ML20247L272
| ML20247L272 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 05/15/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20247L227 | List: |
| References | |
| 50-298-98-02, 50-298-98-2, NUDOCS 9805220355 | |
| Download: ML20247L272 (36) | |
See also: IR 05000298/1998002
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.: 50-298
License No.: DPR-46
Report No.: 50-298/98-02
Licensee: Nebraska Public Power District
Facility: Cooper Nuclear Station
Location: P.O. Box 98
Brownville, Nebraska
Dates: March 8 through April 18,1998
Inspectors: Mary Miller, Senior Resident inspector
Chris Skinner, Resident inspector
Approved By: Elmo Collins, Chief, Branch C
Division of Reactor Projects
ATTACHMENT: Supplemental Information
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9805220355 980515
gDR ADOCK 05000298 I
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EXECUTIVE SUMMARY
Cooper Nuclear Station
NRC Inspection Report 50-298/98-02 l
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Ooerations
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Plant management demonstrated intrusive involvement in successfully demanding focus i
on and resolution of priority issues, allocating and directing engineering resources to l
reduce operator work-arounds, and understanding plant anomalies. Plant management
raised standards for staff performance in response to a snowstorm which blocked routine l
access to the site for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and in the installation of the Z-sump modification l
(Section 01.1). l
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During a reactor startup and power operations, control room crews' operations evidenced
strong safety focus. They successfully implemented strong command and control, !
awareness and assessment of plant conditions, questioning attitude, Technical I
Specification adherence, configuration control, and procedural adherence. Management
involvement was strong. Minor weaknesses were promptly corrected (Section 01.2). l
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Operations response to a snowstorm with limited plant access was excellent
(Section 01.3).
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Operations demonstrated a questioning attitude regarding operability of a safety-related
heat exchanger and successfully obtained engineering focus to address the operability
controls (Section O2.1).
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When a crew did not meet operations and training management expectations during
dynamic simulator training, a remediation was initiated. Inspectors observed that the
remediation process was self-critical and was based on many specific observations of
crew behaviors during simulator training. Operations management demonstrated strong
self-critical standards and continued close involvement with crew performance over the
training cycle (Section 05.1).
Maintenance
During observations of routine maintenance, inspectors observed procedural adherence,
radiation protection, and ALARA practices and found them generally good. Acceptance
criteria were properly referenced and followed. Cases in which data were not within
acceptance criteria, or anomalies were found, were dispositioned with problem
identification reports and/or documentation on a discrepancy sheet. The appropriate
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standards for initiation of problem identification reports appeared to have been met when
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problems were encountered (Section M1.1).
- Maintenance response to a snowstorm which blocked routine access to the site for over
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was outstanding. Two shifts of emergency response organization were formed
onsite as well as two shifts each of operations, security, and maintenance staff to
address plant operations, outage work, and effects of the snowstorm. For the majority of
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activities, maintenance and the outage organization took on a leadership role and
properly prioritized and coordinated site activities (Section M1.2).
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. Several examples of material condition were identified. In general, material condition is
good (Section M2.1).
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Maintenance responded promptly and provided a repair to a failed circulating water
valve. However, the valve was repaired with a modification without appropriate
administrative controls. Maintenance did not promptly verify safety-related valves with
similar designs. Also, similar essential valves were not promptly verified to determine if
the same mechanism may be a concern until after inspector involvement (Section M2.2).
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The licensee failed to properly implement corrective actions for inadequate torquing
instructions which had caused safety system inoperability. Administrative controls were
not implemented to ensure the word tight or tighten would be used appropriately in new
or revised procedures, the licensee failed to identify all maintenance procedures affected
by the concern, and no permanent corrective action for uncontrolled fastener installations
were addressed (Section M8.1).
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A violation for the failure to require verification of Technical Specification operability
requirements before increasing operating modes was not property corrected. The
licensee did not identify all operability verification requirements during the corrective
action process (Section M8.2).
Enaineerina
- The length of fuel had been increased from 144 to 150 inches. However, calculation
changes to implement the design change failed to change the reference point for the top j
of active fuel on fuel range levelindicators and emergency operating procedure
parameters. This caused a nonconservative bias in the fuel range indication of 6 inches.
The licensee evaluation concluded that, although this bias was nonconservative, it did i
not exceed the existing design margin (Section E2.1).
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Procedures for use during a loss of coolant accident and loss of offsite power directed
that core spray be throttled to 4750 gpm per pump, although 6100 gallons were required i
for core coverage, by the Updated Safety Analysis Report accident analysis I
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(Section E2.2).
- Engineering failed to implement clear instructions for controlling the electrical load profile
in emergency operating procedures. This profile is the basis for the Technical
Specification 7-day diesel fuelinventory requirement. Operations had not been
instructed that this profile must be used if the design basis loss-of-coolant accident
occurred (Section E2.3).
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The licensee did not recognize that paint applied in the reactor building contained an
unacceptably high percentage of volatile organics. The initial evaluation and restrictions
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on the painting, as well as the evaluation of the effect of this painting on standby gas
treatment, did not accurately address the technical issue or the iodine release profile,
and the control room was not informed of later developments (Section E2.4).
- For a modification to the Z-sump, engineering did not IS.itify all affected operating
procedures. Inspectors found that, if the nonessential power to the essential heat trace I
was lost due to electrical component failure, no requirements or actions were provided to
operators in abnormal or alarm response procedures to respond to this loss
(Section E2.5).
. The licensee failed to reconcile the design requirements for torus level to remain below
2 inches and the emergency operating procedures which allow a torus level up to
37 inches (Section E2.7).
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Engineering demonstrated weak support of an issue regarding a small amount of water
found in diesel fuel oil day tank. After discovery of water in one train of the diesel fuel oil
day tank, the licensee did not promptly check for water in the redundant train until after
inspector questioning a day later (Section E2.9).
- The licensee failed to evaluate the extent of condition of a violation for improper
incorporation of design modifications in emergency procedures (Section E8.1).
Plant Sucoort
- The work control staff initiated interdepartmental dose reduction efforts, found dose
reduction opportunities, and documented the results in weekly lessons teamed reports to
inform and provide expectations for site staff (Section R1.1).
- During the snowstorm when routine access to the site was cut off for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the I
emergency response organization promptly contacted state officials and assessed
personnel onsite to evaluate emergency response to fulfill requirements for two shifts of
an emergency response organization (Section P1.1).
- After a drill response, the technical support center conducted a self-critical review by
comparing past drill performance observations during the critique, due to ownership by
the technical support center director (Section P7.1).
- Security responded appropriately to indications of a broken seat on a diesel fuel tank
inlet (Section S1.2). l
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Egoort Details
Summarv of Plant Status
The plant was shut down at the beginning of this report period for a midcycle outage. The plant I
achieved criticality on March 13,1998, connected to the grid on March 14, and reached
100 percent power on March 16. On March 21, a circulating water motor-operated valve failed.
Operations reduced power to 71 percent as required by procedures. The plant was retumed to
100 percent power on March 23. On April 13, the lube oil pump for Reactor Feedwater Pump B
seized, causing a momentary feedwater pump trip signal and brief reduction of the feedwater
pump flow. Operators reduced power to 75 percent for troubleshooting and repairs. The lube oil
pump was replaced and full power was restored on April 15.
l. Operations
01 Conduct of Operations
01.1 Plant Manaaement involvement in Licensed Activities
a. Insoection Scoce (71707)
Inspectors observed several routine licensed activities, such as plan-of-the-day
meetings, shift turnovers, condition review groups, corrective action review board closure !
reviews, outage meetings, modification project management meetings, and station
operations review committee meetings.
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b. Observations and Findinas !
During the inspection scope activities, multiple instances of strong plant management
- action were observed. Plant management successfully demanded focus of resources on
l resolution of problems. Inspectors observed plant management performing plant
walkdowns several times per week. Several examples were observed where plant
management demanded and successfully raised standards for improving questioning
attitudes toward anomalous conditions, identification and final resolution of problems,
maintenance of plant equipment, housekeeping, presence of supervision in the field, and
a stronger questioning attitude by plant staff. Plant management successfully demanded
higher standards by the operations organization in interfacing with the work control
organization and implementing plant scheduling requirements in a more thoughtful and
timely manner.
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l Plant management demonstrated strong involvement and demands to focus plant staff to
resolve key plant issues. Examples include resolution of Z-Sump modification
installation, response to a heavy snowstorm blocking roads for 24-hours, understanding
and improving plant thermal performance, involvement and resolution of the fuel bundle
length versus reactor vessel water level indication parameters associated with
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emergency operating procedures, strong demands for engineering support to address
long-term operator work-arounds, and multiple housekeeping and radiation practice
improvements.
Plant management demonstrated leadership of the corrective action program by leading
a generally successful initiative to raise corrective action standards by review of closure
packages for significant conditions adverse to quality. This initiative resulted in rejection
of several closure packages and reopening of several condition reports to further define
problem scope and implement more effective corrective action. Plant management has
also demonstrated a strong positive standard for the station operations review
committee, for both improving a questioning attitude and successfully raising standards
for station operationsireview committee approval actions. Similar effectiveness has been
demonstrated in approximately weekly attendance of condition review group meetings.
c. C_onclusion
Plant management demonstrated intrusive involvement in successfully demanding focus
on and resolution of priority issues, allocating and directing engineering resources to
reduce operator work-arounds, and understanding plant anomalies. Plant management !
raised standards for staff performance in response to a snowstorm which blocked routine
access to the site for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and in the installation of the Z-sump modification. l
O1.2 Strona Crew Performance in Startuo and Routine Ooerations
a. Insoection Scooe (71707)
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Inspectors observed control room crew performance during a midcycle outage, a reactor
startup and return to full power, and routine full power operations. Inspectors held
discussions with licensed and nonlicensed operators and operations management.
b. Observations and Findinos
inspectors observed strong, positive control of plant conditions during all portions of this
inspection scope and many examples of a strong questioning attitude and refusal to
allow schedule pressure to affect plant startup and control room operations. Shift
technical engineers identified problems and coordinated with shift management and
operations management to resolve several issues requiring engineering and licensing
evaluations. Communication between operators was complete, clear, and directed
toward appropriate prioritized activities. Inspectors observed multiple crews coordinate
with work control to minimize control room distractions, particularly during infrequent
evolutions such as reactor startup and power ascension. This indicated correction of a
past vulnerability which caused an event during the last startup. The following examples
provided are indicative of operations performance.
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Inspectors observed Surveillance Procedure 6.1RPS.307, " Reactor Vessel Low-High
Water Level Calbration and Functional Test," Revision 2, scheduled during shutdown
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activities shortly after plant shutdown. The reactor operator in charge of the evolution
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questioned the appropriateness of performing a reactor levelinstrument surveillance i
during this evolution which has the potential to cause a Group 2 isolation of shutdown
cooling. The licensee documented the concern in Problem Identification Report 2-28381
which noted that the test affected Primary Containment isolation System Group 2 and
should not have been perfornied under the current plant conditions. The surveillance ,
was postponed until after the decay heat generation rate had been reduced !
considerably. This demonstrated a strong questioning attitude and good plant i
knowledge.
On March 21, Circulating Water Valve CW-MOV-103 failed, isolating the circulating water
in the Condenser B2 water box, causing condenser maximum increase of 3 inches
mercury absolute. Operations reduced power to 71 percent as required by procedures.
The vacuum reestablished at former levels as power was decreased. Maintenance and
engineering support were called into the site. Reactor engineering provided control rod
adjustment procedures to ensure rod line remained below the 105 percent required by
analysis. During the downpower transient and feedwater heating transition, rod line
reached 108.9 percent. Reactor engineering and the control room staff concluded that
the transient value had been previously analyzed and was acceptable. The required
chemistry analysis was performed. The inspector observed the control room activities
shortly after the transient. The shift supervisor reviewed the plant conditions and status
of the evaluations, solicited input from each licensed crew member, and emphasized
procedure adherence, communications, and attention to detail. The shift technical
engineer coordinated activities with reactor engineering and maintenance. Subsequent
return to full power was also coordinated with reactor engineering.
Shift technical engineers demonstrated strong performance in resolving issues affecting
plant operations and demanding resources and technical support when required. For
example, a shift technical engineer initiated a problem identification report documenting !
that the new engineering process for conveying equipment operability information had l
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not assured adequate or timely information to the control room for an equipment issue.
On a separate NRC issue regarding a potential bias of the vessel fuel zone level
indication, operations support staff and shift technical engineers found indications that
the concern may be valid contrary to the conclusion reached by engineering. Operations
management and a shift technical engineer concluded that the facts and potential scope
of the concern should be researched over the weekend by available shift resources. 1
Shift technical engineers evaluated and documented a seven-page contingency and
scope matrix. When the issue was confirmed, operations promptly implemented the
contingency matrix. i
Generally, turnovers were very well organized. They were complete, formal, and concise
at all crew levels. Turnover meetings were crisp and complete, with strong positive
control of the meeting by the shift supervisor and control room supervisor. Two minor
observations of reduced formality were observed, which were not recognized and
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l corrected by the operations supervisor. After discussion with the inspector, operations
management re-emphasized standards. No further reductions in the level of formality
were observed.
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The licensee implemented a method of controlling shutdown cooling by using the
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residual heat removal heat exchanger outlet valve (RHR-MO-128). This is a
nonthrottleable valve controlled by a keylock switch on control room panel. The valve is
maintained in position by opening its power supply breaker at the motor control center.
The position is changed by closing the breaker for a specified number of seconds,
calibrated to percent of full stroke. Original plant design had the service water heat
exchanger outlet valves (SW-MO-89A and -B) used for controlling shutdown cooling, but
the valves did not work due to river water corrosion effects and the heat exchanger
bypass valves do not have adequate capacity. Operations management identified this
condition as an operator work-around and has added this to the engineering work
assignments to resolve work-arounds. Inspectors also observed that this breaker, which
is out of normal position, is not controlled by a tagging order, but by procedure.
However, the position of the breaker for the residual heat removal pump valve
(RHR-MO-168) was controlled by a tagging order when it was out of its normal position
in the same procedure. This aspect of valve control will be reviewed by operations.
A station operator demonstrated good observation skills when he identified that, when
Service Water Pump C was started, the pump slightly moved on its foundation.
Maintenance technicians performed troubleshooting actions and determined that three of )
the eight foundation bolts were loose. Operations requested that the other service water {
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pump foundation bolts be verified tight, and no other bolts were found loose.
During the outage and subsequent power operations, no violations of Technical
Specifications or procedural adherence were observed. Configuration control was i
excellent. Management presence and involvement was observed on a daily basis.
c. Conclusion
During a reactor startup and power operations, control room crews operations evidenced
strong safety focus. They successfully implemented strong command and control,
awareness and assessment of plant conditions, questioning attitude, Technical
Specification adherence, configuration control, and procedural adherence. Management
involvement was strong. Minor weaknesses were promptly corrected.
01.3 Resoonse to Difficult Site Access Conditions Caused by Snowstorm
a. Insoection Scoce (71707)
Inspectors observed licensee activities during blizzard conditions which significantly
impaired access to the site over 24-hours.
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b. Observations and Findinas ;
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On March 8,1998, during the midcycle outage, with the plant in a shutdown, vented ,
condition, a heavy snowfall and strong wind condition occurred. Plant access was l
difficult because of a heavy winter snowstorm accompanied by strong shifting winds,
causing massive drifting over east-west roads and highways of the area. The licensee
contacted the Nemaha County Sheriff's department and was informed that some major
roads providing access to the site were closed by snow. The licensee contacted the
state officials from both Nebraska and Missouri regarding assessment of site access
requirements. State officials determined that, although some roads were passable by
specialty vehicles, travel of the major east-west highways was not possible. The
licensee initiated a report in accordance with 10 CFR 50.72 informing the NRC that
access to the site was impaired by snowstorm and that state and county officials had
been contacted regarding the difficult access and evacuation conditions. A resident
inspector was on site and observed the licensee's response.
Operations assessed onsite staff and found adequate shift staffing, with the exception of
a second shift supervisor. The licensee provided speciality ground transportation and
brought another shift supervisor to the site. Operations also assessed and determined
that the off-site grid was stable and verified no abnormal plant condition existed.
Operations coordinated with security and emergency planning to assure adequate site i
staffing for two shifts.
Operations coordinated with maintenance to conduct outage activities at a rate
appropriate to the staffing onsite, assuming that relief would not be available within
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Meals were provided for personnel on shift. Further, licensee speciality
vehicles transited major routes to the nearby towns of Auburn and Nemaha, Nebraska,
for the transportation of some licensee staff to and from their homes.
On March 10, Nebraska and Missouri state officials had determined that roads were
sufficiently cleared to allow site evacuation commensurate with emergency plan
requirements. By this time, licensee staffing was returned to normal.
c. _Gpnclusions
Operations' response to a snowstorm with limited plant access was excellent.
O2 Operational Status of Facilities and Equipment
O2.1 Operability of Reactor Eauioment Coolina Heat Exchanoer Run in Backwash
a. Insoection Scooe (71707)
Inspectors reviewed licensee's activities associated with operations' questioning
operability controls for running the reactor equipment cooling heat
exchanger in a backwash configuration.
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b. Observations and Findinos
The shift supervisor questioned the adequacy of the procedure giving instructions to
perform a backwash of a reactor equipment cooling heat exchanger. The procedure did
not specify whether the system was operable. The shift supervisor requested an
engineering evaluation and delayed the backwash evolution. The shift supervisor
declared the reactor equipment cooling heat exchanger inoperable while being
backwashed. The licensee initiated Problem identification Report 2-27269 to question if
, the quarterly backwash of the reactor equipment cooling heat exchanger involved an
operability concern.
Engineering's evaluation concluded that parallel flow in backwash removed less heat
than counter flow in normal operation; the backwashed heat exchanger should be
declared inoperable during the evolution.
The inspectors noted that under design basis conditions the maximum river temperature
would not support removal of design basis heat loads from the backwashed reactor
equipment cooling heat exchanger since the service water first ran through the operable
heat exchanger and then reversed through the inoperable heat exchanger, having
removed heat from the first exchanger in line. The evaluation did not address river water
temperature limit when the backwash heat exchanger could no longer perform its design
basis function or qualifications of piping in use to perform backwash operations.
The licensee also did not address past operability of performing this activity under high
river temperature conditions or the vulnerability of a lack of operational controls to
preclude this con'iguration with high river temperatures. This is an inspector followup
item (50-298/98002-01).
c. Conclusions
Operations demonstrated a good questioning attitude regarding operability of a safety-
related heat exchanger and successfully obtained engineering focus to address the
operability controls.
02.2 Station Ooerators identification of Problerns
a. Insoection Scoce (71707)
During a routine tour in the reactor building, the inspectors identified that a manual valve
hand wheel was in contact with safety-related electrical conduit. Discussions were held
with operations and engineering staffs.
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b. Observations and Findinos
On March 29,1998, during a routine walkdown the inspector identified that the
handwheel on Reactor Core Isolation Cooling Valve RCIC-96 was in contact with a
2-inch electrical conduit leading to the reactor core isolation cooling starter rack. The -
inspectors also observed four scribe marks at approximately 1/8-inch intervals below the
contact point of the valve indicating that, as the valve had been opened and closed in the
past, it had scribed the conduit in multiple locations during its travel.
l Station operators had not questioned the acceptability of the handle for a manual valve
L contacting electrical conduit. Engineering evaluation concluded the condition would not
l have resulted in exceeding code allowables. 1
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Tne inspectors identified a minor plant configuration issue that was not questioned by
station operators.
05 Operator Training and Qualification
05.1 Remediation of Ooeratina Crew Durina Trainino Process
a. Insoection Scone (71707)
Inspectors observed the licensed operator training and remediation process for a crew
which did not meet management expectations during dynamic simulator training.
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b. Observations and Findinas ;
On April 6,1998, a crew in training performed a dynamic simulator scenario. Their i
l actions to obtain important parameters to allow diagnosis of plant conditions were not
l timely enough to meet management expectations. Also, coordination between the shift
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supervisor and the shift technical engineer was not implemented in a sufficiently strong
manner to meet management expectations. The licensee concluded that the crew would
have carried out licensed responsibilities during an event in an adequate manner, but i
that they failed to meet maagement expectations. Therefore both training and l
operations management concluded remediation of the crew performance was warranted.
l inspector review of crew performance found this conclusion to be appropriate.
The inspector observed some of the remediation activities, including a dynamic simulator
scenario evaluation by operations and training staff. The inspector observed self-critical
standards by both the crew and operations management. The evaluation was
comprehensive, specifically addressing several examples of strengths and weaknesses.
The inspector identified several observations, many of which were identified by the crew,
trainers, and operations evaluators. The inspector's observations which were not
originally addressed by the licensee focused on reactivity management and sensitivity to
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the effects of plant conditions and equipment failures on reactor power. Operations
management acknowledged these observations and re-emphasized a need for high crew
sensitivity to reactivity management and effects on reactor power.
During the critique, operations management required that the crew performance be
evaluated with respect to the past performance evaluations to allow the crew to evaluate
their performance and conclude if they considered the remediation adequate. This
indicated a demand for crew members to internalize a strong standard of fact-based,
self-critical performance eva.'uation.
The licensee concluded that the remediation had corrected the majority and severity of
the performance concems. However, operations management concluded that followup
in future training weeks would be performed for this crew to determine if an adverse trend
in any of these areas occurred.
c. Conclusions
When a crew did not meet operations and training management expectations during
dynamic simulator training, a remediation was initiated inspectors observed that the
remediation process was self-critical and was based on many specific observations of
crew behaviors during simulator training. Operations management demonstrated strong
self-critical standards and continued close involvement with crew performance over the
training cycle.
08 Miscellaneous Operations issues
08.1 (Closed) Violation 50-298/96031-01: Failure to provide procedures for expected
abnormal conditions. The control room had mitigated a slush buildup in the circulating
water bay. No guidance had been provided by procedures, although this condition had
occurred in the past. The licensee found that several abnormal or unusual conditions not
always generally known by plant personnel would be expected during the life of the plant.
These conditions had not been addressed in plant references or operations procedures.
To correct this situation, the licensee initiated a collection of unusual or not generally
known information (such as unusual relay arrangements and ventilation system effects)
in a database. This database is available for review throughout the site. A person
assigned by operations has reviewed submittals from all site staff for inclusion and it has
been used repeatedly in the continuing operations training cycles. During instances of
database review, operators identified some examples of information which should be
more properly included in system operating procedures, and they modified procedures to
include the information. Inspectors observed contents of the database, found it to have
collected obscure but potentially usefulinformation, and noted that the purpose of the
corrective action was served by the continuing review and identification of information
which was then incorporated into operations procedures.
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11. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Scooe (71707)
The inspectors observed and reviewed the following work activities and associated work
orders, tagout orders, and other related documents:
6.1(2)RPS.307 Reactor Vessel Low High Water Level Calibration and Functional
15. PAS.301 Post-Accident Sampling Area Radiation Monitor Functional Test
6.RHR.306 Reactor High Pressure Calibration and Functional
6.1 ADS.301 ADS Reactor Pressure Permissive Calibration and Functional and
Logic Tests 6.1SW.101 Service Water Surveillance Operation
MWR 98-1097 Replacement of Flow Switch PC-FS-11 on Division ll H2/02
analyzer
PM 01113 Oil Sample for Service Water Pump A
PM 01115 Oil Sample for Service Water Pump C
c. C_onclusions
inspectors observed procedural adherence, radiation protection, and ALARA practices
and found them generally good. Acceptance criteria were properly referenced and
followed. Cases in which data were not within acceptance criteria, or anomalies were
found, were dispositioned with problem identification reports and/or documentation on a
discrepancy sheet. The appropriate standards for initiation of problem identification
reports appeared to have been met when problems were encountered.
M1.2 Coordination of Midevele Outaoe and Resoonse Durina Snowstorm
a. insoection Scoce (71707)
During the midcycle outage, inspectors observed maintenance coordination of outage
activities, including response to an occurrence of heavy snowfall and wind which closed
routine access to the site for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and a complex modification of Z-sump, which
affects the standby gas treatment system.
b. Observations and Findinas
Maintenance, outage, and construction departments coordinated the midcycle outage.
Scheduling provided plant activity information and coordination. Outage management
responded well to challenges and changes to expected conditions.
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Throughout the outage, maintenance and plant management intervened with
i
engineering to implement required modifications to the Z-sump, a sump located under
'
the elevated release point which can cause standby gas system inoperablity if it is not
properly drained. Engineering was challenged to implement the modification in a timely l
manner due to changes in scope and requirements. Maintenance management provided
direct, proactive project leadership of the modification installation and identified several l
potential safety and scheduled issues and drove them to resolution. Generally strong l
problem resolution standards were demonstrated. Construction and outage
management were also involved in assisting with implementation of the modification.
l
On March 8, the licensee experienced heavy snowfall and high winds. The severity of
the weather conditions are described earlier in Section O1.3. The maintenance, outage,
scheduling and construction departments demonstrated strong proactive involvement
and coordination of all departments on tite to ensure adequate staff.
Plant, outage, maintenance, and construction management demonstrated strong,
proactive involvement in assuring personnel safety and logistic support for staff on site,
shifts were property assigned, priorities for work activities were appropriate, and offsite '
state and county officials were contacted.
c. Conclusions
Maintenance response to a snowstorm which blocked routine access to the site for over
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was outstanding. Two shifts of emergency response organization were formed
onsite as well as two shifts each of operations, security, and maintenance staff to
address plant operations, outage work, and effects of the snowstorm. For the majority of
activities, maintenance and the outage organization took on leadership roles and
properly prioritized and coordinated site activities.
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Plant Material Condition
a. Insoection Scoce (62707)
Inspectors assessed plant material condition.
b. Observations and Findinas
During plan of the day meetings, plant management identified specific areas, of the plant
where housekeeping did not meet management expectations and focused staff attention
l
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on continued diligence on improving housekeeping in various areas of the plant.
Inspectors had observed these areas during routine plant tours and found housekeeping
to be only adequate and therefore the plant manager issues were valid. None of these
areas included safety systems or components.
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l A 96-inch butterfly valve in the circu!ating water system failed in the closed position vehen
a set-screw failed, allowing the shaft key to translate and the valve shaft to become
l disengaged from the motor operator.
A station operator identified that, when Service Water Pump C was started, the pump ,
slightly moved on its foundation. Maintenance technicians performed troubleshooting i
actions and determined that three of the eight foundation bolts were loose. Operations
requested that the other service water pump foundation bolts be verified tight, and no
other bolts were found loose.
The licensee implemented a method of controlling shutdown cooling by using the
residual heat removal heat exchanger outlet valve (RHR-MO-128). This is a
nonthrottleable valve controlled by a keylock switch on the control room panel. The
valve is maintained in position by opening its power supply breaker at the motor control
center. The position is changed by closing the breaker for a specified number of
seconds, calibrated to percent of full stroke. Original plant design had the service water )
heat exchanger outlet valves (SW-MO-89A and -B) used for controlling shutdown 1
cooling, but the valves did not work due to river water corrosion effects, and the heat
exchanger bypass valves do not have adequate capacity.
c. Conclusions
in general, plant material condition was good.
M2.2 Circulating Water Valve Failure
a. Inspection Scooe (62707)
I
inspectors reviewed maintenance actions in response to a valve failure. I
b. Observations and Findinos
On March 21,1998, a 96-inch circulating water valve failed. Maintenance responded ;
promptly and identified that the valve stem had become disengaged from the motor
operator due to a set screw failure and the associated key backing out of the shaft.
Maintenance repositioned the valve and reassembled the spline on the shaft. They
added two set screws on the valve shaft to more securely attach the spline to the va!ve
l stem. Maintenance determined that the failure had occurred due to a combination of
l vibration of the open butterfly disk in a flow stream and installation practice by
l maintenance. The other similar valves on the circulating water supply were inspected
I and found in good condition.
l On March 23, after following up the licensee's activities, the inspector identified two l
concerns: that the set screws installed on the valve spline and shaft appeared to fit the
licensee's definition of a modification, but did not appear to have been evaluated and
documented as such; and the cause of the problem, vibration of the disk in the flow
1
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stream coupled with the improper installation of the key and setscrew, may extend to i
'
safety-related valves of similar design, such as the butterfly valves in the service water,
l reactor equipment cooling, and residual heat removal systems. The licensee had not
- inspected the safety-related valves of similar design and installation characteristics for a
! similar vulnerability. The licensee promptly inspected several butterfly valves in safety- 1
related systems which may be vulnerable to this failure and documented the
unauthorized modification on a problem identification report. The extent of condition
evaluation and inspections found no similar vulnerability on similar design safety related
valves. Engineering management noted that resolution of the condition report had not
yet concluded. Therefore, appropriate bounding of the extent of condition was not
expected before conclusion of the 30 days.
c. Conclusions
Maintenance responded promptly and provided a repair to a failed circulating water
valve. However, the valve was repaired with a modification without appropriate
administrative controls. The licensee did not verify safety-related valves with similar
designs until after inspector involvement.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Licensee Event Reoort 50-298/96-013-00 and -01: Inoperable high pressure ,
coolant injection system due to control oil leak on turbine stop valve actuator. Upon l
investigation, the licensee determined that the leakage originated from the bolted flange. l
The licensee concluded that the apparent cause was overtorquing in 1991. The
overtorquing resulted from a lack of adequate guidance in the procedure used to l
reassemble the hydraulic actuator. The procedure directed the bolts be tightened as
opposed to being torqued to the vendor specified value.
The licensee implemented the following corrective actions: (1) reviewed maintenance
procedures and identified 114 procedures which used the word tighten; (2) based on i
reviews of the procedures, vendor manuals, and using experienced maintenance
personnel, the list was narrowed to seven procedures that needed to be revised; l
(3) placed the seven procedures on administrative hold until revised to include a torque
value; and (4) visually examined the accessible components of the seven procedures for i
signs of overtorquing or looseness.
The inspectors reviewed these corrective actions and determined that no process had
been put in place to ensure revised or new procedures correctly used the word tighten.
Also, the criteria used to determine if the word tighten was appropriate was not
documented. Through interviews with the maintenance personnel who performed the
review, the inspectors determined that, if the vendor manual did not call out a specific ,
l
( torque valve, the word tighten was considered appropriate. The inspectors performed a
word search and identified 12 additional maintenance procedures beyond the 114
identified by the licensee that used the word tighten. The inspectors reviewed two of
f these procedures and identified that Procedure 7.2.47, "MSIV Air Manifold Removal,
l
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o I
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Overhaul, Testing, and installation, " Revision 8, used the word tighten, but the vendor
manual recommended a torque valve of 15 ft/lbs.
The licensee did not follow up on verification that the inaccessible components affected
by the seven procedures were visually examined, nor that a long-term action was put in
place to replace the fasteners requiring controlled torque values.
In summary, although the !icensee performed corrective actions, only maintenance
procedures were reviewed and inspectors found 12 additional affected procedures.
Administrative controls had not been implemented to preclude future inappropriate
guidance for tightening fasteners. Permanent corrective action or controlled fastener
installation in the plant were not scheduled or performed.
The failure to implement procedural guidance with appropriate torque values to prevent
overtorquing and causing the high pressure coolant injection system to become
inoperable is a violation of 10 CFR Part 50, Appendix B, Criterion V, which requires that
activities affecting quality be prescribed by procedures and instructions appropriate to the
circumstances (50-298/98002-02). This licensee-identified violation is being cited,
because the inspectors identified that the licensee's corrective actions were not
adequate.
Conclusion
The licensee failed to properly implement corrective actions for inadequate torquing i
instructions which had caused safety system inoperability. Administrative controls were
not implemented to ensure the word tight or tighten would be used appropriately in new
or revised procedures, the licensee failed to identify all maintenance procedures affected
by the concern, and no permanent corrective action for uncontrolled fastener installations
were addressed.
M8.2 (Ocen) Violation 50-298/97006-01: Failure to follow Technical Specifications and
inadequate procedure for re-inerting. This violation consisted of two examples of
inadequate procedures. In the first example, no procedure allowed the use of installed
24-inch valves for inerting. The second example involved Procedure 2.1.1, "Startup
Procedure," and allowed the operators to place the mode switch in the startup/ hot-
standby position prior to performing the daily jet pump operability check contrary to the
Technical Specifications. This review only addressed the second example associated
with Procedure 2.1.1.
One of the corrective actions associated with the second example was performance of a
review of the Technical Specifications to identify all operability verifications required prior
to a mode change consistent with Technical Specifications. This action was to be
completed by September 2,1997. Procedure 2.1.1.2, " Technical Specification Pre-
Startup Checks," was to be revised to incorporate all of the operability verifications
identified by the Technical Specification review by October 15,1997. Condition
Report 97-1075 documented and tracked the corrective actions for this violation.
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.
On March 11,1998, the licensee identified that Procedure 2.1.1.2 required the average
power range monitors to be tested monthly, although Technical Specifications required a
weekly test. The licensee initiated Condition Report 98-0214. On April 6,1998, the I
'
licensee issued Problem identification Report 2-27100 to document inadequate
corrective actions associated with Condition Report 97-1075. The problem identification
report was closed as a trend item with no actions required. In the evaluation section of
Condition Report 98-0214, a discussion on the failure of Condition Report 97-1075 was
given, but no corrective actions were listed to address why Condition Report 97-1075 l
I
missed the average power range monitors surveillance requirements or to address the
potential extent of condition.
The failure to identify and correct procedures to test the average power range monitors
prior to a mode change as stated in the licensee's response to the Notice of Violation for i
Violation 238/97006-01 is a violation of 10 CFR Part 50, Appendix B, Criterion XVI, which
requires for significant conditions adverse to quality that actions be taken to prevent
recurrence (50-298/98002-03).
This item remains open pending verification of actions for the inadequate procedure for
re-inerting primary containment with the 24-inch valves.
Conclusion
Corrective actions for a violation for the failure to require verification of Technical
Specification operability were not comprehensive. The licensee did not identify all
operability verification requirements during the corrective action process.
M8.3 (Closed) Licensee Event Reoort 50-298/98-C04: Average power range monitors were
not tested as a result of failure to implement a Technical Specification amendment. This
issue is related to the concern described above. On March 11,1998, a problem
identification report (Condition Report 98-0214) was written to determine if the applicable
surveillance requirements were being met for average power range monitors prior to
placing the mode switch in run. The investigation determined that during the December
1995 startup from Refueling Outage 16 and the May 1997 startup from Refueling Outage
17 the mode switch was placed in the run position prior to testing the average power
range monitors within the required one week.
The corrective action section of the licensee event report stated that as immediate
corrective action the procedure was placed on administrative hold pending revision to be
completed by June 2. The discovery date was March 11, but the procedure was not
placed on administrative hold until April 9. The inspectors confirmed that the procedure
was not used from March 11 to April 9. The inspectors questioned the adequacy of the
corrective actions documented in the licensee event report since it indicated that only the
specific problem was fixed, and no actions were identified to prevent a similar problem
from recurring.
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The inspectors reviewed the licensee's Condition Report 98-0214 to determine if more
corrective actions were planned. ' It documented several actions that, when completed,
!- would prevent the problem from recurring. For example, operations would be required to -
I perform a comprehensive review of procedures to identify all operability verifications
required prior to a mode change, the work control center would be required to review
plant records associated with Technical Specification surveillance required for plant l
startup to verify no other requirements were missed, and operations management would
be required to conduct a lessons-learned briefing for each shift. Corrective actions are
scheduled in the licensee action tracking list, with appropriate administrative controls.
These actions and others documented a strong seif-critical review of the condition which
was not documented in the licensee event report. These actions have been completed
l or are in the licensee's action item tracking system.
The failure to perform surveillance testing on the average power range monitors prior to
placing the mode switch to run in December 1995 and May 1997 is a violation. This
nonrepetitive, licensee-identified and corrected violation is being treated as a noncited
violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(50-298/98002-04).
M8.4 (Closed) Violation 50-298/97011-02: Failure to follow procedure and inadequate
procedure. Inspectors identified that the standby gas surveillance testing procedures
allowed nonconservative testing to determine if the system was operable. Other j
inadequacies were found. The licensee corrected these specific findings, but further
work to identify the extent of condition was not performed. Subsequently, an NRC
inspection found further problems, which were cited separately. Also in this violation,
inspectors identified that the licensee failed to follow procedure requirements to promptly
evaluate problem identification reports by condition review groups in that 23 reports were
not evaluated within about a month. These reports were part of a specific initiative to
address problem identification, and were collected as a group over time. Since this
occurrence, the licensee has re-emphasized the need to promptly evaluate reports.
Additional examples have not been noted.
111. Engineering
E2 Engineering Support of Facilities and Equipment
. E2.1 Nonconservative Bias in the Fuel Ranae Level Indicators
a. lasoection Scooe (37551)
Inspectors evaluated the parameters used by operators during ernergency operating
procedures to determine vessel level in the fuel range and make decisions on when
reactor vessel depressurization should be performed.
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b. Observations and Findinas
On March 31,1998, the inspector questioned if the fuel range level parameters
accurately reflected the vessel level with respect to the top of active fuel. Original
procedures assumed a fuel height of 144 inches and the length of active fuel had been
changed from the original 144 inches to 150 inches. The inspector questioned if the
reactor vessel level parameters had been altered to reflect the changed height of the top
of active fuel. Technical Specification Figure 2.2.1 identified a height of active fuel as
144.00 inches and the core spray permissive setpoint as -39 inches as relative to top of
active fuel. Also, Level Indicator Ll-91 measured the reactor vessel level above active
fuel and has not been altered since installation. The inspector noted that, although this
would provide 6 inches less submergence over active fuel, the licensee had verified that
the design basis accident analysis had evaluated core uncovery at the -29-inch level
consistent with the lower edge of the jet pump nozzles regardless of fuel height in i
General Electric accident analysis.
On April 2, the inspector questioned if the correct reference point for top of active fuel in
the plant was zero on Level Indications Ll-91 A, -B, and -C. The application of these
reactor vessel water level parameters are provided in Emergency Operating
Procedure 2A RC/L-14. Operators must wait to depressurize the vessel until reactor
water level drops to the top of active fuel; if reactor vessel injection is available,
emergency pressurization occurs. If reactor vesselinjection is not available, steam
cooling is required and the reactor vessel remains pressurized while water level is
allowed to drop to -40 inches (0 inches is top of active fuel). This value of -40 inches
appeared to be dependent on the General Electric-provided fraction of 150-inch fuel
which must remain covered by liquid in order to assure peak centerline temperature
remains below 1800 F.
Operations review of Emergency Operating Procedure Calculation NEDC 89-1843,
Revision 1, stated that 150-inch fuel had been considered during the calculation. This
calculation stated that it determined various reactor vessel pressure level variables to be
used in emergency operation procedures, including minimum core flooding interval, the
maximum core uncovery time limit, the minimum steam cooling reactor vessel pressure
level water level, and the minimum no injection reactor vessel pressure water level. This
calculation noted that the water level of the reactor vessel pressure level at the top of
active fuel was that listed in Technical Specification Figure 2.1.1, and that water level,
considered zero on Level Indicator LI-91, is based on a 144-inch fuel length. Current fuel
length is 150 inches and this length is reflected as the minimum length of active fuel in
this calculation. The linear heat generation rate of 14.4 kw/ft is referenced by Calculation
DC 90-152, CNS Cycle 14, Reload 13, Design and Safety Analysis.
The generic parameters associated with BWR Owner's Group, emergency planning
guides, were listed in the calculation. Specifically, the minimum active fuel length fraction
which must be covered to maintain peak center line temperature less than 1800 F
without injection in percentage was 70.83 percent. The calculation to determine the
l length of fuel which may be uncovered relative to water level from the top of active fuel
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concluded that, given a ratio of this percentage relative to 150-inch fuel, a water level of
-43.8 inches would be the lowest level i.n which peak centerline temperature would
remain less than 1800 F. Emergency Operating Procedure 2A allowed steam cooling in
the core in absence of injection until water level drops to -40 inches.
On April 3, design engineering concluded that the several inches of inactive uranium
reflector added to the top of the fuelin the new design could be credited as margin.
Based on this, the licensee concluded the issue was not significant.
In response to these issues, operations generated a problem resolution matrix
documenting several outstanding questions and contingencies to be taken upon answers
received for each of those questions. These questions included the inspectors'
'
questions, plus several others. Further, the shift technical engineers identified the need
to review the basis for other reactor vessel water level parameters and other water level
dependent considerations. Examples would be low and high water level trips and
minimum core reflooding interval.
On April 7, engineering stated that when zero was indicated on Level Indicators Ll-91 A,
-B, and -C, the actual water level in the reactor was 6 inches lower than the top of active
fuel as defined in emergency operating procedure calculations. The licensee stated that,
because the 150-inch fuel had 6 inches of reflector on both top and bottom of fuel, this
distance was not significant. The inspector raised the issue that, for the case of the
1800*F peak centerline temperature limit, the required fuel coverage was 70.89 percent.
A 6-inch bias applied in the negative direction would result in fuel becoming uncovered.
The licensee stated that the issue of exceeding 1800 F peak centerline temperatures
involves an event beyond design basis.
The licensee did not address: (1) the nonconservative aspect of the plus or minus l
calibration tolerances on Level Indicator LI-91 manual action points, nor was I
nonconservatism associated with instrument error or calibration instrument error l
addressed; (2) the calculation of core uncovery time which had changed due to the i
relative change of top of active fuel to wide range level zero; and (3) the calculations
associated with volume required at specific vessel levels for boron dilution during an
anticipated transient without scram event and subsequent boration or emergency l
boration, as well as commitments to the NRC regarding implementation of BWR Owner's '
Group Emergency Operating Procedure Guidelines associated with 1800*F fuel
l temperature limits.
l Other areas the licensee did not address included parameters used in generic vendor
calculations. General Electric Service information Letter 529, Supplement 1, dated
l
l
! March 14,1997, described the need for fuel design specific input parameters to be used
i for Appendix C to Emergency Procedure Guidelines, Revision 4, for General Electric 8x8
and 9x9 fuel designs. The service information letter describes steam cooling-related 1
parameters to emergency operating procedure calculations including: (1) the minimum i
length for active fuel which must be covered to maintain peak critical temperature less l
than 1800*F without injection into the reactor pressure vessel, (2) minimum bundle j
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steam flow required to maintain peak critical centerline temperature less than 1500'F for
an uncovered core, (3) maximum time before peak centerline temperature exceeds
l 1500*F for an uncovered core referenced to POHGH equal 13.4 kw/ft, (4) the cold
l shutdown boron concentration requirements, and (5) the hot shutdown boron
concentration requirement. The emergency operating procedure parameters ultimately
effected by these concems were listed as the boron injection initiation temperature, cold
shutdown boron wait, peak capacity level limit, heet capacity temperature limit, hot
shutdown boron weight, minimum alternate reactor pressure vessel flooding pressure, l
minimum core flooding interval, maximum core uncovery time limit, minimum number of
safety relief valves required for emergency depressurization, minimum reactor pressure
vessel flooding pressure, minimum steam cooling reactor pressure vessel water level, j
minimum zero reactor pressure vessel water level, peak centerline temperature,
pressure-suppression pressure, and peak linear heat generation rate. The licensee had
addressed only the top of active fuel parameter.
The licensee issued Problem Identification Report 2-27287 to document that an apparent
discrepancy existed with the 0-inch level assumed as the top of active fuel in the vessel.
The licensee noted that 150-inch fuel potentially extended to above the zero level.
The licensee evaluated the safety significance of the 6-inch nonconservative bias.
Vendor testing had found that fuel peak centerline temperatures of 1800"F would not be
reached until vessel water level dropped below -70 inches (below top of active fuel). The
licensee performed an evaluation which considered various instrument errors, including
errors expected in a harsh equipment qualification environment. They found that the
1800*F limit would not be reached even with the 6-inch nonconservativa instrument bias.
The failure to incorporate the correct fuel length design requirements in plant emergency
operating procedures is an example of a violation of 10 CFR Part 50, Appendix B,
Criterion ill, which requires, in part, that the design basis correctly translated into
procedures (50-298/98002-02).
Additional questions which remain to be resolved include: (1) Technical Specification
Interpretation 96-003 which documented that the fuel length indicated in Technical
Specification was 144 inches, although the Updated Safety Analysis Report stated that
active fuellength was 150 inches. The resciution associated with the interpretation
concluded that the conversion to improved Technical Specifications would remove the
associated figure which showed the top of active fuel relative to the 144-inch active fuel ;
length. The recalculation of setpoints for improved Technical Specification would be l
done in accordance with General Electric setpoint methodology and instrument zero l
would be redefined as a fixed point above the fuel which will be defined for the purposes I
of level monitoring as top of active fuel. The interpretation stated that the reference in j
the Technical Specification bases was not a basis for the limiting safety system setting I
and that safety margin for transient and accident analysis was maintained through ,
administrative controls such as higher trip setpoints and emergency operating j
procedures. This Technical Specification request dated June 8,1996, stated that the '
safety limit was maintained regarding General Electric setpoint methodology. Inspectors
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noted the bases for the top of active fuel measurement in the emergency operating
procedures appears to be based on Level Indicators LI-91 with the top of active fuel
equal to zero. Also, the licensee's emergency operating procedure calculation process
failed to properly consider the change in fuel length.
Inspectors reviewed Surveillance Procedure 6.RHR.305, "RHR Reactor Vessel Shroud
Level Indication Calibration," Revision 1, which required the zero point for Level
Indicator Li-91 A to be set at 381 inches. Technical Specification noted that the zero level
for this indicator was 351 inches. This indicates approximately 30 inches of water over
the top of active fuel when Level Indicator Ll-91 A reads zero. This issue will also be
followed in the closure of the violation.
c. Conclusions
The length of fuel had been increased from 144 to 150 inches. The licensee failed to
change the reference point for the top of active fuel on fuel range level indicators and
improperly performed changes to emergency operating procedure parameters. This
caused a nonconservative bias in the fuel range indication of 6 inches. The licensee
evaluation concluded that, although this bias was nonconservative, it did not exceed the
existing design margin.
E2.2 Imorocer Requirement to Throttle Core Sorav Flow Durina Loss of Coolant Conditions
a. Insoection Scoce (37551)
Inspectors followed the licensee's actions to correct procedures which had required
improper throttling of core spray flow under accident conditions.
b. Observations and Findinos
A licensee engineer identified that an emergency procedure specified that core spray
flow should be throttled back to 4750 gpm per pump (total of 9500 gpm). The Updated
Safety Analysis Report required total core spray flow of 12,000 gpm (two pumps) under
design bases conditions. The licensee issued Prcunm Identification Report 2-26684
documented by Significant Condition Adverse to Quality 98-0197 to address this issue.
The licensee identified that flow had been throttled to adcress diesel fuel consumption
concerns and keep the fuel consumption rate below that specified by a load study. The
safety analysis requked that, for the first 400 minutes of a design basis accident, full core
spray flow of at least 12,200 gpm be prcvided for core reflood. The licensee corrected
the procedure to require operators to ensure full core spray flow to the core for the first
10 minutes of an event and to stipulate that flow be throttled back after that only if core
reflood had successfully occurred.
The licensee reported this issue in accordance with 10 CFR 50.72, as a potential
unanalyzed condition. This issue will be followed in the closure of the licensee event
report.
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l c. Conclusion
Procedures for use during a loss of coolant accident and loss of offsite power directed
that core spray be throttled to 4750 gpm per pump, although 6100 gallons were required
for core coverage by the Updated Safety Analysis Report accident analysis.
E2.3 Inaccuracies in Emeraency Procedure for Diesel Generator Loading
a. Insoection Sepoe (37551)
Inspectors reviewed Procedure 5.2.5, " Lose of All Site AC Power - Use of Emergency AC
Power," Revision 31, and held discussions v/ith operations and engineering personnel.
b. Observations and Findings
The inspectors reviewed the instructions in Procedure 5.2.5, regarding electrical load
controls. Engineering had provided load profile line items so the diesel generator loads
could be outside design calculations. One instruction in the procedures indicated that
diesel generators could be run at 4,000 kw (nameplate rating) for up to 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> and up
to 4400 kw for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> without exceeding design requirements.
However, an attachment indicated that diesel generators could be run only within
particular load limits it listed all motor control centers with letter designators and, further,
referenced a table to indicate how long each particular load was allowed to be run and
for what times during the accident. This attachment referred to the loads being used as
" Load Study for Diesel Generators." Further evaluation found that this load study
represented the design basis condition where only one diesel generator was running and
loads were maintained in a manner to ensure Technical Specifications 7-day fuel
inventory requirements and diesel loading limits were followed.
1
The inspectors considered that under the design basis event for which the design 7-day !
Technical Specification fuel inventory was based (loss-of-coolant accident with loss of
'
one diesel), operators were not likely to follow Procedure 5.2.5 until about 20 minutes
into the event. Further, operations considered these design basis diesel loading limits to
be guidelines, as stated in the procedure, rather than a limit or procedure which must be
followed. On the other hand, engineering stated that the basis for the validity of the
7-day fuel inventory requirement was the implementation of the diesel loading profile as
stated in Procedure 5.2.5.
The inspectors questioned if engineering had provided adequate instructions to
operators to ensure diesel loading would remain within fuel consumption assumptions in
design basis conditions. Operations acknowledged that, in an event situation, following
the table and load study may be cumbersome. The inspector considered the
26 specified chronolegy requirements for each load, and the use of a single dieselload
i
profile for a particular accident, as a basis for allload profile requirements and accidents j
l to be cumbersome and potentially confusing. Operations agreed that a more favorable
I
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format would be helpful.-These :: uce '.;"! be revice :d !a fe!!cefup c/mssassue This
issue is unresolved (50-298/98002-05).
c. Conclusions
Engineering failed to implement clear instructions for controlling the electrical load profile
in emergency operating procedures. This profile is the basis for the Technical
Specification 7-day diesel fuelinventory requirement. Operations had not been
instructed that this profile must be used if the design basis loss-of-coolant accident
occurred. I
E2.4 Paintina Without Procer Evaluation of Effect on Standbv Gas Treatment System
a. Insoection Scoce (37551)
Inspectors questioned the effects of paint fumes on the standby gas treatment system.
Discussions were held with operations and engineering personnel.
b. Observations cnd Findinos
On February 11,1998, the inspector identified that painting activities in the reactor i
building caused significant fumes. Examination of the paint can labelidentified several
ether and acrylate-based compounds which would indicate volatile components.
Discussions with the systems engineer indicated that water-based painting was allowed
for about 10 gallons of paint in a drying status. The inspector questioned if the standby ,
gas treatment charcoal was vulnerable to effects from the volatile components of the l
water-based paint in use.
On March 9, the licensee stated that, since the majority of the organics were light-weight,
these organics would enter and then clear the standby gas treatment system in a
relatively rapid fashion, whereas the smaller fraction of large organics would have a
longer-term effect. Therefore, engineering determined that the total effect was not
significant.
On March 18, in response to inspection questions, the licensee identified that the fraction
of larger organics and the affect on standby gas treatment system operability may have
been greater than previously anticipated. When informed of this condition, the inspector
asked why a problem identification report had not been generated several days prior
when the condition was initially discovered and why the control room had not been
informed that the original operability evaluation was no longer valid.
To address operability concerns, engineering evaluated ventilation flow paths which had
occurred during the painting evolution and found that predominantly, normal ventilation
had removed organic fumes. Engineering determined that a small fraction of organics
may have been entrained in the standby gas treatment system charcoal. Engineering
issued Problem Identification Report 2-19345 after discussing these concerns with the
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inspectors. To date, the licensee had not documented a basis for standby gas treatment
operability had a design basis event occurred during painting activities in the reactor
building.
l
On February 11, the painting was reduced to limits bounded by oil painting. Later
painting in the reactor building was suspended pending results of the charcoal sample
review.
The failure to incorporate controls for paint with a significant fraction of organics,
potentially affecting the standby gas treatment system, is an example of a violation of
10 CFR Part 50, Appendix B, Criterion V, which requires in part that activities affecting
quality be prescribed by procedures appropriate to the circumstances
(50-298/98002-02).
c. Conclusions
Controls for painting inside the reactor building were inadequate. The licensee did not
recognize that some paints contained an unacceptably high percentage of volatile
organics. The initial evaluation and restrictions on the painting, as well as the evaluation
of the effect of this painting on standby gas treatment, did not accurately address the
technical issue or the iodine release profile, and the control room was not informed of
later developments.
E2.5 Z-Sumo Modification Concerns
a. Insoection Scoce (71707)
Inspectors reviewed portions of the Z-sump modification procedures changes and
problem identification reports, attended station operations review committee meetings
associated with these procedure changes, and held discussions with operations, t
engineering, and management.
b. Observations and Findinas
The licensee had identified that the Z-sump and equipment required modification
because it did not meet seismic design requirements. For the modification to correct the
system design weakness, several mechanical, electrical, and instrument and control
installations were performed to support redundant sump pumps and level indications.
Several operating procedures were changed. Under freezing temperatures, absence of
heat trace for over 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> would make the standby gas treatment system inoperable.
The heat trace is normally powered by a nonessential bus. After the procedure changes
were approved, the inspectors noted that no alarm response procedures, abnormal
procedures, night orders, or system operating procedures had directed operators to
respond to a loss of the nonessential power to the essential heat trace providing an
essential power source.
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Operations acknowledged this lack of guidance and initiated changes to night orders, l
abnormal procedures, system operating procedures, and annunciator response
procedures. The inspector observed that, for these examples, engineering had failed to
identify these procedures affected by the modification.
Discussions with operations management indicated that they recognized the concern )
that operations demand more effective action from engineering regarding installation
modifications. No problein identification report was initiated to address engineering
failure to correct all procedures affected by the heat trace requirement. ,
The failure of engineering to identify procedures affected by the Z-sump modification is
contrary to Procedure 3.4.3, Revision 14, which requires that affected procedures be
identified by the modification package. This concern, along with findings by an
engineering inspection team reviewing this modification, and the licensee's corrective
actions for this concern, will be followed by an unresolved item (50-298/98002-06).
The inspector also identified that, although soil compaction testing was scheduled for
areas of excavation for the conduit, in order to confirm that rain and water table moisture
had not degraded the soil compaction over time, no testing was planned to verify if the
soil near the Z-sump, under the elevated release point, had remained compacted. The
area under the elevated release point is flooded for days at a time in high river level
conditions. Engineering promptly ordered this testing, which concluded satisfactory
compaction.
c. Conclusions
For a modification to the Z-sump, engineering did not identify all affected operating
procedures. Inspectors found that, if the nonessential power to the essential heat trace
was lost due to electrical component failure, no requirements or actions were provided to
operators in abnormal or alarm response procedures to respond to this loss.
E2.6 Portion of Service Water Pioino for Residual Heat Removal System Not Analyzed For
Air-Filled Condition
a. Insoection Scoce (37551)
,
inspectors evaluated the engineering response to portions of the essential service water j
system and residual heat exchanger being found filled with air instead of water. )
.
b. Observations and Findinos
The residual heat removal service water system is provided with service water flow from
service water pumps. Service water booster pumps boost flow through the residual heat I
removal heat exchanger to the outfall. Discharge check valves are installed at the
discharge of each booster pump. On December 18,1997, the licensee identified that the i
piping downstream of the service water booster pump discharge check valve
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(SW-CV-19CV) was not filled with water, i.e., air was found when drains and vents were
opened to determine the condition of the piping. The licensee postulated that the check
valve had become stuck and did not allow flow through the piping via the service water
booster pumps. Disassembly of the check valve did not identify the reason for the check
valve to have stuck shut, nor did it confirm that the check valve was stuck shut. The
licensee initiated twice-weekly thermal acoustical monitoring of the piping to determine if
the condition repeated. The licensee concluded that the service water piping and the
heat exchanger were operable while filled with air.
Based on the inspectors' questioning of the licensee's conclusion, the licensee
determined that no analysis was in place to substantiate that the piping and system were l
operable when filled with air downstream of the check valve. On March 4, the licensee I
initiated engineering information document EFOM 98-005 to document the need to verify l
operability of the downstream piping by twice weekly acoustical monitoring. On l
March 12, the inspectors identified that engineering had not updated the operability
evaluation and that the control room was unaware that monitoring was required to assure
operability.
On April 6, the inspector questioned why the piping being in an unanalyzed condition
was not reportable. The licensee concluded that a contractor evaluation would show the
piping had been operable. This issue will be followed by an inspector followup item to
review the licensee's conclusion of operability of the system in the air-filled condition (50-
298/98002-07).
c. Conclusions
A portion of the service water piping and the residual heat removal heat exchanger was
found filled with air rather than water during power operation. The licensee concluded
the piping was operable. Operability of the system piping was not demonstrated by
analysis or calculation. Compensatory actions to demonstrate operability were not
provided to the control room in a timely fashion and the operability evaluation was not
corrected to reflect the operability assessmerit of the as-found condition of the piping
until 3 weeks later.
E2.7 Potential Effect of Hich Torus Level Allowed by Emeraency Operatina Procedures Not
Addressed
a. Insoection Scoce (37551)
inspectors reviewed the basis for torus level with respect to the design limits of critical
components. Inspectors reviewed procedures, corrective action documentation, and
design information; observed simulator scenarios; and held discussions with engineers,
operators, and rnanagers.
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b. Observations and Findinas
l On March 30,1988, the inspector questioned procedural controls for the torus level with
l respect to the design requirements for critical components. Engineering had identified
that the torus strainer penetrations had nonconservatisms in their calculations and that
the hydrodynamic loading was analyzed only when torus level was 2 inches or less. The
j inspector noted that emergency operating procedures allowed a torus level to increase of
37 inches before an emergency depressurization was required. This indicated that the
plant could be vulnerable when the torus level was high.
On March 31, the inspector held discussions with operations, emergency operating
procedures staf' and structural engineering staff. Emergency operations procedure staff
l stated that the 37-inch limit was based on the limit of hydrodynamic loading on the
l safety-relief tail pipe T-quenchers for a manual blowdown via the safety relief valves.
l
'
The engineering staff was unaware that the emergency operating procedures allowed
increase of the torus level to 37 inches, before plant depressurization was required.
On February 7, the licensee stated that the hydrodynamic loading on the strainer
penetrations had been addressed by General Electric and documented in proprietary
information regarding the details of the limiting components of the torus structure.
According to the licensee, the BWR Owner's Group committee stated that large loss-of-
coolant-accident loads would be acceptable for high torus water levels not exceeding the
bottom ring header in Mark I containments. Therefore, the decision that loading on the
T-quenchers was more limiting at high torus levels than loading on the strainer
penetration was based on proprietary information held by the vendor. The licensee did
not provide documentation of this conclusion.
I
No rigorous, dynamic, or hydrodynamic load calculations beyond the Mark I program
l assessments had been performed by the licensee. The licensee stated that probabilistic
risk analysis had typically not considered hydrodynamic loading. The licensee's
- evaluation to resolve the issue addressed three scenarios associated with high torus
level: a design basis loss-of-coolant-accident, a reactor pressure vessel breach, and an
l
anticipated transient without scram greater than 6 percent power. The inspector asked if
the emergency procedure scenarios run on March 18,1998, as well as the licensee's
event in early August 1988, involving an increase in torus level above analyzed level,
were bounded by these 3 analyses. The licensee acknowledged this should be
addressed.
l A conference call on April 24 discussed these concerns among the licensee, General
Electric, and the BWR Owners Group. The participants concluded that further evaluation
was required. This resolution of the issue will be followed by an inspector followup item
I' (50-298/98002-07),
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c. Conclusions
The licensee failed to reconcile the design requirements for torus level to remain below
2 inches and the emergency operating procedures which allow a torus level up to l
37 inches.
E2.8 Inadequacies Associated with Plant Temocrarv Modifications to Feed Pumo Controller
a. Insoection Scoce (37551)
The inspectors reviewed the engineering evaluation and proposal for temporary plant
modification and the associated station operations review committee approval.
Inspectors held discussions with engineers and engineering management. l
l
b. Observations and Findinas l
On March 27,1998, the inspectors observed review and approval of a plant temporary I
modification to monitor a controller circuit on the Feedwater Pump B controller. The !
inspectors noted that several potential vulnerabilities had been addressed and properly
evaluated with the following exceptions:
1. The heat generation due to the temporary equipment in the cable spreading room l
had not been addressed under abnormal or emergency conditions in which
ventilation would be changed.
2. Power sources had not been evaluated with respect to the effect on vital or
nonvital circuits and the resultant effect on power consumption.
3. Radio frequency interference from cellular phones was not addressed. The
temporary modification had considered the radio frequency interference from
plant security radios, and guidance had been made to make jumper connections
as short as possible to minimize the chance of interference.
In response to these concerns, the engineers identified that heat generation and power
consumption were not an issue, since this was well within design margins. Engineers
identified that the cellular phones operated at a frequency of 900 megahertz. This
corresponded to an optimum antenna length of approximately 30 cm. Since this length
was similar to the length of jumper wires, and engineers had not evaluated the use of
cellular phones near the recorders, the inspector raised a concern that no specific
instructions or bounding analysis had been done to ensure cellular phone interference
would not affect feed pump control circuitry.
The plant manager directed a review of the cellular phone radio frequency testing to
determine if routine surveillance testing using test equipment and jumpers had been
addressed. Engineering concluded that the radio frequency testing had not addressed
jumper configurations expected in routine surveillance testing and that vulnerabilities ,
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jumper configurations expected in routine surveillance testing and that vulnerabilities
existed if cellular phones were placed in contact or in near contact with unshielded
jumpers. The licensee is developing specific calculations and administrative controls for
the concern. Problem Identification Report 2-01365 addresses this issue.
c. Conclusions
1
The inspector identified failures to consider potential vulnerabilities of temporary
modification to design basis and radio frequency challenges. The plant manager
demonstrated ownership and a questioning attitude to also require engineering
evaluation of potential cellular phone radio frequency effects on jumpers used in routine
'
surveillance testing, q
l
E2.9 Enaineerina Evaluation of Water in a Diesel Fuel Od Dav Tank l
l
a. Insoection Scoce (37551) {
inspectors followed the licensee's response to finding water in the diesel fuel oil day tank.
Inspectors reviewed procedures and held discussions with operators, engineers, and '
managers.
b. Observations and Findinas
On ' March 23,1998, the licensee had identified that Diesel Fuel Oil Day Tank 2 had
collected approximately 90 ml of water. The licensee initiated Problem identification
Report 2-27175, dated March 24, to document the concern. The licensee took no action
to check the redundant fuel tank to determine if a similar condition existed until after the
inspector raised questions on March 24. Operations promptly added procedural
guidance to consider checking the alternate fuel tank for generic effects, performed a
check, and found no water in the alternate fuel oil tank. Operations issued Problem
Identification Report 2-27177 to document a need to be sensitive to the potential that a
generic concern may exist on the opposite diesel generator fuel oil day tank.
System engineering determined that the water was less than 0.5 percent of the volume
of the day tank and therefore within specifications of dissolved water and suspended
solids associated with the larger tanks and incoming fuel. Inspectors determined that l
engineering did not understand the difference between dissolved and suspended water
'
in fuel oil. They were unable to provide a basis for concluding that the fuel in the day
tank did not exceed the 0.5 percent limit. Inspectors concluded that suspended water,
rather than dissolved water, was being measured, based on use of a centrifuge testing
method. Therefore the inspector was able to conclude that a reasonable basis existed
for the operability of the fuel in both the day tank and the 2,000 gallon tank. The licensee
did not identify the source of water. i
l
When operations found the water in the fuel, the system engineer was informed in l
accordance with the procedure. Operations requested engineering to provide an !
1
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operability acceptance criteria with respect to the amount of water found. The system
l engineer declined to provide an acceptance criteria stating that informing system
l engineering would provide adequate technical support to make an operability decision.
!
Since water had been found in only three cases over the past several years, the system
engineer concluded that a detrimental effect on the fuel was unlikely. The engineer was
unable to provide a basis for this conclusion,
c. Conclusions
Engineering demonstrated weak support of an issue regarding a small amount of water
found in the diesel fuel oil day tank. After discovery of water in one train of the diesel fuel
oil day tank, the licensee did not promptly check for water in the redundant train until
after inspector questioning a day later.
l E4 Engineering Staff Knowledge and Performance
E4.1 Enaineerina Evaluation of Fluctuating Safety Relief Valve Tail Pioe Temperatures
a. Insoection Scoce (37551)
l
Inspectors reviewed engineering actions and evaluations responding to a plant request
to evaluate the cause of a fluctuating safety relief valve tailpipe temperature. Inspectors
held discussions with operators, engineers, and construction personnel.
1
b. Observations and Findinas
On February 12,1998, the plant requested engineering to evaluate fluctuating safety
relief valve tailpipe temperatures. Review of this evaluation found that the engineer had
compared tailpipe temperature profiles during a downpower with a different plant having
leaking relief valves. The profiles did not match. Therefore the engineer ruled out the
potential of a leaking valve.
The inspector noted that the engineer assumed the leakage mechanism was the same
as another plant's mechanism, based on checking a single type of manifestation of l
leakage. The conclusion was based on comparison with one mechanism, without ;
independent confirmation of other parameters, such as trending torus temperature over i
l tirne. The engineer had not interviewed containment coordinators or looked at drawings
to determine if nearby equipment airflow or other artifacts of the containment mechanical 3
or electrical arrangement could have caused this e'fect. The engineer lacked an
understanding of the adiabatic expansion mechanism which could cause leaking steam
temperatures to rise or fall.
During the midcycle outage, a ventilator was found to be blowing directly on the
temperature sensor. This condition was corrected. j
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c. Cpoclusions
Engineering provided weak support in identifying and bounding the potential causes of
fluctuating safety relief valve tailpipe temperatures.
E8 Miscellaneous Engineering issues
E8.1 (Closed) Violation 50-298/96024-07: Multiple violations concerning implementation of
design changes in plant procedures. Inspectors identified examples where emergency
operating procedures did not properly implement design assumptions. The licensee
stated that design and licensing assumptions had not been properly implemented in
procedures. Specifically, the licensee identified that, before 1991, design changes had
not required review by operations and, therefore, some of the violations had occurred.
Inspectors identified that the licensee had not taken corrective action to identify the
extent of condition of those design changes which had not been properly implemented ,
due to the vulnerability of the process before 1991. The failure to identify whether other I
design modifications had been properly reflected in procedures is an indication that the
licensee did not take actions to preclude recurrence of this significant condition adverse
to quality. This is an example of a violation of 10 CFR Part 50, Appendix B,
Criterion XVI, which requires that conditions adverse to quality be corrected and the root
cause of significant conditions adverse to quality be identified and corrected to preclude )
repetition (298/98002-03).
Conclusions
The licensee failed to evaluate the extent of the condition of a violation for improper
incorporation of design modifications in emergency procedures.
E8.2 (Closed) Licensee Event Reoort 50-298/96-003-00 and -01: The reactor isolation cooling
system was declared inoperable due to a failed monthly operability surveillance test.
Upon the pump turbine start, speed initially increased to approximately 4500 rpm (normal
speed) but subsequently decreased and stabilized at approximately 2000 rpm.
Troubleshooting determined an erroneous output from the Woodward EGM control box.
The control box was replaced and the reactor isolation cooling system was satisfactory
tested.
The control box was sent to the vendor for examination and repair. The vendor
performed terts on the control box under the observation of a licensee quality assurance
inspector. The vendor was unable to determine a cause for the failure of the control box.
but did note that a varistor for input power protection only was missing. The vendor
stated that not having the varistor installed would not have caused the control box failure,
The licensee concluded that the root cause was unknown due to a lack of available
evidence or due to evidence unintentionally destroyed.
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The inspectors concluded that the reactor core isolation system failure was an isolated
event since no similar failures have occurred before or since this failure (March 20,
j
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1996). The inspectors identified an example of a weak root cause analysis, because the
licensee failed to evaluate the missing varistor as a loose part and a potential cause of '
the failure or additional failure vulnerability until questioned by the inspectors. Through
discussions with the current system engineer, the inspectors discovered that if the
varistor became loose it could have caused the control box failure. The varistor was
never found, nor does the licensee know when or how the varistor became missing.
Through discussions between the system engineer and the inspectors, the system
engineer stated that the varistor was most likely never installed, since the varistor was
l soldered in place (would not have fallen out), the control box was refurbished (removed
i during refurbishment and not replaced), and the varistor was never found (during
I troubleshooting maintenance or by the vendor),
i
!
IV. Plant Support
j R1 Radiological Protection and Chemistry Controls
R1,1 Interdeoartmentai Coordination to Reduce Dose
l a. Insoection Scone (7175Q)
i
l
l Inspectors reviewed work control initiatives to reduce radiation dose,
b. .Qb33rvations and Findinas
inspectors found that the work control group had initiated review of work activities to
determine if dose reductions could be obtained. Activities where potential reductions
l could be identified in planning stages were discussed with technicians and health
i physics personnel. These initiatives were implemented at the job site. Work control staff
'
j included these practices in the weekly lessons learned documentation to inform other
l
site personnel and document the progress of dose reduction efforts. Savings generally
amounted to a few millirem on each job.
I
c. Conclusions !
l l
The work control staff initiated interdepartmental dose reduction efforts, found dose
reduction opportunities, and documented results in weekly lessons leamed reports to
inform and provide expectations for site staff. I
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P Conduct of Emergency Preparedness (EP) Activities
P1.1 Resoonse to Severe Snowstorm
a. Insoection Scoce (71750)
inspectors observed EP organization response to severe snowstorm conditions.
b. Observations and Findinos
The emergency response organization responded to a severe snowstorm within minutes
after local sheriffs offices declared portions of a highway near the plant to be closed.
The licensee assessed the emergency response capability onsite and found that two
shifts of individuals were available onsite who could staff the response organization.
Most of the individuals held formal qualification in the emergency response organization
positions, the remainder were sufficiently qualified with interim qualifications.
c. Conclusions
During the snowstorm when routine access to the site was cut off for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the
emergency response organization promptly contacted state officials and assessed
personnel onsite to evaluate emergency response to fulfill requirements for two shifts of
an emergency response organization.
P7 Quality Assurance in EP Activities
P7.1 Quality Assurance in EP Activities
a. Insoection Scooe (71750)
Inspectors observed over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of technical support center (TSC) performance in a drill
and the subsequent debrief.
b. Observations and Findin.qS
The response during the drill appeared appropriate. Several weaknesses were
observed, none of which would preclude proper event response. During debrief after the
drill, the facilitatory provided and encouraged staff to discuss specific observations.
During the debrief, the TSC team reviewed past debrief strengths and weaknesses to
determine if improvements were being made from one drill to the next. During several
l prior debriefs observed, the emergency response staff did not refer to documentation of
! past emergency response team performance observations. This self-critical review of
lessons learned was led by the TSC director. When the inspector asked the EP staff
why this practice was not typical, they indicated facilitatory would encourage this practice
in the future.
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I c. Conclusions
After a drill response, the TSC conducted a self-critical review by comparing past drill
performance observations during the critique.
I
Si Conduct of Security and Safeguards Activities
S1.1 Security Resoonse to Severe Weather Conditions
a. Insoection Scooe (71750)
The inspector observed security response to reduced staffing and severe weather
conditions during a snowstorm.
b. Observations and Findings
Security entered into the security plan procedure appropriate to reduced staffing, heavy
weather conditions, and reduced visibility due to heavy blowing snow. Staffing
evaluation found they had approximately one and one-half security shifts. This was
adequate to provide staffing over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. During the event, guards appeared alert and
demonstrated appropriate responses and activities. Security coordinated effectively and
proactively with maintenance and operations to address conditions and put
contingencies in place to respond to potential challenges.
c. Conclusions
Security responded well to a severe snowstorm, reduced staffing, low visibility, and
isolated access conditions. Coordination with other site organizations was outstanding.
S1.2 Broken Lead Seal on Diesel Generator Fuel Tank A
a. Insoection Scooe (71750)
The inspectors observed licensee activities when a security officer reported a broken
seal on Diesel Generator Fuel Tank A. Discussions were held with security and
operations staff.
b. Observations and Findinas
On April 16,1998, a security officer reported to the control room that the seal for the
Diesel Generator Fuel Tank A inlet cover was broken. The control room supervisor
immediately had the seal replaced. The broken seal was retained for evaluation.
Chemistry performed a visual inspection, water test, and particulate test on the fuel.
Also, another sample was shipped to a laboratory to have the broader requirements of
Technical Specification testing performed.
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The security officer who found the broken seal reported to the control room that he may -
have caused the seal to break. The security officer explained that he felt the wire pull :
away from the seal as he tugged on the lead seal. 1
I
Based on the security officer's statement and the tests conducted, on site, the control l
room considered the diesel generators operable. I
c. Conclusion
Security responded appropriately to indications of a broken seal on a diesel fuel tank
inlet. )
)
I
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the exit
meeting on April 20,1998. 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.
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SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
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Licensee
L. Dewhirst, Licensing Engineer
C. Gaines, Maintenance Manager
M. Holmes, Shift Supervisor
B. Houston, Licensing Manager
J. Lewis, Acting Reactor / Fuel Engineering Manager
J. Long, Engineering Support Manager
L. Newman, Operations Manager
O. Olson, Containment Engineering Supervisor
M. Peckham, Plant Manager
J. Pellitier, Senior Manager of Engineering
E. Plettner, Engineering Supervisor
D. VanDerkamp, Assistant Operations Manager
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 92901: Followup - Plant Operations
IP 92902: Followup e Maintenance
IP 92903: Followup - Engineering
ITEMS OPENED, OPENED AND CLOSED, CLOSED AND REVIEWED
Ooened
298/98002-01 IFl Reactor equipment cooling heat exchanger operability in backwash
(Section O2.1)
298/98002-02 VIO Three examples of inadequate procedures or instructions (Sections M8.1, E2.1,
and E2.4)
298/98002-03 VIO Two examples of inadequate corrective actions (Sections M8.2, E8.1,)
298/98002-05 URI Failure to implement 7-day diesel fuel inventory design requirements in
emergency procedures (Section E2.3)
298/98002-06 URI Concerns in implementation of Z-sump modification (Section E2.5)
298/98002-07 URI Operability evaluation of service water system in air filled condition (Section E2.6)
298/98002-08 IFl Inconsistent controls on torus level regarding design requirements for limiting
components (Section E2.7)
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Ooened and Closed
298/98002-04 NCV Average power range monitors not tested when required (Section M8.4).
Closed
298/96031-01 VIO Failure to provide procedures for expected abnormal conditions (Section 08.1)
298/97011-02 VIO Failure to follow procedure and inadequate procedure (Section M8.4)
298/96-013-00
298/96-013-01 LER inoperable high pressure coolant injection system due to a control oil leak
(Section M8.1)
298/96-003-00
298/96-003-01 LER Inoperable reactor isolation cooling system due to a failed operability test
(Section E8.2)
298/98-004-00 LER Average power range monitors not tested when required (Section M8.4)
298/96-024-07 VIO Examples of inadequate implementation of design changes in procedures
(Section E8.1)
Status
298/97006-01 VIO Failure to follow Technical Specifications (Section M8.2).
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