ML20134K191
| ML20134K191 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 02/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20134K171 | List: |
| References | |
| 50-382-96-14, NUDOCS 9702130178 | |
| Download: ML20134K191 (27) | |
See also: IR 05000382/1996014
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ENCLOSURE 2
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-382
License No.:
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Report No.:
50-382/96-14
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Licensee:
Entergy Operations, Inc.
Facility:
Waterford Steam Electric Station, Unit 3
Location:
Hwy.18
Killona, Louisiana
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Dates:
December 1,1996 through January 11,'1997
Inspectors:
L. A. Keller, Senior Resident Inspector
T. W. Pruett, Resident inspector
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C. E. Johnson, Reactor Inspector
G. M. Good, Senior Emergency Preparedness Analyst
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C. J. Paulk, Reactor Inspector
Approved By:
P. H. Harrell, Chief, Project Branch D
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ATTACHMENT:
Supplemental Information
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9702130178 970207
ADOCK 05000392
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EXECUTIVE SUMMARY
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Waterford Steam Electric Station, Unit 3
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NRC Inspection Report 50-382/96-14
This routine, announced inspection included aspects of licensee operations, maintenance,
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engineering and plant support. The report covers a 6-week period of resident inspection.
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Operations
Observed operations activities were generally performed in a manner consistent
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with safe operation of the facility (Section 01.1).
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Operations inappropriately signed off a condition report (CR) on a low pressure
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safety injection (LPSI) Train B water hammer that occurred on November 19,1996,
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as a condition not affecting system operability. This conclusion was premature in
that the cause of the water hammer, the repeatability of the pressure spike
experienced, and an analysis of the effect on system components had not been
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performed (Section O2.4.5).
On November 19 and 21, LPSI Train B experienced a water hammer and no actions
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were taken to discover the root cause until a subsequent water hammer event
occurred in LPSI Train A on December 13. This was despite clear evidence that the
conditions that caused the water hammer would exist during an accident. This
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issue is unresolved pending further NRC review of the licensee's actions
(Section O2.1b.5).
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L'icensee analysis indicated that there was not reasonable assurance of ability to
remotely initiate shutdown cooling following a water hammer in the LPSI piping due
to potential pressure locking of LPSI flex-wedge gate valves. The inspectors
concluded that there was a potential common-rnode failure for pressure locking
flex-wedge gate valves in both trains of LPSI. This issue related to the licensee's
response to the water hammer events is unresolved pending further NRC review
(Section 02.1b.5).
Maintenance
The inspector prevented a welding procedural violation by prompting craft personnel
to take a required interpass temperature reading (Section M1.2).
The inspectors determined that the hydrogen analyzer calibration procedure was
inadequate. The discrepancies indicated a lack of rigor during the development of
maintenance procedures for the hydrogen analyzer and constituted preconditioning.
A violation was identified for not maintaining an adequate test procedure
(Section M1.3).
The licensee's participation in the Arkansas Nuclear One (ANO) Technical
Specifications (TS) audit was a positive initiative to assess the adequacy of their
surveillance program for the plant protection system (Section M3.1).
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The licensee's determination that the channel functional test was not in accordance
with the licensing basis and the subsequent corrective actions were appropriate.
The failure to perform channel functional tests on the core protection calculators
(CPC) in accordance with the licensing basis is considered a noncited violation
(Section M3.1).
Enaineerino
The system engineer did not observe surveillance testing of the hydrogen analyzer
and was not informed when trouble shooting was performed when the analyzer
failed the test. Also, the system engineer did not identify in reviewing the test
procedure that it was preconditioning the test (Section M1.3).
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Engineering support in investigating the November 19 and 21 water hammer
incidents in LPSI Train B was poor. The lack of rigor and questioning attitude
regarding the cause of these water hammer incidents left the LPSI system
vulnerable to further water hammer and loss of shutdown cooling function.
Engineering support following a subsequent water hammer in LPSI Train A was
significantly better, including a good recommendation for modifications to
flex-wedge gate valves (Section O2.1).
Plant Sucoort
A poor radiation protection (RP) work practice was observed in which maintenance
technicians breached an overhead contaminated system without face shield
, protection (Section M1.2).
The licensee substantially improved the quality of permanent and temporary lighting
in the protected area. However, the f ailure of a security patrol officer to report a
lighting deficiency is considered a violation of TS 6.8.1.a (Section S1.1).
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Report Details
Summarv of Plant Status
The plant operated at 88 percent power on December 6 and 7 to perform CPC channel
functional checks. On December 16 and 17, the plant operated at 63 percent power to
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perform maintenance on the main feedwater pumps. The plant operated at essentially
100 percent power during the remainder of this inspection period.
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l. Operations
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Conduct of Operations
01.1 General Comments (71707)
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Using Inspection Procedure 71707, the inspectors performed frequent reviews of
ongoing plant operations, control room board walkdowns, and plant tours.
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Observed activities were generally performed in a manner consistent with safe
operation of the facility. Housekeeping and material condition were generally good.
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Operators were familiar with causes for lit control room annunciators. Preparations
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for cold weather were adequate. Shift turnover and plan-of-the-day meetings were
professional and informative. However, certain activities appeared to be in violation
of NRC requirements or indicate problem areas, as discussed below.
01.2 Nuclear Auxiliarv Ooerator Tours (71707)
The inspectors observed two nuclear auxiliary operators during the performance of
plant tours. The inspectors noted that the auxiliary operators were attentive to
plant equipment and material discrepancies during the tours. Several minor
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discrepancies, involving lighting, minor leakage from pumps and valves, and general
plant cleanliness, were identified and resolved. Operators were knowledgeable of
plant conditions and operating trends of plant equipment.
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Operational Status of Facilities and Equipment
02.1
LPSI System Nitroaen Pockets and Water Hammer Events
a.
Insoection Scone (71707,37551)
The inspectors reviewed the circumstances surrounding the water hammer events
that occurred in LPSI Train A on December 13 and in LPSI Train B on November 19
and 21,1996. Additionally, the inspectors reviewed the licensee's operability
analysis that was completed to evaluate the presence of nitrogen gas pockets in
LPSI Train B.
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b.
Observations and Findinos
b.1
LPSI Train A Water Hammer
On December 13, during a routine surveillance start of LPSI Pump A, a pressure
spike caused by a water hammer occurred in the system piping. An operator
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observing the plant computer display at the time the pump was started, noted that
LPSI pump discharge pressure briefly reached 317 psig (shutoff head of the pump is
approximately 213 psig). The operator at the pump, as well as the operators in the
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control room, heard a banging noise after the pump was started. As a result of the
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water hammer, the shift supervisor declared LPSI Train A inoperable and
appropriately entered TS 3.5.2.
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The LPSI Train A piping was inspected by engineering personnel from the pump to
the containment penetrations and no visible signs of piping or hanger damage was
noted. Ultrasonic testing (UT) was subsequently performed at several high-point
vent areas. The horizontal piping run containing vent Valves Sl-133A and -134A
was found to contain an apparent void in the pipe (12 inches and 14 inches of prc,
respectively). The void was sampled and found to be approximately 97 percent -
Valves SI-133A and -134A were then used to fully vent the piping and UT
confirmed the piping was full of water. The scope of the UT was then expanded to
include the high points of the LPSI Pump A suction, which revealed the piping was
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full. LPSI Pump A was subsequently started with no abnormal noise or pipe
movernent. Based on the UT results and successful pump start, LPSI Pump A was
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declared operable on December 14 and TS 3.5.2 subsequently exited. On
December 14, the licensee conducted UT on portions of the LPSI Train B piping and
the discharge of the High Pressure Safety injection (HPSI) Pump A/B discharge
piping to ensure the piping was full. No voids were found.
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The licensee determined that the source of the nitrogen was leakage of
nitrogen-saturated water from the safety injection tanks (SIT). The SITS contain a
nitrogen blanket pressurized at approximately 650 psig. The SIT outlet valves are
open and the SIT outlet piping connects to a common injection line with LPSI and
HPSI. Therefore, the nitrogen-saturated SIT water can freely communicate back to
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LPSI Header Check Valves SI-142A(B) and -143A(B). Since the solubility of
nitrogen in water is greater at higher pressures, the licensee concluded the nitrogen
pockets were the result of nitrogen coming out of solution in the relatively low
pressure of the LPSI system (less than 50 psig when pump is not running) when the
water leaked backward (i.e., from a high to a low pressure area) through a check
valve and an isolation valve.
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b.2 LPSI Train B Nitroaen Pockets
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in an attempt to identify all nitrogen pocket locations, the licensee again expanded
the scope of the UT program on December 18 and discovered nitrogen pockets in
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the LPSI Train B piping at Penetrations 36 and 37. The pockets were located at the
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high points between Flow Control Valves SI-138B and -139B and the inside
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Containment Isolation Check Valves SI-1428 and -1438. The arc length of the gas
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pocket at Penetration 36 was 11.3 inches over a length of 18 feet, which equates
to a volume of 2.54 cubic feet. The arc length of the gas pocket at Penetration 37
was 10 inches over a length of 16.5 feet, which equates to a volume of 1.74 cubic
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feet. The locations of these particular nitrogen pockets were such that they could
not be removed due to the lack of vent valves in the affected section of piping or
the ability to flush them at power. CR 96-1965 was written to document and
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disposition the presence of these nitrogen pockets. On December 18, the licensee
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initiated an operability evaluation in accordance with Site Directive W4.101,
" Operability / Qualification Confirmation Process," for the LPSI Train B nitrogen
pockets.
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The W4.101 evaluation concluded that the existing nitrogen pockets would cause a
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pressure transient on a LPSI Pump B start that would slightly exceed the design
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pressure of the system (650 psig), but would not prevent the LPSI system from
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providing emergency core cooling in the event of a loss-of-coolant accident. The
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basis for this conclusion was that the very scenario of concern had occurred on
November 21, in that a start of LPSI Pump B resulted in a pressure spike of
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660 psig, which did not result in any obvious component / piping / system damage.
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The licensee believed that the conditions that resulted from the November 21
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pressure transient bounded any future transient.
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The inspectors reviewed the operability evaluation completed by the licensee to
independently assess the continued operability of LPSI Train B with a nitrogen
pocket in the system piping. The specific concern was the capability of the system
to physically withstand another water hammer event. At the end of this inspection
period, a review of the licensee's operability evaluation and the operability of the
LPSI systems by NRC personnel was ongoing. Review of this aspect of the
licensee's response to the water hammer events remains unresolved pending the
completion of the NRC's review (50-382/9614-01, Example 1).
The W4.101 evaluation also addressed concerns related to potential pressure
locking of flex-wedge gate valves in the supply and return lines of the shutdown
cooling heat exchanger (Valves SI-125B and -412B) and the effects on Crosby
Relief Valve SI-132B. The W4.101 evaluation was completed on December 20 and
concluded that shutdown cooling entry could be affected since there was no
reasonable assurance that Valves SI-1258 and -412B would not be pressure locked
following a water hammer when LPSI Pump B started.
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The W4.101 evaluation listed the following corrective actions. At the end of this
inspection period, the licensee was pursuing the completion of the items.
Periodically verify by UT that the arc length of the gas pocket at
Penetration 36 does not exceed 11.8 inches and the gas pocket at
Penetration 37 does not exceed 10.4 inches (as of the end of the inspection
period the UT frequency was every 3 days);
Enter the appropriate limiting conditions for operation (TS 3.9.8.2, 3.4.1.3,
and 3.4.1.4) for potential ;noperability of flex-wedge Gate Valves SI-125B
and -412B;
Initiate a repair package to install vent lines at Penetrations 36,37,38,and
39 during the next refueling outage (currently scheduled for April 1997);
Design engineering to perform a detailed transient analysis that accurately
models the as-found conditions; and
Determine additional long-term corrective actions through CR 96-1965.
b.3 Crosbv Relief Valve Sl-132B Concern
Valve SI-132B is the LPSI Train B discharge header thermal relief, which is set at
650 psig. This valve had been identified in CR 96-0463 as having an incorrectly set
blowdown ring. Tt issue of Crosby relief valve blowdown ring discrepancies is
discus' sed in NRC ..spection Report 50-382/96-202. This setting did not affect the
set pressure of the valve, but effects the pressure at which the valve reseats after
opening. The specified closing pressure was approximately 585 psig (90 percent of
set pressure).
The concern was that a water hammer would cause the relief valve to open and the
incorrectly set blowdown ring would prevent the valve from reciosing, thereby
diverting LPSI flow from the vessel. Since the shutoff head of the LPSI pump is
approximate!y 213 psig, the closing pressure of Relief Valve SI-132B would have to
be less than 33 percent of set pressure for the valve to not reclose. Based on the
magnitude of the blowdown ring error (off by 10 notches) and previous bench
testing of similar valves (worst case reset was 74 percent of set pressure), the
licensee concluded that Relief Valve SI-132B would reset under the scenario of
concern.
The inspectors reviewed the licensee's evaluation and conclusions with respect to
Valve SI-1328 and concluded that they were acceptable.
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b.4 Flex-Wedae Gate Valves SI-125A(B) and -412A(B) Concern
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The inlet and outlet shutdown cooling heat exchanger isolation valves, Sl-125A(B)
and -412A(B), are motor-operated, flex-wedge gate valves and were identified by
the licensee as being susceptible to pressure locking in the response to Genenc
Letter 95-07.
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The concern with pressure locking was that a water hammer would generate a
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pressure wave that would be transmitted to Valves SI-125A(B) and -412A(B) and
allow pressure to be trapped in the valve bonnets, thereby eliminating the ability to
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remotely open the valves. On December 20, the licensee concluded that there was
no reasonable assurance that pressure locking of the Train B valves would not occur
during the scenario of concern and, therefore, declared the valves inoperable. A
modification was initiated to install vents in the valve bonnets to prevent pressure
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locking, which was completed and Valves SI-125B and -4128 declared operable on
December 22. The licensee decided not to perform the modification on the valves
in Train A since voids had not been detected in Train A and since periodic venting
and UT was determined to be adequate to prevent water hammer until the
modification was completed.
As of the end of this inspection period, the licensee was venting both trains of LPSI
once per day and performing UT on both trains of LPSI every 3 days to verify that
LPSI Train A was water solid and the nitrogen pockets in Train B were not
expanding.
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The issue of potential pressure locking of the shutdown cooling heat exchanger inlet
and outlet valves causing a loss of shutdown cooling is another aspect of this
unresolved item, related to the licensee's response to the water hammer events,
pending additional review by NRC personnel (50-382/9614-01, Example 2).
b.5 LPSI Train B Water Hammer Event
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On November 19, while starting LPSI Pump B to recirculate the refueling water
storage pool (RWSP) for sampling, a water hammer occurred in the downstream
piping. Control room operators reported that control room Gauge SI-IPI-036 spiked
up to approximately 500 psig. Normal pump operating pressure of approximately
160 psig was observed by the operators for the duration of this pump run.
Subsequently, on November 19, CR 96-1831 was written to disposition this event.
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On November 20, the shift supervisor signed off CR 96-1831 as a condition that did
not affect operability of the equipment / system. The stated basis for this conclusion
was: "The pump operated at normal pressure when running. The system engineer
was informed and he stated that the start pressure appeared to be a little high.
Currently, some air voiding in the pipe / pump / instrument line is suspected, but not
enough to cause an operability concern. No water hammer was noted by the shift."
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The inspectors considered this conclusion premature in that the cause of the water
hammer / pressure spike, the repeatability of the pressure spike experienced, and an
analysis of the effect on system components (i.e., flex-wedge gate valves and other
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components) had not been performed. The inspectors noted that the crew on shift
at the time of the event associated a water hammer as a " loud banging noise" and
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did not consider this transient a water hammer due to the lack of audible indication.
The inspectors concluded that whether the event was termed water hammer or
pressure spike, the magnitude was sufficiently above normal established parameters
to warrant a thorough investigation.
On November 21, LPSI Pump B was again used to recirculate the RWSP. Prior to
starting the pump, the Train B piping was vented and a strip chart recorder was
installed to closely monitor system pressure. The subsequent pump start resulted in
a pressure transient of 660 psig, as recorded on the strip chart recorder. Shortly
after this pump run, LPSI Train B Flow Control Valve SI 139B was found partially
open because of a valve mispositioning error by the operations crew.
Valve SI-139B was closed, LPSI Pump B was restarted, and no pressure transient
was experienced. Following this pump run without a water hammer, the licensee
took no further tangible efforts to discover why water hammers occurred with
Valve SI-139B open until the LPSI Train A water hammer event occurred in
December.
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The inspectors noted that Valve SI-139B receives an automatic open signal during a
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safety injection actuation signal and the valve opens before the pump starts. These
automatic actions would reestablish the same system configuration that existed
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when significant water hammers occurred on November 19 and 21. The inspectors
noted that there was clear evidence that the cause of the water hammers existed
downstream of Valve SI 139B, yet no tangible effort was made to ascertain the
cause until a subsequent water hammer occurred in LPSI Train A on December 13.
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The inspectors concluded that the failure to adequately investigate the cause of the
LPSI Train B water hammers left the system vulnerable to future water hammer
incidents and potential system operability concerns. As discussed in
Section O2.1b2 above, there was no reasonable assurance that loss of shutdown
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cooling would not occur due to pressure locking of the shutdown cooling
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flex-wedge gate valves following a pressure transient. This aspect of the licensee's
response to the water hammer events is unresolved pending additional review by
NRC personnel (50-382/9614-01, Example 3).
The licensee informed the inspectors at the exit meeting that not all engineering
efforts to determine the cause of the November 19 and 21 water hammers stopped
following the repositioning of Valve SI-139B. The licensee stated that between the
November and December events, the LPSI system engineer held discussions with
Chemistry and others into the possibility of nitrogen being responsible for the water
hammers, and that absent the December 13 event, this line of questioning would
have eventually led to the discovery of the nitrogen pockets. The inspectors could
not confirm or deny the system engineer's possible intentions, but noted there was
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nothing documented in CR 96-1831 nor were there any tangible actions taken (i.e.,
samples drawn, UT performed, etc.) to confirm / quantify possible nitrogen intrusion
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into the LPSI system prior to the December 13 event.
c.
Conclusions
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The inspectors concluded that it was inappropriate for operations to sign off the CR
on the LPSI Train B water hammer that occurred on November 19, without pursuing
the identification of the root cause of the water hammer events. The licensee's
failure to adequately pursue the cause of the November 19 and 21 water hammer
events could have resulted in subsequent water hammers during system response
to an accident.
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The licensee's response to the water hammer that occurred in LPSI Train A on
December 13 was significantly better. Sesequent investigations discovered
nitrogen gas pockets at various high points in the LPSI system. The licensee was
unable to vent two pockets of nitrogen in the LPSI Train B piping near the
containment penetrations and, therefore, LPSI Train B was still vulnerable to water
hammer in the event of a safety injection actuation signal. The operability of the
system and the adequacy of previous corrective actions are unresolved issues. The
licensee concluded that the resulting water hammer, although exceeding system
design pressure, would not prevent LPSI Train B from providing emergency core
cooling. Modifications of the LPSI Train B flex-wedge gate valves for the shutdown
cooling system were completed due to pressure locking concerns; however, the
LPSI Train A was not completed. The potential for common-mode failure of
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shutdown cooling is an unresolved issue.
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Miscellaneous Operations issues (92901)
08.1 The inspectors conducted a survey of the licensee's TS interpretations and
determined that none of the documents contained informal references to NRC
review and approval without formal NRC documentation. The inspectors
emphasized to the licensee that any informal reference to NRC review and approval
in a TS interpretation is not recognized by the Commission and is not an acceptable
practice.
08.2 (Closed) Violation 50-382/9517-01: failure to acknowledge fire protection panel
alarms. This violation involved the failure of control room operators to recognize
and announce fire protection panel alarms affecting the turbine building. In
response to the violation, the licensee revised procedures to require operators to
verify the extent of fires using the fire detection computer, added a strobe light to
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the fire detection panel, and developed required reading material describing the
event. The inspectors observed that the strobe light was effective in gaining
operator attention to the fire detection panel and that operators were utilizing the
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fire detection computer to determine the extent of potential fires. The inspectors
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determined that the licensee's corrective actions were satisfactory to address this
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violation.
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08.3 IClosed) Violation 50-382/9605-02: control room personnel unaware of activities
affecting Emergency Diesel Generator A. This violation irvolvec' the operation of
the emergency diesel generator fuel rack override lever by (1 instructor and
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maintenance personnel without the consent of the control rum. In response to this
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violation, the licensee counseled the individuals involved, discussed the event with
the training department, and issued a plant manager memorandum to all site
personnel reenforcing expectations about the operation of plant equipment. The
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inspectors determined that the licensee's corrective actions were satisfactory to
address this violation.
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II. Maintenan,c_e
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Conduct of Maintenance
M 1.1 _ General Comments
a.
Inspection Scoce (62707,61726)
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The inspectors observed all or portions of the following maintenancs and
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surveillance activities:
MI-003-223
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Core Protection Calculator Response Time Verification
WA 01150587
Installation of a Vent Valve in Charging System
WA 01150409
Replacement of Charging Pump Discharge Relief
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ME-003-431
Containment Hydrogen Analyzer Functional Test and
Calibration
WA 01153825
Troubleshoot Hydrogen Analyzer Pump A Low
Alignment Discharge Pressure
b.
Observations and Findinos
in general, the inspectors found the conduct of maintenance and surveillance to be
adequate. All activities observed were performed with the work authorization (WA)
package and/or test procedures present and in active use. Technicians appeared
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experienced and knowledgeable of their. assigned tasks. When applicable,
appropriate radiation control measures were implemented. The inspectors observed
supervisors monitoring job progress and quality control personnel were present
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whenever required by procedure. However, certain activities violated NRC
requirements or indicated performance problems, as discussed below.
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M1.2 Charaina Pumo Relief Valve Reolacement
a.
Inspection Scoce (62707)
The inspectors observed the replacement of Charging Pump B Discharge Relief
Valve CVC-1928. The inspectors observed removal and installation activities,
reviewed the applicable work packages and system drawings, and interviewed
selected personnel.
b.
Observations and Findinas
On December 10,1996, the inspectors observed maintenance technicians
breaching an overhead section of the char 0 ng system, without protective face
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shields, during removal of the existing charging pump discharge relief valve and
piping / flange connection. The inspectors questioned the RP technician who was in
the area monitoring the work activity about the observed practice. The RP
technician informed the inspectors that procedures did not specifically require
personnel to wear protective face shields when breaching a system. An RP
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supervisor also confirmed the RP technician's statement. The inspectors expressed
concern to the RP supervisor regarding the potential for personnel contamination
and/or injury due to this work practice. The licensee subsequently agreed that this
was a poor work practice. The licensee informed the inspectors that they initiated a
CR to review this issue.
Additionally, the inspectors noted that the bolts and nuts removed from the flange
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were not the type of material specified by Drawing E-3029-LW3-CH-2. The
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inspectors were informed that Document Revision Notice (DRN) M-9502513
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implemented the material change. The inspectors found that the drawing was
stamped with the DRN number; however, the inspectors questioned the licensee as
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to why the DRN was not included in the work package and why the drawing was
not revised after a year. The inspectors were informed that: (1) the subject DRN
was inadvertently omitted, and (2) Design Engineering Procedure NOECP-306,
" Document Revision Notices," Revision 4, allows a time period for up to 18 months
for noncritical drawings to be revised; therefore, no procedural violation was
identified.
The inspectors observed fit-up and welding activities for Field Weld SW-17A (socket
weld) during installation of the new charging pump discharge relief valve and
associated piping. The inspectors noted that after completion of the first weld pass
for Weld SW-17A, the maintenance technician (welder) was starting to initiate the
second weld pass without verifying interpass temperature (350 F maximum) in
accordance with Weld Procedure WPS E-P8-A8. The inspectors stopped the
maintenance technician before the second weld pass was initiated and questioned
him if the interpass temperature was verified. The inspectors noted that there was
no "tempil stick" or pyrometer in the work area for use by the maintenance
technicians. Maintenance technicians in the area sent a maintenance assistant to
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get a pyrometer. The licensee confirmed that absent the inspector's prompting the
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interpass temperature would not have been taken.
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Conclusions
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A poor RP work practice was observed in which maintenance technicians breached
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an overhead contaminated system without face shield protection. The inspectors
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prevented a welding procedural violation by prompting craft personnel to take a
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required interpass temperature reading.
M1.3 Calibration of Hydroaen Analyzers
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a.
Insoection Scope (61726,37551)
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The inspectors cbserved the performance of the Hydrogen Analyzer Train A
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calibration in accordance with Procedure ME-003-431, "Co -
" ment Hydrogen
Analyzer Functional Test and Calibration," on December 3'
66,and
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trouble-shooting activities involving Hydrogen Analyzer Pur,
A discharge pressure
on January 3,1997, in accordance with WA 01153825.
b.
Observations and Findinos
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The instrument and controls foreman was present during portions of the calibration
and all of the trouble shooting. The system engineer did not observe the
surveillance and was not informed of the trouble shooting activities. Several
procedure discrepancies were noted during the performance of the surveillance test.
Procedure ME-003-431, Section 8.2.11, required that the hydrogen analyzer loop
and measurement flows be verified and adjusted if necessary prior to the
performance of the calibration. The inspectors noted that the technicians adjusted
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the loop flow from 3.8 to 4.0 scfh prior to performing the hydrogen analyzer
calibration and that the procedure did not specify an acceptable as-found flow rate
for either loop flow or measurement flow. The inspectors noted that returning the
gas flow to the technical manual referenced values prior to calibration was
preconditioning of the hydrogen analyzer and invalidated the as-found percent
hydrogen data obtained by the technicians. The licensee agreed that the
adjustment on the loop flow preconditioned the hydrogen analyzer and stated that a
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revision to the calibration procedure would be performed to ensure as-found percent
hydrogen data was obtained prior to adjusting hydrogen analyzer flow rates.
Procedure OP-903-120, " Containment and Miscellaneous System Quarterly IST
Valves Test," Section 7.5, required that the licensee verify the hydrogen analyzer
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loop flow greater than or equal to 1 scfh during stroke testing of the containment
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dome hydrogen sample valve. The inspectors noted that Technical Manual
Section 3.5, " Pressure Regulation," required that the loop flow rate be set at 4 scfh
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and that verification of 1 scfh instead of 4 scfh during quarterly inservice testing
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(IST) could allow an adverse condition to go uncorrected in that partial opening of
the sample valve may allow 1 scfh but not 4 scfh. The licensee stated that a
review of @ testing procedure would be performed to determine if a different
sample flow rate should be specified in Procedure OP-903-120.
The inspectors noted that Teleydyne Analytical Instruments Technical Manual,
Section 3.5, stated that the pressure in the return loop is maintained at 10 psig
above containment pressure in order to return gas and water to containment at
positive pressure and to prevent back pressuring the system. The inspectors
observed that the hydrogen analyzer control panel outlet pressure indicated that the
return pressure was approximately 1 psig above containment pressure. The
inspectors identified that the technicians did not note the abnormal outlet pressure
reading and determined that Procedure ME-003-431 did not require that the
technicians verify whether or not the hydrogen analyzer pump developed sufficient
discharge pressure to ensure the sample gas was returned to containment.
In response to these observations, the licensee: (1) stated that
Procedure ME-003-431 would be revised to require recording of the hydrogen
analyzer inlet and outlet pressure, (2) initiated a condition identification to document
the discrepancy, and (3) performed trouble shooting to verify the actual pressure
and flow rates of the hydrogen analyzer.
The inspectors observed the licensee perform the recommended technical manual
testing as part of trouble-shooting activities associated with determining why the
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hydrogen analyzer return pressure was not 10 psig above containment pressure.
With 5 psig nitrogen pressure applied to the hydrogen analyzer inlet, the following
results were obtained:
Test Location
Actual
Reauired Per Technical
Manual
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Pump Suction
2.83
1 psig
Pump Outlet
16.0
15-17 psig
Sample Pressure
4.41
4.0 psig
Loop Flow
4.4
Above 5.0 scfh
Sample Flow
0.25 scfh
Not Specified
Return Pressure
15.5 psia
Not Specified
Containment Pressure
15.0 psia
Not Specified
Based on the results of trouble shooting, the licensee: (1) stated that an 18-month
repetitive task would be developed to ensure the hydrogen analyzer pressure
regulators were properly adjusted to maintain the required sample and measurement
flow rates, (2) determined that the hydrogen analyzer pump developed an adequate
discharge pressure, (3) determined that the low return header pressure was due to
the effects of containment pressure and the location of the return loop pressure
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transmitter, and (4) initiated an additional condition identification to perform testing
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on Hydrogen Analyzer Train B.
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The failure to provide a procedure for calibration of the hydrogen analyzers, which
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properly implements the testing recommended by the technica! manual, is a
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violation of TS 6.8.1 (50-382/9614-02).
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c.
Conclusions
The inspectors determined that the hydrogen analyzer calibration procedure was
inadequate since several procedural discrepancies existed. Collectively, the
discrepancies indicated a lack of rigor by maintenance during the development of
procedures for the hydrogen analyzer and by system engineering during review.
M3
Maintenance Procedures and Documentation
M 3.1 Inadeauate Channel Functional Test Procedure For CPC
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a.
Insoection Scoce (61726)
The inspectors reviewed the circumstances surrounding the licensee's identification
that three of the four CPC reactor protective channels were inoperable due to an
inadequate TS surveillance procedure.
b.
Observations and Findinas
The CPCs are digital computers that calculate local power density and departure
from nucleate boiling ratio (DNBR). A CPC is installed in each of the four reactor
protection channels. The calculated DNBR and local power density are compared
with trip setpoints for initiation of a low DNBR trip and the high local power density
trip. Each CPC receives the following inputs: core inlet and outlet temperature,
pressurizer pressure, react::t coolant pump speed, excore nuclear instrumentation
power, selected control element assembly positions, and control element assembly
deviation penalty factors.
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While assisting ANO personnel who were performing an audit of plant protection
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system TS surveillance compliance, Waterford 3 personnel discovered an issue
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related to the TS surveillance channel functional check for the CPCs that was
relevant to Waterford 3. The issue involved whether all the various inputs to the
CPC were required to be manipulated during the 18-month channel functional test
specified by TS 4.3.1.1, or if it was acceptable to manipulate the excore nuclear
instrumentation input only, and take credit for testing " overlap" for the other sensor
inputs, which was the current practice.
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Waterford 3 TS for the CPCs includes the following statement: "This CHANNEL
FUNCTIONAL TEST shallinclude the injection of simulated process signals into the
channel as close to the sensors as practicable to verify OPERABILITY including
alarm and/or trip functions." The Waterford 3 testing regime had taken credit for
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testing " overlap" for the 18-month channel functional test for all of the CPC inputs
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except excore nuclear instrumentation. Overlap testing employs a series of
sequential, o"erlapping tests of individual sections of the channel which, when
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combined, tas'.'d the entire channel. The ANO Safety Evaluation Report indicated
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that overlap tests for the CPCs were inadequate and that a functional operation
check from C7C sensor inputs to the trip output would be reouired to adequately
ensure that the CPCs were operational. The Waterford 3 Safety Evaluation Report
indicates that Waterford 3 is to meet the requirements on CPCs in the ANO Safety
Evaluation Report; therefore, overlap tests for the CPCs are also inadequate at
Waterford 3. The licensee, therefore, concluded that CPC Channels A, B, and C
were inoperable pending a satisfactory channel functional test. CPC Channel D was
deemed operable because it had successfully passed the reactor trip response time
test during the last refueling outage. The reactor trip response time test adequately
tests the char,nel using all the inputs, but is only performed on one CPC channe1 per
18 months.
On December 5,1996, the licensee declared CPC Channels A,B, and C inoperable
due to the failure to adequately perform Surveillance Requirement 4.3.1.1 and
entered the action requirements of TS 3.3.1 and 4.0.3. TS 3,3.1 requires at least
two CPC channels operable or entry into TS 3.0.3, which requires that within
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, action be initiated to place the unit in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
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' However, TS 4.0.3 allows the action requirements to he delayed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to
comp!e's the surveillance. On December 6, testing was satisfactorily completed on
Channel A by utilizing the reactor trip system response time test, which is normally
performed during refueling outages. The inspectors verified that appropriate
precautions were taken to perform this surveillance at power. Performance of this
test required a power reduction to 88 percent due to the necessity of taking both
channels of the control element assembly calculator system out of service for the
test. The restoration of Channel A resulted in two operable channels, which is
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allowed under TS 3.3.1. Channels B and C were satisfactorily tested and returned
to service on December 6 and 7, respectively.
The inspectors reviewed the relevant documentation in the Waterford 3 and ANO
Safety Evaluation Reports and the Waterford 3 surveillance test procedures for CPC.
The inspectors concluded that the failure to adequately test all the sensor inputs to
the CPCs during the charinel functional test is a violation of TS 4.3.1 A. This
licensee-identified and corrected violation is being treated as a noncitd ;tiolation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the
violation was identified by the licensee, was not willful, actions taken as a result of
a previous violation should not have corrected this problem, and appropriate
corrective actions were completed by the licensee (50-382/9614-04).
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c.
Conclusions
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The licensee's participation in the ANO TS audit was a positive initiative to assess
the adequacy of the Waterford surveillance program for the plant protection system.
The licensee's determination that the channel functional test was not in accordance
with the licensing basis and the subsequent corrective actions were appropriate.
The failure to perform channel functional tests on the CPCs in accordance with the
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licensing basis was a noncited violation.
M4
Maintenance Ste'f Knowledge and Performance
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M8
Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Insoection Followuo item 50-382/94402-02: failure to follow an
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installation weld detail. The inspectors previously identified a program weakness
regarding a failure to follow an installation weld detail during replacement of piping.
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The inspectors performed an inspection on a portion of replaced piping between the
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high-pressure turbine and first-stage feedwater heaters. The inspectors observed
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that Weld FW-20A was not conducted in accordance with the drawing. This
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resulted in the condition of an undressed, notched flame-cut surface on the edges
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of the hole, through the pressure piping which was not in accordance with the
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drawing. This condition was not identified by the responsible craft, quality control
(QC), or supervision. The licensee documented this condition in CR 94-337. The
licensee had committed to the following:
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' Conduct trainin0 or all craft personnel (fitters / welders) involved in cutting
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and welding processes, and
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Revised Procedure MM-001-056 to require QC to verify the ID of the half
couplings and ID match the hole cut of the sockolet.
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The inspectors found that the licensee had closed CR 94-337 before the
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commitments were implemented. The licenses initiated CR 96-1452 as a result of
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the inspectors' finding. CR 96-1452 indicated that the Waterford 3 welding manual
would include appropriate guidance in Design Engineering Administrative Manual
(DEAM), Appendix 2, E-TCG, " Thermal Cutting and Gouging."
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The inspectors reviewed DEAM, Appendix 2 (E-TCG and E-GWS-1) and determined
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that the document provided adequate instructions and details for thermal cutting
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and gouging. The inspectors also determined procedural guidance included in
DEAM, Appendix 2 was adequate to prevent recurrence for safety- and
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nonsafety-related components.
- M8 '2 (Closed) Violation 50-382/9508-01: f ailure to follow procedures to ensure adequate
storage of loose items and currect usage of measuring and test equipment (M&TE).
This violation involved the licensee's f ailure to ensure loose items were adequately
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secured in safety-related areas and to ensure out-of-calibration M&TE was not used
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for testing. In response to the failure to secure loose items, the licensee issued a
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site-wide newsletter, performed training during shop meetings to all personnel, and
revised the construction department craft guide handout. In response to the failure
to use the correct M&TE, the licensee provided training to personnel on procedural
adherence and revised the maintenance procedure to provide additional clarification
on M&TE calibration requirements. The inspectors determined that the licensee
implemented effective corrective actions for this violation.
Ill. Enaineerina
E2
Engineering Support of Facilities and Equipment
E.2.1 Review of Facilitu and Eauioment Conformance to UFSAR Descriotion
A recent discovery of a licensee operating a facility in a manner contrary to the
UFSAR description highlighted the need for a special focused review that compares
plant practices, procedures and/or parameters to the UFSAR descriptions. Wiill.e
performing the inspections discussed in this report, the inspectors reviewed the
applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters. No anomalies between the UFSAR and
operation of the facility were identified.
E8
Miscellaneous Engineering issues (92903)
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(Closed) Violation 50-382/9607-02: failure to perform adequate control room
envelope testing. This violation involved the licensee's failure to perform control
room envelope testing with one of the two airlock doors as the boundary. The
licensee determined that the root cause was a deficient procedure in that
engineering information used to establish requirements for operation of airlock doors
was not periodically verified. Consequer.tir, during the performance of maintenance
on one airlock door, the second airlock door was unable to maintain the integrity of
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The licensee's corrective actions included implementation of TS Amendment 115,
which allowed breaches of the control room envelope for a period not to exceed
7 days, repaired envelope door seals, performed acceptable pressurization testing of
the envelope, established criteria for operations to enter the applicable TS !imiting
condition for operation whenever an airlock door was inoperable, and revised plant
procedures to ensure TS entry prior to performing maintenance.
To improve the ability of the control room ventilation system to maintain the
envelope, the licensee developed Modification PC 8028, which will trip the reactor
auxiliary normal building ventilation on a toxic gas signal. Additionally, the licensee
initiated Modifications PC 8027 and SPEER 9601658, which will replace the control
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room envelope doors with better sealing doors. The inspectors determined that the
implemented and planned corrective actions were effective for this violation.
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E8.2 (Closed) Violation 50-382/9513-06: failure to establish design control measures.
This violation involved plant configuration control problems such as missing solenoid
valve exhaust port covers and weep holes not drilled in the bottom of
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environmentally-qualified terminal boxes. The inspectors verified the corrective
actions described in the licensee's response letter, dated May 19,1995, to be
reasonable and complete. No similar problems were identified.
E8.3 (Closed) Violation 50-382/9513-07: failure to identify conditions adverse to quality.
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This violation involved the failure to initiate a CR for several material condition
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deficiencies (i.e., a pipe cap was missing from the ta!l piece of
Valve EFW-MV-108A). The inspectors verified the corrective actions described in
the licensee's response letter, dated May 19,1995, to be reasonable and complete.
No similar problems were identified.
E8.4 (Closed) Violation 50-382/9521-01: failure to perform proper, detailed engineer.ing
analysis of solenoid-operated valves to establish and maintain equipment
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qualification. The inspectors verified the corrective actions described in the
licensee's response letter, dated February 14,1996, to be reasonable and complete.
No similar problems were identified.
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E8.5 (Closed) Inspection Followuo item 50-382/9513-05: improperly installed terminal
box on an environmentally-qualified shutdown cooling heat exchanger resistance
temperature detector.
The inspectors reviewed and discussed the licensee's actions, documented in their
commitment tracking system (A 22451) related to this item, with an environmental
qualification engineer. The inspectors also reviewed the following environmental
qualification documents to evaluate the qualification of resistance temperature
detectors and associated cable:
LPL-EQA-39.03, " Environmental Qualification Assessment for Rosemount
Resistance Temperature Detectors," Revision 3;
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LPL-EQA 39.04, " Environmental Qualification Assessment for Weed
Instrument Company Resistance Temperature Detectors," Revision 5;
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LPL-EQA-6.3C, " Environmental Qualification Assessment for Rockbestos
Radiation Resistant SR Cable (KF-550 Methyl Phenol Vinyl Silicone Rubber
Insulation)," Revision 0; and,
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The item was initially opened because a nonenvironmentally-qualified resistance
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temperature detector junction box was found loose by an NRC inspector. During
review of this item, the inspectors noted that the environmentally-qualified
resistance temperature detectors had different maintenance requirements to ensure
adequate sealing. The inspectors also noted that the licensee had not identified,
during the review of this issue, any examples of environmentally-qualified resistance
temperature detector junction box covers being improperly sealed. The inspector
found no problems with the sealing of environmentally-qualified resistance
temperature detector junction boxes.
During the discussions with the licensee engineer, the inspectors noted that the
engineer was preparing a design change to replace the resistance temperature
detector cables inside containment. The inspectors learned that this was not the
first time that the cables were to be replaced. In 1991, the licensee replaced the
original Samuel Moore cables with Rockbestos Firewall SR high-temperature
instrumentation cable. The inspectors noted that the replacement was required
because the original cable had deteriorated as a result of being too close to reactor
coolant piping.
The inspectors noted that the replacement cable was qualified by similarity by the
manufacturer and accepted by the licensee. The similarity was based on the
construction of the signal conductors being the same. The similarity evaluation did
not consider the cable shields that were on the replacement cable. The shields
were not considered because their purpose was to reduce or dampen signal noise.
The inspectors found the similarity evaluation to be acceptable.
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The inspectors noted that the licensee experienced noise problems in the instrument
loops after installation of the replacement cables, prior to returning the circuits to
operation. The noise was attributed to the shield wire being grounded in more than
one location, with a resulting potential difference causing circulating currents. The
licensee engineers attributed the cause of the multiple grounds to be due to the
porosity of the braided jacket and high humidity in the containment building. This
allowed a current path to the plant ground through the conduit system. In addition
to the path to the plant ground, the shield wires were connected to the instrument
bus ground, which was not common to the plant ground. The ground buses were
at different potentials, which caused the circulating currents and resultant noise.
To correct this issue, the inspectors noted that the shield wires were lifted at the
outboard containment penetration, breaking the circuit created t the grounded
shield wire inside containment. The inspectors found that the lii
g of the shield
wires was an acceptable action to reduce the noise in the circui ,. Since three
elements were necessary to induce noise in a circuit (a source of electromagnetic
noise, a means of coupling of noise from the source, and a circuit sensitive to the
noise), the breaking of the circuit eliminated the problem.
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The inspectors did not identify any problems with the qualification documentation
for the resistance temperature elements or the cable. The documentation for these
items met the requirements of 10 CFR 40.49, " Environmental Qualification of
Electric Equipment important to Safety for Nuclear Power Plants."
The inspectors noted an additional potential mechanism for creating a ground path
in the esb!es, which was damaging of each cable during installation. This
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mechanism was not considered credible by the licensee since most of the circuits
experienced the noise problems.
The inspectors also noted that the licensee had developed a design change to
improve the existing design. In this change, the cable was to be replaced with a
similar cable that had an insulating jacket between the twisted, shielded pairs and
the braided jacket. This layer would provide protection from physical damage and
also provide a waterproof barrier, thereby eliminating the potential means of
coupling the noise to the circuit. The inspectors found that the design change was
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an enhancement to the existing configuration.
The licensee had adequate procedures to address the sealing of
environmentally-qualified resistance temperature detector junction boxes. The
existing configuration of the instrument cable and its shield wires was acceptable.
The proposed design change to the cable configuration was an enhancement.
IV. Plant Suooort
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R8
Miscellaneous RP issues (92904)
R8,1 (Closed) Violation 50-382/9610-03: failure of personnel to comply with health
physics warning signs. This violation involved the failure of personnel to properly
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control contaminated M&TE and the failure of personnel to comply with warning
signs prohibiting drinking in a radiologically controlled area.
In response to the control of M&TE, operations communicated expectations in the
daily instructions, provided training to operations on the requirements for the control
of contaminated equipment, placed new locks on the M&TE lockers, and required
that the shift supervisors be initially accountable for access to the lockers. The
inspectors performed periodic observations of the contents of the lockers and-
determined that contaminated items were properly labeled and contained.
In response to the failure to adhere to signs prohibiting drinking in radiologically
controlled areas, the licensee removed the cooler from the area, provided training
during safety meetings to plant personnel, and developed a guidance directive on
the use of thirst quencher in radiologically controlled areas. The inspectors
reviewed Directive 96-2, " Outage Emergent items," and noted that the use of thirst
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quencher was to be established for heat stress controls and that individual
containers were to be placed in a secured ice chest labeled "FOR EMERGENCY USE
ONLY."
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The inspectors determined that the licensee's corrective actions were effective for
the examples involving this violation.
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P3
EP Procedures and Documentation
P3.1
Licensee Onshift Dose Assessment Capabilities (Tl 2515/134)
a.
Insoection Scoce
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Using Temporary instruction 2515/134, the inspectors gathered information
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regarding:
Dose assessment commitment in emergency plan
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Onshift dose assessment emergency plan implementing procedure .
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Onshift dose assessment training
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b.
Observations and Findinas
On December 17,1996, the inspectors conducted an in-office review of the
emergency plan and implementing procedures to obtain the information requested
by the temporary instruction. The inspectors conducted a telephone interview with
the licensee on December 18,1996, to verify the results of the review. Based on
the documentation review and licensee interview, the inspectors determined that
the licensee had the capability to perform onshift dose assessments using real-time
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effluent monitor and meteorological data and that the commitment was described in
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the emergency plan and implementing procedures.
c.
Conclusion
The commitment to perform onshift dose assessments was described in the
emergency plan and implementing procedures. Further evaluation of the information
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obtained using the temporary instruction will be conducted by NRC Headquarters
personnel.
S1
Conduct of Security and Safeguards Activities
S1.1
litumination of Protected Area
a.
Insoection Scone (71750)
On December 17, at 10:45 p.m., the inspectors performed a tour to determine the
adequacy of illumination in the protected area.
b.
Observations and Findinas
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The inspectors observed that the quality of permanent and temporary lighting in the
protected area was substantially improved from previous tours performed in January
and May 1996 (NRC Inspection Reports 50-382/9522 and 50-382/9605).
Nevertheless, the inspectors observed inadequate illumination between the
insulators shack and the water treatment bui' ding.
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The inspectors noted that the licensee had staged temporary lighting in the affected
area, but that the extension cord had been removed from the electrical outlet even
though a security placard was attached to the end of the cord which stated
" Temporary security lighting, do not remove." The inspectors informed the shift
security supervisors of the lighting discrepancy. The security supervisors toured the
area with the inspectors and agreed that illumination was less than 0.2-footcandles
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and reenergized the temporary lighting.
The inspectors questioned security to determine if the security patrol officer
identified the discrepancy on the evening tour. Security informed the inspectors
that the evening patrol officer noted the discrepancy and documented the poor
illumination on the security patrol log. However, the individual did not inform the
security shift supervisor of the discrepancy. The inspectors noted that the
supervisors were not aware of the discrepancy until informed by the NRC. The
failure to notify additional personr'el of the lighting deficiency is of concern because
compensatory measures may not have been effective in the event of an actual
security threat.
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Security Procedure PS-012-102, " Protective Lighting," Section 5.3.2, requires that,
in the event a protective lighting system deficiency or failure is observed vehen
lighting is needed, the reporting officer willimmediately notify the central alarm
station or the secondary alarm station. The inspectors determined that the security
patrol officer's failure to notify the central or secondary alarm station of the
deficiency is a violation of TS 6.8.1.a (50-382/9614-04).
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In response to the inspectors identification, security management implemented
immediate corrective actions which included counseling the patrol officer and
security shift supervisors, performing additional walkdowns of temporary lighting,
and discussing the importance of temporary lighting with personnel who may
deenergize temporary lighting during daylight hours.
C.
Conclusions
The inspectors identified a violation for the failure to notify the central or secondary
alarm station of a lighting deficiency. The licensee has significantly improved the
quality of permanent and temporary lighting within the protected area.
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V. Manaaement Meetinas
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Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the conclusion of the inspection on January 15,1997. The licensee
acknowledged the findings presented.
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The inspectors asked the licensee whether any materials examined during the
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inspection should be considered proprietary. No proprietary information was
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ATTACHMENT
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SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
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R. G. Azzarello, Manager, Maintenance
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C. M. Dugger, General Manager, Plant Operations
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J. J. Fisicaro, Director, Nuclear Safety
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T. J. Gaudet, Acting Manager, Licensing
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D. C. Matheny, Manager, Operations
M. B. Sellman, Vice-President, Operations
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D. W. Vinci, Superintendent, System Engineering
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A. J. Wrape, Director, Design Engineering
INSPECTION PROCEDURES USED
37551
Onsite Engineering
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61726
Surveillance Observations
62707
Maintenance Observations
'
71707
Plant Operations
71750
Plant Support Activities
92901
Followup - Plant Operations
92902
Followup - Maintenance
92903
Followup - Engineering
92904
Followup - Plant Support
Tl 2515/134
Licensee Onshift Dose Assessment Capabilities
ITEMS OPENED, CLOSED, AND DISCUSSED
Oper.ed
{
50-382/9614-01
Review of the licensee's response to the water hammer
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events that occurred in the LPSI system (Section 02.1)
50-382/9614-02
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Inadequate procedure for testing the hydrogen analyzers
,
(Section M1.3)
t
50-382/9614-03
Inadequate channel functional test for CPCs (Section M3.1)
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50-382/9614-04
Failure to follow security lighting reporting procedures
(Section S1.1)
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Closed
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50-382/9517-01
Failure to acknowledge fire protection panel alarms (Section
08.2)
50-382/9605-02
Control room personnel unaware of activities affec{ing
Emergency Diesel Generator A (Section 08.3)
50-382/9614-02
Inadequate channel functional test for CPCs (Section M3.1)
50-382/94402-02
IFl
Failure to follow an installation weld detail (Section M8.1)
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50 382/9508-01
Failure to follow procedures to ensure adequate storage of
loose items and correct usage of M&TE (Section M8.2)
.
50-382/9607-02
Failure to perform adequate control room envelope testing
(Section E8.1)
50-382/9513-06
Failure to establish design control measures (Section E8.2)
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50-382/9513-07
Failure to identify conditions adverse to quality (Section
E8.3)
1
50-382/9521-01
Failure to perform proper, detailed engineering analysis of
solenoid-operated valves to establish and maintain
,
j
equipment qualification (Section E8.4)
50-382/9513-05
IFl
Improperly installed terminal box on an environmentally
,
'
qualified shutdown cooling heat exchanger resistance
temperature detector (Section E8.5)
l
50-382/9610-03
Failure of personnel to comply with health physics warning
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signs (Section R8.1)
LIST OF ACRONYMS USED
Arkansas Nuclear One
CFR
Code of Federal Regulations
CR
Condition Report
Core Protection Calculator
!
DN8R
Departure from Nucleate Boiling Ratio
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DEAM
Design Engineering Administrative Manual
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Document Revision Notice
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High Pressure Safety injection
j
Inservice Testing
Low Pressure Safety injection
Measuring & Test Equipment
NRC
Nuclear Regulatory Commission
psig
Pounds per Square Inch Gauge
Pt.biic Document Room
Ouality Control
Radiation Protection
RWSP
Refueling Water Storage Pool
,
Safety injection Tanks
scfh
Standard Cubic Feet per Hour
TS
Technical Specifications
Updated Final Safety Analysis Report
Unresolved item
4
'
Ultrasonic Testing
WA
Work Authorization
.