ML20125D336
| ML20125D336 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 12/08/1992 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20125D293 | List: |
| References | |
| 50-458-92-32, NUDOCS 9212150106 | |
| Download: ML20125D336 (23) | |
See also: IR 05000458/1992032
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report: 50-458/92-32
Operating License: NPF-47
Licensee: Gulf States Utilities
P.O. Box 220
St. Francisville, Louisiana 70775-0220
Facility Name: River Bend Station
Inspection At: St. Francisville, Louisiana
Inspectior. Conducted: . September 27 through November 7, 1992
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Inspectors: W. F. Smith, Senior Resident Inspector
D. P. Loveless, Resident Inspector
R. B, Vickrey, Reactor Inspector, Plant Systems Section,
Division of Reactor Safety
D. L. Kelley, Reactor Inspector, Test Programs Section,
Division of Reactor Safety
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Approved: ) M JL P
. E.'pliardo, Chief, Project Section C . Dalel
Inspection Summar_y
Areas Inspected: Routine, unannounced inspection of onsite response to.
events, operational safety verification, maintenance and surveillance
observations, review of a complex surveillance test,. followup of an unresolved
item, review of motor operated valve- signature testing errors,= onsite review
of a licensee event report, and occupational health and safety inspections.
Results:
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- Overall, the licensee's response to operational events during the report
period was acceptable (paragraph 2.8).
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- A noncited violation was identified for failure to make a timely report-
of a plant shutdown initiation required by Technical
Specification 3.0.3. The licensee's actions to identify and correct the
problem were good (paragraph 2.3).
e The licensee's approach and response to increasing drywell pedestal sump
levels were considered appropriate to the circumstances (paragraph 2.4).
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e The licensee's response to a failed 120 Vac distribution panel was
considered to be good. However, a noncited violation was identified for
failure to follow preventive maintenance procedures prior to the event
(paragraph 2.5).
- A violation was identified for initiating high volume containment purge
with one train of the standby gas treatment system inoperable
(paragraph 2.7).
- Overall, the licensee operated the facility in a safe manner during the
report period (paragraph 3.5).
- A violation was identified for failure to demonstrate the operability of
offsite ac power sources when one diesel generator was inoperable for
greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The Technical Specification action statement was
not entered for this planned equipment outage (paragraph 3.1). A
similar weakness was seen during surveillance testing of the diesel-
driven fire pumps when both pumps were taken out of service and the
condition was not logged (paragraph 5.2).
e While housekeeping improved in some areas of the plant, some areas
required attention (paragraph 3.2).
4 * A noncited violation of security plan implementation procedures was
identified for issuing of a key card to an individual whose training had
expired. The Director of Nuclear Station Security committed to
implementing an active computerized system to correct the root cause of
this problem. This approach was excellent (paragraph 3.3).
e Overall, the maintenance activities observed during this report period
were good (paragraph 4.4).
e The work and controls to repair a containment unit cooler breaker were
considered good. System engineering support and- electrical foreman
oversight for the activity were identified as strengths (paragraph 4.2).
e The workers were knowledgeable of the job requirements and techniques
for repair of the Division I standby diesel generator. The acceptance
criteria were met for the work observed (paragraph 4.3).
e Overall, the licensee's performance of surveillance tests during the
report period was good (paragraph 5.3).
e The licensee's performance of the Division I standby diesel generator.
surveillance on October 13 was excellent, with a possible weakness
indicated in the implementation of the licensee's indepsndent'
verification program (paragraph 5.1).
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e During surveillance testing of diesel fire pumps, an operator ased a
broom handle to verify tank level when the permanent level indicator was
out of service (paragraph 5.2). l
e The completed documentation for surveillance inspections of the
Division I standby diesel generator was good. The specific required
sign offs were completed and the quality control hold points were
observed. The procedure changes were well documented and were properly
reviewed and approved (paragraph 6.1),
e One violation was identified for failure to have adequate procedural
controls covering maintenance activities on the Division I standby
diesel generator (paragraph 7.1). A similar weakness was seen during
Feedwater Pump C maintenance in that work instructions were not ,
sufficiently detailed and workers were not trained for the correct !
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installation of the pump seal (paragraph.4.1).
e The licensee appropriately evaluated potential motor operated valve ;
testing errors and was taking satisfactory corrective actions
(paragraph 8.1).
e One noncited violation was identified for failure to comp.ly with
Technical Specification 3.0.4 when the automatic depressurization system ;
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was inoperable. The operators were alert in recognizing these problems,
and the licensee took prompt corrective action. Operator identification
of the problem was viewed as a strength (paragraph 9.1).
Summary of Inspection Findings:
- Violation 458/92032-1 was opened (paragraph 2.7).
- Violation 458/92032-2 was opened (paragraph 3.1).
6 Violation 458/92032-3 was opened (paragraph 7.1).
- Four noncited violations were identified (paragraphs 2.3, 2.5, 3.3, and
9.1).
e Unresolved Item 458/92026-1 was closed (paragraph 7.1).
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e Licensee Event Report 458/92-018 was closed (paragraph 9.1).
Attachments:
e Attachment 1 - Persons Contacted and Exit Meeting
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DETAILS
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1 PLANT STATUS
At the beginning of this inspection period, the reactor was in Mode 1, at ,
80 percent power.
Power had been reduced to facilitate repairs to Main Feedwater Pump C. On !
October 7, 1992, power was further reduced by about 1 percent upon initiating R
a plant shutdown as required by Technical Specification 3.0.3, in response to
the inoperability of both trains of control room ventilation. One train was-
promptly restored and the shutdown was terminated. Following the feedwater
pumo repairs, the reactor was returned to 100 percent power on October 9.
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On October 18, the licensee again entered the shutdown action statement for
Technical Specification 3.0.3 because both trains of control room-ventilation
were inoperable. Power had been decreased to approximately 75 percent power,
until one train was returned to an operable status. Reactor power was then
restored to 100 percent.
At the end of this inspection period, reactor power was at 100 percent.
2 ONSITE RESPONSE TO EVENTS (93702)
2.1 Highl_y Radioactive Waste Labeled Low Level Waste
On October 1, 1992, the inspectors were informed by the licensee's acting
radiological controls director that two bags of solid radioactive waste were
found in a low activity box, each containing highly radioactive material. One
bag was reading 14,000 millirem per hour on contact bi was labeled less than
2 millirem per hour, and the other was reading 800 miliirem per hour and was
not labeled at all. These issues were addressed in NRC Inspection
Report 50-458/92-33, dated November _ 10, 1992.
2.2 118 Megawatt Electrical Grid Transient
At 9:46 a.m., on October 6, 1992, the facility experienced a 118 megawatt-
electrical _ grid trancient. This was apparently caused by faulty switching at
the Waterloo Substation. As a result of this transient, multiple
uninterruptible power supply inverter and digital radiation monitoring system
alarms were received, which was expected.
In addition to the expected alarms, the containment annulus pressure control
system was lost, resulting in the initiation of Division I and II containment
annulus mixing and standby gas treatment to control annulus pressure. Also,
the Division I control building air handling unit and the supporting chiller
trinped off (Division II was already out of service).
The standby gas treatment system, an engineered safety feature (ESF), started
on the above non-ESF signal. The Shift Supervisor did not make a 4-hour
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report pursuant to 10 CFR 50.72(b)(2)(ii) until 3:17. p.m., when directed to do
so by his management, on the basis that reportability was in doubt. River
Bend Nuclear Procedure RBNP-030, Revision 1, Change Notice 3, " Initiation and
Processing of Condition Reports," specifically listed the initiation of-
standby gas treatment on annulus pressure control system low flow as a non c.SF
control function and, therefore, was not reportable. The licensee concluded
that ESF component actuations, such as this event, which are caused by non-ESF-
control functions were not reportable. The inspector reviewed the licensee's
final reportability determination, and had no other questions on
reportability.
2.3 Inoperability of Both Control Building Filter Trains
At 2:21 p.m., on October 7, 1992, the licensee was notified by an independent
laboratory that the charcoal sample taken from control room ventilation filter
Train A had failed the methyl iodide penetration test. After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />
of operation the charcoal adsorbers must be sampled-and analyzed for 'a methyl
iodide penetration of less than 0.175 percent, as required by Tachi.ical
Specification 4.7.2.d.
At 2:53 p.m., after validating the report, the licensee's radiological
protection representative notified the control room. At the time, Filter
Train B had been out of service for preventive maintenance. Consequently, the -
Shift Supervisor declared the plant in Technical Specification 3.0.3, which
required initiation of a plant shutdown within I hour. The entry time was
logged in as of 2:21 p.m. With the preventive maintenance work completed on
Train B, and only closure paperwork remaining, the shift. supervisor expedited
completion of the paperwork. At 3:07 p.m., the shutdown was initiated by
reducing reactor power from 79 percent to approximately 78 percent, power was
then held at 78 percent to allow time for the paperwork to clear on Train B to
minimize the down power transient. At 3:48 p.m., the paperwork on Train B was
cleared and the unit operationally tested. Technical Specification 3.0.3 was
exited and, by 4:30 p.m., power was restored to 79 percent.
The licensee reported the shutdown initiation required by Technical
Specifications at 5:41 p.m., but 10 CFR 50.72 requires a report to be made
within I hour of the initiation of such a plant shutdown; therefore, the
report was about 1 1/2 hours late. This was a violation of NRC regulations.
When the inspector questioned the delay, the licensee explained that the Shift
Supervisor was in doubt as to the reportability of this event because he felt
the shutdown would not be completed. Licensee management- had already
recognized and identified the violation and promptly counselled the shift'
supervisors involved in reporting the event, and the event described in
paragraph 2.2 above. These untimely reports were incorporated into operating
experience reviews so that all control room operators would understand the
licensee's policy to report on time when in doubt. In view of the minor
safety significance of this issue and the prompt corrective action taken, this
violation will not b6 subject to enforcement action because the licensee's-
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efforts in correcting the violation meet the criteria specified in Section VII
of the NRC's Enforcement Policy.
2.4 Overflow of the Reactor Drywell Pedestal Drain Sump
Between September 29 and October 2, 1992, the operators made several
unsuccessful attempts to pump down the drywell pedestal sump to maintain sump
water level within the detectable range of the sump level instruments. When
either pump was energized, the sump level did not . decrease, and the pump motor
current was equivalent to a nonloaded value. The pumps, located-in the-
drywell, were not accessible during power operation. The licensee's review
concluded, based on drywell temperatures, radiation monitor readings, and a
steady leak rate of about 0.02 gallons per minute (gpm), that the leak did not
appear to be reactor coolant. Condition Report 92-0823 documented the problem
and indicated that the unidentified leakage determination required by
Technical Specification 3.4.3.1 could not be performed if pedestal sump level
should rise above the level indicator range.
On October 6, while performing an operability evaluation, the licensee's
engineers discovered that the sump was already filled to overflowing and that
water level indications were changing at 185.4 gallons per inch of level, in
lieu of 9.9 gallons per inch, which was true when the level was in the sump.
At 6 p.m., the operators entered Technical Specification Action 3.4.3.1.b,
which allowed operation to continue for only 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; then, if the leakage
detection system was not restored, required the plant to be shut down within
the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. By October 7, engineering provided a detailed operability
evaluation and method to determine unidentified leakage using a manual
calculation that accounted for the 185.4 gallon per inch level changes. The
operators exited the action statement on October 7, after receiving the
operability evaluation and making a change to the procedure used to determine-
leakage. The evaluation was reviewed by the inspector with assistance from
the Region IV Division of Reactor Safety and the NRC Office of Nuclear Reactor
Regulation. No unacceptable conditions were identified.
Throughout the period from identification of the sump pump failures on
October 2 until the end of this inspection period, unidentified reactor
coolant leakage remained steady at a rate of approximately 0.02 gpm. On
October 15, the licensee implemented a prompt modification request to shift
the indicating range of the pedestal sump level indicator from 0 to 36 inches,
to 30 to 66 inches to allow for optimum outage planning for the sump pump
repairs and leak investigation.
The inspector reviewed the modification documentation and noted that it was
complete and in compliance with 10 CFR 50.59. There was sufficient margin
(about 5 feet)' before the water could touch the cables extending downward from
the withdrawn source range and intermediate range nuclear instruments. The
slow and steady rise of the water on the pedestal area floor indicated that
the leak was not deteriorating. The licensee planned to reduce power on
November 17 to inspect the drywell pedestal area, to assess the leakage
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source, and to repair the-pedestal sump pumps. The inspector concluded that
the licensee's corrective actions were appropriate. .
2.5 Loss of Neutral from 120 Vac Power Supply
On October 16, while troubleshooting equipment problems, electrical
technicians determined that the neutral wire from the feeder transformer to
Division I 120 Vac Distribution Panel ISCV*PNL8Al had failed open. This
placed the two bus bars in the panel electrically in series. The licensee-
measured phase-to-ground potentials of approximately 260 volts on one phase
and 0 volts on the other phase of the panel. Subsequently, the licensee de-
energized Panel ISCV*PNL8Al and declared it inoperable. De-energizing this
panel affected the following Division I equipment:
e Control Room Chillers lA and 1C
e Control Room Local Intake Radiation Monitor RMS*RE13A
e Fuel Building Filtration Train Fan 3A
e Main Steam Leakage Control System
o Penetration Valve Leakage Control System
o Remote Shutdown Panel
Technical Specification 3.8.3.1 requires that the Division I ac power
distribution system be energized with the reactor-at power. Therefore, with
Panel-ISCV*PNL8Al deenergized, the action statement requires the licensee to
reenergize the panel within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least hot shutdown within the
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next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee repaired the neutral cable and verified that the
voltages were acceptable. The operators declared the power distribution
system operable. However, because the loads on the panel may have been
subjected to overvoltage conditions, the licensee declared each of the loads
from Panel lSCV*PNL8Al inoperable until appropriate testing and inspection
could be performed to evaluate the circuits.
The operability evaluations included inspection, replacement of parts,
continuity checks, and engineering evaluations of equipment voltage ratings
for each load. Subsequent actions included energized voltage checks and
conducting applicable functional checks or surveillance tests, as appropriate.
The inspectors reviewed the licensee's operability evaluations and determined
that the licensee appeared to have taken appropriate measures to declare each
load operable.
As of the end of this inspection period the iicensee had not determined the
root cause.of the failed neutral connection in Panel ISCV*PNL8A1. As part of
the overall corrective action, the licensee performed visual inspections of
other distribution panels and found no similar problems. However, several old
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construction and startup tags were identified that had not been removed.
Also, some panels were found to contain an excessive amount of dirt and
debris. The licensee documented these findings for future corrective action.
The inspectors reviewed the licensee's maintenance history for 120 Vac
distribution panels. The licensee had completed preventive maintenance on six
of the 21 safety-related 120 Vac distribution panels associated with
Divisions I and II. The inspectors reviewed the six completed work packages.
For Panel ISCV*PNL2G1, the inspectors noted that the recorded neutral bus-to-
station ground resistance value was "Im+," which could be interpreted to mean
greater than 1 megohm. That was well above the acceptance criteria limit of
less than 1 ohm specified in Preventive Maintenance Procedure PHP-1015
" Preventive Maintenance of 125, 120/208V Distribution Cabinets (AC&DC)." The
licensee promptly checked that panel, and other panels inspected and tested by
the same individual, and found the resistances to be satisfactory.
The licensee concluded that this was a documentation error and that the safety
significance was minimal. In view of the licensee's prompt action to
reconcile the data and the absence of safety significance, a violation will
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not be cited, because the licensee's efforts met the criteria specified in
Section VII of the NRC's enforcement policy.
2.6 Main Circulation System Hypochlorite Tank Leak
On October 20, 1992, while filling, the licensee discovered a leak on the
10,000 gallon hypochlorite receiving tank. The leak rate was acout 0.2 gpm.
The fill was terminated, and the licensee installed a temporary patch. The
tank was surrounded by a berm, so no leakage was released to the adjacent
ground. No chlorine fumes were sensed in the plant vital and protected area.
The licensee's environmental personnel were notified, and the 'appropt late
authorities were notified. The Senior Resident Inspector was also informed.
The event was reported to NRC pursuant to 10 CFR 50.72(b)(2)(vi). The
inspector reviewed the licensee's corrective actions and concluded that the
licensee's approach appeared appropriate.
2.7 Containment Purae with Standby Gas Treatment Inoperable
On September 24,1992, at 12:05 a.m., control room operators initiated a
containment purge through the standby gas treatment system Filter Train A. At
the time, Filter Train B was re mved from service for maintenance. Technical
Specification 3.6.1.9 requires thet the primary containment purge 36-inch
supply and exhaust isolation valves be closed, except if the standby gas
treatment system is in the purge flow path and both trains of the standby gas
treatment system are operable.
Upon reviewing the control room logs the next day, the shift supervisor
realized that the Technical Specification did not allow this operation.
Technical Specification 3.6.1.9, Action Statement b, states that, without both
trains of the standby gas treatment system operable, discontinue 36-inch purge
system operation and close the open 36-inch valves or otherwise isolate the
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penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least hot shutdown within the next
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
According to the logs, the control room operators secured the purge and
isolated the system at 4:05 a.m. The licensee complied with the Technical
Specification action statement time frama.
Control room operators started the containment purge to support the backwesh
of a reactor water cleanup system demineralizer. The task was being performed
in accordance with System Operating Procedure (S0P)-0090, " Reactor Water
Cleanup System." S0P-0090 directed the operator to Section 5.4 of SOP-0059,
" Containment HVAC System."
The inspector reviewed Section 5.4, SOP-0059, and noted that a caution
statement read, "Only one Standby Gas Treatment train shall be operating in
the Containment Purge mode and both trains of Standby Gas Treatment must be
operable to use Standby Gas Treatment in the Containment Purge mode (Tech Spec 3.6.1.9.b.)." The operators failed to heed this statement in performing the
containment purge.
The inspector concluded that the operators' failure to follow S0P-0059 is in
violation of the licensee's Technical Specifications (Violation 458/92032-1).
Condition Report 92-0806 was initiated on September 24, 1992; however, as of
the end of this inspection period, the licensee had not implemented
appropriate corrective action. On November 6, the licensee discussed plans to
revise S0P-0059 to add a procedural step in lieu of the caution discussed
above, to incorporate the event into departmental training, to add a similar
caution to S0P-0090, and to add a related question to the operator
qualification test data bank.
2.8 Conclusions
e Overall, the licensee's response to operational events during the report
period was acceptable.
- The plant responded as designed to the large,118 megawatt electrical
grid transient. The licensee's reportability determination of the event
was appropriate.
e A noncited violation was identified for failure to make a timely report
of a plant shutdown initiation required by Technical Specifications.
The licensee's actions to identify and correct the problem were good.
e The licensee's approach and response to increasing drywell pedestal sump
levels were considered to be adequate to ensure safety.
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e The licensee's response to a failed 120 Vac distribution panel was
considered to be good. However, a noncited violation was identified for
failure to follow preventive maintenance procedures prior to the event.
- The licensee's approach to control a leak in the hypochlorite receiving
tank was considered adequate,
e A violation was identified for initiating high volume containment purge
with one train of the standby gas treatment system inoperable.
3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were to ensure that this facility was being
operated safely and in conformance with regulatory requirements, and that the
licensee's management control system was effectively discharging its
responsibilities for continued safe operation.
3.1 Control Room Observations
On October 10, 1992, the inspector noted a control room log entry at 1:43
p.m., where the Division I standby diesel generator was inoperable in the
maintenance mode to allow pre-start checks. At 3:01 p.m., a log entry was
made returning the diesel generator to an operational status. Techr,ical
Specification 3.8.1.1, Action b, required, with one diesel generator
inoperable, the demonstration of the operability of certain offsite AC sources
within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The operators indicated that the checks were not performed.
The operators stated that, even though placing a diesel generator in
maintenance mode rendered it inoperable, the Technical Specification action
statement was not normally entered since it has taken less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to do
the prestart checks.
Condition Report 92-0833 was written to enter the problem into the licensee's
corrective action program. The inspector concluded that the practice of'not
entering the Technical Specification action statements for planned, short-
equipment outages was poor. The inspector discussed the issue with the
licensee. The licensee issued a night order requiring the operators to enter
into the control room log any short duration equipment inoperability as a
"short term limiting condition for operations." Failure to comply with
Technical Specification 3.8.1.1 is a violation of NRC regulations
(Violation 458/92032-2).
3.2 Plant Tours
During this inspection period, the inspectors conducted numerous inspection
tours of the plant. While some improvement was seen in housekeeping, some
areas of the plant required attention. In particular, at elevation 95 feet of
the turbine building near the south door, anticontamination clothing, trash,
pieces of material, and maslin cloths were scattered. This area had been set
up for release of nonradioactive material. This reflected a poor attitude on
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the part of the licensee's staff to ensure the careful and orderly release of
material. The inspectors discussed the issue with the licensee and corrective
actions were taken.
3.3 Security Coservations
Throughout the inspection period, the inspectors verified that persons within
the protected area properly displayed their key cards. Vital area portals -
were verified locked and alarmed based on passing through the portals ar.1 upon
visiting the central and secondary alarm stations.
On October 15, 1992, a visiting NRC inspector was issued his protected arer
badge and key card and entered the protected area. Several hours later a
dosimetry clerk identified that the inspector's general employee training had
expired several months earlier. The inspector exited the area and his key _
card access was deleted from_the system.
The licensee determined that the trainiag department had failtd to notify the
security department that the inspector's training had expired. The training
departuent prepared a list of those individuals no longer qualified once each
month. This list was used by security to remove the individuals' key cards
from active status. The visiting inspector's name was inadvertently
overlooked during this process.
The licensee's investigation identified three problem areas:
e The computer printouts were not user-friendly and required a manual
search to prepare the list each month.
e There was no verification process. One clerk prepared and issued the
monthly list independently.
e The list was hastily prepared on the last day of each month, resulting
in a high potential for error.
Training department personnel revised Training Program Procedure TPP-7-018,
" General Employee Training," under Interim Procedure Change IPC-7-018-5-3, to
define how this list of unqualified individuals will be prepared. This
revision included time frames designed to eliminate haste, independent
verification of the list prior to issuance, and use of a better-quality
compc'ar printout, more suited to developing this list. In' addition, the
licensee performed an audit to determine that key cards were only issued to ,
trained, qualified individuals. No additional discrepancies were identified.
Additionally, the licensee has committed to change the data in the access
computer program to make it an active system. Under this system, individual
key cards would carry an expiration date based on the training expiration
date. -Therefore, if a personnel error allows an expired badge to be issued,
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the computer would not allow the individual access to the protected area. The
licensee established a schedule date of December 1,1992, for implementation.
Issuance of a key card to an individual who was not properly trained is a
violation of security plan implementation procedures. However, the licensee-
identified violation is not being cited because the criteria specified in
Section VII of the NRC's Enforcement Policy were satisfied.
3.4 Radiation Protection Activities
On October 28, while inspecting the " hot" (radiologically controlled) machine
shop area, the inspectors observed radwaste workers sorting out numerous
yellow poly bags containing potentially radioactive trash, tools, and
material. The workers were in street clothes and were wearing cotton glove
liners, apparently to protect their hands from possible contamination. Some
of the bags were torn due to sharp edges on the material inside. While no
clothing or skin contaminations occurred, the inspectors questioned the
practice of handling these bags without protective clothing such as rubber
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gloves. The licensee upgraded the protective clothing requirements for this
work.
3.5 Conclusions
- Overall, the licensee operated the paint in a safe manner.
e A violation was identified for failure to determine within I hour the
operability of offsite ac power sources when one diesel generator was
declared inoperable. A poor operating practice in entering Technical
Specification action statements was revealed by this issue.
- While housekeeping improved in some areas of the plant, some a eas
required attention,
o A noncited violation of security plan implementation procedures was
identified for issuing of a key card to an individual whose training had
expired. The Director of Nuclear Station Security committed to
implement an active computerized system to correct the root cause of
this problem. This planned approach was excellent.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703)
The station maintenance activities addressed.below were observed and
documentation reviewed to ascertain that the activities were conducted in
accordance with the licensee's approved maintenance programs, the Technical
Specifications, and NRC Regulations.
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4.1 Repair of Reactor Feed Pump
On October 2,1992, the inspector observed portion; of the replacement of the
rotating assembly f?r Reactor feed Pump C. The work was authorized under
Maintenance Work Order (MW0) R158697. The pump had been vibrating excessively
and, thus, it became necessary to reduce plant power to about 80 percent and
secure the pump for repairs. The inspector reviewed the work package and
found that it did not contain a high level of detail. The inspector noted
from the documentation that the repairmen doing the work were trained and
qualified to do the job. They performed the work in a profess: inal manner and
exhibited good radiological and housekeeping practices. The radiological
protection measures appeared appropriate to prevent the spread of
contamination and minimize exposures. Woro steps were appropriately
documented.
On October 6, after the pump was reassembled, the operators attempted to fill
the pump by opening the suction valve, but the inboard mechanical shaft seal
leaked and water began to flash to steam. The operator then isolated the
pump. -The inspector discussed the possible causes for the failure of the seal
with maintenance supervisory and management personnel and found that an 0-ring
gasket had moved out of position during assembly of the seal. Special clips
to hold the seal together during the assembly and alignment process were not
used and, as a' result, the seal did not function as designed. The inspector
noted that the repair procedure, Corrective Maintenance Procedure CMP 9019,
Revision 6B, " Reactor Feed Pump Disassembly, Inspection, Rework, and
Reassembly," did not address the clips, and the training and briefings given
to the repairmen did not assure correct assembly of the seal. Maintenance
personnel explained to the inspector that there once was a detailed procedure
in place that addressed the seals, but they could not find it. Failure to
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have an adequate procedure and/or adequate training of the repairmen
demonstrated a weakness in the licensee's maintenance program which resulted
in over 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> delay in getting the pump back in service and also caused
unnecessary additional work in a radiologically contaminated area. The seal
was successfully reworked and the pump returned to service.
4.2 Repair of Containment Unit Cooler IB Breaker
On October 30, 1992, the inspector observed maintenance activities associated
with Breaker IEFS*ACB076 for Containment Unit Cooler 18. The work was
authorized under MWO R158388 and was initiated to correct deficiencies
identified during preventive maintenance activities. The inspector noted
that, while there was no clearance established for this work, there were
sufficient electrical interlocks to permit a safe breaker rack-out. The
operaM rs properly authorized the work. The inspector also noted that the
appropriate shutdown Technical Specification action statement had been
entered. The job was witnessed by a quality control representative, who
verified the correct replacement parts and ensured that the shelf life of
consumables had not expired. The inspector verified that the electricians
were trained and qualified to perform the work.
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The electricians noted excessive wear on the freme where the holding pawl
shaft was attached and the system engineer decided to replace the breaker with
a spare currently installed in another panel. The HWO was properly revised
within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and the system engineer assisted in verifying the spare as
being the proper breaker. The spare breaker was installed and retested in
acco,' dance with the MWO, and the faulty breaker was retained for inspection
and evaluation by the vendor. The inspector verified that the operators had
conducted an operational test of the unit cooler uefore exiting the Technical
Specification action statement, in view of the short outage time (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />)
allowed by the Technical Specifications, the electrical maintenance foreman
provided full time supervision and support of the electricians. The system
enoineer and foreman involvements were strengths.
4.3 Leak in Diesel Generator Cylinder Head
On October 16, 1992, the %spector observed maintenance on Division I standby
diesel generator. The wu t was being performed under MW0 R059324. This work
order was written to trouoleshoot lubricating oil flow to the turbocharger.
During the maintenance, the licensee identified a small amount of water in the
oil and concluded that the leak was caused by a defect in a subcover hold down
bolt socket in cylinder Head No. 4. The licensee planned to issue a special
report on the causes and corrective actions for this failure.
The inspector observed the maintenance repairmen replace the cylinder head.
The proper clearances were in place, and the repairmen were following the job
plan. Adminittrative signoffs and approvals were in place. Cleanliness
controls were in effect and the repairmen were policing fellow workers on
materials controls. The repairmen appeared knowledgeable of the job
requirements and techniques.
The int $ector evaluated the results of the rocker arm test as descrs ed in
Step 10 in Revision 4 of the job plan The repairmen blue checked in valves
and checked the rockers in ace.ance with the vendor manual recommendations.
The clearances were checked against the acceptance criteria and found to be
satisfactory.
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4.4 Conclusions
- Overall, maintenance activities observed during this report period were -
good.
e During Feedwater Pump C maintenance, the licensee exhibited a weakness
in getting sufficient detail into the procedure and/or providing
sufficient training or briefing of the repairmen. As a result,
potentially contaminated feedwater sprayed out of the inboard seal,
causing delays and otherwise avoidable rework in a contaminated zone.
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e The work and controls to repair a containment unit cooler breaker were
considered good. System engineering support and electrical foreman
oversight for the activity were identified as strengths,
e The workers were knowledgeable of the job requirements and techniques t
for repair of the Division I standby diesel generator. The acceptance
criteria were met for the work observed.
5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and
components to verify that u.e activities were being perfo.med in accordance
with the licensee's approved programs and the Technical Specifications.
5.1 Division 1 Diesel Generator Operability Test
On October 13, 1992, the inspector observed the performance of an oserability
tv:t of the D' sion I standby diesel generator, as required by Tec1nical
Specification 4.8.1.1.2.a using Surveillance Test Procedure STP-309-021,
Revision 9A, " Diesel Generator Division 1 Operability Test." The test was
performed by a reactor operator trainee under the direct supervision of a
licensed reactor operator. The control operating foreman provided additional
oversight. The operator followed the applicable procedure in a step-by-step
manner, and self-checking was evident. The inspector watched as the control
room operator verified prerequisites completed and then performed a manual
start of the diesel generator. The timing test was satisfactorily completed
using a calibrated stopwatch.
The inspector went to the diesel generator room after the machine achieved
rated load. The diesel was functioning well with no fuel oil or lubricating
oil leaks of any consequence. Upon reviewing the official, signed off copy of
the above referenced procedure, the inspector noted that the independent
verification signature blank was not signed off at Step 7.5.1 This step
closed the turbocharger prelube valve after starting the diesel to prevent the
electric lubricating oil circulating pump from tripping during diesel
shutdown, thus starving hot bearing surfaces from needed lubricating oil.
Upon questioning the equipment operator, he stated that the verification was
done, and then another operator, who stated he did the verification, promptly
signed the verification signature blank. This demonstrated a possible
weakness in the licensee's independent verification program. This was
discussed between the inspector and the Assistant Plant Manager-0perations,
Radwaste and Chemistry, who agreed to review the procedure for possible
revision 'to clearly indicate what must be independently verified and when.
The rem 4inder of the diesel generator surveillance test was condur :nd in an
excellent manner. All acceptance criteria were met.
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5.2 Diesel-Driven Fire Pump Operability Test
On October 26, 1992, the inspector observed the performance of Surveillance
Test Prccedure STP-251-3205, " Diesel Fire Pump Operational Test," and STP-251-
3101, " Fire Protection Water System Minimum Water Volume Check." The portions
observed included the operability test of Diesel Fire Pump 1A as required by
Technical Specification 4.7.6.1.2.a.1 and 4.7.6.1.2.a.2.
The inspector observed preparations for these tests and determined that the
prerequisites were met. The inspector noted that the operator used a broom
handie as a dip stick to determine the level in Fuel Oil Tank 1F0F-TKlA
because the permanent level indicator was out of service. Technical
Specification 4.7.6.1.2.a.1 required the licensee to verify that the fuel day
tank contained at least 300 gallons of fuel. Additionally, Surveillance Test
Procedure STP-25 -3205 required that the operator verify that there was
sufficient fuel to operate the engine without going below 300 gallons.
The operations supervisor careed that using a broom handle as a substitute dip
stick was not the appropritte way to perform this procedure. Initially, the
licensee measured the broom handle and determined that the mark was 1 inch
above the level that is equivaient to 300 gallons. Therefore, the licensee
concluded that the Technical Specification requirements had been met.
Previously, the licensee had reviewed the maintenance history on the process
level indicator for the tank. The indicator had failed a number of times.
Therefore, the licensee had placed a hold on the repair of the indicator for
engineering to evaluate the use of a better design. This review had been
delayed for some time. By the end of the inspection period, the licensee had
repaired the process level indicator for fuel Oil Tank 1F0F-TKlA.
The inspector reviewed the records for nuclear equipment operators and
determined that the operator was qualified to perform these tests.
The inspector reviewed both procedures and determined that they met the
Technical Specification surveillance requirements. The tests were
appropriately released for performance and were included in the surveillance
test progress 109 The inspector noted that Surveillance Test
Procedure STP-251-3205 removed both Fire Pumps A and B from service. However,
the c' 3 trol room log did not document entry into the action statement. The
licensee indicated that the practice had been to not enter action statements
for short-term items. This issue is discussed in paragraph 3.1 of this
report.
The inspector reviewed the calibration records for level Indicator 1FPW-Lil3A
and Flow Indicator IFPW-F1109. Each instrument was within its calibration
cycle. The inspector reviewed the data sheets following the tests ano
determined that all parameters met the Technical Specification acceptance
criteria. Both tests were performed within the time frames required by
Technical Specifications.
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5.3 Conclusions j
e Overall, the licensee's performance of surveillance tests during the !
report period was good.
e The licensee's performance of the Division I standby diesel generator
surveillance on October 13 was excellent, except for a possible weakness
indicated in the implementation of the licensee's independent
verification program.
- Weaknesses were identified during the surveillance of the fire aumps in
that an operator was forced to use a broom handle to verify tan (' level
when the permanent indicator was out of service, and the removal of both
diesel-driven pumps from service was not logged to allow tracking of
Technical Specification requirements.
6 REVIEW OF A COMPLEX SURVEILLANCE TEST (61701)
This portion of the inspection consisted of the review of the documentation
for the surveillance activities associated with vivision I Standby Diesel
Generator LEGS *EGIA performed during Refueling Outage 4. This review was
started with inspectins and observations of the work as documented in NRC
Inspection Report 50-0 1/92-24.
6.1 Discussion
The inspector reviewed four of the completed diesel generator vendor
procedures implemented by STP-309-7614, " Diesel Generator Inspection -
Division I and Division II." The procedures were performed on the Division I
diesel generator. The four vendor procedures reviewed were:
- RF0-430, " Inspect gear train for Worn, Broken, Chipped or Otherw ae
Impaired Gear Teeth"
e RFO-412, " Fuel Injection Equipment Examination and Maintenance"
- RFO-448, " Cylinder Head Removal and Reinsta11ation"
e RF0-459, " Cylinder Block Top Deck inspection by Visible Dye Penetration
Method"
The inspector reviewed the above completed procedures to verify that they were
the correct revision, changes were properly annotated in the procedure and had
been approved, quality control hold points were identified, and acceptance
criteria (documented where required) and step sign-of fs had been completed.
The inspector noteo that the procedures were vendor qeneric procedures and
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were updated prior to use,
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6.2 Conclusions !
e The completed documentation for surveillance inspections of the
Division I standby diesel generator was good. The specific. required
sign offs were completed and the quality control hold points were
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observed. The procedure changes were well documented and properly
reviewed and approved.
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7 FOLLOWUP OF AN UNRESOLVED ITEM (92701)
7.1 (Closed) Unresolved Ittm 458/9226-01: Appropriateness of Procedural
Controls for the Inspection and Reassembly of the Division i Standby -
Diesel Generator
On' July 8, 1992, while licensee personnel were adjusting the valve settings on ,
the Division I standby diesel. generator, the~ engine failed to turn past top
dead-center on Cylinder 5 using the barring device. This event was reviewed
and documented in NRC-Inspection Report 50-458/92-26.
The ins)ector further reviewed the actions taken by the mechanics in
reassem)1ing the engine. Specifically, the licensee-stated that, when
installing the valve rocker arm, a good routine practice was to back out the
adjusting screw first. Had this step been performed, the engine would not
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have been damaged.
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Procedural controls are required by Technical Specification 6.8.1 for
maintenance .affecting safety-related equipment. The 3rocedures and job plans ,
for the work performed failed to require that the mec1anics properly set the
adjusting screw prior to reassembly. This is a violation
,
(Violation 458/92032-3).
This violation was, considered for enforcement discretion; however, the~
licensee did not take adequate corrective action following.the discovery of
the' problems with Cylinder 5. -The licensee did.not perform Inspections which
would have identified the additional three bent push rods, prior to running -
the diesel generator, which had the potential for further damaging the safety-
related engine. Although the bent rods were found during a scheduled ,
inspection, it= is unclear that the_ bent push rods would have been readily
identified by inspecting personnel. Additionally,'the licensee has had ..
several recent events involving inadequate procedures and the acceptance of
the: inadequacies by plant maintenance personnel. Important maintenance steps
have been= missed because of the licensee's reliance on the skill-of-the-craft
when specific procedural steps would have been more appropriate.
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7.2 Conclusions 1
A violation was identified for failure to have adequate procedural controls
covering the maintenance activities on the Division I standby diesel
generator.
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8 REVIEW OF MOTOR OPERATED VALVE SIGNATURE TESTING ERRORS (92701)
8.1 10 CFR Part 21 Notification from liberty Technologies
On October 2,1992, the licensee received a 10 CFR Part 21 notification from
Liberty Technologies that discussed errors in the software supplied with the ;
vendor's valve operation and test evaluation system (VOTES). The notification
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discussed two defects. First, the values for Young's Hodulus and Poisson's
Ratio used in the software was not precise enough to provide the +/- 3.5
percent accuracy assumed in the V0TES error analysis. The second problem
involved calibration errors of the strain gauge when the calibrator was placed
on the threaded portion of the stem PS'"a the antirotation device on small
diameter high-lead stems. This erec was +"A wr the fact that smaller stems
tended to twist, which caused a thin twg et diau cr that offset the
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thickening caused by the thrust of ti.. hatcr.
The effect was that the actual torque of tue valve motor was as much as
7 percent higher than previously calculated ;or valve stems made of 410-SS
material. This is the most commonly used ma'erial for valve stems ai River
Bend Station. However, the concern affected all valves already tested.
The licensee identified 34 valves in which the calibrator could have been
attached to the threaded portion of the stem above the antirotation device.-
for the stem geometries at River Bend Station, the licensee determined that
the predominant torque correction factor was less than 8 percent. However,
the licensee indicated that for a few valves it may be somewhat higher.
Both of these issues caused the indicated thrust to be less than the true
thrust. Therefore, the licensee determined that the thrust margins were not
in question. The concern was in exceeding the maximum allowable thrust
limits. The vendor performed weak link calculations for the licensee in the
past that showed considerable margins. Additionally, these margins were based
on continuous duty ratings. Therefore, based on a limited number of cycles
the margins would be even larger.
Based on this preliminary review, the licensea had provided an interim
operability call for all motor-operated valves previously tested with the
VOTES. Valve specific reviews were underway, and the licensee had obtained
new software which would make corrections to the recorded test data. The
licensee stated they would evaluate the specific valve operability if any of
the corrected values exceeded the allowable limits.
On October 28, the inspectors observed testing of the V0TES system on a
licensee mock-up. The technicians involved were knowledgeable of the system
and the restrictions. The problems identified in the 10 CFR Part 21
notification were well understood, and the impact was being evaluated. The
NRC is still reviewing the implementation of Generic Letter 89-10 on motor-
operated valve testing at River Bend Station.
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8.2 Conclusions
The technicians involved were knowledgeable of the VOTES system and the
restrictions. The problems identified in the 10 CFR Part 21 notification were
well understood, the impact was being evaluated, and the licensee was taking
appropriate corrective actions.
9 ONSITE REVIEW 0F A LICENSEE EVENT REPORT (92700)
9.1 (Closed) Licensee Event Report 458/92-018: Trip System for the "A"
Automatic Depressurization System Inoperable due to Hispositioned Root
Valve
This licensee event report involved a failure to comply with Technical
Specification 3.0.4, which prohibits entry into an operational condition when
the condition required for the Limiting Conditions for Operation are not met.
On September 6, 1992, reactor steam dome pressure was raised to about 100 psig
with the Train A automatic depressurization trip system inoperable, due to an
improperly positioned instrument root valve. The instrument and trip. system
monitored the discharge pressure of Residual Heat Removal System Pump A to
provide a permissive to the Train A automatic depressurization trip system.
The cause was failure to follow administrative requirements to properly change
a surveillance test procedure on August 22, when it became necessary to
connect a test gauge to a different point, thereby requiring the root valve to
be closed for installation and removal of the gauge. The procedure did r.ot
provide for this and, as a consequence, the restoration of this particular
valve was not covered.
While taking logs, the reactor operator noted that the trip units monitoring
the Pump A discharge pressure was reading about 65 psig higher then those
monitoring Pump B. Subsequent investigation revealed that the root valve was
inappropriately shut. Due to the reactor operator's promptness in identifying
the discrepancy, the safety significance of this event was minimal. Train A
automatic depressurization was inoperable for about 1 1/2 hours while it.was
required by Technical Specification 3.3.3 to be operable. The action
statement allowed Train A to be inoperable for up to 7 days before the plant
must be shut down and depressurized to below 100 psig. In addition, reactor
pressure did not exceed the operating range of Pump A, thus the pump could
have injected if called upon. The reactor operator's' actions were considered
to be a strength.
The licensee promptly initiated verification of accessible emergency core
cooling system valves. No additional discrepancies were identified, based on
the inspector's review of the documented valve lineup checksheets. The
licensee also counseled the personnel involved and issued a night order to
inform operations personnel on the lessons learned from this event.
Failure to comply with Technical Specification 3.0.4 was a violation of NRC
regulations; however, this licensee-identified violation is not being cited
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because the criteria specified in Section VII of the NRC's Enforcement Policy
were met.
9.1 Conclusions
A noncited violation was identified for failure to comply with Technical
Specification 3.0.4 when one automatic depressurization system trip system was
inoperable upon changing plant modes. The operators were alert in recognizing
these problems, and the licensee took prompt corrective action. Operator
identification of the problem was viewed as a strength.
10 OCCUPATIONAL HEALTH AND SAFETY INSPECTIONS (93001)
10.1 Corrective Actions to an Industrial Accident
On June 18, 1992, an individual working inside the drywell was injured by a
falling hoist, when the trolley carriage failed. This event was documented in
NRC Inspection Report 50-458/92-24.
NRC Inspection Report 50-458/92-24 concluded that the trolley was installed '
outside of the manufacturer's recommendations, that side lifts were being
performed against the manufacture's recommendations, that frequent inspections
of specific lifting equipment had not been performed, and that inspections of
lifting equipment were poorly documented and the inspection criteria was
vague.
TL inspector reviewed the licensee's corrective action for this event. The
licensee determined that one of the root causes for inadequate inspections was
inadequete training for tool room facility employees. Previously these
personnel had been expected to inspect trollies without appropriate training
or inspection criteria. The licensee had provided training for all tool room
employees on the proper configuration and inspection criteria for beam
trollies, to ensure that all parts were included and in good condition at the
time of issue. The licensee was in the process of developing a more specific
inspection document which will be included in General Maintenance
Procedure (GMP) 0014, " Control of Load Lifting Equipment."
The inspector reviewed a revision to GMP-0017, " General Rigging Practice."
This revision, in Change Notice 92-1264, held the individual in charge of the
lift responsible for ensuring that the trolley had been properly inspected and
identified per the requirements of GMP-0014. The licensee provided a Training
Material Discrepancy Report M-92-018 to incorporate this event into the
training program for rigging practices. The licensee stated that this will
ensure that qualified rigging personnel are trained on the proper
configuration and instal _lation practices associated with trolley use and
,
installation. The inspector reviewed this training material discrepancy
report and verified that it covered the appropriate material.
The inspector noted that the current procedure revisions do not allow the use
of generic beam trollies for applications which require specific trolley
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hoists. In addition, the licensee had painted "NOT FOR USE IN ORYWELL" on all
Harrington type trollies to prevent inadvertent misapplication on the drywell
monorail system.
This occupational health and safety administration item is closed.
10.2 Conclusions
The licensee's corrective actions for the June 18, 1992, event were considered
adequate and should preclude similar events.
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ATTACHMENT 1
1 PERSONS CONTACTED
1.1 Licensee Personnel
D. L. Andrews, Director, Quality Assurance
J. W. Cook, Senior Technical Specialist
T. C. Crouse, Manager, Administration
W. L. Curran, Cajun Site Representative
K. D. Garner, Licensing Engineer
P. D. Graham, Plant Manager
D. N. Lorfing, Supervisor, Nuclear Licensing
S. R. Radebaugh, Assistant Plant Manager, Maintenance
J. E. Spivey, Senior Quality Assurance Engineer
M. A. Stein, Supervisor, Balance of Plant Design Engineering
K. E. Suhrke, General Manager, Engineering and Administration
R. J. Vachon, Senior Compliance Analyst
J. E. Venable, Operations Supervisor
1.2 Other Personnel Contacted
The personnel listed above attended the exit meeting. In addition to the
above personnel, the inspectors contacted other personnel during this
inspection period.
2 EXIT MEETING
An exit meeting was conducted on November 6, 1992. During this m eting, the
inspectors reviewed the scope and findings of the report. The licensee did
not identify as proprietary, any information provided to, or reviewed by the
inspectors.
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