IR 05000528/1987022
| ML17300B041 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/20/1987 |
| From: | Ball J, Fiorelli G, Ivey K, Jim Melfi, Richards S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17300B040 | List: |
| References | |
| 50-528-87-22, 50-529-87-23, 50-530-87-24, GL-83-28, IEB-84-03, IEB-84-3, IEB-85-003, IEB-85-3, IEIN-84-93, IEIN-86-025, IEIN-86-25, NUDOCS 8709100482 | |
| Download: ML17300B041 (31) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
License Nos:
Licensee:
50"528/87"22, 50-529/87-23, 50-530/87-24 50-528, 50-529, 50-530 NPF-41, NPF-51, NPF-65 Arizona Nuclear Power Project
'P.
O.i Box 52034 Phoenix, AZ. 85072-2034
&
Ins ection Conducted:
June 21, 1987, through August 1, 1987 Inspectors:
, Res>den ns ector Dat S)g e
l e li, Resid nspec r
D e
signed K. Iv esident In ector te igned Approved By:
S.
R'
Reactor pector s, Chief,
)neering Se son D
e signed ate igned Summary:
Ins ection on June
1987 - Au ust
1987 Re ort Nos.
50-528/87-22 50-529/87-23 and 50-530/87-24 Areas Ins ected:
Routine, onsite, regular and backshift inspection by the three resident inspectors and a regional inspector.
Areas inspected included:
followup of previously identified items; review of plant activities; plant tours; engineered safety feature system walkdowns; surveillance testing; plant maintenance; preoperational testing; control room annunciator problem reduction; overtime; circulating water system rupture; loss of a LPSI pump motor and "A" and "B" pump seals; surveillance program; temporary instruction 2515-91 inspection followup; IE Bulletin and Information Notice followup; Part 21 reports; and review of periodic and special reports.
During this inspection the following Inspection Procedures were covered:
25573, 36100, 30703, 37700, 61700, 61726, 62703, 70432, 70441, 71707, 71709, 71710, 71881, 90713, 92700, 92701, 92702, 92703, 93702.
Results:
Of the 17 areas inspected, no violations were identified.
8709100482 970824 PDR ADOCK 05000528
0, Persons Contacted:
DETAILS The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro 'ect ANPP R.
Adney,
- J. Allen, L. Brown, R. Buckhalter,
"J.
R.
Bynum, B. Cederquist, W. Craig J.
Dennis, J. Driscoll W. Fernow, D. Gouge,
"J.
G.
Haynes,
"W.
E. Ide, D. Nelson,
"R. Nelson, R.
Papworth, G. Perkins,
"J. Pollard, F. Riedel, T. Shriver, L. Souza, E.
E.
Van Brunt, R. Younger,
- 0. Zeringue, Operations Superintendent, Unit 2 Operations Manager Radiation Protection and Chemistry Manager Outage Management Superintendent, Unit 3 PVNGS Plant Manager Chemical Services Manager Procurement Manager Operations Supervisor, Unit 1 Assistant Vice President, Nuclear Production Training Manager Operations Superintendent, Unit 3 Vice President, Nuclear Production Corporate guality Assurance Manager Operations Security Manager Maintenance Manager Operations Engineering Manager Radiological Services Manager Operations Supervisor, Unit 2 Operations Supervisor, Unit 3 Compliance Manager Assistant guality Assurance Manager Jr.,
Executive Vice President Operations Superintendent, Unit 1 Technical Support Manager The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
"Attended the Exit Meeting on July 30, 1987.
2.
Previousl Identified Items.
Unit 1 a.
Closed Enforcement Item 528/85-31-09
- "Failure To Inde endentl Verif Tem orar Modifications.
'rocedure No.
73AC-9ZZ05 "Temporary Modification Control" Revision 3, dated June 20, 1985, Section 5. 1. 13 required that independent verification of guality Related Temporary Modifications (TM) be performed within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of the time the TM was implemented.
However, TM Nos.
1-85-RC-181 and 1-85-CH-320 were not verified within the 8-hour time frame and a Notice of Violation was issue l
~
To respond to the Notice of Violation, the licensee reviewed the TMs in question and discovered that No. 1-85-RC-181 was installed to Revision 2 of the procedure which only required that an independent verifier be designated by the installer.
However, No. 1-85-CH-320 was installed to Revision 3.
The inspector verified that the following corrective actions had been performed by the licensee:
o A review of TMs that were installed/restored using a Contractor Work Order since June 20, 1985, (this review identified no additional concerns),
o Retraining of all Outage Management Personnel on the requirements of 73AC-9ZZ05, and o
Revision of 73AC-9ZZ05 to clarify the requirements for documenting independent verification of guality Related TMs and to delete the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> requirements.
The inspector also verified, by sampling 6 closed TM packages and
open TM packages, that independent verification of guality Related TMs was being performed and documented in accordance with Revision
of 73AC-9ZZ05.
This item is closed.
b.
Closed Followu Item 50-528/87-13-01
"follow-u on Licensee Pro ram to Track Defects from Outside Or anizations" This followup item was identified from a previous inspection that was inspecting Part 21 reports.
As a result of the inspection, the inspector had the following concerns:
(1)
The licensee did not have a formal documented program for tracking defects, and outlining responsibilities and methods for evaluating the reports.
(2)
Several Part 21 reports identified by other licensees and vendors were not identified in the licensee's informal tracking system, (3)
There had been some Part 21 reports assigned to individual organizations that had requested response dates several months overdue.
The Part 21 reports did not seem to have an initial evaluation.
(4)
There were several Part 21 reports for which the licensee could not provide closure documentation.
During construction, Bechtel had handled the Part 21 notifications.
The licensee stated that they needed to have a formal
CFR Part 21 program and committed to a formal program by May 15, 1987.
The licensee was also concerned that they might not be receiving all applicable Part 21 reports.
A letter has been issued to all
~ ~
suppliers/vendors, directing that a letter be sent to one group in the licensee's organization.
In res'ponse to these concerns, the licensee issued a new procedure, 5N404. 10.00,
"Review of Conditions Adverse to guality for 10 CFR 21," on May 14, 1987.
This new procedure directs that responsibility for the initial review is with the Supervisor of the Independent Safety Engineering Group (ISEG). It also directs that department heads are responsible for transmitting documents to ISEG which may be applicable for a 10 CFR 21 initial review, thus ensuring one organization is responsible for that review.
The procedure is a more formalized approach to evaluating Par't 21 reports.
During the inspection, the inspector reviewed several Part
reports, including the Part 21 reports identified in this followup item.
The licensee supplied sufficient information to close out these reports.
Based on the licensee's actions, this item is closed.
Unit 2 Closed Ins ector Followu Item 529/86-33-01:
Need to Establish Criteria for Sco e of Review for Desi n Chan e Packa e
DCP Review Checklists.
This matter deals with the need for the licensee to revise procedures to establish criteria for the scope of review associated with each signature on DCP review package checklists, ANPP Administrative Procedures and Procedures Manual Section 71414.01.15
"Design and Technical Document Control" contains a listing of design review functions as well as the responsible reviewing organizations.
A separate document
"gA Review of Design/Engineering Documents" now contains the review functions of guality Assurance.
This item is closed.
(Closed Ins ector Followu Item 529/86-32-03 LER 86-46:
Malfunctionin Switch.
This item is associated with the corrosion buildup on the silver coated switch contacts of the "B" train safety injection system manual switch which resulted in its inadvertent operation.
A new switch utilizing gold plated contacts and designed for low voltage/current application has been environmentally qualified and will be installed following purchase.
This item is closed.
Closed Followu Item 50-529/86-33-07
"Review Licensee's Evaluation of the Procurement of and Absence of Unmarked Bolts in Safet S stems" This followup item was identified in the last team inspection at Palo Verde.
The inspector had observed that there were unmarked bolts in the cable, tray supports, which are required by A-307/AISC
to have a man'ufactures identification stamp.
This issue was also raised in the previous Construction Appraisal Team (CAT) inspection at Palo Verde.
The specific concerns with cable tray supports were resolved during the inspection.
However, the inspector's concern was for the root cause for the unmarked bolts observed.
The inspector recommended that the licensee evaluate the circumstances that resulted in the procurement of the unmarked bolts and take actions to ass'ure that procurement of unmarked bolts in other than cable tray supports had not been made.
Also, the inspector recommended that the licensee walk down their safety systems to assure that no unmarked bolts are used.
The inspector discussed this item with the licensee.
The licensee had determined that the absence of markings for the A-'07 bolts was per specification.
The licensee also determined that Bechtel had adhered to design in their material specification procedure',
."Piping Material Classifications,"
in the bolting requirements for the quality class systems in the plant.
The licensee also responded that there were no problems with the procurement documentation for the bolts.
The licensee had performed a review of approximately 100 safety related pipe flanges during the CAT audit.
In their review, the licensee determined that the material was controlled by the Classification and did not note any discrepancies.
The licensee believes that the Piping Material Classification was effective in controlling the design specifications.
The licensee has elected not to do a walk down of the safety systems, based on the above review.
This followup item is closed.
Review of Plant Activities.
a.
Unit 1 The unit operated at lOOX power until June 28 when a plant shutdown was required because of major ruptures in the A/B loop circulating system pipes.
The plant remained shutdown in Mode 5 until July 30, to repair the pipes and correct problems associated with low pressure safety injection (LPSI) pump seal failures.
A power level of 100K was reached on August l.
b.
Unit 2 Unit 2 operated at 100K during the entire report period with the exception of a plant shutdown on July 22.
The plant was tripped on July 23, while power was being reduced for what appeared to be a
steam generator tube leak.
Following an evaluation of the matter, it was concluded no leak existed and that the source of activity detected by the monitors resulted from an ion exchanger venting operation.
The plant was restarted on July 24.
c.
Unit 3 The plant remained in Mode 5 throughout the reporting period.
Retesting of the Train "B" Diesel Generator continued during this
period.
On June 30, 1987, while conducting the 12th of 35 quick start attempts, the diesel engine tripped on high crankcase pressure.
This condition was subsequently determined to have been caused by a seizure of the 9L articulated rod wrist pin.
The articulated rod was replaced and a 24-hour test run was successfully completed on July 6, 1987.
Thereafter, 35 sequential starts and subsequent one-hour runs were successfully completed on July 9, 1987.
During routine inspection of the "B" diesel generator following the first phase of retest, one of twelve generator rotor pole pieces was found to be coming unwound.
On July 17, 1987, the rotor was removed from the generator for replacement of the defective pole piece and shipped offsite for requalification testing.
At the end of the period, the licensee was awaiting the return of the generator rotor.
Initial criticality is currently scheduled to occur in late September, 1987.
d.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspector during the course of the inspection:
Auxiliary Building Containment Building Control Complex Building Diesel Generator Building Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter The following areas were observed during the tours:
(1)
0 eratin Lo s and Records Records were reviewed against Technical Specification and administrative control procedure requirements.
(2)
Monitorin Instrumentation Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
(>>
conformance with 10 CFR 50.54. (k), Technical Specifications, and administrative procedures.
(4)
E ui ment Lineu s Valve and electrical breakers were verified to be in the position or condition required by Technical Specifications and Administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineup (5)
E ui ment-Ta in Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment in the condition specified.
(6)
General Plant E ui ment Conditions Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingtheir functional requirements.
(7)
Fire Protection Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
e)
conformance with Technical Specifications and administrative control procedures.
(9)
~Securit Activities observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
(10) Plant Housekee in Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(ll) Radiation Protection Controls Areas observed included control point operation, records of licensee's surveys within the radiological controlled areas posting of radiation and high radiation areas, compliance with Radiation Exposure Permits, personnel monitoring devices being properly worn, and personnel frisking practices.
No violations of NRC requirements or deviations were identified.
4.
En ineered Safet Feature S stem Walkdowns - Units 1
and 3.
Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspector to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical cabinets, and cables were inspected to determine that they were operable,,and in a condition to perform their required functions.
The inspector also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Unit 1 Accessible portions of the following systems were walked down on the indicated dat Control Room/ESF Switchgear Rooms/DC Equipment Rooms Essential HVAC, Trains
"A" and "B" June
Shutdown Cooling System, Train "A" July 16 Fire Pumps and Mater Supply System Diesel Generator Systems, Trains "A" and "B" July 28 July 30 Unit 2 Accessible portions of the following systems were walked down on the" indicated dates.
Diesel Generator Systems, Train "A" June
Safety Injection Tanks Essential Spray Ponds, Trains "A" and "B" July 2 July 8 125V DC Electrical Distribution, Channel
"D" Auxiliary Feedwater Systems, Trains "A" and "B" July 16 July 28 Fire Pump and Water Supply System July 28 Unit 3 Accessible portions of the following systems were walked down on the indicated dates.
Boron Injection Flow Paths 125V DC Electrical Distribution, Channels
"A" and "C" July 8 July 17 Diesel Generator System, Train "A" July 17 Low Pressure Safety Injection Aligned for Shutdown Cooling, Train "B" July 29 No violations of NRC requirements or deviations were identifie ~
~
~
5.
Surveillance Testin
-. Units 1
and 3.
a.
Surveillance tests required to be performed by the Technical Specifications (TS) 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 specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillances were observed by the inspector on the dates shown:
Unit 1 Procedure Descri tion Dates Performed 41ST-1DG01 31-Day Surveil lance Test of Diesel Generator
"A" July 10 41ST-1SG01 Main Steam Isolation Valve Surveillance July 30 73ST-9SI03 Unit 2 Procedure 36ST-9SB02 Leak Test of Reactor Coolant System Isolation Pressure Valves Descri tion PPS Bistable Trip Units Functional Test.
July 30 Dates Performed June 22, June
36ST-2SE06 Log Power Functional Test July 1 72ST-9RXll COLSS Margin Alarms July 29 No violations of NRC requirements or deviations were identified.
Plant Maintenance - Units 1
and 3.
During the inspection period, the inspector observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required gA/gC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified reportability for these activities was correct.
b.
The inspector witnessed portions of the following maintenance activities:
Unit 1 Descri tion Dates Performed o
Troubleshooting Malfunction of June
Circulating Water Valve HV-10 o
Troubleshooting
"A" Diesel Turbocharger Exhaust Problem July 6 Unit 2 Descr i tion Dates Performed o
Seven Day Surveillance PM on 125V Class lE Batteries June
o Replacement of K110 Relay (Battery Room Damper Control)
o Cleaning and Inspecting PPS Cabinets June
July 16 o
Installation of Slinger Ring on "B" LPSI Pump July 16 Unit 3 Descri tion Dates Performed o
Equipment Access Hatch Closure July 10 o
Diesel Generator
"B" Main July 14 Bearing Instal 1 ation No violations of NRC requirements or deviations were identified.
7.
Pr eo erational Testin
- Unit 3.
The inspector witnessed the performance of preoperational testing to verify that the procedure in use was properly approved and adequately detailed to assure satisfactory performance; test instrumentation required by the procedure was calibrated and in use; work was performed by qualified personnel; and results satisfied procedural acceptance criteria or were properly dispositioned.
The inspector witnessed the performance of portions of the following system testing activities:
Procedure Descri tion 73HF-3SF02 73P E-3DG01 Post-Core CEDM Performance
,Carry Over Testing of Diesel Generator
"8" Engine
'o violations of NRC requirements or deviations were identified.
Control Room Annunciator Problem Reduction - Units 1 2 and 3.
The inspector reviewed the licensee's actions related to the correction of control room annunciator problems in the three units.
The licensee's efforts include the tracking of corrective actions in a monthly annunciator status report which identifies assignments, status, and progress information.
The problem annunciators have been identified at all three units and are listed in the monthly status reports.
The inspector noted that the number of annunciator problems have been reduced significantly in the last six months.
Part of this accomplishment is due
. to daily tracking of the status of corrective actions being taken in the plant morning maintenance meeting.
While the effort.is considered positive, continued management attention and priority must be given this effort to further reduce the problem alarms.
Based on this inspection, followup item 50-528/86-33-04 is closed.
No violations of NRC requirements or deviations were identified.
9.
Overtime - Units 1 2 and 3.
The inspector reviewed overtime records f'r approximately 50 members of the Operations Engineering staff and the Unit 2 Operations staff for the period January 1, 1987, to May 15, 1987.
The inspector noted approximately 20X of the Operations Engineering staff reviewed had worked overtime in excess of the 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight or in excess of the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period.
Plant procedures and Technical Specifications specify the overtime limits when associated with safety related work.
In one case an individual had on two occasions worked in excess of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period.
The inspector pursued each of the cases with respective staff supervision.
In each case a proper authorization to work the overtime was on file or the activities involved administrative work or nonsafety work.
In the case of the individual who had worked in excess of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a.seven-day period, the inspector was provided a
Potentially Reportable Occurrence Report (PRO) 81-87-073 in which the inspector's finding had been previously identified in an ANPP gA audit.
No violations of NRC requirements or deviations were identified.
10.
Circulatin Water CW S stem Ru ture Unit l.
On June 28, 1987, Unit 1 experienced major pipe ruptures on the "A"/"B" loop of the circulating water system with the plant at 100K power.
The piping ruptured at four locations on the hotwell 2 "C" inlet and outlet water boxes and was punctured at one location on the 2 "C" inlet water box.
In addition, all of the large expansion joint studs on the "A"/"B" loop appeared to have been stretched or misaligned.
The studs on the
"C"/"0" loop also appeared to be damaged.
When the ruptures occurred hotwell level increased and secondary chemistry (sodium, conductivity and chlorine) quickly went out of specification.
The turbine building 100'loor was flooded with several inches of wate Shortly after the initiating event, several alarms were received from the circulating water system.
Ground alarms were also received on the PK-M42 and NK-M45 busses.
The condenser began to lose vacuum and plant cooling water pump "8" auto-started.
The Shift Supervisor immediately ordered a
power reduction to 40X so that the affected circulating water loop could be isolated.
The primary operator immediately began decreasing turbine load while the secondary operator borated and inser ted control rods.
At about 70X power circulating water pump "A" was secured.
At 50X power, circulating water pump "8" was secured and the CW cross-tie valve was closed.
The operators began to stabilize the plant and to regain normal operating temperatures and pressures at 40X.
Reactor power continued to decrease to 23X.
The secondary operator then removed the "8" main feed pump from service.
This resulted in a reactor power cutback (RPC)
because the RPCS had not been removed from service.
Subgroups 4,
5 and 22 fully inserted, causing reactor power to decrease to 2X.
The Shift Supe'rvisor ordered that the turbine be manually tripped and to proceed with a normal reactor shutdown.
The operators tripped the turbine.
The part length and regulating CEA groups were then fully inserted in accordance with the reactor shutdown procedure and the reactor switchgear breakers were opened.
Subsequent review has determined that the cause of the event was that the
"A"/"8" circulating loop discharge valve, CWN-HV-10 failed closed.
The failur'e of this valve caused the pressure transient which produced the damage to the circulating water piping.
The root cause of the failure appears to be overloading of the valve operator quadrant gear bolting which resulted from the valve mechanical stop being improperly adjusted.
This misadjustment (about 2X open) prevented the valve from reaching a
fully closed position.
Since the mechanical stops were not set properly, the use of a manual valve operator caused the quadrant gear to be continually driven against the mechanical stops.
This caused an overload on the bolting, not enough to break the bolting, but enough to relax the torque making the bolting susceptible to fatigue failure.
Repeated overloading of the manual portion of the valve operator fatigued the bolting and allowed them to detorque and fail.
The failure of the last bolt allowed the valve to close.
Corrective actions taken on the HV10 valve included replacement of the broken bolts with new bolts and incorporating a hardened washer to permit torquing to 320 foot pounds.
Resetting the mechanical stop to permit full closure was also done.
The bolting of similar valves in Units 1, 2, and 3 were inspected and checked for tightness.
No other broken bolts were found.
For the longer term solution, the licensee s engineering staff is working with the valve operator manufacturer to change to an operator which has a one piece drive sleeve/quadrant gear.
No violations of NRC requirements or deviations were identified.
Loss of "A" LPSI Pum Motor and "A" and "8" Pum Seals - Unit 1.
During the shutdown from the circulating water system pipe rupture, with the Unit 1 "8" LPSI pump providing shutdown cooling in Mode 4 at
approximately 340 degrees F, the pump's mechanical seal was observed to be leaking.
The leakage rate was estimated to be approximately 1 gpm.
As a result, the "B" LPSI pump was secured and the "A" LPSI pump was placed in service.
The "A" LPSI pump seal also developed a leak of approximately 2-3 gpm.
The majority of seal leakage from the "A" LPSI pump was directed up the pump shaft toward the lower motor. bearing assembly.
As a result of this leakage the "A" LPSI pump motor ultimately tripped on overcurrent on July 4, 1987.
An inspection of the "A" LPSI pump mechanical seal was completed on July 10, 1987.
The shaft packing "0-ring" was found to be pliable but swollen.
The tungsten-carbide rotating seal face was found to contain heavy full face wear.
The stationary seal face also exhibited heavy full face wear and chipping on the face inside diameter (I.D.).
The stationary seal also contained a full 360 degree circumferential crack extending from the I.D. to the outside diameter (O.D.).
The preliminary cause of failure of sealing capability is attributed to increased seal face loading produced by the swollen shaft packing "0-ring".
Determination for the reason for "0-ring" growth remains under investigation but is believed to be the reaction of the "0-ring" material to cleaning solvents.
The LPSI "A" motor teardown for failure analysis and repair was performed by the licensee, as well as the motor, seal, and pump vendor representatives.
It was concluded that water injection into the lower motor bearing resulted in the displacement of the bearing lubricating oil.
The resultant lack of lubrication caused the bearing to heat up and subsequently seize.
The" LPSI "B" pump seal assembly also was inspected.
The stationary seal exhibited wear grooves on the face and chipping on the face I.D.
The rotating seal face exhibited a groove on the face.
The "0-ring" seals did not appear swollen; however, the plane of the seal face appeared cocked producing uneven wear.
Based on the introduction of leakage water into the motor bearing oil reservoir, water slingers were fabricated and installed on the LPSI and containment spray pumps at Units 1 and 2.
These slinger rings are to be installed on Unit 3 if a permanent resolution is not in place at the time the pumps are required.
Additionally, pumps will be monitored during high temperature operation to assure early detection of seal leakage/failure, and operations in the high temperature area above 300 degrees F will be minimized.
Appropriate action will be taken in accordance with the Unit Technical Specifications should leakage exceed allowable values per applicable LCOs.
The investigation into the root cause of the seal failures and subsequent resolution is still in progress and will continue to be followed by the inspectors.
The seals of both LPSI pumps have been replaced.
Pump bearings have been inspected and replaced as necessary.
The pumps have been satisfactorily tested and are now in an operable status.
This subject is further discussed in inspection report 50-528/87-26.
No-violations of NRC requirements or deviations were identifie.
Surveillance Pro ram.
The inspector review The procedures reviewed wer e:
ed-the surveillance test procedures for the thr ee units.
This review revealed that the documents were properly approved',
prerequisites and preparations for tests were specified, acceptance criteria for tests were specified, instructions to ensure systems or components are restored to operation following testing were included.
Test requirements were consistent with Technical Specifications.
32ST-9PK03 32ST-9RC01 36ST-9SB04 36ST-9SB09 43ST-2RC02 72ST-9RX01 72ST-9RX02 73ST-9CL03 73ST-9DG03 73ST-9SI03 73ST-9SI01 73ST-9SI02 18 Month Surveillance Test of Station Batteries.
92 Day Pressurizer Heater Capacity Test.
PPS Functional Test - RPS/ESFAS Logic.
Plant Protection System RTD Response Time Test.
RCS Water Inventory Balance.
Core Reactivity Balance.
Moderator Coefficient At Power.
Containment Air Lock Seal Leak Test.
Class 1E Diesel Generator
"A" and "B" 10-year Electrical Surveillance Test.
Leak Test of RCS Isolation Pressure Valves.
ECCS Flow Balance Test.
Containment Spray Nozzle Test.
Additionally, the inspector observed that approved surveillance test procedures existed for each of the major systems identified in the licensees inservice inspection program for pumps.and valves.
Implementation of the surveillance tests has been routinely followed during each of the inspection periods and findings have been documented in the periodic NRC inspection reports.
No violations of NRC requirements or deviations were identified.
13.
Tem orar Instruction 2515-91 - "Ins ection Fol lowu To Generic Letter 83-28 Item 4.1."
This item was discussed in NRC Inspection Report 528/84-51 paragraph 7.
No physical modifications to the reactor trip breakers were required.
The Westinghouse trip breakers used at PVNGS are DS-206 not DB-50 and the undervoltage trip design changes had been incorporate in the breakers purchased by ANPP.
The GE breakers are AR-30 and no modifications were required.
Several preventative maintenances controls recommended by the breaker manufacturers were incorporated into the plant PM program.
This item is closed for Units 1, 2 and 3.
14.
0 en IE Bulletin 85-03
"Motor-0 crated Valve Common Mode Failures Durin Plant Transients Due to Im ro er Switch Settin s
This NRC bulletin requested all licensees to develop and implement a
program to ensure that switch settings on certain safety-related motor operated valves (MOVs) are selected, set, and maintained correctly to accommodate the maximum differential pressures (DPs) expected on these
valves for both normal and abnormal events within the design basis.
The valves addressed in this bulletin are in the High Pressure Safety Injection (HPSI) and Auxiliary Feedwater (AFW) systems.
The motor operators on valves can be adjusted to deliver thrusts to the valve and valve stem within a certain range of possible thrust values.
These operators have limit and torque switches to disconnect power to the motor.
The limit switches can disconnect power to the motor depending on the amount of stem travel.
Torque switches are installed to disconnect the motor if the valve experiences a high thrust on the stem.
A torque bypass switch is also installed to "bypass" the torque switch during initial movements of the stem.
By the proper setting of these switches, the valve will operate under the maximum DP across the valve, without damaging the valve.
The bulletin called for licensees to review their design basis for the valves in the HPSI and AFW systems, that were required to be tested for operational readiness, in accordance with 10 CFR 50. 55a(g).
The six requirements were to:
(A) review and document the design basis for each valve:
(B) establish correct switch settings from item (A): (C) change the settings as needed from item (B):,(D) revise procedures to ensure the settings are maintained over plant life: (E) submit a report to the NRC within 180 days that informs the NRC of the results of (A) and the schedule for items (B) through (D) and:
(F) submit a final report upon the completion of the program.
The initial response to the bulletin was submitted late to the NRC (due
~ approximately May 15, 1986, mailed June 30, 1986).
The NRC requested clarification of the licensee's initial response (Kirsch to Van Brunt, September 17, 1986) within 30 days.
The licensee submitted clarification information in a letter dated October 27, 1986.
The licensee's clarification response was also late.
The licensee has elected to do pressure testing on certain valves to determine if the the valves will liftagainst the maximum DP expected.
Due to the similarity between the units, the inspector was informed that all the valves in the three units would not be done.
The inspector was informed that DP testing on the valves will be done at a later date on some valves to assure that the valves are set properly.
The inspector discussed with the licensee the engineering evaluation for setting of the torque and limit switches.
Combustion Engineering and Bechtel did the DP analysis for the valves in the bulletin.
The licensee contracted with MOVATS for using the DPs to calculate the required thrusts on the valve stem.
This report, "Differential Pressure Thrust Analysis for Palo Verde Nuclear Power Station," included the seating load, wedging load, piston effect and included safety factors in determining the valve thrust.
The report also verified, where possible, the calculated results against data determined in the field from other plant experience.
The licensee is setting the torque bypass for the valves at approximately 20K to 25K of stem travel in the open direction.
The bypass setting should assure that gate and globe valves are off of their seats when
opening.
The licensee is setting the torque switch at a value so that the stem load plus valve inertia is less than 1. 1 times the valve rating (in accordance with the Limitorque allowable limits).
The guality Assurance/guality Control (gA/gC) organizations were involved with.the work done by the licensee.
The inspector was informed that gA had performed a Safety System Functional Inspection (SSFI) audit of work done on the AFW system (Audit 87-13)
and had included a review of the MOVATS program.
The inspector also noted that work orders for the particular valves had guality Control (gC) hold points and sign-offs for independent verification of the as-left condition.
The overall procedures used for maintenance and testing on the systems for the bulletin were the following:
32MT-9ZZ47, "Maintenance of Motor Operators" 40TP-9ZZ01,
"MOVATS Testing for Auxiliary Feedwater System" 40TP-9ZZ02,
"MOVATS Testing for Safety Injection System" The work on the changing of the valves limit and torque switch settings was governed by the work order s generated for each valve.
During the inspection, the inspector observed work on the following valves:
VALVE NUMBER DESCRIPTION 3J-AFB-UV-0034 1J-AFC-UV"0035 1J-AFC-UV-0036 3J-CHB-HV-0530 AFW Isolation Valve, PPB to SG1 AFW Isolation Valve, PPB to SG2 AFW Isolation Valve, PPA to SG1 RWT Suction Isolation The work was done by approved work orders and procedures.
The valve internals observed by the inspector were noted to be free of foreign material and the stems well lubricated.
Problems that were noted by the licensee with these valves generally were grease in the spring pack and one failure of a torque switch due to a damaged roll pin.
Due to the problems that were identified, and other pressing maintenance items at the other units, work was not completed on these valves during the inspection.
The inspector did perform an in-office review of the following completed work orders:
WORK ORDER NUMBER 227303 194505 216757 220568 228715 227279 228713 194511 VALVE NUMBER 2J"AFC-HV"0033 3J"AFB-HV-0030 2J-AFB-HV-0031 2J-CHB-HV-0530 2J"AFA-HV-0032 2J"AFB-UV-0034 2J-AFC-HV-0033 3J-AFA"HV-0032 DESCRIPTION AFW Reg.
Valve, PPA to SG2 AFW Isolation Valve, PPB to SG1 AFW Reg.
Valve, PPB to SG2 RWT Suction Isolation AFW Reg.
Valve, PPA to SG1 AFW Isolation Valve, PPB to SG2 AFW Isolation Valve, PPA to SG2 AFW Isolation Valve, PPA to SG1
The inspector had questions regarding the HOVATS traces on the first 6 work orders listed above.
Some concerns noted by the inspector included a possible bent stem, cyclic loading that could be indicative of gear wear, some initial lowering of the running load as measured by the spring pack and questions regarding some traces that were unusual.
The procedure governing the maintenance of these valves after changing the torque switch setting was still in the draft stage at the time of the inspection.
This procedure, 73PR-9ZZ04, will be reviewed by the NRC to ensure that future maintenance done on the valves will not change the switch settings or the thrust required to liftthe valve.
Discussions by the inspector with the licensee did not reveal any conceptual problems with the draft of the procedure.
This bulletin will remain open pending technical staff review of the design basis for the systems, a review of the procedure for monitoring
, the work and settings on the bulletin valves in the future, and the resolution of the inspectors concerns with the completed work orders:
15.
Information Notices a.
Closed IN 84-93
"Potential for Loss of Water from the Refuelin Cavit
"
Unit 3 onl On August 21, 1984, the Haddam Neck plant experienced a failure of the refueling cavity water seal with the refueling cavity flooded in preparation for refueling.
A leak developed when the pneumatic seal assembly was forced out of its'ormal position as a result of the static water pressure.
This caused the refueling cavity water level to drop 23 feet, which flooded the containment with approximately 200,000 gallons of water in about 20 minutes.
There was no fuel being transferred at the time of this seal failure.
A Bulletin (84-03), "Refueling Cavity Mater Seal",
was issued on August 24~ 1984, as a result of the above incident.
The information notice also identified several other potential failure modes.
Damage of'pneumatic seals due to a dropped object was also identified as a potential failure mode.
The reliability of other pneumatic seals in the refueling cavity including the steam generator nozzle dams, and fuel pool gates should also be considered in this review.
Another possible failure mode identified was valve misalignment of the Residual Heat Removal (RHR) system.
Finally, the refueling cavity could be drained down slower through one of the attached drain lines.
The licensee had the vendor evaluate this issue (Report V-CE-32308)
and had Bechtel evaluate the fuel pool gate seals.
The inspector reviewed this report and determined that the licensee evaluated the above potential failures and the licensee took action to increase the reliability of the seals.
The refueling cavity pool seals had structural pins added to the top flange of the pool seal.
The inspector also observed the cavity seal mentioned and observed that the pins were installed.
The licensee also reviewed procedures to
f~
verify that piping configurations would not cause a loss of cavity water and to incorporate enhancements identified in the report.
The information notice has been closed for Units 1 and 2.
Based on this closure, and the licensee s evaluation, this information notice is closed.
Closed IN 86-25
"Traceabilit and Material Control of Material and E
us ment artscu arl asteners and N 86-2 u
ement
This information notice was issued on April ll, 1986 to inform licensees of potentially significant problems with the use of incorrect or defective materials, particularly fasteners.
The deficiencies in material traceability and control of fasteners at the sites identified in the notice were attributed to ineffective site inspection programs and vendor surveillance activities.
Possible fastener defects, if uncorrected, could adversely affect operation of equipment during seismic events.
The licensee should have a program to ensure traceability of fasteners, in accordance with 10 CFR 50, Appendix B, Criterion VIII, which specifies that measures for control of materials be implemented.
The supplement to this information notice specifically mentions problems with intentionally mismarked Society of Automotive Engineers (SAE) J429K grade 8 bolts.
The Industrial Fastener Institute (IFI) identified that foreign imported bolts have incorrect 'headmarkings'ndicating a grade 8 instead of a grade 8.2.
The mechanical properties of these bolts are essentially identical except when the bolts are used in high temperature applications.
At temperatures near 650OF, the grade 8.2 bolt undergoes stress relaxation while the grade 8 bolt does not.
This was noted as an example which could result from not having a
rigorous procurement inspection program.
This substitution could not be identified by a visual inspection.
The licensee is relying on procurement documentation to assure that bolts meet the material requirements.
The inspector was informed that there are approximately 4500 stock codes for fastener material.
The licensee has the documentation to verify what is in the warehouse.
The inspector toured the warehouse, noting that the materials in question are in a special area for control of the material.
A separate receipt inspection is performed for bolts that leave the warehouse for use in the plant.
In the past, the licensee has received counterfeit bolts.
The licensee's response to this information notice and previous problems included a review of their procurement documentation.
The licensee now requires certifications and grade markings on bolts, from an approved supplier, to help assure material control.
The inspector was informed that the licensee is doing a reinspection on bolts, to assure that the bolts meet the material requirements.
The reinspection includes a users test (Rockwell hardness)
on the bolts.
The inspector was informed that the licensee will soon have a alloy analyzer (spectrometer)
to determine bolt composition.
The licensee
<a
hopes to have this reinspection done in the September to October time frame.
The inspector was informed that the licensee does not use SAE bolts in high temperature applications.
The only seismic application for SAE bolts is for the Diesel Generators, which specifies SAE grade 5.
The bolting requirement for the Diesel Generators was in accordance with the design and was not in a high temperature environment.
On the basis of the licensee's procurement program, and the fact that the licensee does not use SAE bolts in high temperature applications, the inspector concluded that the actions taken by the licensee to address incorrect fastener material were appropriate.
This information notice is closed for all 3 units.
Closed 85-20-P
"GE AK and AKR T e
Low Volta e Tri Breakers" A 10 CFR 21 notification was issued to the NRC on September 13, 1985, by the vendor regarding possible defects on AK and AKR low-voltage power circuit breakers.
The deficiencies apply only to alternating current powered trip breakers.
The undervoltage trip devices on these breakers failed to trip when power was removed for the following two reasons:
(1)
Devices made between mid 1978 and May 1985 may have had the mating surfaces of the armatures and pole pieces improperly painted.
Heat may soften the paint, causing the armature to stick to the pole piece, (2)
Some devices were manufactured with insufficient clearance between the armature and mounting studs.
In the Part 21 report submittal, it was noted that twenty AKR type breakers were supplied to the licensee as original equipment.
These breakers are part of the Reactor Protection System (RPS).
The deficiencies mentioned above could hinder or prevent the trip device from actuating.
The paint described as vulnerable to this type failure was black.
The licensee inspected all of the trip breakers they had for the above deficiencies.
It was determined by this inspection that the breakers had the proper clearances and that the armatures were not painted black.
Therefore, the trip breakers are not vulnerable to the failures described in this Part 21 report.
Based on the licensee's actions, this Part 21 report is close Closed 86-18-P
"Crackin of Limitor ue Switch Rotors on SMB Series MO's" A 10 CFR 21 notification was issued to the NRC on June 10, 1986, from the Rancho Seco Nuclear Generating Station.
During a routine inspection of the Environmental gualification (Eg) of the Limitorque.
series SMB motor operators, cracks were detected on the white (melamine) rotors near the groove pin which secures the rotor to the metallic actuation shaft.
The failure of these rotors was also discussed in Information Notice 86-71.
A hypothetical failure of these rotors could remove indication of valve position to the control room and/or fail to disconnect the power to the motor when the valve is Limit Open (LO) or Limit Closed (LC).
In discussions with the licensee, the inspector was informed that those types of rotors had been present at Palo Verde (before 1984),
but that the rotors have subsequently been replaced and were no longer present at Palo Verde.
Based on the licensee's actions', this item is closed.
Closed 86-25-P
"Limitor ue Su lied 724 Terminal Stri s
Environmental uglification" This Part 21 report was issued by Arkansas Power and Light (AP8L) as to their questioning the Eg of Buchanan 724 terminal strips.
During AP8 L's work on IE Bulletin 85-03, it was decided to replace the original Buchanan 524 terminal strips.
The Buchanan 524 terminal strips are made of a phenolic (black in color) material.
In contracting the vendor (Limitorque) for replacement parts, the licensee was informed that the 524 strips were not available.
The vendor responded that the 724 strips were a replacement.
While replacing the strips, AP8L personnel noted that the strips were white instead of the black material expected.
The licensee determined that the 724 strips were of a nylon or polypropylene material (which is white in color).
Documentation could not be provided that the 724 strips had the proper Eg.
Using terminal strips which are not environmentally qualified could lead to valve inoperability.
Palo Verde did a search of their receipt inspection documentation and determined that no 724 strips had been supplied to ANPP.
The inspector did not note any white terminal strips during his inspection.
I Based on the licensee's actions this item is close.,
Review of Periodic and S ecial Re orts - Units 1
and 3.
)
~
~
Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained
'he information required to be reported by NRC requirements; test res01ts and/or supporting information were consistent with design predictions"and performance specifications; and the validity of the reported information.
Within the scope of the above, the following reports were reviewed by the inspector.
Unit 1 o
Monthly Operating Report for June, 1987.
Unit 2 o
Monthly Operating Report for June, 1987.
No violations of NRC requirements or deviations were identified.
The inspector met with licensee management representatives periodically during the inspection and held an exit on July 30, 1987.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee representatives.