IR 05000528/1993055
| ML17310B045 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 02/07/1994 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17310B042 | List: |
| References | |
| 50-528-93-55, 50-529-93-55, 50-530-93-55, NUDOCS 9402230076 | |
| Download: ML17310B045 (30) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION V
~Re ort Nos.
Docket Nos.
License Nos.
Licensee:
~Ins ection Conducted:
~Ins ection Location:
~Ins actors:
50-528/93-55, 50-529/93-55, and 50-530/93-55 50-528, 50-529, and 50-530 NPF-41, NPF-51, and NPF-74 Arizona Public Service Company P. 0.
Box 53999, Station 9082 Phoenix, AZ 85072-3999 Palo Verde Nuclear Generating Station Units 1, 2, and
December
.7, 1993, through January 10, 1994 Maricopa County, Arizona K. Johnston, Senior Resident Inspector H. Freeman, Resident Inspector J.
Kramer, Resident Inspector A. MacDougall, Resident Inspector T. Alley,
. Department of Energy
~ll dd
~Summer:
H.
ong, Chi f Reactor Projects 8ranch II
>>h Date Signed Areas Ins ected:
Routine, announced, resident inspection of:
Plant activities and operational safety verifications Units 1,2, and
(inspection procedure 71707, 71710, and 30702)
Surveillance testing Units 1, 2,
and 3 (61726)
Plant maintenance Units 1, 2, and 3 (62703)
Temporary modi fications Unit
(37700)
Unit 3 mid-cycle outage (61726, 62703, and 71707)
Steam generator U-tube plug mis-insertion Unit 3 (62703)
Unit 2 reactor coolant system flow reduction (93702)
Followup on previously identified items -,Units 1, 2, and 3 (92701 and 92702
'Safet Issues Mana ement S stem SIMS Items:
None.
9402230076 940208 PDR ADDCK 05000528 Q
~
I
!
l l
I l
i
Results:
General Conclusions and S ecific Findin s:
Strengths:
Unit 2 personnel demonstrated good command and control of plant activi ties during the sleeving of the essential cooling heat exchangers (Paragraph,5.b).
Inspector noted that Unit 3 operators were especially attentive during reactor coolant system inventory reductions to mid-loop and displayed a
good awareness of reactor vessel level indi cation and system configuration.
The inspector also noted improved verbal communication in the control room (Paragraph 7).
Meaknesses:
Operations personnel had not performed a surveillance test to verify the
'operability of ventilation systems required by Technical Specifications (TS)
when a train of the essential chilled water system was taken out of service for planned maintenance.
TS allowed one hour to complete the verification and, even after 57 minutes, actions had not been started when the train was restored to an operable condition (Paragraph 3.a).
I Unit I maintenance demonstrated poor communication with engineering personnel and inadequate use of equipment history in the work planning process for maintenance performed on the pressurizer spray valves (Paragraph 5.a).
~
Corrective actions for previous steam generator U-tube plug mis-insertion events did not prevent the mis-insertion of a tube plug in Unit 3. It appeared that licensee had not been sufficiently critical of the tube plugging vendor's performance (Paragraph 8 and 9.b).
Si nificant Safet Matters:
None.
Summar of Violations:
None.
Summar of Deviations:
None.
Unresolved Items:
Non i I
f J
DETAILS Persons Contacted The below listed technical and supervisory personnel were among those contacted:
Arizona Public Service Com an APS
- R J'.
L.
- S
- R R.
- R.
D.
- B Adney, Bailey, Clyde, Coppick, Flood, Fountain, Fullmer, Gouge, Grabo,
- D
- W G.
F.
C.
C.
- W R.
- D p.
Hauldin, Hontefour, Overbeck, Riedel, Russo, Scott, Seaman, Simko, Stevens, Stricker, Wiley, Others
- N. Hooshmand,
- W; Ide, J.
Levine, Plant Manager, Unit 3 Assistant Vice-President, Nuclear Engineering
& Projects Manager, Operations, Unit 3 Supervisor, Valves Services Engineering Plant Manager, Unit 2 Supervisor, guali ty Audits and Monitoring Manager, guality Audits and Monitoring Director, Plant Support Supervisor, Nuclear Regulatory Affairs Valves Services Engineering Plant Manager, Unit
Vice President, Nuclear Production Director, Site Maintenance and Modifications Senior Coordinator, Management Services Director, Site Technical Support Nanager, Operations, Unit
Manager, guality Control Assistant Plant Hanager, Unit 3 Director, guality Assurance and Control Manager, Valves Services Engineering Director, Nuclear Regulatory
& Industry Affairs Engineer, Valve Services Engineering Manager, Operations, Unit 2
- J
- F
- R
- p Draper, Gowers, Henry, Luther, Site Representative, Southern California Edison Site Representative, El Paso Electric Site Representative, Salt River Project Si te Representati ve, Publ ic Servi ces New Mexico
Denotes personnel in attendance at the Exit meeting held with the, NRC resident inspectors on January 18, 1994.
Plant Status Summar 71707 a ~
Unit
Unit 1 operated at essentially 85 percent power throughout the inspection period.
From December 15 through December 22, 1993, the unit experienced numerous problems with both pressurizer spray valves
{Paragraph 5.a).
On December 28, 1993, operators determined that a pressurizer level transmitter was drifting high.
A
containment entry was made and a leak in the reference leg flexible sensing line was identified.
The line was isolated, all the required Technical Specification actions were taken, and the sensing line was replaced on December 30, 1993.
The unit ended the inspection period at 85 percent power.
b.
'Unit 2 Unit 2 began the inspection period at 85 percent power.
During the inspection period, the unit sleeved both of the essential cooling water (EW) heat exchangers.
The NRC granted a one-time amendment to extend the duration of the Techni cal Speci ficati on Action Statement from 72 to 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br /> in order for the work to be performed while the unit was on line (Paragraph 5.b).
On the evening of January 7,
1994, operators noted that an apparent reduction in reactor coolant system flow of approximately 2 percent had occurred over the previous 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (Paragraph 9).
On the evening of January 8, the unit was shut down for a mid-cycle outage.
The licensee planned to perform steam generator U-tube inspection and steam generator secondary side chemical cleaning.
c.
Unit 3 Unit 3 began the inspection period midway through a mid-cycle outage and was conducting steam generator U-tube inspections.
The licensee had previously committed to conduct U-tube inspections following a review of previous refueling outage inspection data (Paragraph 7).
The tube inspection did not reveal any axial cracks or any other indications, The licensee completed the mid-cycle outage and commenced reactor startup on December 25.
Unit 3 ended the inspection period at 85 percent power.
3.
0 erational Safet Verification 71707 The inspectors performed several plant tours and veri fied the operability of selected emergency systems, reviewed the tag-out log and verified proper return to service of affected components.
Particular attention was given to housekeeping, examination for potential fire hazards, fluid leaks, excessive vibration, and verification that maintenance requests had been initiated for equipment in need of maintenance.
The inspectors also observed selected activities by licensee radiological protection and security personnel to confirm proper implementation of and conformance with facility policies and procedures in these areas.
a.
Failure to Use Technical S ecificati on Action Procedure When Essential Chi llers Declare Ino erable Unit
On December 10, 1993, reviews of'he Unit 1 logs by the inspector noted that the "B" train essential chiller (ECB-POl)
had been declared inoperable at 2: 13 p.m. to allow maintenance personnel to adjust the chiller circulating water pump packing.
The inspector noted that maintenance was completed and ECB-P01 was declared
)
)
l i
l (
)
l
operable at 3:10 p.m.
The inspector reviewed this activity to assess compliance with Technical Specification (TS) 3.7.6,
"Essential Chilled Water System,"
and procedure 40ST-9EC03,
"Essential Chilled Water and Ventilation Systems Inoperable Action Surveillance."
TS 3.7.6 requires at least two operable essential chilled water loops to ensure that sufficient cooling is available for safety-related equipment and to ensure control room habitability during accident conditions.
If one essential chi'lied water loop is declared inoperable, Action b. of TS 3.7.6 requires that within one hour the normal ventilation system providing cooling to the vital power distri bution rooms associated with the inoperable essential chilled water loop be verified to be in operati on.
This requirement ensures the operability of the safety-related equipment associated with the vital power distributi on rooms.
The inspector noted that the TS verification of the operability of the vital power distribution room ventilation system was not completed, even though it took 57 minutes to restore operability of train "B" of the essential chilled water system after the maintenance and post-maintenance system testing were completed.
Performance of the ventilation verifications would have taken approximately six minutes.
Although the shift supervi sor met the requirements of the TS, the inspector was concerned that the shift supervisor took an unnecessary risk in not performing the verifications earlier.
The maintenance activity was a pre-planned corrective maintenance activity.
The one-hour TS action requirement for ventilation verification is provided to allow time for assessment of the situation and verification efforts following an unplanned event that makes the essential chiller inoperable.
Additionally, one-hour TS action requirements are typically reserved for significant actions necessary to ensure the plant is in a safe configuration.
It is good plant operations practice that the ventilation verifications be performed early enough to avoid rushed actions.
The inspector noted that NRC Inspection Report 50-528,529,530/93-48 describes the licensee's failure to verify the operability of alternate power sources when an emergency diesel generator was taken out of service (a non-cited violation);
This incident is similar in that operations personnel did not promptly perform the required verifications.
Technical Specifications specify the time requirements when the verification must be completed, but are silent as to when the process. must be started.
The verification process should be started early enough such that hurried actions are not required by the licensee and to avoid transients on the plant.
It appears that there is not sufficient operations guidance as to when verification must be starte ~
I I
I l
l l
I f
I l
The inspector discussed this issue with plant management who agreed with the inspector that the surveillance procedure should have been performed earlier.
The licensee conducted a review of this issue and determined that the control room essential air handling unit should also be listed in 40ST-9EC03 and declared inoperable when an associated essential chiller is inoperable.
The inspector noted that the appropriate Action Statement for the control room essential ventilation (3.7.7)
was entered and listed in the Unit logs.
The license'e initiated Condition Report/Disposition Request (CRDR)
1-4-0006 to investigate the signi ficance of this error.
The inspector will review the results of the CRDR during a future inspection.
b...
Radiation Protection Controls in the Unit 3 "B" LPSI Pum Room On January 10, 1994, while touring the "B" LPSI pump room in Unit 3, the inspector noted that a large deposit of boric acid had formed on one of the flange bolts on the pump bowl.
The licensee had previously posted the area surrounding the bowl as a contaminated area.
The posting's rope barrier encircled all of the flange studs except this particular stud.
The inspector brought this condition to the attention of health physics, who committed to correct this posting deficiency.
Because the boric acid deposit was just outside of the rope boundary and because the area immediately surrounding the LPSI pump,was posted as a high radiation area, the inspector concluded that the 'likelihood of an inadvertent contamination spread was low.
No violations of NRC requirements or deviations were identified.
4.
Sur veillance Testin Units
2 and
61726 Selected surveillance tests required to be performed by the Technical Specifications were reviewed on a sampling basis to verify that:
1) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency speci fied in the Technical Specifications; and 4) test results satisfied acceptance criteria or were properly dispositioned.
Control Element Assembl 0 erabi lit Checks - Unit
On December 23, 1993, the inspector observed surveillance test 41ST-1SF01,
"Control Element Assembly (CEA) Operability Checks."
To perform the test, operators inserted a group of CEAs about 5 inches (7 steps),
and then returned the CEAs. to their fully withdrawn position.
This was done sequentially for both shutdown groups of CEAs and all five regulating groups of CEAs.
The inspector concluded that the surveillance was well controlled by the assistant shift supervisor.
Additionally, there was good coordination between the primary operator, who was affecting reactivity of the core
I
I t
I
with the CEA movement, and the secondary operator, who was controlling turbine power.
This ensured that the lower temperature limit was not-approached.
No violations of NRC requirements or deviations were identified.
5.
Plant 'Maintenance Units
2 and
62703 During the inspection period, the inspector observed and reviewed se'lected documentation associated with maintenance and problem investigation 'activities listed below to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required quality assurance/quality control department involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified that reportabi lity for these activities was correct.
Specifically, the inspector witnessed portions of the following maintenance activities:
Unit
~
Corrective maintenance on pressurizer spray valve RCPV-100F
~
Auxiliary buil.ding essential ventilation supply damper 1MHFBM06 inspection Unit 2 Unit Main steam and feedwater penetration room normal exhaust fans preventive maintenance Essential Cooling Water (EW) heat exchanger sleeving
Turbine driven auxiliary feedwater pump speed control corrective maintenance a ~
Reactor trip breaker
"D" corrective maintenance Pressurizer S ra Valve Maintenance Unit
62703 Between December 15 through December 22, 1993, Unit 1 experienced several problems with the operation of both pressurizer spray valves.
Maintenance personnel made a total of four containment entries during power operations (resulting in 800 mrem of exposure and 60 man-hours in the containment)
to correct the problems.
The inspector reviewed this work activity and concluded that there was poor communication with engineering and inadequate use of equipment history in the work planning proces '
f I
r 1f
J f
The spray valves (1JRCPVE0100E and 100F) are air-operated valves that use spring pressure to close and air pressure to open.
The-inspector noted that both spray valves were repacked during the last refueling outage in October 1993, and both subsequently experienced positioner calibration drift and problems with the valves not staying closed.
Operators had to keep pressurizer backup heaters on to maintain plant pressure due to the spray valves being partially open.
The inspector observed in containment the 'first attempt to correct the problem with spray valve 100F.
The zero bench set was found to be low.
Mith a low bench set there was not enough pre-load on the air-operated valve spring to ensure a positive seat when the reactor coolant system pressure was applied under the valve seat.
Spray valve lOOF was recalibrated and the bench set was raised.
The inspector questioned the licensee as to why the initial calibration during the refueling outage had not ensured a positive valve seat.
As a result of the inspector's questions, the licensee determined that although the bench set and valve stroke length were included in all the work orders, engineering information contained in Engineering Evaluation Request (EER)
88-RC-147 and Condition Report/Disposition Request (CRDR) 2-3-0080 were not included in the work orders.
This information would allow the bench set to be raised to a value of 22 psig.
This would cause an additional pre-load on the operator to help ensure a positive seat.
The, engineering evaluation in CRDR 2-3-0080 determined that there had been a total of about 12 problems with the spray valves in Unit 2 since 1986 (Units 1 and 3 have had a similar number of problems).
The CRDR evaluation also identified a problem with setting of the zero error in procedure 36HT-9RC01,
"Tracor Mestronics H11E Recorders Haintenance Procedure,"
which may have contributed to the positioner calibration drift.
This procedure was scheduled for revision in Harch 1994.
Several other long term corrective actions, including a design change to install a larger operator on the valves were recommended.
At the exit meeting, the inspector expressed concern that the lessons learned from the Unit 2 spray valve problems had not been applied during the Unit 1 refueling outage.
It appeared that the subsequent containment entries at power to perform corrective maintenance, resulting in increased personnel dose, could have been avoided had these actions been taken.
Additionally, it appeared that plant maintenance personnel were slow to involve the appropriate engineering group.
The licensee stated that they were aware of'hese concerns and would determine why the considerable maintenance history on the pressurizer spray valves had not been applied during the Unit 1 outage.
The inspector will review these corrective actions in a future inspection report (Followup Item 50-528/93-55-02).
f I
l I
Essential Coolin Water Heat Exchan er Sleevin Unit 2 In mid-December the licensee removed the Unit 2 essential cooling water (EW) heat exchangers (HXs) from service, one at a time, to sleeve the heat exchanger tubes.
The Unit 2 EW HXs have experienced several leaks in the past due to a manufacturing defect at the HX tube sheets.
The licensee sleeved all of the EW HXs tubes at the tube sheets at both ends of the EW HXs to prevent future tube leaks and to,recover previously plugged tubes.
A one-time 4S amendment was approved by the NRC to provide a seven-day out-of-service time, allowing sufficient time for the tube sleeving to be performed.
The inspector observed the tube sleeving activities.
The inspector noted that operations, maintenance, guality Control (gC),
and operations management demonstrated good command and control of all plant activi ties during the sleeving of the "A" and "B" EW HXs.
Using the lessons learned from the sleeving process on the "B" heat exchanger, the licensee shortened the outage time of the "A" heat exchanger by approximately l0 hours.
In addition, nearly all of the previously plugged tubes in both heat exchangers were returned to service.
The licensee ensured that activities affecting the operable train of ESF equipment were kept to a minimum.
The inspector observed most portions of the sleeving process and noted strong gC and mechanical maintenance support.
Auxiliar Feedwater Pum Troubleshootin Unit 3 During the performance of an operability test on the Unit 3 turbine-driven auxiliary feedwater pump (43ST-3AF02)
on January 4,
1994, operators were unable to adjust turbine speed into the range required by the surveillance test (3590 3600 rpm).
The operators declared the pump inoperable at 4:15 a.m.
and contacted engineering for troubleshooting.
The inspector reviewed the licensee's troubleshooting plan and discussed the subsequent corrective maintenance activities with maintenance and engineering personnel.
During troubleshooting, technicians determined that the speed clamp circuit associated with the manual speed "control was set such that it had prevented operator manual actions from adjusting the turbine speed above 3583 rpm.
The purpose of the speed clamp circuit is to prevent manual adjustment of turbine speed to an overspeed condition.
The licensee concluded that while the nominal setting of the speed clamp circuit should allow turbine operation between 3590 3600 rpm, instrument tolerances could result in the condition observed.
The licensee reset the speed clamp circuit to allow an larger operating adjustment range.
The turbine was retested satisfactorily and returned to service in the evening of January 4.
The inspector observed good interaction between engineering and operations.
Engineering responded rapidly and developed an action plan shortly after the AFW pump was declared inoperable.
Engineering concluded that the turbine-driven auxiliary feedwater
I l
!
~
pump would have been able to perform its safety function if required.
Pump operation between 3590 3600 rpm was required by the surveillanc~ test to support ASNE Section XI testing requirements.
During an earlier portion of the surveillance test, operators were able to raise pump speed to 3508 rpm.
This
.established that the pump met the Technical Specification required flow of 750 gpm and 1270 psia.
Following the adjustments to the speed clamp circuit, operators successfully completed the Section XI portion of the surveillance test.
The inspector agreed with the licensee that the pump could have performed its safety function and also concluded that the licensee's decision to declare the pump inoperable was conservative and appropriate.
d.
Reactor Tri Breaker
"D" Troubleshootin Unit 3 62703 During a post-maintenance surveillance test of reactor trip breaker (RTB) "D" on December 13, 1993, the breaker failed to open.
The licensee subsequently determined that the breaker's test position switch had fai 1ed.
The licensee replaced the switch and completed the surveillance test satisfactorily.
The inspector observed the licensee perform troubleshooting on RTB
"D" on December 14, 1993.
The troubleshooting was performed by electrical maintenance personnel and supervised by the electrical maintenance supervisor.
In addition, the system engineer, who directed the troubleshooting activity, and guality Control personnel were present.
The licensee's troubleshooting revealed a
failure of the test position switch.
The test position switch allows the breaker to be tested when it is racked into the "test" position in its cubicle.
The licensee determined that the failure would not have affected the breaker's ability to trip open had it been fully racked in and placed in service.
The inspector noted an appropriate level of engineering, maintenance and quality control involvement.
The inspector concluded that test failure was appropriately handled by the licensee.
No violations of NRC requirements or deviations were identi fied.
6.
Tem orar Modification Review Unit I 37700 The inspector reviewed a sample of temporary modifications (THODs) to determine if the requirements of procedure 70AC-9NS01,
"Temporary Nodification Control," were being met.
The inspector concluded that the modifications were properly installed, controlled, and reviewed per the licensee's procedure.
The inspector reviewed THDD I-89-EC-08I which installed a plug on the exhaust port of the essential chiller purge vent valve.
Th'e plug was installed to prevent a loss of refrigerant through the thermal purge valve, which has had a high failure rate.
The inspector interviewed the responsible system engineer, verified the installation, and reviewed the
CFR 50.59 evaluation and periodic justification reviews.
The
e
)
according to the activities potential impact on plant safety.
Licensee management determined that only activities that had no potential impact on plant safety or those that were required to be performed (such as installing nozzle dams)
would be performed during mid-loop operations.
The inspector reviewed the list of maintenance activities and determined that the licensee was conservative in its categorizations.
The inspector noted that operators were especially attentive during reactor coolant system inventory reductions to mid-loop and displayed a
keen awareness of reactor vessel level indi cati'on and system con'figuration.
The inspector also noted improved verbal communication in the control room.
No violations of NRC requirements or deviations were identified.
8.
Steam Generator U-tube Plu His-insertion - Unit 3 62703 On December 18, 1993, a guality Control (gC) inspector discovered that a steam generator U-tube plug had been inserted into the wrong tube.
The plug was removed, reinserted into the correct tube, and then rolled into place.
During an independent verification of a tube plug video tape, the gC inspector discovered that the plug intended for row 117, line 64 (R117 L64) was actually. inserted into location R117 L66.
The verification was performed after the plug's location was accepted by the vendor performing tube plugging operations, Babcock
& Wilcox Nuclear Technologies (BWNT),
and prior to the actual plug rolling (to secure the plug into the tube).
The licensee will document its investigation in Condition Report/
Disposition Request (CRDR) 3-3-0512.
Three similar mis-insertion/mis-plugging events have been documented in previous NRC inspection reports.
Inspection Report 50-528,529,530/90-20 documented mis-plugged tubes caused by a transposition of the row and line numbers.
Inspection Report 50-528,529,530/93-11 documented a mis-plugging discovered after the Unit 2 tube rupture (further discussed in Paragraph 9.b).
Inspection Report 50-528,529,530/93-35 documented a mis-inserted plug discovered during the independent verification phase by gC.
At the exit meeting, the inspector expressed concern regarding the ineffectiveness of past corrective actions in preventing the repeat plug mis-insertions.
While it appears that previous licensee corrective actions have raised gC's awareness for potential mis-plugging events, the inspector questioned whether the licensee had been sufficiently critical of the tube plugging vendor's performance.
The inspector will review the licensee's findings and corrective actions to this latest mis-insertion as part of the followup to Yiolation 50-529/93-11-02.
No violations of NRC requirements or deviations were identified.
i I
('
t
justification reviews were properly completed at least every six months.
A permanent change request (PCR)
was approved to install a strainer md ball valve upstream of the thermal purge valves.
The auxiliary operator logs were updated to ensure that readings were taken to determine when the chiller needed to be vented.
The inspector also reviewed THOD 1-90-SG-040-08 which installed several thermocouples and a data acquisition unit to monitor the surface temperature of the steam supply lines to the auxiliary feedwater pump.
This modification 'was installed to allow auxi 1'iary operators to monitor steam admi'ssion line temperatures and ensure that the line is properly warmed to prevent condensation.
Significant condensation in the steam line can result cause the auxiliary feedwater pump turbine to overspeed dur'ing an emergency start.
The inspector noted that a
PCR was approved and scheduled for Hay 1995.
No violations of NRC requirements or deviations were identified.
Unit 3 Hid-C cle Outa e
61726 62703 and 71707 The licensee conducted a outage in Unit 3 to inspect steam generator U-tubes.
Eddy current testing did not identify any mid-span axial cracks similar to those found in Unit 2 during the spring refueling outage in 1993.
The inspector concluded that the licensee conducted the outage in a safe and controlled manner.
The licensee's initial eddy current inspection scope included 8191 full length bobbin coil tests, 434 partial length motorized rotating pancake coil (MRPC) tests near the tube bend region, and 4500 HRPC tests in the tubesheet region.
The partial length MRPC tests near the tube bend region were selected based on a susceptible
"arc" region identified during the Unit 2 refueling outage.
The 4500 HRPC test in the tubesheet region were selected to determine if Unit 3 steam generators had circumferential cracks similar to those identified during the Unit 1 fall 1993 refueling outage.
The licensee did not find mid-span axial cracks in Unit 3 steam generators, including the six tubes exhibiting signs of possible axial indications during reviews of the previous refueling outage data (NRC Inspection Report 50-528,529,530/93-43).
The licensee expanded the scope of the HRPC tests in Steam Generator 32 to test all remaining tubes on the hot leg side (10,918 tubes)
at the tubesheet region after discovering three circumferential cracks.
This inspection revealed one additional circumferential crack.
The licensee concluded that the Unit 3 steam generators did not have any unusual indications and completed the tube inspections.
The inspector observed several aspects of the mid-cycle outage which included infrequent evolutions, such as reduced inventory and mid-loop operations, and maintenance activities.
The inspector noted that in all cases, the workers were sensitive to the impact that their activity had on plant safety.
The licensee had categorized each maintenance activity
Unantici ated Reactor Coolant S stem Flow Reductions Unit 2 93702 On the evening of January 6,
1994, with the plant at 85 percent power, operators noted that reactor coolant system (RCS) flow had dropped approximately 2 percent over the previous 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, as indicated"by the f1ow instruments for all four reactor coolant pumps (RCPs).
The operators also noted increases in the differential pressure across the RCPs (approximately 2 percent)
and across the core (approximately 1~),
and increases in RCP amperes (approximately 5 percent) for all four RCPs.
These RCS parameters appeared to have gradually changed over a 12-hour pe'riod and then stabilized.
Reactor power and the RCS hot leg and cold leg temperatures did not change appreciably.
Licensee engineering initiated an investigation of the flow decrease on the morning of January 7.
They verified that the instrument readings obtained by the operators represented actual plant parameters by comparing diverse indications.
In addition, the licensee used the plant computer to obtain a history of pertinent parameters and established a
detailed chronology of the flow reduction.
The inspector evaluated the parameters selected by the licensee and determined that they represented diverse indications.
The licensee determined that the plant was safe to operate since power was at 85 percent, core flow continued to be above Technical Specifications (TS) requirements, and RCS flow had stabilized at the lower value.
Discussions were held with NRC Region V and NRR personnel on the morning of January 7 to determine the actions taken and planned by the licensee to investigate this condition'.
.Unit 2 shut down for its scheduled mid-cycle outage on the evening of January 7.
At the end of the inspection period, the licensee was reviewing the RCS flow reduction to determine its cause.
The licensee theorized that the flow reduction may have been caused by a chemistry-induced build up of corrosion products on the fuel cladding or fuel cladding oxidation.
There have been similar events previously documented at other plants.
The inspectors will review the licensee's root cause analysis in a future inspection (Follow-up Item 50-529/93-55-01).
Followu on Previousl Identified Items Units
2 and
9270I and 92702 a.
Closed Followu Item 50-528 93-12-10 Lifted Landed leads Corrective Action Units I
and
This item involved continued problems with personnel errors involving lifted/landed leads identified in Corrective Action Report (CAR) 92-0123.
The inspector reviewed the CAR and determined that the broader issues of inattention-to-detail were addressed by the licensee.
This was accomplished by conducting several safety meetings and industry events briefings, updating the sensitive issues manual, and temporarily requiring second party verifications of all lifted/landed lead activities.
The requirement for second
t
~
f I j
I
party verification of all activities was removed in November 1992.
Safety-related work still requires second party verification in"-
accordance with the licensee's maintenance procedures.
The inspector reviewed the monthly guality Control (gC) reports from
. July through November 1993, and noted that the gC inspectors did not identify any lifted/landed lead deficiencies.
Additionally, the inspector observed the lifting of electrical leads during maintenance on valve SG-UV-134A in Unit 2
{NRC Inspection Report 93-43, Paragraph 5)
and several electrical determinations of motor operated valve actuators in Unit 1 during refueling outage 1R4.
The inspector concluded that maintenance personnel understood the significance of properly removing electrical leads and displayed good attention-to-detai 1 during the work.
Based on this review, this item is closed.
0 en Violation 50-529 93-11-02 Steam Generator U-Tube Nis-lu in - Unit 2 92702 This violation was issued for the licensee's failure to plug a steam generator U-tube as required by Technical Specification 4.4.4.4.b.
During refueling outage 2R4, the licensee discovered that during the previous refue'ling outage a defective tube had been correctly plugged on the cold 1 eg side but not on the hot 1 eg side (a nearby tube had been plugged).
Typically, the tube insertion tool operators counted from a known location such as a "stay" {reference point) to the desired tube.
The tube to be plugged was located three columns away from the stay.
The licensee determined that the tube insertion tool operator had counted tubes in the opposite direction and mis-plugged a tube located three columns away on the other side of the stay.
The inspector concluded that this was a reasonable explanation.
Additionally, the licensee reviewed the verification tape and found that the tape was of poor quality.
The licensee determined that the tape was inadequate and that this prevented the discovery of the mis-plugged tube during the gC verification process.
The inspector reviewed the licensee's corrective actions to the violations and determined that they have been implemented.
However, the inspector also concluded that the corrective actions centered on improving the gC involvement in the tube plugging process and did not address the performance of the vendor personnel conducting the tube plugging.
While the inspector found that gC's involvement was more than adequate, as evidenced by their subsequent discovery of other mis-inserted plugs (Paragraph 8), the licensee had not corrected the root cause of the problem.
The licensee agreed that the root cause of the mis-insertions and mis-pluggings had not been addressed.
They planned to implement corrective actions to address the performance of the tube plugging vendor prior to plugging tubes in the Unit 2 mid-cycle outage which began on January 8.
This item
will remain open until after the inspector reviews the licensee's corrective actions.
c.
Cl osed Viol ati on 50-529 93-40-08 Auxi 1 iar Feedwater Val ve Testin Unit 2 This item pertained to inadequate work instructions for replacing the torque switch in the motor operator for the auxiliary feedwater supply isolation valve to Steam Generator 22 (AF-UV-35).
The inspector concluded that the torque switch had been replaced correc'tly without the use of the appropriate procedure and diagnostic testing confirmed the torque switch was replaced correctly.
The licensee counseled the p'lanners and the Valve Services supervisor and technician on their expectations to ensure all necessary work instructions are provided to perform the activity and to stop if the work order or procedure does not have the needed work instructions to continue.
Additionally, the licensee developed guidance for central and unit planners on the appropriate use of procedure 32HT-9ZZ46, "Disassembly/Assembly of Limitorque Type SHB/SB-0 thru SHB/SB-4 Actuators," in developing work orders.
The inspector concluded the corrective actions taken by the licensee were appropriate to prevent recurrence.
This item is closed.
No violations of NRC requirements or deviations were identified.
1l.
Exit Meetin 71707 An exit meeting was held on January 18, 1994, with licensee management and resident inspectors during which the observations and conclusions in this report were discussed.
The licensee had no additional comments to the inspectors'indings.
The licensee did not identify as proprietary any materials provided to or reviewed by the inspectors during the inspection.
15