ML20202B940
| ML20202B940 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 02/06/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20202B904 | List: |
| References | |
| 50-458-97-19, NUDOCS 9802120129 | |
| Download: ML20202B940 (22) | |
See also: IR 05000458/1997019
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.: 50-458
License No.: - NPF-47 3
Report No.: 50-458/97-19
Licensee: Entergy Operations, Inc.
Facility: River Bend Station
Location: 5485 U.S. Highway 61
St. Francisville, Louisiana
Dates: November 30,1997, through January 10,1998
Inspectors: G. D. Replogie, Senior Resident inspector
Approved By: E. E. Collins, Chief, Project Branch C ,
Division of Reactor Projects
Attachment: SupplementalInformation
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9902120129 980206
PDR ADOCK 05000458
G PDR
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EXECUTIVE SUMMARY
River Bend Station
NRC inspection Report 50-458/9719
This inspection included aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a 6-week period of resident inspection.
DRatatiODS
- The conduct of operations was generally professional and safety-co7ss lous
(Section 01.1).
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The separation criteria between a temporary cable and an uncovered safety-related
cable tray was not maintained consistent with the Updated Final Safety Analysis Report
and plant procedures (Section O2.2).
- A nuclear equipment operator trainee demonstrated excellent attention to detail during a
diesel generator surveillance. While looking for fluid discharge on the cylinder head test
valves, the operator noticed oil residue on piping adjamnt to the number eight cylinder
(versus the cylinder head test valve itself, Section M1.2,
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Operations and Maintenance personnel were not effective in maintaining the
postaccident sampling system (PASS). The PASS was out of service for approximately
50 percent of the time during the past 10 months. Repairs were often not performed in a
timely manner, and the overall material condition of the system was poor (Section M8.1).
A shift technical advisor failed to consider the Technical Specifications Limiting
Conditions for Operability when determining operability for emergency core cooling
system minimum flow valve instruments (Section E8.1).
Maintenance
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Maintenance activities were generally completed thoroughly and professionally
(Section M1.1).
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On-line risk assessments were not always thorough. In one instance operators assumed
that a delay in placing standby service water pumps in service would not adversely affect
the availability of the standby service water pumps or the associated diesel generators
without fully understanding equipment response, in another case, the potential
consequences associated with a freeze seal failure were not pioperly considered in the
risk assessment (Section M1.3).
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While overall plant material condition was good, there were notable equipinent and
system performance problems. The inspector noted material condition concerns
involving excessive main generator hydrogen leakage, an inoperable PASS, an
inoperable suppression pool pumpback pump, a degraded control rod drive pump, a
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failed containment isolation damper, and air entrapment in the instrument sensing lines
to safety-related instruments. Conversely, spent fuel cooling Pump 18 and the
suppression pool cleanup mode of the alternate decay heat remr' val system were
repaired and returned to service (Section M2,1).
Engineenng
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The diesel generator system engineers promptly and effectively evaluated the
significance of fuel oil discharge coming from a diesel generator cylinder. The prompt
assessment helped to minimize the out of service time for the diesel generator
. (Section M1.2).
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Engineers did not assess in a timely manner the significance of exceeding the
flammability thresho'd for hydrogen cc centration at the seal oil detrainment tank vent.
Consequently, the flammability threshold was exceeded before safety issues were
thoroughly evaluated (Section E2.1).
- Corrective actions to add,ess air entrapment in reactor core isolation coo:ing minimum
flow valve instrument lines (January 1997) were not comprehensive and did not prevent
recurrence. Subsequently, one high pressure core spray and two residual heat removal
systam minimum flow valves malfunctioned for the same or similar causes (air
entrapment in the instrument lines, Section E8.1).
Plant Suo;-ort
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Housekeeping was considered good (Section 02,1).
During routine tours, the inspectors noted that the security officers were alert at their
posts, security boundaries were being maintained property, and screening processes at
the Primary Access Point were appropriately performed (Section S1,1).
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! Report Details
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Summarv of Plant Status
At the beginning af this inspection period, the plant was in Operational Mode 1 at 100 percent
reactor power. On December 20,1997, power was reduced to approximately 60 percent in
support of planned maintenance on reactor feedwater pumps. At the ccactusion of the work on
December 21 reactor power was retumed to 100 percent, where it essentially remained for the
remainder of the reporting period.
l. Qnerations
01 Conduct of Operations
01.1 General Comments.171707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
plant operations. The conduct of operations was generally professional and safety-
conscious.
02 Operational Status of Facilities and Equipment
O2.1 Enaineered Safetv Feature System Walkdowns (71707)
The inspectors walked down accessible portions of the following
safety related systems:
High Pressure Core Spray (HPCS)
Diesel Generators (DGs) I ano il and HPCS
Residual Heat Removal (RHR), Trains A, B, and C
Reactor Core Isolation Cooling (RCIC)
- Division I, ll, and ill Switchgear and Battery Rooms
The systems were found to be properly aligned for the plant conditions and in good
material condition. A few minor housekeeping issues were identified but, overall,
hcusekeeping was good. One problem associated with electrical separation of safety-
related and nonsafety-related cables is discussed in Section O2.2.
^ 02.2 Scoaration of Temocrary Cables
b. Observations and Findinas
On December 4,1997, while touring the auxiliary building, the inspector identified that an
extension cord was draped over the top of uncovered division 11 Cable Tray 1TX8178.
Procedure ADM-0073, " Temporary Installation Guidelines," Revision 2, Step 5.2, requires
that temporary installations adhere to design separation criteria specified on Drawing EE-
34ZE. Drawing EE-34ZE, " Standard Details for Separation Requirements," Revision 7,
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identified the separation requirements for " free air cables to trays" as one foot.
Additionally, the one foot separation requirement was specified in the Updated Final
Safety Analysis Repori, Section 8.3.1.4.2. In response to the inspector's concem, the
temporary cable was promptly re-routed and the problem was documented on Condition
Report (CR) 97-2080.
The inspector further noted that CR 97-1610, dated September 1997, was previously
initiated to address similar concerns. In that CR, Quality Assurance personnel toured the
facility to inspect compliance with cable separation requirements. The Quality Assurance
inspectors identified eight instances where cable separation requirements were not met.
Corrective actions planned or taken in response to CR 97-1610 included: (1) training
plant personnel on cable separation requirements (complete); and (2) changing
Procedure ADM-0073, to clarify the separation requirements (planned).
The inspector considered the most recent instance of a cable separation infraction to be
repetitive, Corrective actions for previous occurrences were not fully effective at
preventing recc.rence. The failure to maintain cable separation in accordance with
Procedure ADM 0073 is a violation of 10 CFR Part 50, Appendix B, Criterion V
(50-458/97'i9-01).
c. Cnaciusions
Ona violation was identified for the failure to comply with procedural cable separation
requirements.
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ll. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Scoce (61726. 62707)
The inspectors observed portions of the following maintenance and surveillance activities
(except as noted below):
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STP-309-0202, " Division 11 Diesel Generator Operability Test," Revision 18E
(documentation review)
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STP-309-0201, " Division 1 Diesel Generator Operability Test," Revision 16C
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Maintenance Activity item (MAI) 302635, Replacement of Service Water
Valve SWP-V-70
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MAI 341613, Replacement of Service Water Valve SWP-V-69
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mal 314783, Division i Service Water Cooling Tower Inspection (documentation
review)
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MAI 314938, Division il Service Water Cooling Tower Inspection (documentation
review)
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STP-403 7301, " Containment Purge System Isolation Valve Leak Rate Test,"
Revision 1 (documentation review)
b. Observations and Findinas
The performance of maintenance generally was thorough and professional. Exceptional
performance demonstrated during the Division 11 DG surveillance is discussed in
Section M1.2. Concerns related to less than thorough on-line risk assessments is
addressed in Section M1.3, while the failure of a containment isolation damper is
discussed in Section M1.4.
M1.2 Division 11 DQ_Qperability Test
a. Insoection Scoce (61726)
Fuel oil sprayed out of the Division ll, Cylinder 8 head test valve during the air roll portion
of the DG operability surveillance. The inspector performed followup to this licensee
observation.
b. Observations and Findinas
Licensee Actions: While looking for fluid discharge on the cylinder head test valves, a
nuclear equipment operator (NEO) trainee noticed oil residue on piping adjacent to the
Cylinder 8 (versus the cylinder head test valve itself). The NEO was concemed because
oil discharge could be an indicator of cylinder damage.
In response to the finding, operators declared the DG inoperable and entered the
Technical Specification (TS) ACTION Statement. Subsequently, DG system engineers
identified the substance as fuel oil and contacted the vendor for additional guidance. The
engineers determined that an unloaded DG run on November 20,1997 (troubleshooting
for a different problem), had resulted in leaving a small amount of unbumed fuel in the
cylinder. Per the vendor, this was not an uncommon finding following an unloaded run
and the additional amount of fuel oil in the cylinder did not adversely impact the
s. e operability of the DG. As a precautionary measure, a compression test was satisfactorily
completed on the DG prior to retuming the unit to service later that day.
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NRC Assessment: The NEO trainee demonstrated excellent attention to detail when he
found oil residue on piping adjacent to Cylinder 8, as his actions exceeded the ;
procedure's inspection requirements.
In response to the finding; system engineers demonstrated effective problem resolution
- capabihties (including good utilization of the DG vendor) and promptly evaluated the -
, significance of the oil discharge. The accomplishment of the compression test, as added
assurance of their conclusions, demonstrated a good safety focus. The prompt work by
the engineers helped to minimize the out of service time for the DG.
c. Conclusions
An NEO trainee demonstrated excellent attention to detail in identifying oil discharge -
' coming from the Division ll DG, Cylinder 8. Additionally, engineering promptly and
effectively assessed the significance of Le problem and conservatively performed testing
to verify thc!r conclusions.
M1.3 Risk Assessments for On-Line Maintenance
a. Insoection Scooe (62707)
The inspectors observed the licensee's risk assessments in support of on-line
maintenance activities.
b. Observations and Findinas
Background: The licensee performs a substantial amount of work on-line (versus during
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an outage).l The Maintenance Rule (10 CFR 50.65(a)(3)) states, in part:
"In performing monitoring and preventative maintenance activities, an
assessment of the total plant equipment that is out of service should be
taken into account to determine the overall effect on performance of safety
functions."
To meet the intent of the above, maintenance is controlled via the "On-Line Maintenance
- Guidelines," Revision 3. These guidelines specify the use of a " blended approach," when
assessing the potential risk of maintenance. The blended approach consists of
quantitative as well as qualitative aspects of risk assessments. Risk is evaluated
quantitatively via the equipment out of service (EOOS) computer, which provides
numerical values for " instantaneous" as well as " cumulative risk (which are then
compared to predetermined acceptance criteria). ' Due, in part, to limitations with the
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EOOS computer model, engineering judgement is also utilized to qualitatively evaluate
. risk.
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The Maintenance Guidelines stipulate that equipment may be considered "available"in
the EOOS computer program when it ic capable of performing its safety function, even
when it is tagged out of service or declared inoperable. The guidelines stress, however,
that conservative and safe opwation must be the foremost consideration when making a
determination involving availability of plant equipment.
Standby Service Water (SSW) Tower Inspections: The inspector identified that the
ncensee had not appropnately considere risk for work on the SSW cooling tower.
The licensee performed visual inspections of the SSW cooling tower (one safety-related
division at a time). To ensure the personal safety of the workers, the licensee had placed
the service water pumps in the " pull-to-lock" position, declared the service water division
and its associated DG inoperable, and entered the applicable T3 ACTION Statements.
However, the equipment was considered svailable (in the EOOS program) because the
service water pumps could be started in a short period of time. Operators estimated that
evacuation of the SSW cooling tower and starting of the SSW pumps would take
approximately 3-4 minutes.
The inspectors contacted a DG system engineering supervisor and inquired how long a
DG could operate without service water The supervisor stated that the DG vendor had
demonstrated that a DG could operate for approximately 2 minutes (while fully loaded)
before failure might be experienced. Without the load of the SSW pumps, however, the
< DG could operate for an additional unknown period of time.
Based on the above, the inspector concluded that the licensee's action were inconsistent
with the recommendations contained in the "On-Line Maintenance Guidelines."
Specifically, the licensee did not have reasonable assurance that the DG (which powers
the SSW pumps during events that include a loss of offsite power) was capable of
performing its safety function. This issue demonstrated poor attention to detail when
assessing overall plant risk for this job.
Service Water Valve Replacements: The inspector observed the on-line replacement of
four SSW valves (service water isolation valves to the Division i HVK chillers). The
inspectors noted that the train of SSW and its associated DG were unavailable in the
EOOS program and this resulted in a risk level at the upper administrative limit for
" acceptable risk." Additionally, the work required the use of two freeze seals to isolate the
valves from the SSW system (6-inch diameter lines). This method of isolation, in itself,
had the potential for causing an additional event (loss of freeze seals and flooding of the
control building).
The contingency actions associated with the potentiailoss of freeze seals included:
(1) installation of blind flanges over the open valve bodies; and (2) isolation of the normal
service water header to Division I components. While the contingency actions seemed
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appropriete for the work, the EOOS computer model did not have the capability to
evaluate te potential risk associated with a loss of freeze seal event. The risk significant
aspects included:
- lsolation of normal service water to the safety-related loads (normal service water
is a risk significant system).
- Flooding of the control building. Divisions I and 11 switchgear are located on the
same floor of the control building. The licensee's generic flooding analysis
considered minimal flooding (approximately 120 gpm), which did not approach the
flow rate that could be expected from a freeze seal failure,
The inspector considered the use of freeze seals to constitute some unquantifiable
additional risk with this job. Since the quantified risk (per the EOOS program) was
already at the administrative limit, the qualitative evaluation for the job was not well
focussed on safety and did not appear to provide additional value to the risk assessment
process,
c. Conclusions
On-line risk evalurfion assessments were not always thorough. In one instance
operators assumed that a delay in placing SSW pumps in service would not adversely
affect the availability of SSW pumps and Dgs without fully understanding equipment
response. In another case, the potential consequences associated with a freeze seal
failure were not properly considered in the risk assessment,
M1,4 Containmant Purae Damner (HVR-AOV-165) Found Inocerable
a. insoection Scone (61726)
Containment purge Damper HVR-AOV 165 failed during local leak rate testing (LLRT).
The inspector performed followup to this licensee observation.
b. Observations and Findinas
Background: HVR-AOV-165 is a 36 inch diameter butterfly valve (damper) located in
the containment purge system and is the outboard containment isolation damper. The
unit is air operated to open, spring to close, but is also equipped with a separate hydraulic
actuator to manually open the damper during maintenance. For manual operation, a skid
mounted petcock valve is closed and the hydraulic actuator is manually pumped to open
the damper. For damper closure, the petcock valve is opened, which releases the
hydraulic lock and permits the actt,ator to retract. Drawing 410318 requires that the
petcock be at least one turn open when the damper was operated in the pneumatic mode
(the safety-related mode).
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The inspector noted that closure of the petcock, alone, will not necessarily render a
damper inoperable. The hydraulic actuator would slso have to be manually operated
(jacked) at least one time before the actuator piston would extend and affect damper
closure.
Damper Failure: During the performance of Procedure STP-403-7301," Containment
Purge System Isolation Valve Leak Rate Test," Revision 1, on January 8,1998, leakage
through Damper HVR AOV 165 was in excess of the capacity of the leak rate monitor
(2000 sccm). Further examination revealed that the maintenance actuator petcock valve
was out of position (closed) and the actuator was partially extended (preventing the
damper from reaching the full closed position). Operators promptly declared the damper
inoperable and completed the ACTIONS required by TSs. The petcock was then opened
and the damper was observed to go to the fully closed position. The LLRT was then
successfully performed.
in response to the finding the licensee checked the position of the petcocks on the other
similar dampers in the system. The petcock for the penetration's inboard damper (HVR-
AOV-123) was found open. However, the petcocks for the containment isolation dampers
on the ventilation portion of the system (HVR-AOV-128 and HVR AOV-166) were found
closed. A maintenance supervisor opened the petcocks for the containment ventilation
dampers and reported that no damper movement was observed. The LLRT for that
penetration was subsequently performed without event.
At the close of the inspection, the licensee had not determined the root cause of the
damper failure or the length of time that the damper may have been inoperable.
However, the previous LLRT for Damper HVR-AOV-165 was successfully completed
approximately 90 days prior to the damper failure. As such, the damper had not been
inoperable for more than 90 days. This is considered an unresolved item pending further
NRC review of the licensee's root cause evaluation (50-450/9719-02).
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Review of Material Condition Durina Plant Totgs
a. Insoection Scoce (62702)
During this inspection period, the inspectors conducted routine plant tours to evaluate
plant material condition.
b. Observations and Findinas
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Main Generator Hydrogen Leakage: Main generator hydrogen leakage was
considered excessive. The identified leakage pathway was through the collector
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end generator seal and out the roof vent. A further worsening of this condition
could require a plant shutdown to support repairs.- A detailed discussion is
provided in Section E2.1 of this report.
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PASS: The PASS was found inoperable on November 12,1997, when two
system fuses blew during a surveillance. Repairs on the system were completed
on December 11,1997. However, extensive work was ctill planned to inspect and
repair air operated valve actuator,' *st may have been damaged due to water
intrusion into the system. PASS has been unavailable approximately 50 percent
over the past year and, overall, material condition was considered poor (see
Section M8.1).-
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Suppression Pool Pumpback Pump DFR P5B: The subject pump failed
inservice testing on December 22,1997, and remained out of service for the
remainder of the inspection period. Pump DFR P5B is one of four pumps
provided to pump emergency core cooling system (ECCS) leakage from the
auxiliary building sump back to the suppression pool during a design basis event.
The loss of the pump leaves one train of the suppression pool pumpback system
in a degraded condition (each train consists of two pumps).
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Contrc,1 Rod Drive Pump 1 A: The subject pump was experiencing higher than
normal vibration, which was believed to be caused by a damaged coupling. The
licensee considered the pump degraded but operable. The pump may utilized
during emergency operating procedure implementation for manual contsc! rod
movement and as a backup source of primary coolant.
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Containment Isolation Damper HVR AOV 165: The damper was found
inoperable during a surveillance on January 8,1997. Although corrective actions
to restore the damper were prompt, the length of time that the condition existed
was not known (see Section M1,4).
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ECCS and RCIC Flow Transmitters: Air entrapment was identified as a generic
problem in the instrument sensing lines for the ECCS and RCIC flow transmitters.
This resulted in the misoperation of the HPCS, RHR B and C minimum flow
valves. Additionally, the generic ramifications of the problem were not yet fully
investigated (see Section E8.1).
Material condition improvements included:
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Spent fuel pool cooling (SFC) Pump 1B: The SFC Pump 1B was repaired
recently (new impeller) and returned to service. The pump had been in a
degraded condition for approximately one year. The recent repaire restored the
original design margin to the pump.
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- Alternate Decay Heat Removal (ADHR), Suppression Pool Cleanup (SPC)
Mode: The SPC mode of ADHR was repaired and retumed to service this
inspection period. Suppression pool clarity has steadily improved since the
system was restored.
c. ConclusiQDA
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Whila overall plant material condition was good, there were notable equipment and
system performance problems. The inspector noted material condition concems with
main generator hydrogen leakage, the PASS, suppression pool pumpback Pump DFR-
PSB, control rod drive Pump 1 A, containment isolation Damper HVR AOV-165, and
ECCS and RCIC flow instruments. Conversely, SFC Pump 18 and the SPC mode of the
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ADHR system were repaired and returned to service.
M8 Miscellaneous Maintenance issues (92700)
M8.1 Poor Availability for the PASS
a. Insoection Set.9e (61726)
The inspector reviewed maintenance records associated with the PASS.
b. - Qblorvations and Findinas
Background: Out-of service time for the PASS is administratively controlled vin
" Operations Policy 6," which states, in part:
"The Pass System shall be given the same level of attention as a 30 day
LCO [ Limiting Ccndition for Operability). This will ensure the appropriate
level of management oversight for restoring the sys'em to an operable
status. . ."
"For 30 day LCOs, a daily assessment SHALL be made. Information
should be obtained at the moming meeting to ensure an action plan is in
place and satisfactory progress is being made to clear the LCO in a timely
manner,"
Additionally, the "On-Line Maintenance Guidelines," Revision 2, states, in part:
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"Out of service time should be minimized for system outages. No more
than 50% of the Technical Specification allowable out of service time
should be scheduled for a system outage."
Failure to Minimize PASS Unavailability: The inspector identified that Maintenance
and Operations personnel did not meet management expectations with regard to
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, accomplishing maintenance in less than half the administrative Lc0 and ensuring that
satisfactory progress was made to clear the administrative LCO in a timely manner,
The inspector observed that the PASS failed a monthly surveillance, due to blown fuses
(shorted limit switch), and remained inoperab;9 from November 12 through December 11,
1997 (29 days). During this period, there were long periods of time where the PASS was
not worked. For example, between November 12 and November 20 little or no
maintenance was performed on the PASS. Likewise, between November 23 and
November 30, no maintenance was accomplished.
Poor Availability History: The inspector also observed that the PASS was inoperable
for approximately 50 percent of the past 10 months. Additionally, material condition was
considered poor and long standing equinment problems were not fixed in a timely
manner. For example:
a in March 1997, water was found in the PASS control cabinet and was determined
to be caused by leakage past Check Valve D24 VF010 (boundary valve between
the nitrogen supply and the domineralized water tank). Water leaked past the
valve, into the air lines for multiple air-operated valves, and entered the valve
ac.tuators. When the air-operated valves v are repositioned, the actuators wcre
vented and water sprayed inside the PASS panel.
NOTE: A normally closed manualisolation valve (D24 VF012) was in the
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nitrogen line adjacent to Valve D24 VF010. The manual valve was
opened during surveillane.es (only). It was during this time that leakage
traveled past Valve D24 VF010 and into the nitrogen lines,
Initially, the licensee believed that sediment prevented Valve D24 VF010 from
seating properly and flushed the valve (a small amount of corrosion products was
observed during the flush). The valve was considered operational even though
minimal postmaintenance testing was perforred and no actions were taken to
address the source of the sediment.
- On May 9 the PASS failed due to a faulty sample needle. The licensee attempted
to return PASS to service on June 12.
- On June 12 leakage past three valves (in series, including D24 VF010) allowed
leakage out of the reactor coolant system and into the PASS nitrogen lines. The
nitrogen supply system relief valve lifted and sprayed the PASG area with
contaminated water. Shortly thereafter, MAI 312853 was initiated to repair the
leaky valves. However, the licensee returned the PASS to service on July 12
without repairing Valve D24 VF010.
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- On September 11 power was lost to the PASS control cabinet when water
sprayed the circuitry (due to leakage past Valve D24 VF010). The PASS was
returned to service on October 13 without effecting repairs to Valve D24 VF010.
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- On November 20, aftar the most recent PASS failure, Valve D24 VF010 was
finally repaired. Maintenance craftenen reported that the valve was not seating '
properly. The valve seats were lapped and the valve reassembled.
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Due to water intrusion into the nitrogen lines, the licensee was concerned that the
reliability of some of the air operated valves could be compromised. An extended PASS
outage was scheduled to start January 12,1998, to inspect some of these salves.
c C9nclualons
The high PASS unavailability was indicative of ineffective maintenance. The PASS was
taken out of service and often not worked in a timely manner. The amount of time taken
to return the PASS to service (approximately 30 days in all cases) was considered
excessive when considering the actual work accomplished.
The inspector concluded that the failure to maintain the PASS system operable, to a
reasonable extent, was a violation of TS 5.5.3. This TS requires the licensee to have 1
provisions for maintenance of sampling and analysis equipment sufficient to ensure the '
capability to obtain and analyze vanous samples under accident conditions. These
provisions were inadequate (VIO 50-458/9719 03). I
lit. Engineering
E2 Engineering Support of Facilities and Equipment
E2.1 Excessive Main Generator Hydrogen Leakage
a. Insoection Scoce (37551)
The inspectors observed Engineering's involvement addressing excessive main
generator hydrogen leakage.
b. Qhsgrvations and Findin96
NRC Inspection Report 9717 discussed excessive main generator hydrogen leakage.
Leakage was approximately four times normal at the close of the previous inspection .
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pe riod (2 5 percent concentration of hydrogen in air at the seal oil detrainment tank vent).
During this inspection period, the hydrogen leakage worsened and exceeded the
4.0 percent flammability threshold on December 17,1997. On the following day,
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hydrogen leakage increased and the concentration approached 6.0 percent, before
positive actions were taken to reduce the leakage,
in response to the problem, management directed operations to reduce hydrogen
pressure in the main generator (within desigra allowables), which resulted in a significant -
reduction in the effluent hydrogen concentration. At the clnse "'.he inspection period, the
effluent concentration was approximately 3 percent and a, ad to be slowly worsening.
Continued degradat on of the problem could result in a plar , nutdown to effect repairs.
The inspector observed that Engineering had identified the excessive main generator
leakage shortly after startup and had been actively trending the effluent concentration, but
had not appropriately evaluated the safety consequences of the leakage before the
flammability limit was exceeded. Furthermore, senior plant managers were not
adequately informed of the magnitude of the problem untilit was too late to avoid
exceeding the flammability threshold Engineers had demonstrated a poor safety focus in
their failure to recognize the significance of the issue and accomplish an appropriate
engineering evaluation in a timely manner.
c. CODelusions
Engineering did not evaluate in a timely manner the significance of exceeding the
flammability threshold for hydrogen concentration (measured at th9 seal oil detrainment
tank vent). Consequently, the flammability threshold was exceeded before safety issues
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were thoroughly evaluated.
I
E8 Miscellaneous Engineering Issues (37551)
E8.1 (Closed) Unresolved item (URI) 50-458/9717 05: air in HPCS flow-meter instrument lines
caused minimum flow valve malfunction. During the performance of inservice testing on
, the HPCS system (November 11,1997), the minimum flow valve failed to open when the
I test return valve was closed. Additionally, later in the surveillance, the minimum flow
valve unexpectedly closed when the HPCS suction was swapped from the suppression
pool to the condensate storage tank, in both instances the va've closure resulted in
" dead heading" the HPCS pump. An operator manually opened the minimum flow valve
after each misoperation. In response to the malfunction, HPCS was declared inoperable
and operators entered the TS ACTION Statement.
l
During troubleshooting, air was found in the HPCS flow transmitter instrument sensing
lines. The Rosemont flow transmitter provl des an input to the minimum flow valve control
circuits. Since the trip setpoint (minimum o,710 g,nm per TSs) corresponds to a very
. tall differential pressure across the flow meter (6 inches water column), a small amount
of air in the lines could have a significant impact on the instrument setpoint. At the close
of the inspection period, the licensee had not demonstrated that the instrument setpoint
had remained within a range permitted by TSs.
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During subsequent reviews, the licensee determined that the controllogic had reset itself
after each misoperation and, had the operator not repositioned the valve, the valve would
have automatically repositioned to the open position in a short time (10 to 15 seconds),
As such, the licensee did not believe that the pump could have been damaged by the
valve misoperations. Nonetheless, as a minimum, the condition represented a significant
distraction to the operators.
!
. Additional Events: During this inspection period, additional operational problems were
2
experienced with two other ECCS minimum flow valves:
valve was found closed (it should have been open in the standby lineup).
- On December 12,1997, after securing the RHR B pump, an operator attempted to
open the pump's minimum flow valve (the normal standby position) but the valve
unexpectedly cycled closed. After making a second attempt at opening the valve,
the valve remained open.
The licensee vented the instrument lines for the two RHR minimum flow valves tsnd
observed relatively large amounts of air coming from the vents. As a precautionary
measure, the remaining ECCS minimum flow valve instrument lines were vented.
Varying amounts of air were observed coming from all of the vents.
NOTE: Since the instrument lines are isolated during instrument calibration, air in
the lines would not be apparent during the evolution.
Licensee's Cause Determination: The licensee concluded that air had likely
accumulated in the instrument lines over a long period of time. The instrument lines
utilize high point vents (versus the preferred installation where the instrument lines are
routed with a continuous upward slope from the instrument to the process tap).
Additionally, there were no provisions for venting the lines periodically to preclude-
adversa affects from air entrapment.
The licensee had not determined all of the corrective actions necessary to address the air
entrapment problem by the close of the inspection period. More than one hundred other r
saft.ty related instruments utilize high point vents in the instrument's sensing lines, but
none were believed to be as sensitive to air entrapment as the flow monuring
instruments. At the close of the inspection period the licensee was still evaluating the
necessity of venting other instrument tensing lines.
Historical Problems: The inspector noted one recent instance of a similar pioblem. Air
w
' as found in the RCIC minimum flow valve instrument linea in January 1997.
The RCIC minimum flow valve instrumentation problems were first observed in January
1993 (CR 93-0022A). When the HPCS system was placed in service (with RCIC in a
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standby status) the RCIC minimum flow valve controllogic failed. Since the anomaly did
not appear to render the RCIC system inoperable when RCIC was in service, the licensee
was not o' rly concerned with the condition. Engineers continued to troubleshoot the '
problem for approximately 4 years. On December 31,1996, the CR was closed without
correcting the condition.
On January 23,1997, at the request of engineering, maintenance workers vented the
RCIC minimum llow valve instrument senting lines and found a substantial amount of air.
This condition, coupled with HPCS Induced pressure transients (through a common
suction line), caused the flow instruments to cycle rapidly and fail. Venting the lines ;
appeared to resolve the long standing RCIC problem. No CR was written to document
the condition and no actions were taken to vent other instrument lines with high point
vents. At the time, engineers did not recall having a similar problem with other
instruments so .3y assumed that a generic problem did not exist.
The following related issues were documented on CRs.
- On October 26,1994, the SSW flow indication was erratic. Further investigation
found air in the instrument sensing lines (CR 94-1396). '
- On August 30,1991, the indication from the HVK Chiller 1 A flow transmitter was
higher than normal when the chi'ler was not in service. Further investigation found '
air trapped in the instrument sensing lines (CR 910379). !
- On October 25,1987, HPCS instruments were reading erratically. The instrument
lines were filled and vented to resolve the problem.
Prior is the most recent events, River Bend Station engineers had believed that the
_
design of the instrument lines precluded the need for periodic venting, even after system
draining. The lines are equipped with a loop seal that inhitits the movement of air from .
- the process line to the instrument lines.
NRC ldentified InstaandAttensments:
Venting Recommendations: The inspector identified that the licensee did not
implement original recommendations for periodic venting of instrument lines with high
point vents. In a Stone and Webster document entitled "High Point Vents," dated
September 23,1982, the following information was provided to River Bend Str' ion:
'Within the industry, it is understood that high points are undesirable; when
they do occur, they must be ventc i . . ."
" Anticipated Venting Frequency
1. Required prior to every calibration.
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2. From a history of venting during calibration, a maintenance schedule could
be developed,if required, ' a case by-case basis.
3. When the instruments disagree."
The inspector requested that the licensee provide evidence that the above
recommendations were implemented. Ne such evidence was provided to the inspector.
Design: The inspector observed that tr's licensee's installation of fbw metenng
instruments did not appear to conform with GE design requirements. GE Design
- Specification 22A3137AA, Section 4.2.4.2, states, in part:
" Installation and arrangement of differential head meters shall conform with
the recommendations defined in Chapter 11 - ll of " Fluid Meters" for . . ,
onfice and venturi type devices . . , in no case shall the requirements of
this specification be violated without specific GE Engineering approval."
" Fluid Meters" recommends, in part, the following:
.
For connecting the primary element to the secondary element,1/2 inch tubing and
fittings are recommended.
Contrary to this recommendation,3/8 inch tubing was utilized for portions of the
instrument lines.
- Differential oressure measuring gages should be installed in accordance with the
specific int,tructions furnished by the manufacturer of the instrument.-
The Rosemont vendor manual states that high point vents in liquid instrument
sensing lines should be avoided.
Contrary to this recommendation, Rosemont differential pressure flow transmitters
were installed with high points in the instrument lines.
3
At the close of the inspection pericd, the licensee had not found where approval to
deviate from the above recommendations was provided from GE Further NRC review
will be necessary to evaluate the apparent failure to: (1) abide by the GE design
specification; and (2) follow the Stone and Webster venting recommendations. This is
considered an inspector followup item pending further NRC review of these issues
(IFl 50-458/9719 04).
Corrective Actions: Air in the sensing lines has been a historical problem at River Bend
_ __
_ Station. Although most CRs were documented several years ago, the licensee missed a
more recent opportunity to identify this common mode problem when air was identified in
the RCIC minimum flow valve instrument lines in January 1997. Engineering actions in
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response to that event were not comprehensive and did not prevent recurrence. More
specifically, engineers did not document the problem on a CR, which ultimately resulted in
circumynting the licensee's corrective action process. As a result, the cause of the
condation was not identified and the potential generic impact of the problem was not
properly considered. The failure to take appropriate actions in response to air entrapment
in the RCIC minimum flow valve instrument lines (a significant condition adverse to
quality)is a violation of 10 CFR Part 50 Appendix 8, Criterion XVI(50-458/9719 05).
In addition to the above, the licensee has repeatedly missed opportunities to correct the
generic misconception that lines with high point vents don't have to be vented. Even
, when problems periodically occurred, corrective actions were limited to the instruments
directly affected and generic applicability was not properly addressed.
Weak Operability Oetermination: The inspector observed that, when the HPCS and
RHR C minimum flow valve problems were experienced, operators promptly declared the
valves inoperable and entered the appropriate TS ACTION Statements. However, when
the same problem was observed with RHR B, the valve was not declared inoperable and
the TS ACTION was not entered.
An operations shift superintendent determined that the RHR B minimum flow valve was
operable based on a generic operability determination performed by a shift technical
advisor (STA). The inspector interviewed the STA to discuss the document and identified
that the STA had not properly considered the TS LCO for instrument operability. For
example. TS 3.3.5.1 requires, in part, that the RHR B minimum flow valve close at a
setpoint greater than 900 gpm - a setpoint less than 900 gpm would require the licensee
to call the instrument inoperable. Furthermore, the STA did not have a clear
understanding of how the condition (air in the instrument lines) could affect the instrurnent
setpoint, potentially affecting instrument operability. The STA indicated that he did not
believe that the condition would have resulted in damage to an ECCS pump, but admitted
that he did not consider the operability requirements for the flow instruments themselves.
Since corrective measures were promptly taken to vent the RHR B minimum flow valve,
the safety consequences of the oversight were negligible. However, the inspector
considered the failure to consider TS operability requirements when making an operability
determination to be an example of poor attention to detail when making operability calls.
IV. Plant Suonort
Si Conduct of Security and Safeguards Activities
S1.1 General Comments (71750)
De routine tours the inspector noted that the security officers were alert at their posts,
s6woty boundaries were being maintained properly, and screening processes at the
Primary Access Point were performed well.
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V. Management Meetings
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Xi Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on January 15,1998. 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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ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensta
J. P. Dimmette, General Manager, Plant Oporations
M. A. Dietrich, Director, Quality Programs
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D. T. Dormsdy, Manager, System Engineering
T. O. Hildebrandt, Manager, Maintenance
P. W. Chapman, Superintendent, Chemistry
H. B. Hutchens, Superintendent, Plant Security
D. N. Lorfing, Supervisor, Licensing
J. R. McGaha, Vice President Operations
M. G. McHugh, Licensing Engineer lll
W. P. O'Malley, Manager, Operations
D. L. Pace, Director, Design Engineering ,
A. D. Wells, Superintendent, Radiation Control
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations -i
IP 62707: Maintenance Observations
I?71707: Plant Operations
, IP 71750: Plant Support
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O
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lTEMS OPENED AND CLOGED
Ooened
50-458/9719-01 VIO Failure to Follow Procedures Addressing Electrical deparation
Criteria
50-458/9719-02 URI Failure of Containment isolation Damper HVR AOV-165
50-458/9719 03 VIO Failure to Maintain PASS Operable
50-458/9719-04 IFl Failure to Comply with GE Design Recommeridations and Archi'ect
Engineers Venting Recommendations for Instrument Sensing Lines
50-458/9719-05 VIO Failure to Take Adequate Corrective Actions to Address Air in
Instrument Sensing Lines
Closed
50-458/9717 05 URI Air in HPCS Instrument Una Causes Minimum Flow Valve
Malfunction
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LIST OF ACRONYMS USED
ADHR alternate decay heat removal
CFR Code of Federal Regulations
CR condition report
ECCS emergency core cooling system
EOOS equ:pment out of service computer
DG diesel generator
IFl inspector followup item
LCO limiting condition for ope:rability
LLRT localle,ak rate testing
MAI maintenance ac!ivity item
NEO Nuclear Equipment Opsrator
NRC U.S. Nuclear Regulatory Commission
PASS postaccident sampling system
RCIC reactor core isolation cooling
SFC spent fuel cooling
SPC suppression pool clet.nup
SSW standby serWe water -
STA shift technical advisor
TS Technical Specification
URI unresolved item
VIO violation
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