ML20217A935
| ML20217A935 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 04/17/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20217A910 | List: |
| References | |
| 50-313-98-03, 50-313-98-3, 50-368-98-03, 50-368-98-3, NUDOCS 9804220368 | |
| Download: ML20217A935 (24) | |
See also: IR 05000313/1998003
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
i REGION IV
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l Docket Nos.: 50-313
50-368 ,
License Nos.: DPR-51
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! Report No.: 50-313/98-03
l 50-368/98-03
Licensee: Entergy Operations, Inc.
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Facility: Arkansas Nuclear One, Units 1 and 2
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! Location: 1448 S. R. 333 4
l Russellville, Arkansas
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l Dates: February 15 through March 28,1998
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Inspectors: K. Kennedy, Senior Resident inspector l
l J. Melfi, Resident inspector
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l S. Burton, Resident inspector '
Approved By: Elmo E. Collins, Chief Project Branch C
Division of Reactor Projects
Attachment: Supplementallnformation
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9804220368 980417
PDR ADOCK 05000313
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EXECUTIVE SUMMARY
Arkansas Nuclear One, Units 1 and 2
NRC Inspection Report 50-313/98-03,50-368/98-03
This routine announced inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 6-week period of resident inspection.
Ooerations
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Unit 2 operators performed well during several major plant evolutions, including a reactor
shutdown to begin Steam Generator Tube Inspection Outage 2P98, placing the
shutdown cooling (SDC) system inservice, draining the reactor coolant system (RCS) to
reduced inventory, and a reactor startup. Operators consistently demonstrated strong
command and control, communications, use of procedures, response to abnormal
indications, and control of trainees. Management oversight of these activities was
appropriate (Sections 01.1, 01.2, 01.6, and 01.8).
Unit 2 operators demonstrated good attention to detail while conducting midloop
operations. Periodic reviews indicated that midloop activities were properly monitored
and reasonable concern existed among crew members in regard to activities that could
impact the evolution. Inspectors noted strong procedural requirements which controlled
and monitored all phases of midloop operations. Shift turnovers, briefings, senior
management participation, and specialized training indicated that the licensee was
sensitive to controls and activities associated with midloop operations (Section 01.4).
A probing quality assurance audit of the computer code used to calculate the Unit 2 time
to core boiling and time to core uncovery identified a potential error in the assumptions
regarding RCS vent path size (Section 01.5).
The licensee's walkdown and cleanup of the Unit 2 containment building was effective in
preparing Unit 2 for power operation (Section 01.7).
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The Unit 1 plant shutdown to commence Refueling Outage 1R14 was conducted in a
controlled manner. Operators responded appropriately to two equipment malfunctions
experienced during the shutdown. In addition to a previously identified inoperable control
rod, the licensee experienced a sticking problem with a second control rod
(SecF ' 01.9).
Maintenance
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The limited change package developed for the modification of Unit 2 component cooling
water (CCW) containment isolation valves provided incomplete instructions for
implementation of the modification, resulting in seven revisions to the modification
package. Engineers failed to fully evaluate the changes in configuration created by the
modification during development of the modification package (Section M1.2).
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Although the licensee took appropriate precautions during construction of a large gantry I
crane in the vicinity of the Unit 1 main transformers and Startup Transformer 2, a '
qualitative or quantitative risk assessment of the activity using probabilistic safety i
assessment tools had not been conducted and several weaknesses were identified with !
the plant impact evaluation (Section M1.3).
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The licensee developed a comprehensive work plan to repair a tube leak on Unit 2 SDC
Heat Exchanger 2E-35A. There was good coordination among organizations in
planning and impicmenting the repairs (Section M1.4). l
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Proper controls were established to maintain containment integrity while installing a
modification on Unit 2 containment electrical penetrations. Maintenance personnel l
performed the modification in accordance with approved procedures using proper )
radiological work practices. Personnel demonstrated strong familiarity with the design I
change and had been trained for the activity using a penetration mockup (Section M1.5).
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Technicians demonstrated good knowledge, procedural compliance, foreign material
controls, and radiological practices during the replacement of Unit 2 Reactor Cooiant
Pump (RCP) C mechanical seal (Section M1.6). l
Enaineerina
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Engineering evaluations and design changes were comprehensive and supported plant
operations and modification and maintenance activities. One exception was noted with
the limited change package associated with modifications to component cooling water
containment isolation valves (Sections 01.3,01.5, M1.2, M1.4, and E.1).
Plant Sucoort
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Radiation protection technicians failed to update Unit 2 radiological information postings
to reflect the results of radiation surveys conducted in the auxiliary building during
periods of changing radiological conditions (Section R1.2).
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Report Details
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Summarv of Plant Status i
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Unit 1
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Unit 1 began the inspection period at 100 percent power. Power was reduced to 85 percent on L
March 6 for turbine valve / governor valve testing and returned to 100 percent power on March 7. l
The reactor was shut down on March 28 for the commencement of Refueling Outage 1R14.
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Unit 2 !
Unit 2 began the inspection period at 100 percent power. Power was reduced to 97 percent on
February 15 to support emergency feedwater check valve testing and retumed to 100 percent
power the next day. The reactor was shut down on February 21 for the commencement of .
Steam Generator Tube Inspection Outage 2P98. The reactor was restarted on March 21 md I
full power was achieved on March 25. Power was reduced to 70 percent on March 26 for l
approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> to repair a leaking condenser waterbox manway cover. Following l
completion of the repairs, power was retumed to 100 percent and remained there for the '
duration of the inspection period, f
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l. Operations ;
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01 Conduct of Operations
01.1 Unit 2 - Plant ShutdoWD
a. Insoection Scoce (71707) 1
On February 20, Unit 2 operators shut down the reactor to begin Steam Generator Tube
inspection Outage 2P98. The inspectors observed the reactor shutdown from
100 percent to O percent power.
b. Observations and Findinas
The inspectors observed shutdown activities commencing with the shutdown briefing and
ending with the mode change to hot shutdown. The shift briefing was thorough and
included discussions of: individual duties; procedural precautions and limitations;
Technical Specification requiremente; reactivKy changes using the turbine, boration, and
control rods; the sequence for removing equipment from service; maintaining questioning
attitudes; communications; lessons learned from previous shutdowns; and alarm
awareness. The operations manager participated in the prejob briefing and was present
for the duration of the shutdown, The Mspectors observed that licensed operator
canddates performed reactivity manipulations during the reactor shutdown. Licensed
operators provided appropriate oversight of the candidates. The inspectors found that
the trainees were knowledgeable on their responsibilities, reactor theory, and procedural
requirements. Three-part communications by trainees and crew members were
observed. The shutdown was conducted in accordance with Procedure 2102.004,
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. Revision 24, " Power Operations." Power was reduced and components removed from
service as delineated within the applicable sys, tem procedure. At 20 percent power, the
reactor was manually tripped in accordance with procedure. Equipment deficiencies
identified during the shutdown were minimal and actions were initiated to correct the
deficiencies.
c. Conclusions
Unit 2 operators demonstrated good command and control, communications, and
procedure usage during the reactor shutdown. Personnel received training on the
shutdown evolution, and the oversight of trainees was appropriate.
01.2 Unit 2 - Transfer to SDC for Steam Generator Tube Ins _naction Outana 2P98
a. Inspection Scone (71707)
On February 22-23, the inspectors observed Unit 2 operators place SDG inservice in
accordance with Procedure 2102.010, Revision 31, " Plant Cooldown," and
Procedure 2104.004, Revision 24, " Shutdown Cooling System." The inspectors also
observed operators conduct surveillance testing of the low pressure safety injection
system in accordance with Procedure 2104.040, Revision 31, "LPSI System Operation,"
Supplement 4, " Stroke Test LPSI SI Valves (Cold Shutdown)," Supplement 8A, "2P60A
Full Flow Test (Cold Shutdown)," and Supplement 88, "2P60B Full Flow Test (Cold
Shutdown)."
b. Observations and Findinas
The inspectors observed that operators followed their procedures, maintained the RCS
within the allowed pressure and temperature limits, and demonstrated good control of the
evolutions.
c. Conclusions
Unit 2 operators demonstrated good command and control when placing the
SDC system in service to remove decay heat from the RCS and during the performance
of low pressure safety injection system surveillance testing.
01.3 Unit 2 - SDC Heat Exchanaer Leak
a. insoection Scooe (71707)
. .n February 23, the licensee identified a minor tube leak in SDC Heat Exchanger
25-35A The inspectors reviewed the licensee's actions after the discovery of this leak.
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b. Observations and Findinas
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The licensee identified, from radiation monitor indications and chemistry samples, that
SDC Heat Exchanger 2E-35A developed a 0.05 gallon per minute leak. The licensee -
evaluated whether this heat exchanger was operable for SDC operations. The licensee
concluded that the heat exchanger remained structurally sound. The licensee evaluated
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the offsite dose consequences using a conservatively high value for RCS activity and j
concluded that the offsite dose consequences were minor. The heat exchanger was I
declared operable.
The licensee developed a thorough plan to test and repair the tubes in SDC Heat
Exchanger A. These repairs were completed by the end of the outage, portions of which
were observed by the inspectors (see Section M1.4).
c. Conc!usions
The licensee's evaluation of the effects of a leak in SDC Heat Exchanger 2E-35A on
offsite dose consequences was conservative and supported the determination that the
heat exchanger was operable.
01.4 Unit 2 - Drainina of the RCS to Midioon
a. Insoection Scoos (71707)
On February 25, the licensee drained the RCS to established midloop conditions to
allow inspection of steam generator tubing. The draining of the RCS was conducted in
accordance with Procedure 2103.011, Revision 24, " Draining the Reactor Coolant
System." The inspectors observed draining operations and periodically monitored the
licensee's controls of this activity until the water level in the RCS was restored on
March 14. Subsequently, RCP A developed seal leakage and reduced inventory was
re-established for seal replacement on March 17. Section 01.4 discusses the second
drain to reduced inventory for RCP seal replacement.
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The licensee conducted a shift pre-evolution briefing in preparation to drain the reactor to
midioop conditions on February 24. The inspectors observed the pre-evolution briefing
and found it to be thorough. Present at the briefing were shift crew members, outage
support staff, the Operations Manager, and the General Manager of Plant Operations.
Items in the briefing included: emphasis on the safety significance and sensitivity of the
drain down; chain of command and communications for the evolution; a review of '
procedural precautions and limitations; reduced inventory requirements; an overview of
the sequence of events; procedural hold points; plant safety impacts; termination ;
requirements; actions to be performed in the event of off-normal indications; and lessons '
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learned and industry events. Additionally, each crew member discussed individual
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responsibilities for the evolution. Management re-enforced the necessity for
conservatism and provided insights for draining and reduced inventory operations.
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l Risk assessments and risk score cards were developed that covered cold shutdown
! operations. The score cards and risk profile considered SDC, inventory control, vital ac
l and de power, reactivity control, and containment closure. The score cards, which were
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part of the shutdown operations protection plan, identified and evaluated the availability
of safety function systems.
The licensee indicated that training was conducted for the shifts involved in the draining
l operation. Training included simulator operations, procedural reviews, and discussions
of pre-evolution briefing requirements.
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Operators calculated the estimated time to boil and time to core uncovery prior to the
draining operation using the minimum expected reactor coolant volume. These
calculations were recalculated using actual data upon attaining midloop operations and
l every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.
The inspectors reviewed the licensee's lineup for SDC. Multiple control room indications
were available to operators to assist in identifying system degradation. Operators were
i stationed at the SDC pump during draining and for 30 minutes after the completion of
l draining operations to ensure that tne pump did not vortex or cavitate and remained
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operable under the new operating conditions. Additional available injection systems
included two trains of high pressure safety injection, containment spray, and the charging
system. Injection from the refueling water storage tank was available using gravity feed.
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The boric acid makeup tanks were also available as a source of inventory.
Vent paths were established using the pressurizer and reactor head vents during the
draining evolution. After midloop, level conditions were established and steam generator
manweys were removed; additional vent paths existed via the manways to both reactor
coolant hot and cold legs. Reactor coolant loop nozzle dams were not installed during
this outage. Covers, which preclude the entry of foreign material yet continue to provide
a vent path, were installed over the nozzles.
- Three containment penetrations existed during the draining operations
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j hatch, tiie equipment penetration containing steam generator eddy current cables, and )
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the ongoing containment purge. The licensee maintained Procedure 1015.008,
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Revision 14, Form A, " Containment Closure Impairment List," which identified
containment breaches. The inspectors walked down the containment breaches
periodically during the outage and found them properly logged and personnel assigned
for closure if required. The inspectors also noted that the breach for eddy current testing i
equipment was properly installed and maintained, that disconnects were provided for
eddy current testing cables, and that a breach plate was available as a backup
boundary. The inspectors found that the licensee had established controls to ensure that l
containment breaches coula be closed within the procedurally required time of
45 minutes.
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The inspectors found that the licensee established appropriate controls for evolutions
l which had the potential to perturb reactor level or level indication. Operators maintained
Procedure 1015.008, Revision 14, Form B, " Reactor Coolant System Perturbation List,"
which identified these types of activities. Control of p; ant activities, while draining and
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when in reduced inventory, were discussed during the pre-evolution brief.
Command and control was strong throughout the draining process. Personnel
responsibilities were discussed during the pre-evolution briefing and the senior operator
in charge ensured that all personnel were aware of the chain of command and of each
shift member's responsibilities. Three-part communications were consistently utilized.
Level was monitored by two operators in the control room and an operator located at the
tygon tube level indicator inside containment. The operator at the tygon tube was in
constant communications with the control room and had backup methods for
communications. The inspectors noted that the control room operators halted the
draining evolution any time that the tygon tube level watch did not immediately respond
to a query or when the watch had to move to a different building elevation due to level
lowering in the tygon tube. Additionaily, operators stopped draining when the three level
indicators did not indicate within required tolerances of each other. On multiple
occasions, moisture had to be dried from the reference leg of one instrument to bring it
within proper tolerance. The licensee planned to evaluate methods to minimize the
effects of accumulated moisture on ir0cated level. After draining was completed and
stable conditions were established for 30 minutes,' the responsibilities of the tygon tubing
level watch were transferred to the control room drain down operator who monitored the
tygon tubing level indication via closed circuit camera.
RCS level indications, temperature indications, and SDC system parameters were
continuously monitored by control room operators. Computer trends of RCS temperature
and level were displayed on moriitors in the control room. The SDC pump and system
mimics, which containm.1 digital outputs of system parameters, were also displayed in the
control room. Controi a,om operators utilized variable alarms for reactor level and
temperature, and SDC pump flow and motor current, to maintain narrow alarm bands
which would provide prompt indications of any adverse trends during reduced inventory.
. Procedure 2103.011 defined the conditione and limits for use of the controller variable
alarm setpoints. The inspectors periodically 'terified that alarm setpoints were properly
maintained until reduced inventory was exiteo.
While in midloop operations during the period betveen reactor draining and reactor refill,
the inspectors periodically assessed the licensee's controls associated with reduced
inventory operations. Controls identified above were maintained throughout reduced
inventory operations. During shift tumovers, operators discussed plant activities that
could perturb reactor level or SDC and identified containment breaches. The inspectors
interviewed several drain down operators / level watches and found that they were
cognizant of procedural requirements, plant activities that could perturb reactor level, and
containment breaches. On March 2 and 3, the inspectors accompanied both control
room and auxiliary operators as they verified proper system alignment and operation
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using Procedure 1015.008, Revision 14, " Unit 2 Shutdown Cooling Control,"
Attachment B, " Verification of Shutdown Cooling System Alignment," and Attachment C,
" Verification of Reactor Coolant System Makeup System Alignment." These activities
were performed without error and within the time limitations established by the
procedure.
c. Conclusions
Unit 2 operators demonstrated good attention to detail while conducting midioop
operations. Periodic reviews indicated that midloop activities were properly monitored ;
and reasonable concem existed among crew members in regard to activities that could !
impact the evolution inspectors noted strong procedural requirements which controlled !
and monitored all phases of midloop operations. Shift tumovers, briefing % senior l
management participation, and specialized training indicated that the licensee was
sensitive to controls and tactivities associated with midloop operations.
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01.5 Unit 2 - Quality Assurance identifies Potential Probigh ;
Covers
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a. Insoection Scooe (71707)
During observations of reduced inventory operations during Steam Generator Tube
Inspection Outage 2P98, quality assurance personnel identified a configuration issue
associated with the steam generator piping nozzle foreign material covers. These covers ;
are installed over the RCS inlet and outlet nozzles to the steam generators to prevent the
introduction of foreign material into the RCS. The inspectors reviewed the quality
assurance surveillance, associated condition report, and corrective actions associated
with the covers,
b. Observations and Findinas
On March 3, quality assurance personnel performed a review of the computer code used
in calculating core time to boil and time to core uncovery upon loss of core cooling.
During system walkdowns to verify that plant configuration was consistent with the
assumptions in the computer code, quality assurance personnel identified a concem
associated with the RCS vent path. Specifically, quality assurance personnel identified
that the temporary foreign material exclusion covers installed on the RCS to steam
generator nozzles may adversely impact the assumptions for the RCS vent path size
used in the computer code for calculating time to boil and time to core uncovery.
Engineering determined that the covers, which are designed to simultaneously prevent
foreign material intrusion and provide a vent path, did not significantly impact calculations
nor were any procedural requirements violated due to their presence. However, it did not
appear that the installation of the covers or a subsequent modification to install retaining
bars on the covers had been previously evaluated for its affect on the RCS vent path
assumptions. The ficensee planned to evaluate the procer,s which authorized the
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l installation of the covers to determine if proper evaluations and engineering reviews were
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Followup ltem (IFI) 50-368/9803-01).
c. Conclusions
A probing quality assurance audit of the computer code used to calculate the Unit 2 time
to core boiling and time to core uncovery identified a potential error in the assumptions
regarding RCS vent path size.
01.6 Unit 2 - RCS Drain to Midlooo to Reolace the RCP A Seal
a. Insoection Scone (71707. 37551)
During RCS refilling and system pressurization on March 14, the licensee discovered
that the RCP A vapor seal had failed. The inspectors observed the licensee drain the ,
RCS to midloop on March 17 to establish conditions necessary for pump seal
replacement.
b. Observations and Findings
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The inspectors observed midloop draining and periodically observed reduced inventory
operations associated with RCP A seal replacement. Licensee activities were consistent
with activities identified in Section 01.4, " Unit 2 Draining of the RCS to Midloop."
Operators experienced continued problems with RCS level instrument deviations due to
reference leg moisture accumulation while draining. hx..hnicians again were required to
air dry the reference leg of one instrument when excessive deviations were encountered.
Operators identified one new level instrument anomaly which was documented in
Condition Report 2-1998-0127. Operators observed that the RCS level indicated on all
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three level indications (two-level transmitters and a tygon tube) was approximately
4 inches higher than the actual level in the RCS. The three level instruments share a
common variable leg which connects to the cold leg of the RCS, An operator was sent to
flush the common variable leg, and level indication changed to the expected level of
42 inches.
The inspectors were concemed that the lack of independent level instrumentation
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presented a vulnerability, which could lead to inaccurate RCS level indication during
!' drain down to midioop conditions and adversely affect decay heat removal. The
licensee's response to Genaric Letter 88-17, " Loss of Decay Heat Removal," indicated
that the level indications were not independent and identified compensatory actions to
ensure accurate level indication, such as periodically flushing the instrument lines to ,
ensure that they were not obstructed. The NRC, subsequently, reviewed the licensee's j
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compensatory actions and noted that they " appeared appropriate for improving the
l' reliability of the levelinstruments." J
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As a result of the levelindication problems encountered during the RCS drain down on
l March 17, the licensee planned to evaluate corrective actions to prevent further
recurrence. A review of the licensee's planned corrective actions will be conducted
, during a future inspection (IFl 50-368/9803-02).
c. Conclusions
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While draining the RCS to midloop, Unit 2 operators demonstrated good system
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knowledge and awareness when they identified that all three level indications were
i reading incorrectly. The error was corrected when the common variable leg for the level
instruments was flushed. The licensee planned to evaluate corrective actions to prevent
recurrence.
01.7 UWt 2 - Containment Walkdown
a. Insoection Scoce (71707)
The inspectors toured the Unit 2 containment building on March 19 during reactor heatup l
following completion of maintenance activities performed during Steam Generator Tube
inspection Outage 2P98. This tour was conducted following the licensee's preheatup
l walkdown of the building but prior to their precriticality walkdown.
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[ b. Observations and Findinas
The inspectors toured the Unit 2 containment building following completion of
, maintenance activities during Steam Generatcir Tube Inspection Outage 2P98. The !
l inspectors referenced licensee Procedure 1015.036, Revision 5, " Containment Building i
- Closeout," for this walkdown. l
l The inspectors found that the containment building was very clean, indicating that the
! licensee's previous walkdown and cleanup was effective. The sump screens were intact
l and no gaps were identified. The inspectors walked down portions of the RCP
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lubricating oil collection system and found it to be properly configured. Items such as
! radiological postings and some scaffolding located in containment were scheduled to be
l removed prior to reactor criticality,
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c. Conclusions
The licensee's walkdown and cleanup of the Unit 2 containment building was effective in
preparing Unit 2 for power operation.
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01.8 Unit 2 - Startuo and Criticality
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a. Insoection Scone (71707)
On March 20 and 21, inspectors observed Unit 2 operators perform a reactor startup
followir ; the completion of Steam Generator Tube inspection Outage 2P98 activities.
b. Observations and Findings
Prior to startup, the inspectors reviewed licensee identified items that needed to be
resolved prior to criticality. The inspectors found that the licensee had resolved these
issues.
Operators conducted the reactor startup in accordance with Procedure 2102.016,
Revision 5, " Reactor Startup." The licensee conducted a prejob brief prior to
commencing the startup. The operators foHowed the procedure and monitored the plant
response and indications during the approach to criticality. Operators used proper
three-part communications and reactor engineering performed 1/M plots to determine the
l control rod position'where the reactor would become critical. The inspectors noted that
operations management provided appropriate oversight during the startup.
Operators withdrew control rods and reactor criticality was achieved on March 21. The
estimated critical positior. calculated by reactor engineering accurately predicted the rod
height when the reactor became critical.
Operators experienced f ome equipment problems during the startup, including spurious ,
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plant computer alarms Mdicating control rod deviation from the rod group and a
Channel B log range power nuclear instrument that lagged the other channels by several
decades 'unti'. reactor power was approximately 1 percent. l
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The inspectors observed that the control room operators applied good command and
control in responding to alarms and identifying and resolving the equipment malfunctions.
c. Conclusions . l
Unit 2 operators demonstrated good communications, procedural adherence, and
command and control during the reactor startup following completion of Steam Generator
Tube Inspection Outage 2P98.
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O1.9 Unit 1 - Shutdown for Refueling Outaae 1R14
a. insoection Scone (7170h
. On March 27 and 28, the inspectors observed Unit 1 operators begin the shutdown for
the beginning of Refueling Outage 1R14. The inspectors observed control room
activities during the shutdown.
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b. Observations and Findinas
On March 27 operators began the shutdown of the Unit 1 reactor using
Procedure 1102.010, Revision 48, " Plant Shutdown and Cooldown." Operators
followed the procedure and used three-part communications when performing the
evolution. Operations management was present during the shutdown.
Operators appropriately responded to several equipment problems during the shutdown,
includity a failed Channel C wide range cold leg temperature instrument and an
unresponsive heater drain tank level controller. l
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During the shutdown, the inspectors observed operators perform stroke tests of
Atmospheric Dump Valves A and B in accordance with Procedure 1106.016,
" Condensate, Feedwater and Steam System Operation," Supplement 7, " Atmospheric
Dump Control Valve Stroke Test." The operators also performed trip testing of the
control rods following completion of the reactor shutdown. One rod, Group 1 Rod 3
(Rod 1-3), had previously been declared inoperable and was not tested. During a plant
shutdown on January 5, operators identified that this rod would not insert beyond the l
5 percent withdrawn position as they attempted to drive Group 1 rods inward. Inspection
of this issue was documented in NRC Inspection Report 50-313/98-02; 50-368/98-02.
Inspection Followup ltem 50-313/9802-01 was opened to review the results of the
licensee's inspection of the control rod drive mechanism during Refueling Outage 1R14
and their subsequent root cause evaluation and corrective actions. Curing this
shutdown, Rod 1-3 again failed to fully insert in addition, during rod testing following
completion of the shutouwn, the licensee identified that Group 2 Rod 6 (Rod 2-6) stuck at
the 2.5 percent withdrawn position. Rod 2-6 had fully inserted into the core when tripped
during the shutdown. At the conclusion of the inspection period, the licensee planned to
conduct a thorough inspection of these two control rod drive mechanisms. Followup
inspection of the licensee's resolution of this issue will continue to be tracked under
IFl 50-313/9802-01,
c. Conclusions
The Unit 1 plant shutdown to commence Refueling Outage 1R14 was conducted in a
controlled manner. Operators responried appropriately to two equipment malfunctions
experienced during the shutdown. In addition to a previously identified inoperable control
rod, the licensee experienced a sticking problem with a second control rod.
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II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Scoce (62707)
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The inspectors observed all or portions of the following maintenance activities:
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Unit 1 - Job Orders (JOs) 00960301, 00960302, and 00960303 associated with
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Limited Change Package (LCP) 96-3523-L201, 'MOV Modification for 2CV-5236,
! 2CV-5254, and 2CV-5255," observed between March 3-13. j
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Unit 2 - JO 00967560, Work Request 2WR42-3, " Unit 2 Containment Electrical
Penetration 2E-33 Upgrade," observed on February 24.
Unit 2 - JO 00969290, "2SI-15C Check Valve Inspection," observed between
March 1-7.
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Unit 2 - JOs 00958971 and 00975509, " Replacement of Reactor Coolant Pump
l C Mechanical Seal," observed between March 1-7.
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Unit 2 - JO 00975532, " Structural Support Removal and Component Rigging for
l CEA 48 Repair," observed on March 3.
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Unit 2 - JO 00969646, " Repack 2EFW-8A," obsented on March 7.
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Unit 2 - Work Plan 2409.584, "2E-35A Heat Exchanger Leak Test," with
JO 00975343 observed on March 15 and 16.
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b. Observations and Findinas
The inspectors found all the work performed in these activities to be professional and
l thorough. All work was performed according to procedures and the workers were
l knowledgeable of their assigned tasks. Maintenance supervisory involvement was
! observed on all of these activities and appropriate foreign material exclusion controls
j were implemented. Infrequently performed tests or evolution briefs were held when
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required.
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l In addition, see the specific discussions of maintenance observed under Sections M1.2
through M1.6 below.
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M1.2 Unit 2 - CCW Valve Modifications
a. insoection Scooe (62707)
The inspectors observed modification activities asscciated with three CCW Conta'nment
Isolation Valves 2CV-5236-1, -5254-2, and -5255-1.
b. Observations and Findinas
The inspectors observed the licensee perform a minor modification on three
CCW containment isolation valves per LCP 96-3523-L201. These butterfly valves use a
worm drive gearbox unit to translate the actuator motion into a rotation for the butterfly
valve disc. The modification installed a larger gear box unit to increase the closing
torque on the valve.
Electricians and mechanics were knowledgeable on the work and followed the JOs and
LCP associated with the modifications. As the work progressed, situations developed in
the field that were not addressed in the work instructions. The craftsmen asked for
guidance when these situations arose.
This was the first modification of a drive gearbox unit that the licensee had performed in
many years. When a configuration exists in the field that is not addressed in the l
modification package, the licensee can issue documentation describing the differences, )
including field change requests or maintenance engineering requests. This modification
was relatively simple but resulted in six field change requests and one maintenance
engineering request. These changes included torque values for the yoke to valve
bonnet, yoke to actuator body, and drilling of retaining screws. The inspectors
concluded that engineers did not fully evaluate the changes in configuration created by
the modification during development of the modification package.
c. Conclusions
The limited change package developed for the modification of Unit 2 CCW containment
isolation valves provided incomplete instructions for implementation of the modification,
resulting in seven revisions to the modification package. Engineers failed to fully
evaluate the changes in configuration created by the modification during development of
the modification package.
M1.3 Unit 1 - Erection of Gantry Crane to Sucoort Main Condenser Tube Reolacement
a. Insoection Scoce (62707)
On March 3, the licensee commenced the construction of a gantry crane to be used for
replacement of the Unit 1 main condenser tubes during Refueling Outage 1R14
scheduled to begin on March 28. The crane was beirig assembled in the Unit 1
transformer yard in close proximity to the main transformers and Startup Transformer 2.
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A mobile crane was used to construct the gantry crane. Although Startup Transformer 2
was not inservice on either unit as a source of offsite power, it was available to be placed
in service if needed. During the time that the crane was under construction, Unit 1
operated at 100 percent power and Unit 2 was shutdown for midcycle Steam Generator
Tube Inspection Outage 2P98. The Unit 2 RCS was in a reduced inventory condition
during this period. The construction of the crane was performed using JO 00972061 and
Control Work Package 951018D101/972061-27. The inspectors reviewed the licensee's
risk assessment for activity and the controls established to minimize the potential
impacts of the crane construction activity on the operation of the plant.
b. Observations and Findinas
The inspectors observed that the licensee established a number of controls to ensure
personnel safety and to minimize the potential of the crane construction activity affecting
the main transformers or Startup Transformer 2. Prior to the start of the activity, the
licensee constructed a new fence which separated the construction area from the
transformers and constructed a barrier next to Startup Transformer 2 to prevent
inadvertent impact with the transformer. The work plan established limits on the
operation of the mobile crane, including limits on the height of the boom as the work was
performed under both 500 and 161 kv power lines and the use of mechanical stops to
prevent lateral movement of the crane. These limitations were required to be verified by ;
the modifications engineer whenever the mobile crane entered the transformer yard.
The inspectors reviewed the Plant Impact Statement which the licensee prepared for this
work. The Plant impact Statemeat provided a description of the work activity, the impact
that the work activity may have on the plant, the required plant mode for conducting the
work, requirements for the minimum available offsite and onsite power sources, and
special precautions. The Plant impact Statement required the presence of a spotter to
direct the movement of equipment in the area. It also included precautions to stop the
activity in the event of severe weather.
The inspectors identified the following concerns during this inspection:
. Although the licensee had evaluated the activity for potential impacts on plant l
operations, they did not evaluate the risk of the crane construction activity using
probability safety assessment tools. In response to the inspectors' questions, the
licensee performed a risk assessment of the activity for Units 1 and 2 and found
that the increase in plant risk was insignificant. l
. The scope of the work activities covered by the Plant Impact Statement was too
broad. In addition to the construction of the gantry crane, the Plant Impact I
'
Statement applied to the installation of steel plates over manholes, the removal of l
tube pull pit covers, a dry run of the delivery of a tube bundle, and other general i
support activities. Because these activities were scheduled to occur over a l
period of several months, the Plant impact Statement was completed on
January 9,1998, approximately 3 months before the construction of the crane i
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began. Personnel completing the Plant impact Statement did not anticipate that
crane construction would occur during the Unit 2 midcycle outage with the RCS in
a reduced inventory condition. As a result, the Plant impact Statement did not
include any special precautions or limitations for performing the activity with
Unit 2 in a reduced inventory condition. The licensee stated that the Plant Impact
Statement was re-evaluated on the day that Unit 2 entered reduced inventory )
conditions and it was determined that the Plant Impact Statement remained valid.
However, the inspectors identified that the Plant impact Statement did not contain ,
precautions to restrict activities in the area of the transformers in the event that i
Startup Transformer 2 was supplying offsite power to Unit 2 when the RCS was in
& reduced inventory. In response to the inspectors' concems, the licensee
modified the Plant Impact Statement to state that equipment movement would be
stopped if Startup Transformer 2 was in service to either unit.
.
-The Plant impact Statement stated that the minimum offsite and onsite power
supply requirements were applicable during the dry run of the tube bundle
delivery and did not apply to the other activities listed in the Plant impact
Statement, which included construction of the gantry crane. The inspectors noted
that the licensee's shutdown operating protection plan for the Unit 2 outage
contained minimum requirements for offsite and onsite power supplies.
On March 3, the inspectors observed portions of the crane construction activity
and found that the licensee had properly implemented the established controls to l
minimize the potential for impact on plant operations. The boom height of the l
mobile crane was monitored by the crane operator using a computer display
located in the cab. As a backup indication, a rope was attached to the end of the '
boom which was marked to provide a visual indication when the boom height was ,
approaching its limit. During observations of the operation of the mobile crane on l
March 4, the inspectors noted that the rope was not attached to the end of the
mobile crane boom. The licensee informed the inspectors that personnel had !
identified that the rope was not attached during the first lift of the day and
attached the rope as soon as this lift was completed. The licensee stated that the
crane operator monitored boom height in the cab during this equipment move.
c. Conclusions
Although the licensee took appropriate precautions during construction of a large gantry
crane in the vicinity of the Unit 1 main transformers and Startup Transformer 2, a
qualitative or quantitative risk assessment of the activity using probabilistic safety
assessment tools had not been conducted and several weaknesses were identified with
the plant impact evaluation.
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M1.4 Unit 2 - SDC Heat Exchanoer 2E-35A Leak
a. Inspection Scone (62707)
l The inspectors assessed licensee activities to repair a leak in SDC Heat
Exchanger 2E-35A.
b. Observations and Findinos
'
The licensee developed Work Plan 2404.584, "2E-35A Heat Exchanger Leak Test," to
repair the heat exchanger. The licensee began the work on March 15.
The inspectors observed that the licensee followed the work plan and that there was
, good coordination between health physics, operations, engineering, and maintenance.
! The work plan was well developed and properly implemented. Good radiation work
l practices were observed during the activity.
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l The licensee's initial attempt to find the leak was accomplished by pressurizing the shell
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l side of the heat exchanger with air and listening for a leak with an acoustic probe. This
! effort was successful and the licensee identified and plugged one cracked tube.
The licensee also identified some rust discoloration on two additional tubes that were
! adjacent to each other. The licensee examined these tubes and identified a piece of
foreign materialin one tube, which they could not remove. The licensee believed that
this material was introduced into the tube during the manufacture of the heat exchanger, i
i Even though these tubes were not leaking, the licensee plugged both these tubes as a
preventive measure.
c. Conclusions
l
The licensee developed a comprehensive work plan to repair a tube leak on SDC Heat
Exchanger 2E-35A. There was good coordination among organizations in planning and
- implementing the repairs.
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M1.5 Unit 2 - Containment Electrical Penetration Uoorade
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! a. Insoection Scooe (62707)
The inspectors observed activities associated with the modification of Containment
Electrical Penetration 2E-33. The inspectors reviewed the modification package,
precautions, and compensatory measures established for the penetration replacement
and observed portions of the penetration removal and installation.
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l- b. Observations and Findinas
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The modification of Unit 2 Containment Electrical Penetration 2E-33 was conducted per
JO 00967560 and Work Request 2WR42-3. On February 24, inspectors reviewed the
work request and found precautions and limitations that required " containment breaches
to be closed within 45 minutes or where possible within the time to boiling to re-establish
l containment integrity." Penetration plugs had been staged at the work area to afford
I quick closure of containment breaches. In the event the breach was required to be
closed, the control room had established communications with a breach watch who was
trained on the installation of the penetration plugs. Maintenance technicians had
performed training on a penetration mockup for the change out of the electrical '
assemblies and installation of the penetration plugs. The licensee indicated that the
assemblies were removed and the breaches secured with approved penetration plugs j
prior to securing the containment breach watch.
The inspectors observed the replacement of two modules. Personnelinterviewed l
l demonstrated familiarity with the precautions and limitations outlined in the procedure. l
Torque wrenches were calibrated and properly logged. Quality control personnel were j
present and conducted required inspections at hold points identified in the JOs. The j
system engineer demonstrated good familiarity with procedures, modification design, and
health physics requirements. Personnel performing work within the contamination area l
were logged on to the correct radiation work permit. Personnel were observed utilizing i
proper radiological work practices.
c. Conclusions
Proper controls were established to mainicin containment integrity while installing a _
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modification on Unit 2 containment electrical penetrations. Maintenance personnel
performed the modification in accordance with approved procedures using proper
radiological work practices. Personnel demonstrated strong familiarity with the design
l change and had been trained for the activity using a penetration mockup.
M1.6 Unit 2 - RCP C Mechanical Seal Reolacement
a. Insoection Scooe (62707)
Inspectors observed portions of the replacement of the RCP C mechanical seal with
modified, Style N9000, cartridge seals throughout the week beginning on March 1.
i
b. Qhgervations and Findinas
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Replacement of the RCP C mechanical seal was accomplished using two procedures.
Removal of the old style seal was conducted per JO 00958971 and Procedure 2402.018,
Revision 9," Unit 2 Reactor Coolant Pump Seal Replacement." Installation of the new
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seal was per JO 00975509 and Procedure 2402.218, Revision 0, " Unit 2 N9000 Reactor '
Coolant Pump Seal Replacement." Maintenance was conducted throughout the week
.beginning March 1.
The inspectors found that the modification packages, JOs, and procedures were
complete. The inspectors observed procedural compliance by technicians during work
activities. Proceduralized foreign material exclusion and Level 1 cleanliness restrictions
were adhered to by the technicians. The inspectors discussed the modification with
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l technicians and found them knowledgeable. Technicians indicated that they had worked
with the vendor when the same modification was performed on two prior occasions.
c. Conclusions
Technicians demonstrated good knowledge, procedural compliance, foreign material
controls, and radiological practices during the replacement of the Unit 2 RCP C
mechanical seal.
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M1.7 General Comments on Surveillance Activities
a, insoection Scoos (61726)
The inspectors observed all or portions of the following surveillance activities:
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Unit 1 - Procedure 1306.017, Revision 14, " Unit 1 Main Steam Safety Valve
Test," observed on March 26.
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Unit 1 - Procedure 1106.016, " Condensate, Feedwater and Steam System
Operation," Supplement 7, " Atmospheric Dump Control Valve Stroke Test,"
observed on March 28.
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Unit 2 - Procedure 2104.040, "LPSI System Operation," Revision 31,
l Supplement 4, " Stroke Test LPSI Sl Valves (Cold Shutdown)," observed on
l February 22.
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Unit 2 - Procedure 2104.040, "LPSI System Operation," Revision 31,
Supplement 8A, "2P60A Full Flow Test (Cold Shutdown)," observed on
February 22.
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Unit 2 - Proce ' 2104.040, "LPSI System Operation," Revision 31,
Supplement 8B, 260B Full Flow Test (Cold Shutdown)," observed on
February 22.
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Unit 2 - Procedure 2104.039, "HPSI System Operation," Supplement 6, " Full Flow
HPSI Test," observed on March 14.
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l b. Observations and Findinas
The inspectors found that these surveillance activities were performed according to these
procedures by knowledgeable operators and workers. When applicable, calibrated test
l equipment was used and personnel showed an awareness of the procedural
requirements and safety while testing this equipment.
Bil. Enaineerina
E1 Conduct of Engineering
l E1.1 General Comments
a. Insoection Scooe (37551)
The inspectors reviewed all or portions of the following engineering work packages:
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Unit 2 - Design Change Package 963543D201, * Backup Source for Main Turbine
Controls and EFW Alarm Modifications."
. Unit 2 - JO 00975533, "CEA 48 Cable Determination / Redetermination."
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Unit 2 - JO 00975461, "CEA 48 Upper Gripper Coil Stack Replacement."
Unit 2 - JO 00975532, " Structural Support Removal and Component Rigging for
CEA 48 Repair."
Unit 2 - ER 980206, " Engineering Calculstbns for CEA 48 Coil Stack
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Replacement."
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Unit 2 - Temporary Alteration 98-2-003, "Startup Channel 1."
b. Observations and Findinas
The inspectors found that engineering documentation and design changes generally
contained clear instructions which accomplished the desired objective. Work packages
demonstrated that engineering and technical support to other organizations were
effective in resolving plant problems while ensuing that design bases were maintained.
c. Conclusions
l Engineering and technical support performed by the licensee was professional and
thorough. Engineering documentation was accurate, preserved the design basis, and
contained clear instructions. Engineering provided good support of plant operations and
maintenance activities. l
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IV. Plant Support
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R1 Radiological Protection and Chemistry Controls j
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R1.1 Radiological Practices Durina Filter Movement (71750)
On February 27, the inspectors observed the movement of a filter canister from the
turbine building train bay into the auxiliary building drumming station. The evolution
required an access cover in the turbine building train bay, located in a radiological
controlled area, to be lifted with h crane and a filter canister to be transported to a lower
elevation through the opening with the same crane. Once opened, a path existed
between auxiliary building controlled access and the turbine building. Health physics ,
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technicians were present and property monitored the activities. Personnel working
within, entering, and exiting the radiation area followed appropriate radiological practices.
Security was present to ensure that proper access controls were applied to the
temporary breach between the turbine and auxiliary buildings. )
R1.2 Failure to Uodate Radioloaical Survev Forms
a. Insoection Scoce (71750)
l
The inspectors conducted tours of the Unit 2 auxiliary building and reviewed the
radiological postings located at the entrance to various rooms for completeness and
timeliness,
b. Observations and Findinas
During a tour of the Unit 2 auxiliary building on March 2, the inspectors observed that the
radiological survey map posted at the entrance of High Pressure Safety injection Pump
Room A had been updated on February 3 when the plant was at 100 percent power. In
the interval from February 3 to March 2, a number of activities were conducted which
changed the radiological conditions in this pump room, including a plant shutdown to
commence midcycle Steam Generator Tube Inspection Outage 2P98, placing SDC
inservice, and conducting a chemically induced crud burst to reduce source term. The
licensee stated that, although surveys had been performed at various times during this
period in the pump room, the posted survey map was not updated to reflect the results of
the surveys. The inspectors determined that the radiologicalinformation postings were
used by station workers, such as operators, to inform them of the radiological conditions
in a room or cubicle. Upon further review, the licensee found that survey maps for six
additional rooms within the auxiliary building had not been updated to reflect radiological
surveys performed in those rooms. The licensee conducted surveys of these room and
updated the radiological information postings.
Procedure 1012.018, Revision 3," Administration of Radiological Surveys," Step 6.1,
contains the general radiological survey requirements. Step 6.1.2 states, in part,
" Observe the following requirements when conducting any survey. Update the
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radiologicalinformation posting located outside of the room or cubicle where the survey
was conducted, as applicable." The failure to update the radiological information
postings following completion of surveys was determined to be a
violation (50-368/9803-03).
c. Conclusions
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l Radiation protection technicians failed to update Unit 2 radiological information postings
j to reflect the results of radiation surveys conducted in the auxiliary building during
periods of changing radiological conditions.
1
i S1 Conduct of Security and Safeguards Activities
!
S1,1 Conduct of Security
,
The inspectors reviewed security measures and operations periodically throughout the
l inspection period and noted that they were properly imple',ented. included were
i observations of personnel and package access, personnu searches, and applications of
l temporary lighting in areas where outage related equipment, components, and truck
l trailers were stored.
!
l V. Management Meetings
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X1 Exit Meeting Summary i
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The inspectors nresented the inspection results to members of licensee management at !
the conclusion of the inspection on March 31,1998. The licensee acknowledged the
findings presented.
1
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information tvas identified.
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j* ATTACHMENT
l PARTIAL LIST OF PERSONS CONTACTED
1
Licensee
C. Anderson, Plant Manager, Unit 2 j
G. Ashley, Licensing Supervisor I
B. Beard, Unit 2 Electrical Superintendent
l B. Bement, Manager, Radiation Protection and Chemistry
J. Bradford, Unit 2 Instrumentation and Control
M. Chisum, Manager, Unit 2 System Engineering
M. Cooper, Licensing Specialist
P. Dietrich, Manager, Unit 1 Maintenance
B. James, Unit 2 Outage Manager
j
R. Lane, Director, Design Engineering 4
M. Little, Unit 1 Shift Superintendent
J. Sutterfield, Unit 2 Assistant Outage Manager
J. Vandergrift, Quality Director
C. Zimmennan, Unit 1 Plant Manager
NBC
Peter Alter, Project Engineer, Branch C
INSPECTION PROCEDURES USED ,
1
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
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IP 62707: Maintenance Observations I
IP 71707: Plant Operations l
lP 71750: Plant Support Activities
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-368/9803-01 IFl Review of licensee's evaluation for installing foreign material
exclusion covers on steam generator nozzles (Section 01.5) l
50-368/9803-02 IFl Review of licensee's corrective actions to address RCS level
indication anomalies (Section 01.6)
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( 50-368/9803-03 VIO Failure to update radiological survey maps (Section R1.2)
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l LIST OF ACRONYMS USED
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l CCW component cooling water
l IFl inspection followup item
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JO job order
LCP limited change package
RCP reactor coolant pump
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