were down from an average of
172 to 10. The Maintenance Department performance has significantly
improved for processing CRs. The inspector reviewed 27 CRs to determine
21
what types of problems were being reported to maintenance and if any
trends were identified. Five different CRs identified that work was
performed on live electrical circuits. The cause was personnel error in
most of the cases. However, the licensee agreed that more attention
should be placed in this area concerning work on live electrical
circuits.
CR 96-02505 involved a plant clearance for the electrical circuit for
motor operated valve MOV RHR-744B during plant modification ESR 95
00764. The clearance was taken out by the contractor to do the work,
however, plant Instrumentation and Control (I&C) personnel did not sign
on. When the work was completed, the contractor closed the clearance as
required by the modification work procedure to allow I&C to test the
valve. The clearance was removed to allow power to be restored to the
MOV for testing. At that time, testing could not be performed and the
clearance was not re-initiated. Several hours later, Operations
personnel operated the valve although testing and the modification were
not completed. No damage was done to the valve and no procedures were
violated concerning the clearance or work. However, a weakness was
identified in the "clearance" area concerning electrical power. The
licensee agreed to address this weakness and implement appropriate
corrective action.
Reactor Trip - The inspectors reviewed CR 96-02804, concerning the
investigation into the reactor trip following plant startup after RFO
17. After the trip, I&C personnel performed multiple checks to
determine what caused the auto-manual control station to fail. No
equipment failure was identified; the auto-manual control station
functioned properly. However, I&C replaced the control station with
another unit. (The reactor was placed on back on line with no other
problems). The control station was taken back to the I&C shop for
evaluation and testing. No problems had been noted. The inspectors
examined the control station and reviewed its testing. No problems were
identified. The licensee indicated that a previous problem had been
identified with the auto-manual control station for the B FRV during
RFO-17. As a result this problem, defective capacitors had been
replaced. The inspectors concluded that the root cause of the reactor
trip could not be verified since the auto-manual control station had not
failed since the trip. In addition, engineering stated that at low
power operation (below 20% power) the feedwater control system has been
known to suffer some instability in the automatic mode of operation.
The control system works well above 20% power and is stable.
Post Outage Review - The inspectors observed a post outage lessons
learned critique by the maintenance department management. The critique
was held as a self assessment to identify problems during the outage.
The inspectors reviewed 169 comments where the maintenance department
identified areas for improvement. Many of the problems identified were
to be shared with the other sites. The inspectors concluded the
maintenance department was implementing another tool for self assessment
and improvement in their work methods.
22
c. Conclusions
The inspectors concluded that the Maintenance Department had implemented
a thorough and detailed program to train and control contract personnel
during RFO-17. The Maintenance Department continues to expedite and
place emphasis on identifying and resolving problems through the use of
CRs and self assessment. The root cause of the reactor trip during re
start after RFO-17 could not be identified as equipment failure with the
feedwater control system "Auto-Manual Control Station".
M1.3
Inservice Inspection Activities Performed in Refueling Outage 17
a. Inspection Scope (73753)
In October, 1996, the licensee completed the 1st refueling outage (RFO
17) in the 2nd 40-month inspection period of the 3rd 10-year inservice
inspection (ISI) interval. There will be one more refueling outage in
the 2nd 40-month inspection period. The applicable code for ISI in the
3rd 10-year examination interval is the American Society of Mechanical
Engineers (ASME) Code,Section XI, 1986 edition with no addenda.
The following licensee documents and ISI activities were reviewed: the
third ten-year interval inspection program including relief requests and
augmented examinations, RFO-17 examination plan, ISI program procedures
and other plant interfacing procedures, completed examination
documentation, personnel and equipment certifications, Code repairs, and
the effectiveness of licensee controls for ISI.
b. Observations and Findings
The third ten-year interval program was reviewed to determine whether
the first inspection period sample of examinations met minimum Code
requirements and which relief requests had been approved by NRC and
implemented by the licensee. The review revealed that all 1st period
examinations had been performed as required and the total number of
examinations performed exceeded Code minimum requirements. Approved
relief requests were also properly implemented.
The RFO-17 examination plan was reviewed in order to select a diverse
sample of 10 completed line item examinations for a detailed review.
The review of the completed examination records revealed that the
examinations had been conducted and documented as required by the
approved ISI procedures, and personnel and equipment certifications were
in accordance with Code requirements. Instructions and documentation
for two Code repairs and the results of the eddy current examinations
for the "A" steam generator were reviewed and also found to be
satisfactory.
ISI program procedures, as well as procedures for post maintenance
testing, work control processes, engineering services, and documents
such as CRs and licensee assessments were reviewed to determine the
effectiveness of licensee controls for ISI. The inspectors identified
23
eight recent CRs which involved ISI. Six of these reports had been
written to document tardiness of ISI personnel in assigning post
maintenance test requirements (PMTRs) or unclear PMTRs. All of these
CRs were open and licensee corrective actions had not been documented.
The inspectors determined that sufficient procedural requirements were
in place for the ISI program; therefore, additional training and closer
supervision of the process should be sufficient corrective action.
The two other CRs (96-01899 & 96-02437) dealt with the potential problem
that ASME ISI isometric piping drawings may not reflect new welds added
to, or old welds deleted from, the ISI program via the work
request/modification process. Similar drawing error problems were
identified in previous NRC inspections of the licensee's ISI program
(see NRC Violation 50-261/90-24-01). The need for more accurate as
built and formalized drawings was discussed during this previous
inspection.
A licensee self-assessment performed in October 1994, on the ISI 10-year
plan for the third inspection interval, found numerous examples where
specific welds or components were identified in the plan but not on
isometric drawings. In addition, a NAS audit of the ISI program (Report
File No. R-ES-95-02) identified that during RFO-16, Modification MOD
1164 removed several supports within the ISI program scope; however, the
modification package did not identify the ISI program isometrics as
requiring revisions. Both of these assessments recommended that the ISI
isometric drawings be made controlled documents.
In mid-1995 the licensee completed corrective actions for NRC Violation
90-24-01. These actions included verification of the accuracy of
isometric drawings and formalizing the control of these drawings.
However, as discussed above CR 96-02437 reported that a potential
problem still existed because of the numerous questions that had been
raised by ISI and nondestructive examination personnel on the process
for adding and deleting welds that are required to be examined in
accordance with the Code.
Enhancements being considered by the licensee to address this continuing
problem were to ensure that procedural requirements for drawing controls
were adequate and clear, and that applicable personnel were
knowledgeable of the requirements for revising drawings. In order to
verify adequate implementation and completion of the licensee's
corrective actions, this issue was identified as an IFI 50-261/96-12-04:
Review Licensee Actions to Address Potential ISI Isometric Drawing
Problems.
c. Conclusions
ISI activities examined by the inspectors were found to be satisfactory.
The licensee had recently replaced personnel responsible for ISI.
The
inspectors found that the new personnel had assumed their duties in an
effective manner. Problems continued in the area of updating isometric
drawings after welding or component modifications.
24
M8
Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) LER 50-261/94-02-01, Plant Condition Outside Design Basis Due
to MSIV Inoperability: This supplemental LER provided information
clarifying details contained in the originally submitted LER and
information provided in a Notice of Violation response from the
licensee. The corrective actions in the LER were the same as those
included in the response to NRC violation 50-261/94-16-05: Inadequate
Corrective Actions Concerning MSIV Accumulator Volume, which was
reviewed and documented in NRC Inspection Report 50-261/96-08. This LER
was closed based on the previous review of the violation and associated
corrective actions.
M8.2 (Closed) EEI 50-261/94-16-03, Inadequate Corrective Action to Potential
TS Deficiencies: This violation involved the failure to take adequate
corrective action in a timely fashion for potential TS deficiencies
identified by an internal assessment of compliance with the surveillance
requirements of TS Table 4.1-1 conducted by Enercon Services, Inc.
between 1991 and 1992.
The licensee responded to this violation by letter dated September 29,
1994. The cause of the violation was determined to be the lack of
management oversight and involvement in the Corrective Action Program.
The corrective action process was not effectively used to ensure methods
and timely schedules for addressing the deficiencies. Also, because the
Enercon assessment had been directed by the Plant Nuclear Safety
Committee (PNSC) in 1990, accountability for resolution of the results
were not clearly established.
Licensee corrective actions for the violation included enhancing the
corrective action process to provide greater management oversight and
tracking of CR schedules and the quality of evaluations. In addition,
PNSC Action Items were to be formally assigned to the responsible
organization unit and tracked to completion. The inspectors reviewed
Plant Program (PLP) procedure PLP-026, Revision 18, which implemented
the licensee's enhancements. Major changes noted included: 1)
clarification of responsibilities and criteria for completing CR
reportability reviews, trending, and evaluations, 2) another level of
CRs was created for lesser significant "improvement" conditions in order
to foster the identification of problems, and, 3) management was
assigned responsibility for trending CRs. Based on review of the
current version of PLP-026 (Revision 24), the inspectors determined that
these, as well as other enhancements made since the earlier revision,
were still in effect. The inspectors reviewed PLP-001, Plant Nuclear
Safety Committee, Revision 16, and determined that provisions for
assigning and tracking PNSC Action Items were established. The
inspectors reviewed the electronic CR database and determined that PNSC
Action Items were correctly being entered into the licensee's CR
database. The inspectors concluded that the licensee's corrective
actions for this violation had been adequately implemented.
25
M8.3 (Closed) LER 50-261/94-01-00, -01, Failure to Test Instrumentation
Channels Per Technical Specifications: These LERs dealt with
inadequacies in surveillance test procedures that resulted in portions
of the 4 Kilo-Volt Undervoltage trip circuitry and Overpressure
Protection System not being properly tested in accordance with TSs. The
tests for the applicable TS Surveillance Requirements were revised to
include the untested portion of the equipment in question and were later
performed with satisfactory results. These procedural discrepancies
were previously identified in 1992 during an independent assessment of
the TS surveillance program but were not promptly resolved. The root
cause for the failure to promptly resolve the issues was the result of
program weaknesses in the licensee's corrective action process.
The inspectors previously reviewed the technical aspects associated with
the LERs in NRC Inspection Report 50-261/94-16. The LER supplement (94
01-01) was submitted primarily to provide corrective actions to address
weaknesses in the licensee's corrective action program. The corrective
actions described in the LER were the same as those in the licensee's
response to violation EEI 50-261/94-16-03: Inadequate Corrective Action
to Potential TS Deficiencies, discussed separately in this report.
These LERs are closed based on the review of the violation and
associated corrective actions.
M8.4 (Closed) VIO 50-261/95-12-03, Maintenance Planner Fails To Properly
Develop Breaker PMTR:
On April 6, 1995, the licensee removed circuit
breaker HVH-2 (52-20C) from service to perform preventative maintenance
(PMs).
Material deficiencies were observed during the PMs and a
replacement circuit breaker was installed. The inspectors observed the
PMTR for the replacement circuit breaker and questioned its adequacy.
The PMTR consisted of the operators closing the breaker from the RTGB.
The inspectors did not consider that the PMTR met the requirements of
Maintenance Management Manual Procedure (MMM)-003, Appendix A, Post
Maintenance Testing. This procedure requires that post maintenance
testing demonstrate that the circuit breaker responds to all demand
signals. It also requires that breakers on the E-1 and E-2 busses which
respond to an autostart signal from a safeguards actuation have a time
test as part of its PMTR. The licensee opened the replacement circuit
breaker from the RTGB and performed a time test in response to the
inspectors' concerns. CR 95-00927 was written to address the issue.
Investigation revealed that Work Request (WR) 95-AEPZ1 was issued to
change the contacts on circuit breaker 52/20C. The planner was
requested to revise the WR to perform PM-402, Inspection nd Testing of
Circuit Breakers for 480 Volt Bus E-1, on the spare circuit breaker as a
contingency. The planner was asked to revise WR 95-AEPZ1 to include
instructions to install the spare circuit breaker if the repairs to the
installed circuit breaker were unsuccessful.
Post maintenance testing
was determined from WR history and a review of PM-402 and CM-305,
Westinghouse "DB" Type Circuit Breaker Maintenance. Past practice had
not been to verify post maintenance testing in MMM-003, Appendix "A".
The licensee determined that MMM-003, Appendix "A" had been revised on
June 16, 1994. The planning organization was unaware of the change as
26
they were not included in the review process for this procedure.
Administration Procedure (AP)-022, Document Change Procedure, Attachment
9.2 Review assignment criteria Section 29 for Work Control did not list
MMM-003 as required to be reviewed by Work Control.
The revision to MMM-003 which added the circuit breaker timing test
requirement did not include any acceptance criteria. The licensee
determined that the requirement to perform the timing test was included
in a note in the Circuit Breaker Maintenance Section and was not listed
in the test requirements. In addition, it was not added to PM-402 or
PM-163 which was for bus E-2.
Engineering Service Request (ESR) 95-00357 was initiated to provide
guidance on acceptable closing time for HVH-2 to meet the requirements
of MMM-003. Engineering determined that in this application that
circuit breaker closing within 0.5 seconds would not impact the
capability of the motors fed from buses E-1 or E-2 to start when
required.
The licensee's corrective actions included successfully performing the
timing test and the planner was issued and required to use OMM-003,
Appendix "A". Procedure AP-022 was revised to require Work Control
review of changes to MMM-003 which was also revised to clearly state
when circuit breaker testing was required and list acceptance criteria.
PM-402 and PM-163 were revised to include circuit breaker timing testing
as part of in-process testing.
The inspectors reviewed WR 95-AEPZ1 and noted that the request for
testing was vague,"perform the appropriate testing." Procedure CM-305,
Revision 6 was reviewed and the inspectors did not locate any references
to circuit breaker timing tests. The inspectors verified that Procedure
AP-022, Revision 25, Section 9.2.29.4 contains the requirement that Work
control review all changes to MMM-003. They also verified that
Procedures PM-163, Revision 2, Section 7.24 and Attachment 10.8.5,
Section 7.24.7 and PM-402, Revision 13, Section 7.24 and Attachment
10.8., Section 7.24.7 specify that a closing time test is required for
circuit breakers 52/24B (HVH-4) and 52/20C respectively, the acceptance
criteria is also listed. The inspectors verified that MMM-003, Appendix
"A", Revision 18, Attachment 7.4.1, Section 1.1.5 contains requirements
to perform a timing test for safety related DB-50 circuit breakers and
specifies acceptance criteria. The inspectors noted that the acceptance
criteria specified in MMM-003 is more conservative than that listed in
ESR 95-00357 (200 vs 500 msecs). The inspectors questioned the licensee
about the difference in circuit breaker closing times. The 500 msecs
closing time was obtained from CP&L calculation RNP-E-8.002, Attachment
0, Overall Load Block Tolerance. ESR 95-00360 was issued to evaluate
the closing time requirements of all circuit breakers on the E-1 and E-2
busses. The Revision 2 response to the ESR provided vendor design data
for DB circuit breaker closing times. Westinghouse Letter RCS/ESE(95)1
145 stated that the DB circuit breakers were designed to close
electrically within 200 msecs. Engineering recommended that MMM-003,
Appendix A be revised to reflect the design closing times. The
27
inspectors verified the licensee's corrective actions and this item is
closed.
M8.5 (Closed) VIO 50-261/95-14-01, Inadequate Control Of Contractor Services:
Three examples of inadequate licensee control of contractor services
were identified between May 3 and May 8,1995. Each example will be
addressed separately.
1.
Collision of Polar Crane and Manipulator Crane
On May 3, 1995, the containment polar crane collided with the refueling
manipulator crane. A contracted refueling technician had moved the
manipulator crane in the path of the polar crane. Subsequently, a
contracted crane operator moved the polar crane without verifying the
position of the manipulator crane. The polar crane collided with a
cross piece on the manipulator crane's monorail. The top of the
manipulator crane was bent approximately two to three feet and resulted
in the failure of three welds.
Investigation of the event revealed that the refueling technician had
not received CP&L crane training nor had the polar crane operator been
trained on Maintenance Instruction (MI)-510, Polar Crane General
Instructions. A copy of MI-510 was not in the crane's cab as required
nor had the operator been given a proficiency examination. In addition,
the licensee did not have a formal coordination process to use when
multiple cranes were in use.
The licensee determined that the event
was caused by a series of personnel errors and an over reliance on an
inadequate Polar Crane protective System.
The licensee formed an Event Review Team (ERT) to determine the cause of
this event. CR 95-01069 was issued to track this event. Engineering
Service Request (ESR) 95-00427 was issued to evaluate the structural
damage to the manipulator crane. Engineering determined that the
structural deformation was within acceptable limits. The damaged welds
were repaired by Work Request (WR) 95-AFNS1. The inspectors reviewed
the ESR and WR and verified that the recommended work had ben completed.
2.
Polar Crane Auxiliary Hook Strikes Steam Generator Cubicle
On May 4, 1995, the polar crane auxiliary hook struck the concrete
cubicle surrounding the "C" steam generator. The crane operator had
been operating the crane from the refueling floor. He had lowered the
auxiliary hook for a planned lift but lift priorities changed. He moved
the polar crane to position it for the next lift but failed to adjust
the height of the auxiliary hook. The crane operator commenced to
reposition the polar crane on his own initiative without direction from
the signalman. The polar crane's auxiliary hook hit the north side of
the concrete cubicle around the "C" steam generator. The crane operator
was the same that was involved in the previous event. He was reassigned
to other duties.
28
The licensee expanded the scope of the ERT's charter to include this
event which was also addressed in CR 95-01069. ESR 95-00436 was issued
to provide an engineering inspection of the "C" steam generator cubicle.
The inspection revealed that there was no structural damage and only
scuff marks were observed on the concrete.
The inspectors reviewed CR 95-01069 which included the ERT's findings
and recommendations. The ERT concluded that the polar crane operator
had worked 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> in the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Technical specification
work limitations were imposed on the craft. The design limitations for
the polar crane interlock system were evaluated and recommendations were
made. The preferred solution was to enhance training. The ERT
concluded that the contractors training was inadequate. They also
concluded that CP&L Procedure MMM-009, Operation, Testing and Inspection
of Cranes and Material Handling Equipment, was inadequate in that it was
weak in specifying training and testing requirements for non CP&L
personnel.
The inspectors concluded that the ERT report was thorough
and in-depth. MMM-009, Revision 18 was reviewed and the inspectors
verified that the recommended procedural changes had been incorporated.
The changes included training and testing requirements.
3.
Inadequate Control of Contract Refueling Personnel.
On May 8, 1995, during the performance the initial steps of the insert
shuffle in the Spent Fuel Pit (SFP) in accordance with Fuel Movement
Procedure (FMP)-019, Fuel and Insert Shuffle, 19 steps were initialed as
complete when no thimble plugs had been removed. The refueling crew,
after discovering the problem, verified that no thimble plugs had been
moved. The crew consisted of a qualified contractor refueling, two CP&L
refueling technicians, and a SFP reactor operator (RO).
They
determined that the tool being used was 90 degrees out of align. The
tool was realigned and additional lighting was acquired. The crew
initiated repeating steps commencing with the first step of the shuffle.
The crew failed to notify Management of their problems. CR 95-01132 was
initiated to follow this issue.
The licensee's investigation revealed that the event was caused by
inattention to detail and crew members making assumptions as to actions
by the other crew members. The contractor supervisor failed to verify
the alignment of the thimble plug tool as required by FHP-001, fuel
Handling Tools Operation and which clearly delineates the correct
orientation. The area of the SFP in which they were working was not
well lit and the water was quite turbulent. The SFP RO was able to
verify SFP grid locations but unable to view the assemblies because of
water conditions. The refueling technicians on the refueling bridge had
difficulty viewing the assemblies. The crew discovered their error when
work moved to a better lighted area of the SFP. Crew members assumed
that someone else had notified the control room and/or management. The
event was not discovered until the next day during a review of the logs.
The licensee's corrective actions were to relieve the contractor
supervisor, stand down meetings with the refueling contractor and
29
operations, and provide additional crew members as well as contractor
oversight. In addition, under water TV cameras and improved SFP
lighting were provided. The inspectors reviewed CR 95-01132 and
consider it to address all the issues.
In addition, the licensee initiated Significant CR 95012632 to address
issues relating to procedure adherence and personnel errors committed by
their labor contractor (Becon) which were identified during refueling
outage (RFO)-16 and documented in CRs. The licensee determined that the
personnel provided by the contractor frequently lacked experience in the
nuclear industry and were not adequately trained. The licensee surveyed
the contractor craft and the results of the survey supported their
findings. The licensee concluded that its contract was inadequate and
renegotiated a new contract to address the identified issues. The
inspectors consider that the licensee addressed this issue in sufficient
depth and this item is closed.
III. Engineering
El
Conduct of Engineering
E1.1 Generic Letter (GL) 89-10 Program Implementation
a. Inspection Scope (TI 2515/109)
The licensee's completion of implementation of GL 89-10 "Safety-Related
Motor-Operational Valve Testing and Surveillance" was assessed by the
NRC inspectors.
The licensee had committed to implement GL 89-10 in
letters dated December 27, 1989 and June 6, 1991, and had subsequently
notified the NRC that implementation was complete in a letter dated July
28, 1994. In a letter dated December 28, 1995, the licensee submitted
information to support closure of the NRC review of GL 89-10
implementation for Robinson.
The inspectors conducted the assessment through a review of the
licensee's GL 89-10 implementing documentation and through interviews
with licensee personnel.
The inspectors first reviewed the documents
that prescribed the program and methods used to implement GL 89-10 and
the documents that summarized information from related licensee testing
and evaluations. These documents included the licensee's December 28,
1995 letter (referred to above); Technical Management Manual Procedure
TMM-032, "Motor Operated Valve Program," Rev. 8, dated June 10, 1996;
Standard Procedure EGR-NGGC-0203, "Motor-Operated Valve Performance
Predication, Actuator Settings, and Diagnostic Test Data
Reconciliation," Rev. 0, dated May 31, 1996; and an informal tabulation
of information from the testing performed on all motor operated valves
(MOVs) in the GL 89-10 program. Following review of the preceding
documents, the inspectors performed the following reviews of
computations, tests, and evaluations which the licensee used to
determine and verify the settings and capabilities of their MOVs:
30
The inspectors selected and reviewed calculations and test data
for a sample of rising stem (gate and globe) and butterfly valves.
The sample included valves whose settings were based on all
methods which the licensee used to demonstrate design-basis
capability in accordance with GL 89-10. The valves were as
follows:
AFW-V2-14A Steam Drive Auxiliary Feed Water Pump Discharge Valve
to Steam Generator "A"
Electrical Penetration Sprinkler System Upstream
Isolation Valve
MS-V1-8B
Steam Admission Valve to Steam Drive Auxiliary Feed
Water Turbine
RHR-744A
Residual Heat Removal Loop to Reactor Coolant System
Cold Leg
SI-870A
Boron Injection Tank Outlet Isolation Valve
SI-880D
Containment Spray Pump B Discharge Isolation Valve
V6-16B
Service Water to Turbine Building Isolation Valve
The scope of valves originally in the licensee's GL 89-10 program
had been reviewed previously by the NRC and would be considered
acceptable based on current NRC positions. The inspectors
reviewed the subsequent changes which the licensee had made to the
scope of valves included in the program to assure that any
deletions were adequately justified. The inspectors identified
the changes by comparing the valves in the original program (TMM
032, Rev. 0) with those in the current program (TMM-032, Rev. 8).
The inspectors then verified satisfactory bases for all valves
deleted from the scope of the program. The verifications were
accomplished through a review of justifications for excluding the
valves described in the licensee's "Mechanical Analysis and
Calculations" (e.g., RNP-M/MECH-1401 for valve CC-716) and through
a review of functional information described in the licensee's
design basis document (DBD/R87038) and Updated Final Safety
Analysis Report (UFSAR).
The inspectors reviewed the licensee's documented evaluation of
potential pressure locking in response to GL 95-07. For three
groups of valves potentially susceptible to pressure locking, the
inspectors assessed the actions which the licensee had or was
taking to ensure that pressure locking would not prevent the
valves from performing their design-basis functions. These valves
were:
RC-535 and 536
PORV Block Valves
(3-inch Westinghouse flexible-wedge gate valves)
31
RHR-744A and B
RHR Cold Leg Injection Valves
(10-inch Velan flexible-wedge gate valves)
SI-870A and B
Boron Injection Tank Outlet Isolation Valves
(3-inch Anchor/Darling double-disk gate valves)
b. Observations and Findings
1.
Program Scope Changes
The MOV program currently contained 58 valves. Thirty-two valves had
been removed from the scope of the program previously reviewed by the
NRC. The inspectors found the bases for the removal of these 32 valves
was satisfactory. They had been removed either because they did not
have a safety function or because they were excluded by Supplement 7 to
2.
MOV Sizing and Switch Settings
Robinson's thrust calculations typically utilized standard industry
equations to determine setting requirements for rising stem gate and
globe valves. Mean seat diameter was used to calculate valve seat area.
Valve factors were obtained from in-plant test results or from other
industry sources, as specified by the licensee's methodology. A stem
friction coefficient of 0.20 was typically used for determination of
actuator output thrust capability. The licensee applied a 20% bias
margin that was intended to cover load sensitive behavior. Thrust
requirements were adjusted to account for diagnostic equipment
uncertainty (except as noted in 6 below) and torque switch
repeatability.
3.
Valve Factor (VF) and Grouping
The licensee had not divided their MOVs into groups of similar valves
and used the test data from the dynamically tested MOVs within a group
to establish settings for the non-dynamically tested MOVs. They had
attempted to dynamically test as many MOVs as possible but had not been
able to perform satisfactory dynamic tests on all of the MOVs in their
GL 89-10 program. The settings of gate valves that were not
satisfactorily dynamically tested were generally calculated assuming a
generic VF of 0.50. When justification for their use of this VF
assumption was requested by the inspectors, licensee personnel stated
that it was based on "industry experience."
However, the licensee
indicated they could not provide a documented analysis of applicable
industry test data to support this assumption. The inspectors noted
that utility and industry test programs have found VFs in excess of 0.50
for some valves under certain fluid conditions.
The following are examples of valves for which the licensee did not have
satisfactory dynamic test measurements for VF determination and the
licensee assumed a 0.50 VF without any written justification:
32
Velan 3" Flex-Wedge Gate Valve: CC-735 and FCV-626
Crane 16" Solid-Wedge Gate Valve:
CC-749A and CC-749B
Crane Aloyco 3" Double Disc Gate Valve: CVC-381
Copes Vulcan 14" Double Disc Gate Valve:
RHR-750 and RHR-751
Anchor Darling 14" Double Disc Gate Valve: SI-860A, SI-860B,
S1861A, SI-861B, SI-862A, and SI-862B
Anchor Darling 16" Double Disc Gate Valve: SI-864A and SI-864B
Anchor Darling 3" Double Disc Gate Valve: SI-869
Anchor Darling 6" Double Disc Gate Valve: SI-880A and SI-880C.
The licensee's failure to justify the VF assumptions used in MOV setting
calculations was considered to represent inadequate design control and
is identified-as Example 1.a of Violation 50-261/96-12-05:
Unjustified
Design Assumptions and Incorrect Stem Rejection Load.
Valve factor is used to relate the valve stem force required to overcome
disc/seat friction to the differential pressure pushing the disc against
the valve seat. During review of licensee procedure EGR-NGGC-0203, the
inspectors noted that Section 6.6 (Diagnostic Test Data Reconciliation),
provided the option to use either of two different equations for
calculating open VF from the licensee's stem thrust measurements.
Measured stem thrust includes both the thrust force required to overcome
the disc/seat friction load and the force required to overcome other
loads, such as stem rejection and packing loads. The licensee's
equations for calculating VF provided for separate determination and
removal of the loads not associated with disc/seat friction, one
correctly and the other incorrectly. The first equation which EGR-NGGC
0203 specified for determining VF subtracted out the packing load
obtained in static testing and added the stem rejection load calculated
based on line pressure and stem area. This equation resulted in correct
open VF determinations. It was the only equation contained in the older
dynamic test evaluations that were evaluated by the inspectors. In the
second equation stem rejection and packing loads were accounted for by
simply subtracting out the running load measured during the opening
dynamic test (when the valve is unseated and partially open) from the
initial opening thrust required to overcome dynamic effects. This
equation was incorrect, because it did not properly account for the stem
rejection being greater at the beginning of an open stroke (when the
line pressure forcing the stem out is higher) than when the running load
was measured. Help due to stem rejection is less during the running
portion of the open stroke in a dynamic test (where the second equation
measures running loads) because the pressure pushing against the stem is
lower than when the valve initially starts to open. Therefore, the
equation did not properly account for the helping force provided by stem
rejection at the point of the open stroke where the VF was measured.
33
This resulted in a nonconservative prediction of open VF. The
inspectors noted during review of dynamic test evaluation packages for
MS-V1-8B, AFW-V2-14A, FP-248, and SI-880D, that the opening VF had been
calculated incorrectly, as the running load was used without any
correction for the reduced pressure at the point where running load was
measured. The inspectors noted that the effect of this error would
typically be small and that the existing practice could be corrected by
adding an additional term to account for the difference in stem
rejection between the start of the open stroke and the running portion
of the open stroke. The licensee's incorrect calculation of opening VFs
was considered to represent inadequate design control and is identified
as Example 2 of Violation 50-261/96-12-05: Unjustified Design
Assumptions and Incorrect Stem Rejection Load.
During the review of the close dynamic test for AFW-V2-14A (Steam Drive
Auxiliary Feed Water Pump Discharge Valve to Steam Generator "A"), the
inspectors noted that licensee personnel selected an apparently
nonconservative point on the close force trace to represent the force
needed to achieve flow isolation (VOTES mark C10).
This is the force
point that would be used to calculate an apparent VF. Valve AFW-V2-14A
is a 4" Anchor Darling double disc gate valve which uses an internal
wedging action to seal off flow. The inspectors noted that the selected
point might be nonconservative because the force trace continued to
increase significantly prior to reaching hard seat contact (VOTES mark
C11). The inspectors also noted that the licensee had not used any
other diagnostic sensor (e.g., accelerometer) to confirm their choice
for flow isolation. Robinson personnel indicated that this valve did
not have a leakage criteria requirement and that total flow isolation
was not necessary. The inspectors considered the licensee's argument to
be adequate for the purpose of an operability assessment.
4.
Load Sensitive Behavior
In determining settings for rising-stem MOVs that were dynamically
tested, the licensee used the measured load sensitive behavior values.
The licensee's MOV switch setting methodology specified a margin of 20%
to account for the effects of load sensitive behavior for MOVs that were
not dynamically tested. When the justification for this margin was
requested by the inspectors, licensee personnel stated that it was based
on testing performed at the Brunswick plant. However, no justification
was provided to show that the Brunswick data was applicable to Robinson.
Given the sensitivity of load sensitive behavior to differences in 1)
load profiles during a valve stroke under dynamic conditions, 2)
potential differences in thread surface conditions, 3) types of stem
lubricants used, and 4) methods and frequency of lubricant application,
the inspectors did not consider the use of results from a different
facility to be adequate when load sensitive behavior data was available
from the testing performed on Robinson's MOVs. Licensee personnel
offered no explanation for not analyzing the load sensitive behavior
performance at Robinson. Supplement 6 to GL 89-10 indicated that, for
valves that could not be satisfactorily dynamically tested, the use of
34
plant-specific data (i.
e., Robinson data) was considered more reliable
than use of data from other plants.
Licensee personnel performed an initial review of the available load
sensitive behavior data obtained from their dynamic test program and
determined an average load sensitive behavior value of approximately
12%. However, using an average value was not acceptable due to the high
probability that a 12% margin would be nonconservative for many MOVs in
Robinson's generic letter program. The inspectors performed an
independent evaluation of Robinson's load sensitive behavior data and
determined that a mean plus 2 standard deviations of the available data
was equal to approximately 27%. This indicated that Robinson's 20%
margin might be nonconservative. The licensee's failure to justify the
load sensitive behavior assumed in their setting calculations was
considered to represent inadequate design control and is identified as
Example 1.b of Violation 50-261/96-12-05: Unjustified Design
Assumptions and Incorrect Stem Rejection Load.
5.
Stem Friction Coefficient
The licensee's thrust calculations typically assumed the use of a 0.20
stem friction coefficient (SFC) in the open direction and 0.15 for the
close direction. The licensee had statically measured the SFCs of their
valves at torque switch trip and, when a measured value exceeded the
assumed value, the measured value was used. The licensee had not
monitored SFC performance during dynamic tests and had no analysis to
justify the adequacy of the values which they had assumed in their
calculations of design-basis capabilities.
The inspectors noted that
this was inadequate, as industry testing has shown that stem friction
coefficients measured under design-basis conditions are typically higher
than values measured at torque switch trip during a static test. This
is of particular concern for the open direction because the licensee did
not include any margin for load sensitive behavior in the open
direction. The licensee's failure to justify the SFC assumed in their
setting calculations was considered to represent inadequate design
control and is identified as Example 1.c of Violation 50-261/96-12-05:
Unjustified Design Assumptions and Incorrect Stem Rejection Load.
6.
Design-Basis Capability
The inspectors found that the dynamic force traces for valves MS-V1-8B,
SI-870A, and FP-248, were similar in response characteristics to those
obtained for these valves under static (no flow) test conditions. This
indicated that the tests might not have achieved the intended
differential pressures and flows. This was not recognized in the
licensee calculations which evaluated the results of the tests. The
inspectors reviewed the test conditions described in the licensee's
completed test procedures for these valves and found further indications
that the intended differential pressures and flows had not been
achieved. Their findings for each valve were as follows:
35
MS-V1-8B: This is the steam admission valve to the steam driven
auxiliary feedwater pump turbine. The licensee's test lineup for
this valve provided both upstream and downstream pressure
instrumentation. However, the downstream pressure was obtained by
recording the data manually from a pressure instrument and could
not be correlated precisely with valve position. There was no
instrument available to measure steam flow. The auxiliary
feedwater pump was aligned for recirculation back to the
condensate storage tank and was not pumping water into the steam
generators (as would happen under accident scenarios). This
recirculation lineup would be expected to provide only about 10%
of the volumetric flow rate that would be achieved when
discharging to the steam generators. Therefore, the steam flow
through the turbine and through MS-V1-8B would be small, as
compared to design-basis conditions. The actual differential
pressure at the time of valve closure may have been much less than
recorded, due to the turbine's condenser vacuum quickly drawing
the downstream piping pressure so that the pressure instrument
indicated zero psi when test personnel recorded the test
differential pressure data.
SI-870A This is the boron injection tank outlet isolation valve.
The inspectors' review of the system piping diagram and the
completed dynamic test procedure found that a downstream valve was
positioned to throttle flow to approximately 300 gpm during the
test. This throttle valve was located between SI-870A and the
downstream pressure gauge. Therefore, the recorded downstream
pressure did not reflect the true pressure at SI-870A at the point
of flow isolation. (The licensee's evaluation for this valve was
documented in Calculation RNP-M/MECH-1473, Rev. 0)
FP-248 This is the electrical penetration sprinkler system
upstream isolation valve. The dynamic test lineup for this valve
involved discharging into a temporary fire hose connected to a
flush station. Flow was controlled by downstream manual valve FP
294. Step 7.2.14 of Special Procedure SP-1042, "Fire Protection
System MOV Full Differential Pressure Stroke Test," cracked open
FP-294 to initiate flow in the system. No measurement of system
flow conditions were recorded during the test. Given the effect
on flow rate that a downstream throttle valve which is cracked
open would have, the inspectors believed this to be the cause of
the dynamic force trace appearing similar to a static force trace.
Flow through this valve would be much higher when the system is
performing its safety function to supply the containment
electrical penetration sprinkler system. Therefore, this was not
considered to be a near design-basis test and the intended test
conditions were apparently not achieved.
Based on the above, the inspectors found that the licensee's evaluations
of the results of the subject MOV tests were inadequate, as they failed
to recognize that the dynamic test results were not consistent with the
perceived test conditions. Further, the original test procedures did
36
not assure that the intended design-basis test conditions were achieved
during the tests. This was considered indicative of inadequate test
control and is identified as Example 1 of Violation 50-261/96-12-06:
Inadequate Evaluation of Test Results.
During the review of Robinson's diagnostic test evaluations, the
inspectors noted that the licensee had not made adjustments to open
thrust measurements to account for the measurement uncertainty
identified by the licensee's VOTES diagnostic equipment vendor, Liberty
Technologies, in Customer Service Bulletin 31 (issued November 19,
1993). At Robinson, open thrust requirements were compared to the
actuator's capability under degraded voltage conditions without
considering this diagnostic equipment uncertainty associated with open
VOTES measurements. This uncertainty applies when tension measurements
are significantly outside the test sensor's calibration range. The
licensee's failure to consider this uncertainty in evaluating their test
results was considered a further example of the inadequate test control
referred to in the previous paragraph and identified as Example 2 of
Violation 50-261/96-12-06:
Inadequate Evaluation of Test Results.
During the review of the dynamic test package for MS-V1-8B, the
inspectors noted that the open force trace for the dynamic test
performed on November 13, 1993, exhibited a large sustained increase of
approximately 10,000 lbf, starting approximately 3 seconds into the open
stroke, and continuing throughout the remaining open stroke. Section 7
of Calculation No. RNP-M/MECH-1406, "Evaluation of Differential Pressure
Test Data of MS-V1-8B, Steam Admission Valve to SDAFW Turbine," did note
the anomaly but did not resolve the issue. Licensee personnel stated
that no condition report was initiated to resolve this anomaly or to
correct any potential problems related to the VOTES sensor location.
The licensee's failure to evaluate the significance of this anomaly was
considered indicative of inadequate test control.
This was identified
as Example 3 of Violation 50-261/96-12-06:
Inadequate Evaluation of
Test Results.
7.
Pressure Locking
For the three groups of valves reviewed by the inspectors, the licensee
used calculations to demonstrate that the valves could overcome pressure
locking and perform their design functions. A double-disk area formula
was used in predicting the thrust required to overcome pressure locking
and GL 89-10 program calculations were used to predict the thrust
available from the motor actuators. The inspectors found that the
licensee had not validated its calculation method for predicting the
- thrust required to overcome pressure locking as part of its long-term
actions in response to GL 95-07. Further, the licensee relied on
pressure measurement in the injection line between the check valves and
RHR-744A/B to demonstrate that check valve leakage was currently low,
resulting in an MOV bonnet pressure much lower than reactor coolant
system pressure. However, the licensee did not justify that the valve
bonnet pressure for RHR-744A/B would remain low over time.
37
Although referencing its general thrust prediction equation, the
licensee had not documented the specific calculations for predicting the
thrust required to overcome pressure locking for its valves. The
inspectors performed independent calculations and did not identify any
immediate concerns regarding operability of SI-870A/B, RC-535/536 and
RHR-744A/B. However, the licensee had not adequately justified its
analytical method to predict the capability of MOVs to overcome pressure
locking as a long-term response consistent with the recommendations of
GL 95-07. In response to this issue, in its letter dated February 13,
1996, the licensee committed to modify SI-870A/B to prevent pressure
locking during refueling outage RO-18 in 1998. At the time of the
inspection, the licensee was relying on the actuator capability of RC
535/536 and RHR-744 A/B to overcome pressure locking and did not have
any plans to modify these valves. However, the licensee stated that
they would address concerns regarding the long term capabilities of
RC-535/536 and RHR-744 A/B as part of a response to an NRC request,
dated July 3, 1996, for additional information. The licensee plans to
submit this response by November 22, 1996. The NRC staff is continuing
its evaluation of these MOVs and others within the scope of GL 95-07 as
part of its review of the licensee's response to potential pressure
locking and thermal binding.
The adequacy of the licensee's long term actions to preclude pressure
locking of the above valves was identified as IFI 50-261/96-12-07:
Actions to Preclude Pressure Locking.
8.
Butterfly Valves
The licensee had only three butterfly valves in its GL 89-10 program.
These were identical 16-inch Allis-Chalmers butterfly valves. The
safety function of each was to close and closure was controlled by
torque switch settings with the valves torquing closed into stopnuts.
The valves normally operated at a differential pressure exceeding that
experienced in a design-basis accident, demonstrating the adequacy of
the licensee's torque settings. However, the inspectors observed that
torque closure of these valves into the actuator stopnuts was contrary
to the recommendations of the actuator vendor and they considered this a
weakness. The inspectors reviewed the licensee's maintenance history (6
years) for one of the valves and the results of a recent inspection of
such valves for evidence of damage from torque seating. There was no
evidence that the torque seating had resulted in damage. The inspectors
did not consider the licensee to have sufficiently justified its long
term reliance on torque closure of butterfly valves into their stopnuts.
The NRC will review this issue further during a future inspection of
Robinson's implementation of GL 89-10.
c. Conclusions
The licensee had not satisfactorily implemented GL 89-10. Important
assumptions used in setting and capability calculations had not been
justified and calculations used in determining valve opening setting
requirements contained errors. These were indicative of inadequate
38
design control and were cited as Violation 50-261/96-12-05, Unjustified
Design Assumptions and Incorrect Stem Rejection Load. Further, the
licensee's test data had not been adequately evaluated, as valve opening
thrust measurement error had not been adequately assessed, the licensee
failed to recognize that test conditions were not as intended, and
anomalous data was not resolved. These were indicative of inadequate
test control and were identified as Violation 50-261/96-12-06,
Inadequate Evaluation of Test Results.
E7
Quality Assurance in Engineering Activities
E7.1 Special UFSAR Review
A recent discovery of a licensee operating their facility in a manner
contrary to the Updated Final Safety Analysis Report (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 inspection discussed in this report, the inspectors
reviewed selected portions of the UFSAR that related to the areas
inspected. The inspectors verified that for the select portions of the
UFSAR reviewed, the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters.
E8
Miscellaneous Engineering Issues (37551 and 92903)
E8.1
(Closed) LER 50-261/93-20-00, Technical Specification Violation Due to
Exceeding F-Delta-H Hot Channel Factor:
On December 3, 1993, the
licensee determined that while operating at 30% reactor power prior to
November 17, 1993, the Technical Specification hot channel factor F
Delta-H limit was exceeded. The reason for exceeding the thermal limit
was determined to be the result of six misloaded fuel assemblies placed
in the core during the previous reload. The corrective actions included
in the LER were similar as those included in the licensee's response to
Violation 50-261/93-34-02: QA Failure. The inspectors reviewed the
licensee's corrective actions associated with this violation previously
in NRC Inspection Report 50-261/95-21. This LER was closed based on
previous review of the violation and associated corrective actions.
E8.2
(Closed) IFI 50-261/94-06-05, Adequacy of Periodic Verification Methods:
Recently the NRC has issued GL 96-05 on periodic verification of design
basis capability of safety-related motor-operated valves. Further NRC
assessment of the licensee's periodic verification will be addressed in
regard to this generic letter.
E8.3 (Closed) IFI 50-261/94-06-07, Mispositioning: This issue dealt with a
GL 89-10 recommendation to ensure that valves could return to their
safety positions, if inadvertently mispositioned. Supplement 7 to GL 89-10 removed this recommendation.
E8.4 (Closed) VIO 50-261/94-27-07, Failure to Adequately Control
Calorimetric: This violation of 10 CFR 50, Appendix B, Criterion II,
Quality Assurance Program, involved inadequate controls associated with
39
the licensee's power range calorimetric program. Deficiencies
identified included use of uncalibrated instrumentation, failure to
control the plant condition prerequisites under which the program
results were valid, failure to specify a timing for acquiring manually
input data, lack of verification of automatically input data, and
inconsistent controls on the instruments used in the program. These
problems did not result in exceeding any licensed thermal power level.
The licensee responded to this violation by letter dated January 30,
1995. The licensee determined that lack of proper management oversight
for control of the calorimetric program was the cause of this violation.
Corrective actions included verifying that all inputs to the program
were using calibrated instrumentation. Some instrumentation had to be
replaced with new calibrated equipment. The licensee revised
maintenance procedures to require a review of the impact of
instrumentation used in the program that are found out of calibration.
This change was documented in Revision 13 of Maintenance Management
Manual (MMM) procedure MMM-002, Maintenance Procedure Preparation. In
addition, the inspectors noted that MMM-006, Calibration Program,
Revision 17, also contained formal provisions ensuring that the impact
of out-of-tolerance instruments are evaluated by a Technical Reviewer
with assistance from the system engineer. Corrective actions to address
control of plant conditions during performance of the calorimetric were
accomplished by a revision of OST-010, Power Range Calorimetric During
Power Operation Daily. The inspectors reviewed Revision 22 of OST-010
and determined that adequate controls were implemented to ensure that
stable plant conditions are required during performance of the
calorimetric. The inspectors concluded that the licensee's corrective
actions had been adequately implemented.
E8.5 Degraded ECCS Sump Screen Design Issues
On September 11, after having shutdown for RFO-17, engineering walkdowns
of the containment ECCS sump identified openings that were in excess of
the sump screen mesh size of 7/32 inch. An assessment of the impact of
the openings was initiated. On September 30, after identifying actual
debris in the sump piping that was greater than the screen mesh size,
the licensee concluded that the ECCS sump screens were not consistent
with their design. The openings could have allowed debris greater than
the sump screen design to enter the sump and related ECCS recirculation
flowpath. Debris larger than 3/8 inch could have resulted in potential
clogging of the Containment Spray (CS) System nozzles. An LER
describing the impact of the degraded sump condition was issued on
October 30. During RFO-17, the licensee performed repairs to the sump
screens to ensure that there were no openings greater than screen design
requirements. The inspectors inspected the sump repairs and determined
that the licensee had adequately completed these repairs and returned
the screens to an acceptable condition. The licensee planned to replace
the screens in their entirety during the next refueling outage.
The licensee determined from a "qualitative" assessment of the affects
of the degraded screen condition that the likelihood of adverse impact
40
on the operation of ECCS equipment was small.
Part of the information
used to support this position was a statement in the original FSAR that
"one-fifth of CS nozzles in one train of the CS system, complete outage
of the other train, and disability of all four containment fan coolers
could be tolerated at the time of recirculation without losing the
ability to transfer residual heat from the containment atmosphere."
This statement was no longer in the current UFSAR. The inspectors
requested that the licensee provide additional information to support
this and other qualitative conclusions. The inspectors concluded that
further review of this information was necessary in order to evaluate
the full impact of the degraded ECCS sump condition on the operation of
the ECCS equipment. This was identified as URI 50-261/96-12-08:
Resolution of ECCS Sump Design Issues.
The licensee determined that the cause of the degraded screen condition
was the lack of adequate control over previous alterations to the sump.
Alterations were previously made to accommodate pipe restraints and
piping that was routed through the screens, as well as the result of
general screen repairs that had been made as a result of identified
discrepancies. While procedures existed to inspect the condition of the
sump, sensitivity to the size of openings had not been previously
recognized.
During review of this issue, the licensee became aware of another design
problem with the ECCS sumps that had previously been identified and
evaluated in 1988. This previous design problem involved identification
that the original calculated containment vessel flood level of 3.2 feet
above the containment floor elevation was in error. New calculations
determined the actual level to be 6.2 feet above the floor elevation.
The licensee's previous evaluation of the impact from this difference
was mainly related to the Environmental Qualification of equipment not
previously known to be in the flood zone. The evaluation was performed
under Engineering Evaluation No.88-132. However, this previous
evaluation failed to consider the impact of the higher flood level on
the operation of the ECCS sump screens during sump long term
recirculation conditions. In particular, UFSAR Section 6.3.2.2.2,
Recirculation Phase, states as one of the screen filtration functions,
that the sump baffle wall excludes floating debris from entering the RHR
suction. However, as a result of the higher flood level, the top of
this baffle wall would be below the water level allowing debris which
reached the baffle to float into the sump.
The licensee conducted an evaluation of the impact of the higher flood
level on the design of the ECCS sump filtration function. The results
of this evaluation concluded that the ECCS sump would continue to
perform its design function with the flood level above the height of the
baffle wall.
This was based on the determination that no additional
floating debris would be deposited on the screens as long as the upper
portion of the screen was above the flood water level.
At the end of
the report period, the inspectors were continuing to review the impact
of the higher flood level on the ECCS sump screen design. This issue
41
was identified as part of URI 50-261/96-12-08: Resolution of ECCS Sump
Design Issues.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1 Radiological Controls
a. Inspection Scope (83750)
The inspectors evaluated the adequacy of licensee radiological controls
with emphasis on external occupational exposure controls during outage
operations. Areas inspected included locked high and very high
radiation area controls, radiation area postings, radiation work permit
controls, and labeling of rad material.
The inspectors made frequent
tours of the radiologically controlled area (RCA), observed compliance
of licensee personnel with radiation protection procedures for high dose
outage work evolutions, and conducted interviews with licensee personnel
with respect to knowledge of radiological controls and working
conditions.
b. Observations and Findings
The inspectors verified observed controls for external and internal
exposures met applicable regulatory requirements and were designed to
maintain exposures ALARA. The inspectors reviewed several Radiation
Work Permits (RWPs) utilized to control ongoing outage work within the
RCA, including high dose activities within containment, and noted that
the controls observed were appropriate for the described tasks and
radiological conditions.
During plant walkdowns within the RCA, the inspectors conducted
interviews at random with radiation workers inside containment. The
interviews were conducted with workers of various disciplines in order
to determine the level of understanding of RWP requirements from a
representative cross-section of plant workers. The workers interviewed
were verified to have signed onto an RWP, were wearing electronic
dosimetry appropriate to their work activities within the RCA in
accordance with plant procedures, and were performing specific work
activities on several different RWPs. The workers interviewed signified
that they had in fact read and understood the conditions and
requirements of the RWP being logged in on in accordance with
procedures. The questions asked included the RWP number of the RWP
signed in on, electronic dosimetry dose limits, and general radiological
working conditions for the areas worked in. For the workers
interviewed, a good knowledge of RWP requirements and a good knowledge
of radiological working conditions, generally, was demonstrated.
The inspectors reviewed total whole body exposures for all plant
radiation workers and determined that all whole body exposures assigned
since the beginning of the SALP cycle (6/18/95) through the end of this
42
inspection were within 10 CFR Part 20 limits. A review of licensee
personnel exposure records indicated the following maximum individual
exposures at the plant during this period: Total Effective Dose
Equivalent (TEDE): 1390 mrem; Committed Effective Dose Equivalent
(CEDE): 32 mrem; and Shallow Dose Equivalent (SDE) whole body: 3633
mrem. A 54 mrem CEDE internal dose occurred on 5/13/95 which was prior
to the current SALP cycle. The inspectors determined the licensee had
adequately monitored and tracked individual occupational radiation
exposures in accordance with 10 CFR Part 20 requirements and that all
doses reported were at a small percentage of applicable regulatory
limits.
The inspectors reviewed and discussed with licensee representatives the
program for controlling access to high radiation areas (HRAs), locked
high radiation areas (LHRAs), and very high radiation areas (VHRAs).
These areas were inspected during tours for proper posting and access
controls.
No HRAs, LHRAs, or VHRAs were identified where required
postings were needed but not posted. Areas controlled as LHRAs were
inspected and found locked in accordance with licensee procedures. The
licensee had completed a posting upgrade with respect to radiation areas
to achieve full conformance with the regulatory intent of 10 CFR
20.1902. The inspectors noted significantly upgraded and improved
posting practices throughout the plant.
Key controls for entry into locked and very high radiation areas were
evaluated against the requirements of the licensee's administrative
control procedure and determined to be controlled in accordance with the
procedure. During a tour of the Spent Fuel Pool the inspectors observed
no items hanging from the side of the pool and good radiological
controls in place in this area overall. A large sample of survey
instruments and respirators available for issuance were inspected
and all determined to have current calibration dates. Radiation workers
during peak traffic periods were observed exiting the RCA fully in
accordance with procedures for frisking out of the RCA to include
properly clearing small articles with the small articles monitor.
Pre-job RWP work planning and ALARA briefings for observed ongoing
outage work evolutions inside containment, including the tasks of
reactor head stud tensioning and decon of a transfer canal hot spot,
were found to be conducted in an indepth, effective manner. During
tours of the plant, the inspectors observed Health Physics (HP)
technicians performing radiation and contamination surveys in accordance
with procedures. Also, during inspection of the tool issuance rooms,
good controls for slightly contaminated tools inside the RCA, and for
clean tools outside the RCA, were noted.
On October 8, 1996, the inspectors observed a worker exiting the RCA
whose electronic dosimeter (ED) was in the pause mode. Upon further
review it was determined that the ED had not been turned on at the time
the worker had entered the RCA. A check of the Radiation Information
Monitoring System (RIMS) disclosed that the worker was not logged in on
an RWP, nor was the worker wearing a TLD. A reconstruction of the
worker's activities while in the RCA for a relatively short period
43
indicated the likelihood of the worker having received significant dose
was minimal and the overall safety significance of the incident was low
from this standpoint. However, contrary to the external whole body
monitoring requirements of licensee procedure NGGM-PM-0002, Radiation
Control and Protection Manual, Revision 26, Paragraph 6.13.1, dated
August 30, 1996, all individuals who enter the primary Radiation Control
Area shall be monitored for external whole body radiation exposure using
an appropriate individual monitoring device. Although most workers
entering the plant RCA are not likely to receive an occupational dose
exceeding ten percent of annual regulatory limits, the licensee has
chosen to require monitoring on a more conservative basis by procedure.
This non-compliance with licensee procedures was not isolated in that on
September 29, 1996, another radiation worker entered the RCA and was
inside a high radiation area briefly without electronic dosimetry as
required by RWP. Significant condition reports were issued for both
incidents which required root cause analysis and commitment to
corrective actions although the corrective actions were not complete at
the conclusion of the inspection.
The incident on October 8, 1996, as documented in Condition Report 96
02636, is a violation of paragraph 6.13.1, External Whole Body
Monitoring, of licensee procedure NGGM-PM-0002, Radiation Control and
Protection Manual. This 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. This issue was documented as NCV
50-261/96-12-09: Failure to Comply with Radiation Monitoring Procedure.
c. Conclusions
The radiological controls program was being effectively implemented and
good occupational exposure controls during outage conditions was
demonstrated. Good radiological control performance was apparent in the
occupational exposure activities observed by the inspectors. An upgrade
in radiation area posting throughout the facility was evident.
Continued emphasis on procedural adherence to radiation control
procedures remains a challenge. One NCV was identified for failure of a
radiation worker to wear an appropriate monitoring device within the RCA
as required by procedure.
R1.2 Contamination Controls
a. Inspection Scope (83750)
The inspectors evaluated the licensee's increasing numbers of personnel
contamination events (PCEs) and the adequacy of corrective actions and
related followup. Also evaluated was the adequacy of contamination
surveys required to evaluate the extent of the radiation hazard to
workers and the adequacy of contaminated area controls.
44
b. Observations and Findings
During the ongoing outage through October 10, 1996, the site had
incurred 146 PCEs which substantially exceeded the initial outage goal,
of 100. The licensee has also exceeded the annual PCE goal of 130 with
172 incurred through the same period. Although the number of PCEs
incurred is not a significant radiological safety concern considered
alone, high numbers of PCEs do reflect on the quality and effectiveness
of an organization's contamination control program as well as the
adherence of radiation workers to fundamental contamination control
practices. Furthermore, those PCEs which stem from hot or discrete
particles are the most likely to cause a significant skin exposure which
may challenge regulatory limits. The licensee applies a rigorous PCE
definition (100 ccpm) but the numbers of PCEs being experienced are high
for a single unit PWR. During the current outage, the licensee
experienced high numbers early in the outage (i.e., between September
11-14) with another spike toward the end (October 7-9). Of particular
concern to the inspectors was that over half of the PCEs were
attributable to discrete particle activity and several PCEs (>10
percent) were found in "clean" areas. In order to independently
determine the effectiveness of the licensee's contamination control
program, the inspectors, with RC Technician support, selected
approximately 70 swipe locations in likely locations within the RCA for
smearable contamination. Although all smears were within licensee
limits, and most were negligible, two approached the licensee's dpm
limit. The inspectors also selectively reviewed the higher assigned
dose PCE reports and noted no assessment or procedural errors. Where a
skin dose assessment was required by licensee procedure based on the
level of skin activity in corrected counts per minute, the inspectors
were able to verify the assessment had been performed as per procedure
with conservative dose assessment methodology utilized.
The licensee, in response to the high number of PCEs being experienced,
initiated a significant condition report evaluation which will require a
root cause and corrective action plan for the negative PCE trend. The
licensee will evaluate the effectiveness of the laundry vendor in
decontaminating protective clothing, the limited vacuuming time (partly
on outage critical path) used during the outage which may have
contributed to higher contamination conditions at the start of the
outage, effect of heat stress concerns, close contact in undress areas,
reduced use of double sets of protective clothing this outage, worker
practices, and effectiveness of worker training programs.
c. Conclusions
The licensee continues to experience a high level of personnel
contamination events which represent a continuing challenge in the
licensee's radiological control program although no deficiencies were
identified with respect to adequacy of followup on individual personnel
contaminations or controls for contaminated areas. Although PCEs remain
relatively high and a challenge area in radiological controls overall,
licensee actions with respect to improving personnel contamination
45
controls were determined to be appropriate with no regulatory concerns
noted.
R8 Miscellaneous Radiation Protection and Chemistry Issues
R8.1 ALARA Program Effectiveness
a. Inspection Scope (83750)
Part 20 to the Code of Federal Regulations requires that licensees use,
to the extent practicable, procedures and engineering controls based
upon sound radiation protection principles to achieve occupational doses
and doses to members of the public that are as low as reasonably
achievable. The ALARA area was evaluated to determine whether the
licensee was establishing and tracking performance against ALARA goals,
whether continuing ALARA initiatives are ongoing to reduce dose, and to
evaluate the overall effectiveness of the ALARA program.
b. Observations and Findings
Through October 8, 1996, the licensee projected a total site dose goal
of 187 person rem but actually achieved a reduced 129 person rem
(approximately 30 percent less than goal). The licensee is now on track
to achieve less than their annual dose goal of 211 rem based on good
dose performance during the refueling outage (which represents 75
percent of annual planned dose) and due to very low dose accrual during
power operations the first nine months of 1996. The inspectors observed
pre-job ALARA briefings and evaluated ALARA pre-work packages for select
high dose outage activities. During the pre-job ALARA briefings, the
inspectors noted thorough and detailed pre-job planning for specific
high dose activities and observed good task analysis as well as a
questioning attitude as to potential dose saving opportunities for the
planned activities. The inspectors reviewed with the licensee current
and planned ALARA initiatives. During 1996, the licensee has undertaken
several dose reduction initiatives including an expanded use of video
monitoring technology, expanded application of long term shielding,
additional advanced radiation worker training, additional ALARA training
for engineering personnel, evaluation of preventative maintenance
frequencies for possible reduction, and evaluation of chemical
decontamination for the RHR system. The licensee has established an
aggressive exposure goal for 1996 which, if achieved, will represent a
very low exposure at the site for a refueling outage year and approach
the favorable dose performance of 1991 (193 rem).
The licensee did not
undertake a full system chemical decon during the outage but did realize
good curie removal results from a primary system hydrogen peroxide wash.
The licensee indicated an intent to evaluate the feasibility of
conducting a full system chemical decon as an ALARA initiative during
future outages. Overall, the inspectors determined that collective dose
is being effectively controlled and reduced.
46
c. Conclusions
Overall, based on an evaluation of ALARA initiatives and ALARA work
plans for high dose work evolutions, the inspectors concluded that the
licensee's ALARA program was effectively controlling collective site
dose and that the total site dose was on a favorable reducing trend.
S8
Miscellaneous Security Issues (92904)
S8.1 (Closed) VIO 50-261/95-12-05, Failure To Control Safeguards Information:
On April 5, 1995, the inspectors observed unsecured Safeguards
information (SGI) stored on a bookshelf in the shift supervisor's
office, which was adjacent to the active control room. The shift
supervisor's office was often unoccupied which resulted in Safeguards
information not being under the control of an authorized individual.
The inspector notified the site Security manager who had the SGI moved
to the control room. CR 95-00900 was written to address the issue.
Control room modifications were in progress at the time of the event and
the licensee had moved the SGI to the shift supervisor's office for
better control. The licensee's corrective action included placing
control of SGI under the Security organization and relocating the
control room SGI to the Secondary Access Station (SAS). The SGI program
was reviewed by the licensee and improvements were initiated where
required. The inspectors reviewed CR 95-00900 and found it to be
adequate. No other control of SGI in the control room issues have been
identified and this item is closed. However, other control of SGI
issues have been subsequently identified and are documented in
Inspection Reports 50-261/96-02 and 50-261/96-03. Escalated Enforcement
Item (EEI) 50-261/96-03-02 was issued for control of SGI violations.
F1
Control of Fire Protection Activities
F1.1 Observation of Plant Areas
a. Inspections Scope (64704)
A general plant walkdown inspection was performed by the inspectors to
verify: acceptable housekeeping; compliance with the plant's fire
prevention procedures such as "Hot Work" permits and transient
combustibles; operability of the fire detection and suppression systems;
emergency lighting; and, installation and operability of fire barriers,
fire stop and penetration seals (fire doors, dampers, electrical
penetration seals, etc.).
b. Observations and Findings
Within the areas observed, the inspectors determined that the general
housekeeping was satisfactory, considering that the unit had just
restarted from a refueling outage and maintenance and repair activities
had been ongoing. During maintenance activities the inspectors observed
that fire protection equipment was readily accessible. The majority of
47
the wood used during plant activities was treated to make it fire
retardant. Fire retardant plastic sheeting and film materials were also
being used. Lubricants and oils were properly stored in approved safety
containers.
No discrepancies were noted with the fire pumps, outside fire hose
houses, fire main valves or headers. Carbon dioxide (CO
2) storage
cylinders were at the proper fill pressures and fire extinguishers had
been inspected and had a current inspection date. Controls were being
maintained for transient combustibles and areas containing potential
lubrication oil and diesel fuel leaks, such as the diesel generator
rooms, were being controlled.
c. Conclusions
Good compliance with plant fire prevention procedures was observed. The
general housekeeping and control of combustibles was satisfactory. The
control of combustible and flammable materials was effective.
F1.2 Fire Reports
a. Inspection Scope (64704)
The inspectors reviewed the plant fire incident reports for 1996 in
order to assess maintenance related or material condition problems with
plant systems and equipment that initiated fire events. The inspectors
verified that plant fire protection requirements were met in accordance
with Fire Protection Procedure FP-002, Fire Report, Revision 5, when
fire related events occurred.
b. Observations and Findings
The fire incident reports indicated that there were eight incidents of
fires in 1996, of which three required fire brigade response. There had
been only one minor fire event involving cutting or welding activities
associated with the refueling outage, and the remainder were minor fires
involving electrical failures. Only two of the eight fires had occurred
within the plant protected area.
c.
Conclusions
Good compliance with plant fire prevention procedures has resulted in a
low incident of fire within the plant protected area.
F2
Status of Fire Protection Facilities and Equipment
F2.1 General Comments
a. Inspection Scope (64704)
The inspectors reviewed fire protection Equipment Inoperable Records
(EIRs) from January 1996 to the present to assess maintenance-related or
48
material condition problems with fire protection systems and equipment.
The inspectors verified that plant fire protection requirements were met
in accordance with OMM-007, Equipment Inoperable Record, Revision 36,
when the equipment was declared out of service. Fire protection water
supply systems, the dedicated safe-shutdown system, and plant fire
barriers were inspected to determine the material conditions of the
plant's fire protection systems, equipment and features.
b. Observations and Findings
The EIRs indicated that the number of fire protection impairments for
repairs recorded for the ten month period was relatively small and
adequately monitored to limit their duration. The inspectors determined
that most of the plant repair impairments involved problems with fire
doors, however, in all cases, the repair impairments had been restored
to service within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. A small backlog of open work orders
remained for scheduled completion.
The inspectors toured the following plant fire zones/areas and inspected
the fire protection features to determine if the systems were operable
and properly maintained:
Unit 2 electric and diesel driven fire pumps (Fire Zone 29),
Pyrocrete fire barrier walls for Charging Pump Room (Fire Zone 4),
Appendix R eight-hour emergency light units for the dedicated
safe-shutdown system (Fire Zone 25),
Sprinklers for Auxiliary Building Hallway (Fire Zone 7), and,
1-Hour Fire Wrap for Component Cooling Water Pumps (Fire Zone 5).
The inspectors noted that all of the fire protection systems inspected
were operational and appeared to be well maintained, however, minor
configuration discrepancies were noted with the pyrocrete fire barriers
walls. The barrier contained several exposed bolts and a cable junction
box connected to the barrier but not coated with fire resistant
material. The licensee was unable to locate Generic Letter 86-10
engineering evaluation documentation in the Fire Hazards Analysis (FHA)
nor the Safe Shutdown Analysis (SSA) that justify these deviations from
tested fire barrier configuration. The inspectors determined that no
operability concern existed based on review of available fire test
results of the pyrocrete fire barrier material. The licensee indicated
that this item would be reevaluated under corrective actions to CR 96
00733. This CR identified similar licensee identified issues where the
FHA/SSA did not accurately reflect the current plant configuration.
This issue was considered a fire barrier configuration weakness.
49
c. Conclusions
When fire protection systems are found degraded or inoperable, a high
priority is assigned to promptly return these systems to service. The
number of fire protection impairments for repairs recorded for the last
ten month period was relatively small and adequately monitored to limit
their duration. With one exception noted above, all of the fire
protection features inspected were operational and appeared to be well
maintained. Most of the plant repair impairments involved problems with
fire doors, however, in all cases the repair impairments had been
restored to service in a timely manner.
F3
Fire Protection Procedures and Documentation
F3.1 General Comments
a. Inspection Scope (64704)
The following Plant Operating Manual and Fire Protection Procedures were
reviewed for compliance with NRC requirements and guidelines:
OMM-002, Fire Protection Manual, Revision 25,
OMM-009, Locked Valve List, Revision 57,
FP-001, Fire Emergency, Revision 29,
FP-002, Fire Report, Revision 5,
FP-009, Surveillance of Fire Protection Activities, Revision 6,
FP-012, Fire Protection Systems Minimum Equipment and Compensatory
Actions, Revision 4.
Plant tours were performed to determine procedure compliance.
b. Observations and Findings
The above procedures established the guidance used to implement the fire
protection program at Robinson and included the requirements for the
control of combustibles, ignition sources and fire brigade organization
and training. The specific procedures were satisfactory and met NRC
requirements and guidelines.
The operability, surveillance and test requirements for the fire
protection systems and features had been removed from the TSs and
incorporated into the site fire protection administrative procedures.
In general, these requirements met the requirements for the fire
protection features which were formerly in the TSs. However, there was
no overall plant administrative procedure that documented the Fire
Protection Program positions, responsibilities, authorities, or the Safe
Shutdown Analysis and 10 CFR 50, Appendix R exemptions. Engineering
50
responsibilities for fire protection related activities were not well
defined in the fire protection procedures. A recent 1996 Nuclear
Assessment Section (NAS) audit of the fire protection program identified
several similar weaknesses with fire protection procedures.
c. Conclusions
Implementation of the fire protection and prevention procedures was
satisfactory. However, there was no overall plant administrative
procedure that documented the Fire Protection Program positions,
responsibilities, authorities, or the Safe Shutdown Analysis and 10 CFR
50, Appendix R exemptions. Engineering responsibilities for fire
protection related activities were not well defined. A recent 1996
Nuclear Assessment Section (NAS) audit of the fire protection program
identified several similar weaknesses with fire protection procedures.
This was identified as a program weakness.
F5
Fire Protection Staff Training and Qualification
F5.1 Fire Brigade Drill
a. Inspection Scope (64704)
The inspectors witnessed a fire brigade drill for compliance with the
facility's fire protection program and the NRC guidelines and
requirements.
b. Observations and Findings
On October 22, 1996, the inspectors witnessed a fire brigade drill with
the off-site fire department located in Hartsville, South Carolina. The
drill involved a simulated fuel oil fire on the Unit 1 fossil plant
boiler. The Unit 2 fire brigade team leader and five fire brigade
members responded in full fire fighting turnout gear. Personnel from
Unit 1 operations, security and off-site emergency medical services also
responded to the drill.
The actions by the fire brigade and support
personnel were satisfactory except that it appeared that there was some
confusion between the fire brigade team leader and the off-site
department related to a fire fighting strategy.
The plant fire team
leader committed to a defensive strategy, electing to let the fire on
the boiler burn while protecting the surrounding plant structures.
The
off-site Fire Department was expecting an offensive strategy, which led
to some confusion and time delay in setting up fire attack hose lines
and the off-site aerial fire truck. A drill critique was conducted with
the fire brigade members following the drill. The drill controllers
addressed several weaknesses and "lessons learned" which had been
identified during the drill.
These included additional training planned
for fire brigade team leaders, use of additional fire drill props to
improve fire drill realism, and improved access of the fire equipment
cart through security vehicle barriers.
These corrective actions were
scheduled to be completed by January 1997.
51
c. Conclusions
The performance by the fire brigade during the drill was marginally
satisfactory and did not appear to be up to the standards previously
demonstrated by the plant fire brigade. The fire brigade drill
performance was not as intense as it could have been and guidance to the
off-site fire department personnel was minimal.
F7
Quality Assurance in Fire Protection Activities
F7.1 General Comments
a. Inspection Scope (64704)
The following reports and responses for audits performed by the licensee
Quality Assurance (QA) organization, NAS, and licensee insurer (Nuclear
Mutual Limited (NML)) were reviewed:
NAS Assessment R-FP-95-01, Fire Protection, April 11, 1995,
NAS Assessment R-FP-96-01, Fire Protection, March 15, 1996,
NML Audit 9501, Property Loss Prevention Report, March 15, 1995,
NML Audit 9502, Property Loss Prevention Report, November 14,
1995.
b. Observations and Findings
The audits were thorough and identified a number of issues, enhancements
and observations for resolution to improve the facility's fire
protection program. The inspectors reviewed the audit issues and
recommended enhancements from each QA report and determined that timely,
appropriate corrective action had been taken on all of the identified
issues.
The 1996 NAS audit identified four issues and three weaknesses. Two of
the identified weaknesses, R-FP-96-01-W1 and -W2 were related to plant
Fire Protection Program procedural problems. These open items were: (1)
the plant does not have a stand alone Fire Protection Plan that
encompasses the overall Fire Protection Program positions,
responsibilities, authorities, equipment, and Safe Shutdown Analysis,
(2)
the engineering responsibilities are not well defined in any
document, and, (3)
the administrative and technical content of Fire
Protection Procedures does not meet management standards (CRs 96-00733
and 96-00735). As previously discussed in Section F3.1, the inspectors
identified similar examples of these types of FHA/SSA discrepancies.
Licensee corrective actions for the NAS weaknesses were scheduled for
implementation by February 28, 1997. The effectiveness of the
licensee's corrective actions associated with these Fire Protection
Program issues will be reviewed during future NRC inspections.
52
c. Conclusions
The audits and assessments of the facility's fire protection program
were thorough and appropriate corrective actions were being taken to
resolve identified issues. During this inspection period, similar
examples of FHA/SSA discrepancies were identified. The effectiveness of
the licensee's corrective actions associated with these Fire Protection
Program issues will be reviewed during future NRC inspections.
F8
Miscellaneous Fire Protection Issues
F8.1 Fire Protection Related NRC Information Notices (64704)
The inspectors reviewed the licensee's evaluation for the following NRC
Information Notices (IN):
IN 92-18, Potential Loss of Shutdown Capacity During a Control
Room Fire,
IN 94-28, Potential Problems with Fire Barrier Penetration Seals,
and,
The licensee's evaluations for these INs were appropriate and the
required corrective actions had been completed.
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 November 20, 1996. Interim
exits were conducted on October 11, 25, November 1 and 8, 1996. The licensee
acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
53
PARTIAL LIST OF PERSONS CONTACTED
Licensee
H. Chernoff, Supervisor, Licensing/Regulatory Programs
J. Clements, Manager, Site Support Services
D. Crook, Senior Specialist, Licensing/Regulatory Compliance
C. Hinnant, Vice President, Robinson Nuclear Plant
J. Keenan, Director, Site Operations
B. Meyer, Manager, Operations
G. Miller, Manager, Robinson Engineering Support Services
R. Moore, Manager, Outages/Scheduling
J. Moyer, Manager, Maintenance
D. Stoddard, Supervisor, Operating Experience Assessment
R. Warden, Manager, Nuclear Assessment Section
T. Wilkerson, Manager, Environmental Control
D. Young, General Manager, Robinson Plant
NRC
J. Zeiler, Acting Senior Resident Inspector
P. Byron, Resident Inspector, Surry
54
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 40500:
Evaluation of Licensee Self-Assessment Capability
IP 61726:
Surveillance Observations
IP 62700:
Maintenance Implementation
IP 62707:
Maintenance Observation
IP 64704:
IP 71707:
Plant Operations
IP 71714:
Cold Weather Preparations
IP 71750:
Plant Support Activities
IP 73753:
Inservice Inspections
IP 83750:
Occupational Radiation Exposure
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactor
T12515/109: Inspection Requirements for Generic Letter 89-10, Safety-Related
Motor-Operated Valve Testing and Surveillance
ITEMS OPENED, CLOSED, AND DISCUSSED
.
Opened
lype
Item Number
Status
Description and Reference
50-261/96-12-01
Open
Failure to Maintain Containment Integrity
During Refueling (Section 01.2)
50-261/96-12-02
Open
Inadequate Safety Injection Check Valve
Testing (Section 01.3)
IFI
50-261/96-12-03
Open
Review Licensee Justification for not
Completing Non-Validated DBD and GID
Evaluations (Section 08.1)
IFI
50-261/96-12-04
Open
Review Licensee Actions to Address
Potential ISI Isometric Drawing Problems
(Section M1.3)
50-261/96-12-05
Open
Unjustified Design Assumptions and
Incorrect Stem Rejection Load (Sections
E1.1.b.3, 4, and 5)
50-261/96-12-06
Open
Inadequate Evaluation of Test Results
(Section E1.1.b.6)
IFI
50-261/96-12-07
Open
Actions to Preclude Pressure Locking
(Section E1.1.b.7)
55
50-261/96-12-08
Open
Resolution of ECCS Sump Design Issues
(Section E8.5)
50-261/96-12-09
Open
Failure to Comply with Radiation
Monitoring Procedures (Section R1.1)
Closed
Iype
Item Number
Status
Description and Reference
50-261/94-23-01
Closed
Failure to Properly Establish Containment
Integrity (Section 08.1)
LER
50-261/94-20-00
Closed
Condition Outside Design Basis Due to
Mispositioned Valves (Section 08.2)
LER
50-261/94-20-01
Closed
Technical Specification Violation Due to
Mispositioned Valves (Section 08.2)
50-261/95-12-01
Closed
Operations Failure To Follow Procedure
During OST-254 (Section 08.3)
50-261/95-14-03
Closed
OST-156 Valve Lineup Improperly
Established (Section 08.4)
50-261/95-19-01
Closed
Operations Configuration Control Events
Concerning RHR Pump Flow Path, Valve SI
883R, Steam Driven Auxiliary Feedwater,
and The Containment ventilation Unit
(Section 08.5)
50-261/95-19-02
Closed
Safety Injection Pump Breaker Racked-In
with LTOP in Service (Section 08.6)
50-261/95-19-03
Closed
Loose Paint in Containment (Section 08.7)
LER
50-261/94-02-01
Closed
Plant Condition Outside Design Basis Due
to MSIV Inoperability (Section M8.1)
EET 50-261/94-16-03
Closed
Inadequate Corrective Action to Potential
TS Deficiencies (Section M8.2)
[ER
50-261/94-01-00
Closed
Failure to Test Instrumentation Channels
Per Technical Specifications (Section
M8 .3)
LER
50-261/94-01-01
Closed
Failure to Test Instrumentation Channels
Per Technical Specifications (Section
M8.3)
50-261/95-12-03
Closed
Maintenance Planner Fails To Properly
Develop Breaker PMTR (Section M8.4)
56
50-261/95-14-01
Closed
Inadequate Control Of Contractor Services
(Section M8.5)
LER
50-261/93-20-00
Closed
Technical Specification Violation Due to
Exceeding F-Delta-H Hot Channel Factor
(Section E8.1)
IFI
50-261/94-06-05
Closed
Adequacy of Periodic Verification Methods
(Section E8.2)
IFI
50-261/94-06-07
Closed
Mispositioning (Section E8.3)
50-261/94-27-07
Closed
Failure to Adequately Control Calorimetric
(Section E8.4)
VEO
50-261/95-12-05
Closed
Failure To Control Safeguards Information
(Section S8.1)