IR 05000528/1991005
| ML17305B557 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 05/14/1991 |
| From: | Huey F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B556 | List: |
| References | |
| 50-528-91-05, 50-528-91-5, 50-529-91-05, 50-529-91-5, 50-530-91-05, 50-530-91-5, IEB-88-004, IEB-88-4, NUDOCS 9106030018 | |
| Download: ML17305B557 (38) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-528/91-05, 50-529/91-05 and 50-530/91-05 Docket Nos.
50-528, 50-529,'0-530 License Nos.
NPF-41, NPF-51, NPF-74 Licensee:
Arizona Public Service Company Facility Name:
Palo Verde Nuclear Generating Station (PVNGS) Units 1, 2 and
Inspection at:
Palo Verde Site, Mintersburg, Arizona Inspection Conducted:
February 4 - April 26, 1991 Inspectors:
C.
A. Clark, Reactor Inspector D.
E. Corporandy, Reactor Inspector Approved by:
uey,
gineering Sec ion e
gne Ins ection Summar
Ins ection Durin the Period Februar 4 -
A ril 26 1991 (Re ort Nos
~
an Areas Ins ected:
An unannounced routine inspection by two reqional snspec ors.
reas inspected include:
previously identified stems, effectiveness of the licensee s maintenance activities, a'eview of available Inservice Testing of pumps and valves, and application of NRC Bulletin 88-04
"Potential Safety-Related Pump Loss" (SIMS MPA number X804).
Inspection procedures 30703, 62700, 92701, 73756 and Temporary Instruction 2515/105 (for application of NRC Bulletin 88-04) were used as guidance for the inspecti on.
Results:
General Conclusions and S ecific Findin s
The recorded status of work in maintenance procedures maintained at one job site were not up to date.
The late entries of signatures/signoffs in maintenance procedures were not performed correctly.
9106030018 910514 PDR ADOCK 05000528 Q
-2-Maintenance procedures
'issued for work observed, at times appeared to be treated in the field as reference documents, rather than specific instructions/requirements to be followed.
Work orders and procedures issued for repetitive maintenance work in radiation areas, did not 'contain detailed tool lists.
Mhen non-routine management inspections are required for activities being conducted in radiation areas, additional procedure hold points should be identified to ensure work activities do not proceed past the point of inspection.
Si nificant Safet Matters:
None Summar of Violations:
One non-cited violation (NCV 50-528/91-05-01)
was s
en s
se in paragraph 2.B.
0 en Items Summar
Six new open items were identified, four followup items were c ose an wo followup items were left open.
Of the.six new open items, three related to application of NRC Bulletin 88-04 (reference TI 2515/105, SIMS MPA number X804).
DETAILS 1.
Persons Contacted J
J
" R.
- R; S
S K.
" R.
" R.
S D
D
- J
" R.
C
- J
- B p.
Baxter, Compliance Engineer Bradish, Compliance Manager Draper, Southern California Edison Company Site Representative Flood, Unit 2 Plant Manager Fountain, Quality Assurance (QA) Deficiency Coordinator Grove, Unit 2 18C Maintenance Supervisor Guthrie, QA Deputy Director Hall, El Paso Electric Company Site Representative Hazelwood, QA Supervisor Henry, Salt River Project Si.te Representative Kanter, Ower Services Senior Coordinator Marks, Nuclear Safety Manager Mauldim, Site Maintenance Director Minnicks, Unit 3 Maintenance Supervisor Rouse, Compliance Supervisor Russo, Quality Control (QC) Manager Schmadeke, Unit 3 Work Control Manager Simko, Unit 2 Maintenance Manager Winsor, Unit 1 Maintenance Supervisor
" Denotes those attending the exit interview February 22, 1991.
The inspector also held discussions with other licensee and contractor personnel during the course of the inspection.
2.
Maintenance Pro ram Im lementation (62700)
Using available Probabilistic Risk Assessment information, specific available maintenance activities were selected for inspection.
The areas and maintenance activities inspected are identified below:
A.
Unit 1 Emergency Core Cooling System Sump Inspection For Both A and B Trains.
The subject sump inspections were performed by licensee personnel and closed in accordance with instructions in surveillance test procedure 31-ST-9SI-01.
After closure on the same day the inspection was completed, it was identified that the licensee's management had made commitments to participate in the subject sump inspections.
Work order numbers 00469960 (Train A) and 00469963 (Train B) were issued the following day to reopen, visually inspect and close the sumps.
Since the subject ECCS containment sumps were located inside a
RCA, additional radiation exposure was received by personnel involved in establishment and disassembly of access entry areas, removal and reinstallation of sump access port covers, initial work area surveys, and any required retestin The generation of this additional radiation exposure did not appear to follow the general guidance of an effective As Low As Reasonably Achievable (ALARA) Radiation Exposure program.
The licensee identified that these management sump inspections appeared to have been a one time only follow-up inspection, and, therefore, they were not identified with procedural holdpoints or sign-offs.
To prevent recurrence of similar problems in the future, the licensee stated they would consider including steps in procedures with sign-offs for management action items.
Unit 1 Pressurizer Code Safety Valves-Replacement and Installation Activities.
Maintenance activities included the replacement of one of the three pressurizer code safety valves and the installation of a new thinner gauge ring at the inlet flanges of all three of the pressurizer code safety valves.
The three pressurizer code safety valves were being worked in accordance with following licensee instructions:
Valve 1JRCEPSV0200 1JRCEPSV0201 1JRCEPSV0202 Work Order No.
00454762 No.
00454763 No.
00452499 It was observed that a pen and ink change entered as step 4. l. 1 was signed after performance of steps 4. 1.2, 4.2 and 4.3 had been performed and valve flange studs, nuts, and qaskets had been removed.
Step 4. 1. 1 stated,
"Remove insulation at inlet flange."
Since the valves had been removed several times before, the fact that a pen and ink change had to be added to the WO appeared indicative of inadequate preplanning for this job.
Furthermore, the gaskets and some studs and nuts had been reinstalled to control noble gas leakage, but the working documents at the job site did not identify this.
The inspector expressed concern that neither the WO's nor procedure 31MT-9RCll contained a detailed tool list and questioned how radiation exposure to maintenance personnel could be kept as low as reasonably achievable (ALARA) when details of specific tools to accomplish a job were not provided.
The inspector also observed that contrary to procedure 30DP-9M01,
"Conduct of Maintenance,"
which states that maintenance instruction steps should be done in sequence, steps 5.2 through 5.8 of procedure no.
31MT-9RC11 had been performed and signed off prior to the required sign-off in preceding step 4.1.
In response to this, the Maintenance Department issued Incident Investigation Report No.
3-1-91-019 and performed subsequent corrective actions initiated by the repor One of the corrective actions was to make late entries for step 4.1.
The late'entry sign-offs were not performed in accordance with section 3.8. 10 of licensee procedure 30 DP-9MPOl in that they were not identified as "late entry" and the date the activity occurred was not listed.
This is an apparent violation (NCV 50-528/90-05-01)
.of 10 CFR Part 50, Appendix B, Criterion V which requires that
"Activities affecting quality shall be prescribed by documented instructions...and shall be accomplished in accordance with those instructions."
After reviewing the report and corrective actions, and an April 15, 1991 licensee letter (102-02008-.WFC/TRB/JRB)
the inspector concluded that the criteria set forth in 10 CFR Part 2, Appendix C, Section V.A for non-cited violations had been satisfied.
Consequently, this violation is not being cited and no response is required.
Details of Incident Investigation Report Number 3-1-91-019 and other licensee actions taken to address the inspector's concerns are identified below:
Pen and Ink Addition of Ste 4. 1. to WO's to remove insulation.
Installation of this change appeared to indicate inadequate preplanning or previous work feedback yia a Work Enhancement form, for a repetitive job in a radiation area.
The Maintenance Department identified that there appeared to have been a misunderstanding between the planner and field crew as to whether insulation should be removed, before or after, implementation of Procedure 31 MT-9RCll.
This item will be resolved pr'ior to issuing these documents again for similar work.
Detailed Tool List The Unit 1 Maintenance Department identified:
(1)
That they hav'e been working on the improvement of procedure tool lists through the development of Model Work Instructions per Procedure 30DP-9WP06, Revision 3, "Model Work Instruction Control," and increased emphasis on previous work feedback per the completion of Work Enhancement forms identified in procedure 30 DP-9MP01, Revision 3.
The licensee identified that, to date, approximately ten Model Work Instructions have been prepared for Unit 1 repetitive maintenance activities.
(2)
To minimize tooling problems and delays with work in containment, an increased inventory of tools was staged just outside containment adjacent to the personnel entry door.
The open hours of the hot tool room were also expanded t'o minimize tooling problems.
The licensee actions to improve maintenance procedures in the areas of detailed tool lists and feedback from previous
performance of similar work in all 3 units will be-followed as followup item (50-528/91-05-02).
This item will remain open unti 1 an inspector has reviewed new maintenance procedures, procedure writer guides, or other instructions -that show these concerns have been addressed.
Performance of Work Not Pro erl Documented The Incident Investigation Report attributed the root cause of omission of the step 4. 1 signoff to '!...a lack of attention to detail during the transfer of information from working copies to the original work document."
The recommended corrective action was to use only one working copy of the WO at the job site and to assign signoff responsibilities to one crew member with verification required by another crew member.
The report identified that the Unit 1 maintenance crew had.received training on this subject through a briefing on February 8, 1991.
One non-cited violation and no deviations were identified in the areas reviewed.
3.
Inservice Testin of Pum s and Valves (73756)
Inservice Testing (IST) activities were observed during this inspection, and the observations are identified below by equipment involved:
A.
Unit 1 Auxiliary Feedwater System (AFS) motor operated valves, IJAFB-UV-34 and IJAFB-UV-35.
These valves and the similar system valves in Units 2 and 3, have had a history of not closing fully during past full flow, high differential pressure (DP) testing.
Past testing identified that the valve actuat'ors for these valves have torqued out prior to full closure.
To. correct this problem a larger size valve actuator was scheduled to be installed on these valves, in all three units, at the next refueling outage.
At the time of this inspection the valves in Unit 2 had the larger actuators installed and tested acceptably.
Larger actuators had also been installed on the Unit 1 valves.
Ouring the initial testing of the Unit 1 valves per procedure 73TI-9ZZ44,
"MOVATS Testing for Auxiliary Feedwater System,"
valve 1JAFB-UV-35 failed to close during the first attempt at a flow of approximately 1100 gallons per minute (GPM).
The valve had a leak rate of 150 GPM after the motor tripped at.the torque switch setpoint.
The licensee identifie'd that the valve torque switch was adjusted by MOYATS to trip out at a closing thrust of 24,264 LBS Force (LBF) and this value was exceeded prior to complete closure of the valve.
The licensee identified that after the valve failed to close completely, the torque switch setpoint was adjusted to the next higher load adjustment index point and the valve was cycled open and fully closed.
The MOVATS equipment identified a valve actuator closing thrust of an estimated 33-,136 LBF.
The maximum allowed thrust was I
32,000 LBF.
A Material Nonconformance Report (MNCR) No.
91-AF-1003 was issued February 7, 1991, to identify that the maximum allowable thrust had been exceeded.
To continue testing of this valve a
Conditional Release Request was issued February 7, 1991.
This conditional release request identified that the actual overthrusting could have been as high as 35,256 LBF due to overall equipment inaccuracies, and that there did not appear to be any damage to the valve or actuator.
The inspector was concerned that the licensee adjusted the valve past the maximum allowable thrust setpoint.
The licensee stated that due to inaccuracies in the methods used to adjust these valve thrust setpoints, they could not accurately predict the thrust after changing the torque switch setpoint to the next higher load adjustment index point; hence there was no assurance of not exceeding the maximum allowable thrust value of 32,000 LBF.
To disposition NNCR No, 91-AF-1003 the licensee reviewed the design
, calculations for maximum allowable stem thrust for valve 1JAFB-UV-35 and revised the permissible design thrust range.
The new maximum'llowable stem thrust is 39,000 LBF.
The original estimated thrust values of 33,136/35,256 LBF were less than the new maximum value.
During review of historical stem thrust data on these valves in Units 1 and 2, it was identified that Unit 1 Auxiliary Feedwater valves 1JAFB-UV-34 and 35 required approximately 4000 LBF more stem thrust to close during full testing than Unit 2 valves.
The Engineering Department identified that since Unit 1 valves had a
larger number of operating hours than the Unit 2 valves, they considered that a possible reason for the required additional stem thrust.
The Unit 3 valves will have the larger valve operators installed this next outage..
The NRC will review the required stem thrust data identified during full flow testing of those valves.
In addition to observing and assessing results of testing on the subject valves, the inspector was concerned about the impact of larger operators on valve and system, dead load and dynamic loading.
Design Change Package (DCP)
No.
IFJ-AF-091 was issued to replace the operators on valves 1JAFB-UV-34 through 35 with larger operators.
This DCP was reviewed for appropriate consideration of increased actuator weight and eccentricity of the actuator from the valve body centerline.
The DCP included calculations which evaluated changes
'to valve fundamental frequency, valve and operator acceleration, seismic stresses, gravity stresses and increased loading on adjacent supports.
Accelerations, stresses, and loads on the subject valves and adjacent components.
were demonstrated to remain within allowables.
Unit 2 Auxiliary Feedwater System (AFS)
Pump P01 Calibration and Testing of 'the pressure loop instrumentation on the Pump B discharge line (Mork Order No.
00459964)
Calibration and testing of the pressure loop instrumentation on the AFS pump 8 discharge l)ne was observed.
The purpose of this pressure loop instrumentation is to provide indication to the control room of AFS pump B discharge pressure.
Calibration and testing were performed in accordance with the procedures.
Unit 3 Essential Cooling Mater (ECM)
Pump A Operability Test The operability test for Unit 3 Essential Cooling Mater Pump A was observed.
This test is required to be performed in accordance with procedure No.
Part of the test was performed by a control room reactor operator while other parts of the test were performed by a-nuclear operator and an electrician stationed locally at the pump.
Communication between personnel at the two locations was maintained over the duration of the test.
Step 3.2.4 of the test procedure requires monitoring by the control room r'eactor operator of pump flow and motor current.
Flow and current are to be verified at the control room to be within certain values before proceeding to the next step.
Only pump flow deviation requires action by the nuclear operator.
The inspector noted that the nuclear operator received verification of the pump flow from the control room operator.
The control room operator also verified motor current to be within the acceptable range, but this was not directly communicated to the nuclear operator.
Although verification of acceptable motor current was implied by the communication to proceed to the ne'xt step, it was suggested that future tests of this type require that both parties acknowledge each required verification prior to proceeding to the next step.
It was noted that insufficient pump flow would have required manipulation of the associated throttle valve (valve EWA-HCV-053) to adiust pump flow within the acceptable range for testing.
Valve EWA-HCV-053 is located in a different room from that in which Essential Cooling Water Pump A is located.
At the time of testing valve EWA-HCV-053 was located in a high radiation area.
It was noted that future tests, which could potentially require entrance into locations other than that of-the main, test; should take proper precautions to make necessary preparat'ions for entry into any areas which could be required by contingent actions contained in the procedure.
The inspector verified that at the pump location, pump operability tests were conducted in accordance with procedures.
V'ibration readings were taken at permanently marked locations on the pump in order to maintain consistency o'f measurement points between tests.
It was noted that section 6. 1 of procedure No, 43ST-3EM02 states that two maintenance personnel/electricians are required for vibration readings in accordance with procedure no.
Procedure no.
32HT-9ZZ66 requires only one maintenance person/electrician for vibration readings.
The discrepancy in
procedures was pointed out to the licensee.
The licensee issued PVNGS Instruction Change Request no.
49406 on February 22; 1991 to change procedure no.
43ST-3EW02 to reflect the requirement for one maintenance person/technician for vibration reading. Unit 2 High Pressure Safety Injection (HPSI)
Pump B Operability, Test The operability test for Unit 2 HPSI pump 8 was observed.
This test is required to be performed quarterly in accordance with procedure no. '2ST-2S 110.
During the prestart checking, flow gauge SI-FE-304 was.found to be failed low.
Steps were taken in the control room to acknowledge failed flow gauge SI-FE-304 and to make the necessary log recordings, so that the gauge could be repaired.
Per the procedures, operable flow gauge SI-FI-300 (per procedure, the preferred gauge for flow reading)
was used to verify and record the flow in thss miniflow operating mode.
The verified flow of 154 GPM exceeded the 110 GPM minimum requirement of procedure 42 ST-2SI10 and the minimum flow recirculation of 85 GPM recommended by the manufacturer, Ingersoll-Rand.
It was noted that measurements of pump head, vibration, and visual inspection for pump leakage were consistent with the recommendations of Ingersoll-Rand.
As with procedure no.
43ST-3EW02, procedure no.
42ST-2SI10 was shown to be inconsistent with procedure no.
32MT-9ZZ66 in that the 42ST procedure requires two maintenance/electricians for vibrations testing; whereas procedure no.
32 MT-9ZZ66 requires only one maintenance person/electrician for vibration testing.
PVNGS Instruction Change Request No, 49406 has been issued to correct the discrepancy in procedure no.
42ST-2SI10 and to make sure that other-simi lar ST procedures are corrected if required.
Fifty-four ST procedures were identified as having similar requirements for vibration testing.
No violations or deviations were identified in the areas reviewed.
4.
Snubber Functional Testin and Failure Evaluations The inspector reviewed the licensee's root cause fai lure evaluation of failed snubber 1-CH-020-H-OAB.
The evaluation methodology and conclusions appeared reasonable.
The inspector also reviewed the portion of Calculation no.
13-MC-22-604, which evaluated the effect of failed snubber 1-CH-020-H-OAB on the Unit 1 Reactor Coolant Pump Seal Injection line.
The subject snubber had failed the drag test, and, per procedure, was replaced with a functional snubber of the same size.
The drag test had been. terminated when the snubber failed to move after application of more than 50K of the rated snubber load capacity.
Consequently the snubber was modelled in the analysis as a rigid restraint.
Initial review of the calculation r aised two concerns, which the inspector conveyed to the licensee:
1)
the system forces, moments, and stresses appeared low for the condition with the locked snubber 2)
the maximum line temperature used in the analysis appeared low given the system configuration Regarding the first concern, subsequent review by the licensee found that the initial thermal anchor displacements at the connection to the Reactor Coolant Pump (RCP)
had been improperly modelled and as a result excluded from the analysis.
Most significantly, this resulted. in the omission of approximately 1 3/4 inches of horizontal movement which would have been restrained at the snubber location.
The original analysis for the failed snubber had been-performed by Sargent and Lundy Engineers (SLL).
SKL's review of the problem found that "...the pump thermal movements at the piping connection..
~ " (to the RCP)"..,.were incorrectly specified at the first node upstream of the nozzle, rather than at the nozzle/anchor point.'-'eanalysis by S8 L with the thermal movements at the nozzle/anchor point included yielded a large increase in thermal loads and stresses but all parameters were demonstrated to remain within allowable acceptance criteria.
In terms of design margin, the most critically affected component was the pump nozzle where loads acting on the nozzle were calculated to be 100%%u'f the allowable interaction equation imposed by the pump vendor.
The results of the revised/corrected evaluation of the effects of locked snubber 1-CH-020-H-OAB appeared reasonable.
The licensee has reviewed and approved the revised/corrected calculation.
A root cause evaluation of the above error was also performed by SEL; 50X of the snubber evaluations (21 of 42) done by S8L were reviewed for similar errors.
Included in the sample were all calculations per formed by the individuals involved in Calculation no.
13-MC-ZZ-604.
SEL found the subject error to be unique.
Calculation no.
13-MC-ZZ-604 modelled the additional 14 inches of pipe between the flanged connection at the.
pipe/pump interface and.the RCP shell in order to take advantage of the extra flexibility.
The analysis, however, failed to change the displacement input data point from the original flanked connection to the new anchor point at the RCP; hence the stress analysss program ignored the thermal displacements, since they were no longer imposed at a restraint point.
S5L's review showed that thermal anchor displacements had been correctly applied to the equipment nozzles-in the calculations involving the other 20 snubbers.
SEL concluded that the error in Calculation No.
13-MC-ZZ-604 was unique.
The findings and conclusions of the SEL root cause evaluation appeared reasonable given that line geometry would rarely be changed from that of the "as-built" analysis when analyzing for a failed snubber and that a reasonable sample including a similar seal injection line connected to the RCP had been reviewed and shown to have equipment nozzle thermal displacements correctly input.
Regarding the issue on maximum line temperature, the inspector was concerned that potential temperature excursions from maximum normal operating temperatures had not been c'onsidered and that the problem could
be generic to other lines.
The maximum analyzed -temperature for the Seal Injection line adjacent to the RCP was 125'F.
Upstream of the analyzed line is valve UV-231 which is set to close on a high temperature signal and a low temperature signal.
The setpoint for the high temperature, isolation is 148'F.
Subsequent review with the licensee showed that Combustion Engineering (CE) had performed an evaluation to predict system responses for'arious temperature excursions (the title of the pertinent CE report is "Compilation of NSSS Responses to Design Bases Dynamic Events for the System 80 Standard Design.").
The CE report shows that the subject piping is in "group 7" of the Seal Injection System and that the maximum temperature for group 7 will not exceed 125'F.
The 148'F high temperature setpoint for valve UV 231 was intended to prevent excessive temperature in the Seal Injection line which, could occur when too much Auxiliary Steam is injected into the line.
At PVNGS the Auxiliary Steam is now isolated from this line.
The inspector concluded that 125 F appears to be the maximum temperature for this line for normal and upset modes of operations.
The inspector noted that the PVNGS UFSAR excludes emergency and faulted conditions from consideration in the evaluation of ASME III piping secondary stresses.
. APS engineers pointed out that PVNGS does not have a centralized system of calculations for line maximum operating temperatures; however-, current procedures for line additions and modifications include a requirement to document the verification of maximum operating temperatures and pressures.
Although no specific concerns on maximum operating line temperatures were identified, future inspections of piping stress analysis calculations will remain sensitive to this issue.
No violations or deviations were identified in the areas reviewed.
5.
Miscellaneous Observations A.
Unit ¹1 Main Steam Isolation Valve (MSIV) UV-170 Potential Interference.
A flexible electrical cable which provided current to the MSIV UV-170 operator was observed to have a clearance of only 1/2 inch between it, the valve yoke, and the cutout in the adjacent metal grating.
The valve was in its cold position at the time of observation.
Review of pipe stress calculation 13-MC-SG-509, problem no.
SG-509A which listed thermal and seismic/dynamic displacements for MSIV UV-170 showed that the 4 inch gap was sufficient.
No violations or deviations were identified in the areas reviewe.
Ins ection of Previousl Identified Follow-u Items (92701)
A.
B.
(Closed)
Unresolved Item No. 50-528/89-02-02 uglification of
) re ro ec i on a
o er orm as n enance.
The subject unresolved item,identified a concern that due to'lack of experience and training the PVNGS fire protection staff was not properly qualified to perform certain tasks.
One such task was calibration testing of instruments used for fire protection systems.
During this inspection the licensee identified an October 17, 1990 Letter (ID ¹240-00854-HFB/CB) that identified fire protection procedures which had been revised to delete all I 8 C tasks assigned to the Fire Protection Staff, as of June ll, 1990.
- The I8C tasks formerly performed by the Fire Department Staff, have been assigned to the I8C department.
The inspector performed a sample review of applicable licensee procedures and veri.fied the reassignment of ILC tasks.
Since the Fire Department staff is no longer directly involved in the performance of 18C maintenance activities for the fire protection systems, it appears the licensee has initiated actions to address this concern.
The training and qualification deficiencies identified in this area in equality Assurance Investigation Report No.87-072, were addressed in Corrective Action Report (CAR) No. C(87-0099.
Maintenance activities performed on fire protection systems will be the subject of future NRC inspections.
This item is closed.
(Closed)
50-55 Re ort Item No. 50-528/89-12-01 EE-580 S stem a
a ase ra e
ro ram.
The EE-580 system data base was a computer program designed to maintain up-to-date records of cable routing and cable termination for each unit.
This system was designed to provide field construction, maintenance operation, and engineering organizations with timely and accurate information concerning raceway, cable routing and termination identification.
In 1985 problems with the accuracy of this configuration database system were identified, and the licensee reviewed this concern and contracted with Bechtel in December 1987, to verify the installation configuration of the EE-580 circuit and raceway tracking system for Units 1, 2, and 3.
The Bechtel verification program resulted in a total of approximately 106,000 EE-580.installation cards being reviewed.
As of May 1988 a total of 6184 items were not found and required further action.
Of the 6184 cards, 5136 cards were Class 1E installation cards which were associated with safety systems.
To resolve the concerns with these remaining 6184 cards the licensee identified that they would perform further engineering evaluations and field walkdowns, as necessar A January 31, 1991 licensee letter (IO¹282-00294-JTB/MAK) identified that per the latest (January 1991) review of questionable EE-580 installation cards',
there were:
Approximately 691 cards remaining that were initiated prior to January 1987, that still required review and resolution.
Approximately 1524 cards issued after January 1987, the verification program cut-off date, that would be reviewed/returned in the normal process of closeout of work.
Based on the information identified above and in other documents, it appears the cognizant organizations have addressed this item satisfactorily,,
and have taken actions to resolve this concern.
This item is closed.
C.
(Closed)
Followu Item No.50-529/89-09-02 Inservice Testin licensee roce ures o
o en s
en orrec
>ve c lons ou e n>>a e.
The original inspection identified the following:
The licensee Inservice Testing (IST) and/or system engineer procedures did not appear to clearly identify what licensee corrective actions were to be performed once the trended IST performance parameters indicated licensee corrective action was required.
Also, these same procedures did not identify when corrective actions should be initiated.
The licensee Engineering Oepartment evaluation procedures did
'ot identify that a documented engineering review was required, when the operational readiness of ASME code pumps and valves was questioned by a required increase in the frequency of IST surveillance testing.
Ouring this inspection the licensee identified that applicable procedures had been revised to address these concerns.
As an example of a revised procedure, the licensee identified Sections 3.1.1.6, 3.1.2.3, 3.2.6.3 and 3.3.2.3 of procedure 73 AC-ON102, Revision No. 2, Procedure Change Notice (PCN)
No. 03, "Inservice Testing of Safety Related Pumps and Valves."
Based on review of the above document, other licensee documents and interviews with licensee personnel, it appears the licensee has initiated actions to address these concerns.
This item is close D.
(Closed)
Followu Item 50-.528/89-41-01 Sam lin -Lines for so ine ic
>r am ers The Palo Verde FSAR commits to using ANSI N13.1-.1969, ANSI N13. 1-1969, Appendix B, Particle Deposition in Sample Liners, Section B5 Deposition 1n Elbows in Sample Delivery Lines states:
"Elbows in sampling lines should be avoided if at all possible, but when they are required, the bend radius of the elbow should be as long as practical..."
Contrary to this recommendation, during a previous inspection it was noted that two 90-degree elbows were installed in the sampling line for the Unit 3 non-ESF Radwaste Building Ventilation Exhaust Filter Inlet Monitor 3-J-SQN-RU-014 and for the Unit 3 Post-Accident Plant Vent Low Range Monitor 3-J-SQN-RU-143.
Subsequent APS review and walkdown of all the radiation monitoring system particulate monitoring sample lines identified several lines with elbows.
However, PVNGS piping specification 13-PN-205 does allow the substitution of fittings for bends in cases where the substitution is not within two bends of the equipment attachment.
Accounting for this provision,- only one of the radiation sampling lines identified by APS review and walkdown, sampling line 2-'J-SQB-RU-001, was not in accordance with specification 13-PN-205.
Material nonconformance reports (MNCR's)'ere initiated for 3-J-SQN-RU-014 and 3-J-SQN-RU-143 (identified in NRC followup item 50-528/89-41-01)
as well as 2-J-SQB-RU-001 (identified in the APS review).
The three MNCR's were dispositioned as follows:
Line No.
3-J-SQN-RU-143 3-J-SQN-RU-014 NIICR tl
.
~Di gati 89-SQ-0003
. Rework~
89-SQ-0004 Rework*
Status Work Order 00427497 Prefab complete.
WO to be completed during next refueling outage no later than June 91.
Work Order 00427496 Complete 2-J-SQB-RU-001 89-SQ-0005 Use-as-is The "rework" is to replace the elbows with 5D bends as recommended in ANSI N13. 1-1969.
Completion of the "rework" will return the line to a configuration acceptable within piping specification 13-PN-205.
The disposition of the MNCR's for radiation sampling lines 3-J-SQN-RU-143 and 3-J-SQN-RU-014 appeared reasonable, since replacing the elbows with 5D bends would satisfy the recommendations of ANSI N13. 1-1969 and return these lines to the configuration as
shown on drawings 13-P-ARF-402, Rev.
13.
and 13-P-HRF-601, Rev.
12, respectively.
The inspector performed a walkdown of line 3-J-SQN-RU-014 (completed WO ¹00427496)
and verified that the elbows had been replaced by 5D bends.
A random walkdown of other radiation sampling lines did not identify any other sampling lines with elbows other than those already identified by the licensee.
It was noted that APS had committed to complete WO ¹ 00427497 for line 3-J-SQN-RU-143 no later than the end of June 91.
The "Use-as-is" disposition of line 2-J-SQB-RU-001 represented a
deviation from the configuration shown on drawing 13-P-HAF-201, Rev.
10; hence this change in the facility necessitated
CFR 50.59 evaluation.
The 10 CFR 50. 59 evaluation for this line was reviewed.
'he evaluation and required response justifications appeared reasonable.
Details of the. inspector s review of the
'Use-as-is"
.
disposition of MNCR 89-SQ-0005 for line 2-J-SQB-RU-001 follow.
2-J-SgB-RU-001 is used to continuously monitor the Unit 2 containment building atmosphere for particulate, iodine, and gaseous activity, The particulate and gaseous channels serve as two methods of Reactor Coolant Pump B leak detection in accordance with Regulatory Guide (RG) 1.45, however, the PVNGS UFSAR takes exception to position C.5 of RG 1.45 which requires capability to detect leak rates of 1 GPM.
The UFSAR states that the "...airborne particulate and gaseous monitoring methods are capable of identifying leakage conditions, but are not used for quantifying that leakage,"
The PVNGS "as-ss" configuration of line 2-J-SQB-RU-001 is capable of identifying leakage conditions; hence it fulfills its UFSAR commitments.
It was also noted that once the indication alarm activates, procedures are available that instruct operators to perform steps which will help to quantify leakage rate (refer to UFSAR sections 1.8 and 5.2).
Based on the preceding findings, the
'use-as-is'isposition for line 2-J-SQB-RU-001 appears reasonable.
Based on the results of this review and the commitment to complete WO ¹ 00427497 to replace the elbows on line-3-J-SQN-RU-143 with 5D bends by the end of June 91, this followup item is closed.
E.
(OPEN) Follow-u Information Notice No. 90-26 Potential Inade uate ow a es o
ssen
>a
>
e a er o
n >neere a
e
- ea ure an in ns s
s NRC Information Notice No.
90-26 "Inadequate Flow of Essential Service Water to Room Coolers and Heat Exchanqers for Engineered Safety-Features Systems" identified that Amencan Air Filter (AAF)
had supplied incorrect pressure drop data to Clinton Power Station.
Except for the control room AHU's supplied by AEROFIN, AAF supplied the ESF AHU's to all of the three PVNGS units.
APS requested AAF, by letter, to confirm that the pressure drops originally supplied by AAF, and used to balance the chilled water
flow to the ESF AHU's were correct.
AAF responded, by, letter, that ressure drop data had been based on AHU's without cleanout plugs.
he AHU's supplied for PVNGS had cleanout plugs.
Consequently the pressure-drop data used to determine flows was incorrect and could result in water flow rates from 64K to 98% of design.
On 2/7/91, PVNGS ISSUED MNCR 91-EC-A002 which stated that in light of the incorrect pressure drop data used by APS to balance the flow to the individual AHU's, "Assurance that the ESF air handling units will perform their intended function during accident conditions is therefore indeterminate..."
A summary of the status of this issue as of 2/27/91 follows:
FLOM MEASUREMENT APS has completed measurement of "as found" flow rates for each of the 54 individual AHU s at Palo Verde (3 units, each with 2 trains per unit and 9 individual AHU's per train).
Measured flow rates for 10 of the 54 AHU's were found to be less than the values specified in the UFSAR.
ENGINEERING CALCULATIONS
'PS performed calculations to determine minimum flow requirements for the AHU s.
Minimum flow requirements were derived by taking the original design calculations and removing room heat load margins added by Bechtel to the calculated room heat loads.
It was noted that the original margins appeared to have been arbitrarily assigned
- i.e. there was no apparent consistency between calculations.
Flow acceptance criteria was than established by adding a 5X margin to the calculated minimum flows to account for measurement errors from the acoustic flow monitoring test instrumentation.
MEASUREMENT FINDINGS Of the 10 measured AHU flow rates found to be less than the values specified in the UFSAR, 9 were found to exceed the minimum flow acceptance criteria.
-The Unit 3 LPSI Train A AHU was unable to pass 'the established flow acceptance criteria.
ASSESSMENTS OF COOLER CAPABILITY Detailed analyses based on Sargent and Lundy heat balance methodologies were performed for each of the 10 AHU's with flow rates less than UFSAR values.
Based on the observed flow rates to the AHU's and accounting for room dimensions and heat input, calculations for each of the 10 AHU's demonstrated that maximum room temperatures would not exceed UFSAR values.
The question of AHU performance was addressed.
AAF has performance data for individual coil assemblies.
AAF's test program to
f
establish performance r'atings was approved by the NRC (reference Topical Report AAF-TR-7701A dated 2/20/72).
The coil assemblies were tested at containment design conditions which exceeded the maximum ambient conditions which would be experienced by the Palo Verde cooling coils.
AHU's are an assemblage of individual cooling coils and fan units.
Performance test figures are unavailable.for the, AHU packages'.
However, Sargent and Lundy has developed (through*an independent contractor)
a program to calculate heat transfer performance of AHU assemblies made up of multiple heat transfer components.
This program was used to predict heat transfer performance for the various types of AHU's used at Palo Verde.
Performance data obtained from these independent verifications showed good correlation to the manufacturer's performance ratings with the maximum difference between AAF and Sargent Lundy values deviating by no more than U.
FUTURE PLANS Palo Verde's future plans for this issue will concentrate on establishing flow balances on each train.
Palo Verde has obtained the 9 additional flow transducer instruments required to make concurrent flow measurements on each of the 9 individual AHU's in
.
each train.
The flow instruments have been sent for calibration.
The duration for completing the calibrations is estimated at 1 month.
Flow balance measurements on each of the 6 trains 'is anticipated to take about 1 week per train.
An additional month has been included in the schedule to allow for contingencies; so the estimated completion date for this phase is June 15, 1991.
Palo Verde plans to prioritize the flow measurements to first address the trains where flows appear to be marginal (e.g.
Unit 3, train A with the LPSI room AHU with b'e tested first).
The PVNGS Incident Investigation Report on this problem is not yet complete.
The completed report will be provided for NRC review.
NRC plans to review this Incident Investigations Report and to further monitor the APS methodology and actions towards resolution of this issue.
(Followup Item No. 50-528/91-05-03)
7.
(OPEN) Ins ection of Licensee Activities in Reference to NRC Bulletin
-
o en sa a
e
-
. e a
e um oss In determining the adequacy of the APS response to NRC Bulletin No.
88-04:
"Potential Safety-Related Pump Loss," the inspector witnessed the ASME Section XI pump testi ng of Unit ¹2 High Pressure Safety Injection Pump B during minimum recirculation flow conditions, reviewed the test results, interviewed APS engineers involved with the NRC Bulletin No.
88-04 response and reviewed applicable document A.
Existence of a Common Header Existence of a common headei for the licensee's safety related pumps was documented in earlier APS responses to NRC Bulletin 88-04 and confirmed in NRC inspection report 90-38.
Both trains on all three units are affected for the following pump arrangements:
A common header exists on both the suction and discharge side of the High Pressure Safety Injection Pumps, Low Pressure Safety Ingection Pumps, and Containment Spray Pumps (referred to as Safety Injection System)
A common header exists on the discharge side of the Auxiliary Feedwater Pumps and Condensate Transfer Pumps.
B.
Evaluation of the Common Header S stems (1)
Safety-Injection System (SIS)
Calculation 13-MC-SI-307 documents the evaluation of the Safety Injection System pump interaction.
"Weak" and "strong" pump flows were measured by testing all three pumps of each train in parallel in the miniflow mode.
It was noted that, although both A and B pump trains were tied together by a common header on the suction and discharge side, all six pumps were not.run at once (A and B trains each have three pumps).
However, the evaluation computed the additional flow resistance resulting from six-pump flow in parallel using the SIS pump with the lowest ("weakest") tested miniflow rate (the LPSI pump) and calculating the flow resistance by doubling the highest ("strongest")
recorded miniflows with three pumps running.
In accordance with the requirements of NRC Bulletin 88-04, the evaluation accounted for the effect of test instrument error and reading error as well as ASME,Section XI, Paragraph IWP-3100 allowances for deviation of pump test parameters.
The evaluations concluded that the available head loss margin of the "weakest" pump was more than adequate to compensate for the additional head loss from operating all six pumps in parallel.
The calculated miniflow through the "weakest" pump orifice of 120 GPM was greater than the 100 GPM minimum required by the pump manufacturer.
Separate studies were performed by APS to compare the differences between the "-as-built 'ipe configurations for the Safety Injection System piping versus the "as-designed" configuration used in calculation 13-MC-SI-307.
The APS
. studies concluded that the. differences between "as-built" and
"as-designed" configuration were negligible for the subject Safety Injection pipin e
The evaluation of the SIS pump interaction appeared to provide reasonable assurance that dead-heading of the "weak" pumps would not occur under any of the poss)ble minimum flow operating conditions.
(2)
Auxiliary Feedwater (AF) and Condensate Transfer (CT) Pumps Auxiliary Feedwater and Condensate Transfer Pumps Calculation 13-MC-CT-303 documents the evaluation of the AF, and CT pump interaction in the miniflow mode.
Measured flow for the AF pumps during miniflow conditions varied from 240 GPM to 260 GPM.
Minimum flow rates through the CT pumps were approximately
GPM.
Given that the AF pumps were clearly the
"strong" pumps (design head of 3280 feet at rated flow) and the CT pumps were clearly the "weak" pumps, (design head of 61 feet at rated flow), the use of actual test data for the CT,pumps was not verified by the inspector, because any deviation of flow rate within the acceptable test band would not have any significant affect on the calculation of head loss when both the AF and CT pumps were operating in the miniflow mode.
The evaluation calculated the piping friction losses due to the miniflow from both the AF and CT pumps operating in parallel.
260, GPM and 30 GPM were used for the AF and CT pumps respectively.
Ninimum CT pump suction head was assumed.
As directed by NRC Bulletin 88-04, pump degradation taken as the worst case deviation allowance from ASNE Section XI, Paragraph IMP-3100.
CT pump mi niflow under these conditions was calculated as 26.3 GPM.
The licensee performed a separate study to determine if any differences existed between the "as-designed".pipe configuration as used in calculation 13-MC-CT-303 and the
"as-built" pipe configuration which might yield the calculation unconservative.
The comparison study of "as designed" versus
"as-built" pipe configuration concluded that no significant difference existed.
However, the licensee, identified minor errors in the determination of piping friction losses, and the inspector identified that the effect of test instrument error and reading error as required in action item 2c of HRC Bulletin 88-04 had been omitted in the calculation.
The net effect of the errors and omissions were small and would account for a small reduction in calculated CT pump miniflow.
However, in 1-ight of the fact that the calculated CT pump miniflow of 26.3 GPM was less than the manufacturer's miniflow recommendations of 30 GPM, the responsible engineers committed to revising the calculation and submitting the revised calculated CT pump miniflow to Ingersoll Rand for their concurrence.
The licensee committed to transmit, by letter, the results of the vendor correspondence on this matter by mid-
C.
Pum ow May of this year.
This commitment will be reviewed 'in a later inspection (Fol 1owup Item No. 50-528/91-05-04).
Vendor Information Recommendations and Bases for Minimum a acl res n er on
)
sons o
x en e
era ion Safety Injection System All of the SIS pumps are manufactured by Ingersoll Rand, (IR).
Correspondence from Ingersoll Rand recommends specified minimum flow rates for each of the pumps as follows:
Pum Service LPSI CS HPSI S ecified Minimum Flow (GPM)
100 150
According to IR and Duramettalic, the manufacturer of the pump mechanical seals pump useful life is limited primarily by the mechanical seal )ife.
Mechanical seal life is affected by vibration and high temperatures with high pressures.
The HPSI pumps do not operate at high temperatures.
The LPSI pumps are the only SI pumps that experience high temperatures under normal operating conditions.
These conditions would occur in the shutdown cooling mode after full power operations.
PVNGS administrative procedures limit these conditions. 'ccording to APS, Duramettallic figures that the exposure of the LPSI pumps to high temperatures consumes about 4X of seal life.
IR s limitations on time at minimum flow are, according to the'anufacturer,
"... conservatively based on empirical data of vibration at low flow rates correlated to force and shaft deflection...", which affect mechanical seal life.
Mechanical seal life is determined by an equation which factors number of starts/stops, pump run time between specified minimum flow and minimum continuous stable flow (MCSF, a flow value given by IR)
and pump run time'above MCSF.
According to IR, pump operations which remain within the limits of the equation acceptance criteria are recommended in order to maintain mechanical seal life; hence pump useful life.
As discussed in the following section on "Modifications to Plant Operating Procedures or Hardware," maintenance schedules for SIS pumps have been modified to require periodic replacement of pump mechanical seals.
The schedule for replacement of pump mechanical seals was developed to allow ample margin to ensure that pump operations would remain within the vendor's recommended acceptance criteria.
In previous correspondence with the NRC, APS has committed to maintain the pump vendor information discussed in this report for a minimum of two year P Auxiliary Feedwater (AF) and Condensate Transfer (CT) Pumps The Auxiliary Feedwater pumps are manufactured by Sulzer Bingham Pumps Inc. (SBPI).
Correspondence from SBPI to APS recommended that minimum flow for short term pump operation (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or less in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />)
be no less. than 165 GPM and that minimum flow for pump operations in excess of two hours be at least 240 GPM.
. The pump vendor indicated that these flow rates were "...in accordance with SBPI's latest design standards and will not cause excessive internal wear to the pumps from over heating or hydraulic instability.
The inspector noted that measured flow for the AF pumps during miniflow conditions varied from 240 GPM to 260 GPM.
The CT pumps are manufactured by IR.
Minimum flow rate (30 GPM) and data for performance under conditions of extended operation were provided with the same vendor correspondence that transmitted the miniflow performance requirements for the SI pumps.
Relative to the CT pumps, the equation for estimating pump useful life under conditions of extended operation was ambiguous.
IR stated that the equation was based on the life of the pump mechanical seals yet the
.CT pumps were equipped with packing glands instead of mechanical seals.
The inspector recommended that APS request IR to clarify the ambiguities.
APS Engineering Evaluation Report EER ¹89-CT-004 addressed the miniflow through the CT pumps.
Archived work orders were reviewed.
No significant problems involving packing glands were found., APS further noted that operation of the CT pumps during minimum flow conditions was limited to short periods of.
.time.
Also, the maximum horsepower requirements at full flow were under four horsepower.
APS noted that the examples of pump damage referenced in Information Notice'9-08 involved only high energy pumps.
Based, in part on the evidence above, APS concluded that the CT pumps were unlikely to experience low flow damage for the minimum flows expected for the CT pumps.
However, based, in part, on the lack of clear guidance from the pump manufacturer, APS felt that the most "...effective detection of low flow damage to the internal of the pumps is from pump disassembly and inspections..."
APS has disassembled and inspected a Unit 1 CT pump and is currently evaluating the inspection data, According to APS, Unit 1 CT pumps have been in service for eight years and have experienced considerable testing (especially during plant star tup) in the minimum flow mode.
APS felt that the information obtained from inspection of the Unit 1 CT pumps will provide the information needed to establish the basis for determininq future preventative maintenance activities and inspection frequencies for the CT pumps.
It was suggested that when Ingersoll Rand is contacted regarding the potential fo'r CT pump miniflow at less than
GPM, that further clarification be requested on the issue of acceptable pump operating time during miniflow conditions for the CT pumps.
The licensee's current plans for investigating performance of the CT pump during mi niflow conditions and for determining
'reventative maintenance/inspection frequencies appear to be appropriate for the current conditions.
However, it is expected that further action by the licensee in this matter, wH 1 consider any future responses by Ingersoll Rand relative to the issues discussed in this.section.
Furthermore, in considering pump maintenance/inspection frequencies, such activities should take account of any risks associated with placing the pump out of service versus the risk of degraded or inoperable pump operations from less frequent maintenance/inspection activities--i.e.
there should be evidence that the licensee's PRA (Probabalistic Risk Assessment)
group has been involved in the decisions on maintenance/inspection activities.
The inspector plans on reviewing the licensee's assessment of the Condensate Transfer pump operability under conditions of extended operation in the miniflow mode after more information such as vendor clarifications on CT pump useful life and evaluation of the disassembled CT pumps become available.
(Followup Item no. 50-528/91-05-05).
D.
Modification to Plant Operating Procedures or Hardware At the time of the inspection the licensee's evaluations of the pump operations during the miniflow mode had concluded that the
"as-designed" piping configuration for the pump systems had sufficient margin to preclude dead heading of the pumps on the miniflow mode.
The licensee concluded that based on the calculational data, previous operating experience, and surveillance test data which showed no evidence of excessive pump wear, hardware modifications were unnecessary.
Previous correspondence from the licensee committed to routine maintenance and testing of the affected pumps as recommended by the vendors "...until a trending system can be developed..."
The inspector noted that a trending system had not been developed.
However, for the Ingersoll Rand Safety Injection system pumps, the licensee developed seal replacement schedules based on detailed review of pump operating and maintenance histories and consideration of the vendor recommended seal life equation.
LPSI pump mechanical seals will be changed out every other outage, and HPSI and CS pump mechanical seals we'll be changed out every third outage.
Based on the mechanical seal replacement schedules and quarterly survei llances to measure pump performance the licensee contended that no further trending would be require e
After examining the above program for the SI pumps and witnessing the surveillance testing on Unit 2 HPSI pump 8, the inspector concluded that the current program was acceptable in lieu of trending.
Some of the important points leading to this decision follow:
The licensee demonstrated effective use of. plant operating records, surveillance records, and vendor pump performance data in establishing a proactive schedule for replacing pump mechanical seals.
The pump mechanical seals'had been identified by the pump vendor and mechanical seal manufacturer as the critical components affecting pump useful. life.
A major contributor to, and indicator of, pump degraded performance is pump vibration.
Pump vibration is monitored quarterly on a consistent basis (refer to sections 3D of this report).
There are a small number of SI pumps, 18 for all three units; hence, performance monitoring data is manageable without a computer trending data base.
The group of engineers responsible for SI pump performance is small with a central manager; hence, transfer and retention of.
pump performance data within the group should be simple and uncomplicated.
The licensee committed to documenting this change from their earlier trending commitments in a letter to the NRC to be issued by mid May of this year.
The review of this letter as well as maintenance and operating procedures for the Auxiliary Feedwater and Condensate Transfer pumps will be covered in a future inspection.
.(Followup Item no. 50-528/91-05-06).
No violations or deviations were identified in the areas reviewed.
S.
~Eit H ti The inspectors met with the licensee management representatives denoted in paragraph 1,
on February 22, 1991.
The scope of the inspection and the inspector's findings up to the time of the meeting were discussed.
At this meeting the inspectors identified that additional information would be reviewed in order to complete the inspection.
Additional dialog with the licensee and receipt of pertinent documents necessary to complete the inspection were concluded on April 26, 1991.