IR 05000311/2004028
| ML17299A332 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde, Salem  |
| Issue date: | 05/15/1985 |
| From: | Bosted C, Fiorelli G, Miller L, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17299A330 | List: |
| References | |
| 50-528-85-08, 50-528-85-8, 50-529-85-09, 50-529-85-9, NUDOCS 8506060722 | |
| Download: ML17299A332 (42) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
50-528/85-08, 50-529/85-09 50-528, 50-529
'icense Nos: NPF-34; CPPR-142 Licensee:
Arizona Nuclear Power Project P.
O.
Box 52034 Phoenix, AZ. 85072-2034 Ins ection Conducted:
March Inspectors:
85 -
April 28, 1985 R.
Resid erman, Se 'or t Insp c or Date Signed Approved By:
G. F orelli Resi t Ip p c r C.
osted, Res nt In ct L. Miller, Ch Reactor Proje t Section
Date Signed C-'(CHs Date Signed
"Is=IF'ate Signed Summary:
Ins ection on March ll 1985 - A ril 28 l985 (Re ort Nos. 50-528/85-08 and 50-529/85-09 Areas Ins ected:
Routine, onsite, regular and backshift inspection by the resident inspectors (Unit 1 - 399 hours0.00462 days <br />0.111 hours <br />6.597222e-4 weeks <br />1.518195e-4 months <br />; Unit 2 - 151 hours0.00175 days <br />0.0419 hours <br />2.496693e-4 weeks <br />5.74555e-5 months <br />).
Areas inspected included:
review of plant activities, surveillance testing, plant maintenance, preoperational testing activities, allegation followup, Unit 1 license commitment followup, Engineered Safety Features (ESF) configurations, Licensee Event Reports, followup of previously identified items, periodic and special reports and plant tours.
Results:
Of the eleven areas inspected, three violations at Unit,l were identified in three areas.
(Failure to maintain the control room essential ventilation system operable - paragraph 3.c; failure to complete the necessary surveillance testing prior to declaring a
component operable paragraph 4.c; and, failure to take adequate corrective action for a condition adverse to quality - paragraph 6).
8506060722 850516 PDR
- DOCK 05000528
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DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro ect (ANPP)
R.
O'J, L.
J.
W.
R.
p,
"CW.
AD R.
D.
-R.
J.
C.
T.
L.
"E
"-R.
J O Adney, Allen, Auterino, R.
Bynum, Donahue, Fernow, Gouge, Hicks, E. Ide, B. Karner, Heyer Nelson, Nelson, Pollard, Russo, Shriver, Souza, E. Van Brunt, Younger, Zeringue, Operations Superintendent, Unit 2 Operations Manager Nuclear Steam Supply System Test Supervisor, Unit-2 PVNGS Plant Manager Shift Test Director Supervisor Plant Services Manager Operations Supervisor, Unit 1 Training Manager Corporate Quality Assurance Manager Assistant Vice President, Nuclear Production Pire Protection Supervisor Operations Security Hanager Maintenance Manager Operations Supervisor, Unit 2 Quality Audits Manager Quality Systems and Engineering Manager Assistant Quality Assurance Manager Jr.,
Executive Vice President Operations Superintendent, Unit 1 Technical Support Hanager The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
"-Attended the Exit Meeting on April 16, 1985 Followu of Previousl Identified Items (Closed)
83-41-03 (Inspector Followup Item): Licensed Operator Training on the Radiation Monitoring System and Procedure.
The licensee committed to complete training of the Unit 1 licensed operators on the radiation monitor system and radiation monitoring procedure 41AC-1SQ01 "Radiation Monitoring,Alarm Responses".
The inspector verified by reviewing training records that all the licensed shift superviors, assistant shift supervisors, nuclear operators, and shift technical advisors for Unit 1 had completed the training on the above radiation monitoring procedure and had received
"hands on" training on the Unit 1 radiation monitoring system by February 1,
1985.
This item is close I
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3.
Review of Plant Activities a
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During most of the inspection period, Unit 1 remained in Mode 5 while work continued on licensee commitments that were required; to be completed prior to Mode 4 entry.
Unit 1 entered Node
on April 21,'1985 in preparation for post core hot. functional testing.
Unit 2 continued preoperational tests in preparation for the Hot Functional Test which has been rescheduled for June, 1985.
b.
An Unusual Event. was declared on April 23, 1985 when a Unit 2 main generator output breaker exploded and caught Sire following initial testing of the breaker.
Plant fire protection equipment was dispatched and the fire was extinguished.
Damage was isolated to the affected breaker and to the control cables for several, other breakers in the switch yard.
The incident did not affect the off site electrical distribution to either Units 1 or 2, and equipment realignments were not necessary as a result of the fire.
No injuries occurred.
C.
Plant Tours The following plant areas at Units 1 and 2 were toured by the inspector during the inspection:
Auxiliary Building Containment Building Control Complex Building Diesel Generator Building Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter During the week of March 18, 1985, the inspector observed that Control Room access doors J317 and J319 were being maintained in the blocked open position.
Door J317, the main access door to the Control Room, was being maintained open with a security guard posted, due to a hardware problem associated with the security card reader system.
Door J319, providing access to the Control Room through the Tagging Office, was blocked open as a convenience for personnel conducting business with the Tagging Office.
The inspector questioned whether the Control Room essential filtration system was capable of performing its intended function with the above doors open.
Specifically, the inspector was concerned whether the filtration system could automatically initiate and maintain the Control Room at a
positive pressure of at least 1/8-inch water gauge related to adjacent areas, as required by Technical Specification 4.7.7.d.
Inspector review of FSAR Chapter 6.4, Habitability Systems, determined that the control room access doors were considered'
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part of the control room essential filtration system.
Further, the FSAR description included reference to the corridor between the doors as acting as an air lock with each door equipped with a self closing device that shuts the door automatically following the passage of personnel.
Following a discussion with licensee management, the licensee closed door J319, allowing opening only for the passage of personnel.
Additionally, the licensee initiated a review to determine the effect maintaining door J317 and J319 open simultaneously had on the filtration system.
The licensee performed a functional test of the filtration system on April 9,
1985 and determined the system could not maintain the required 1/8-,inch 'water gauge with both doors open; 1/20-inch water gauge was actually measured.
Testing with door J319 closed and J317 open provided acceptable results.
The inspector concluded that during the period both doors were blocked open, March 1-20, 1985, both control room essential filtration systems were inoperable, in that upon automatic initiation, the systems were unable to maintain the required positive pressures.
This is contrary to Technical Specification 4.7.7.d and represents a Severity Level IV Violation.
(50-528/85-08-01)
d.
The following areas were observed during the tours:
l.
0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative procedure requirements.
2.
Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
observed for 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 by plant lineup procedures for the applicable plant mode, This verification included routine control board indication reviews and conduct of partial system lineups.
Details are provided in paragraph 5.
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 specifie ~
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6.
Pire Protection.
Pire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
Problems identified with compensatory fire watches is documented in paragraph 6.
7.
Plant Chemist
.
Chemical analysis results were reviewed for conformance with Technical Specifications and administrative procedures.
8.
~8ecnrit
.
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.
9.
Plant Housekee in
.
Plant conditions and material/equipment storage were observed to determine the general state of cleanliness, housekeeping and adherence to fire protection requirements.
No violations or deviations were identified.
4.
Surveillance Testin
- Unit 1.
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Surveillance tests required to be performed by the Technical Specifications were reviewed on a sampling basis to verify that:
1) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the Technical Specifications; and, 4) test results satisfied acceptance criteria or were properly dispositioned.
The following completed surveillance tests were reviewed:
32ST-9PK01 32ST-9PK02 14ST-1ZZ24 14ST-1ZZ25 41ST-1ZZ16 41ST-1ZZ09 41ST-1ZZ18 41ST-1ZZ19 Seven day Surveillance Test of Station Batteries performed March 13, and April 12, 1985.
Ninety-day Surveillance Test of Station Batteries performed March 13, 1985.
Unlocked Pire Door Position Verification, performed March 15, April 2, and April 5, 1985.
Automatic Pire Door Inspection, performed March 15, April 2 and April 22, 1985.
Routine Surveillance Daily Midnight Log, performed March 15, March 20, April 2, and April 17, 1985.
Routine Surveillance Hode 5-6 Logs, performed March 15, April 2 and April 5, 1985.
Routine Surveillance Mode 1-4 logs, performed April 23, 1985.
Routine Surveillance Mode 5-6 performed March 20, and April 17, 198 ~
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41ST"lDG05 41ST-1DG06 41ST-1SI11 92PE-1SB17 36ST-9SB98 36ST-9SB02 41ST-1SI10 41ST"1CH02 14ST-9ZZ01 77ST-9SB06 41ST"1EC01 74ST-1SB03 Emergency Diesel Generator
"A" Modes 5 and
Operability Check, performed five times between January 1 and March 5, 1985.
"B" Modes 5 and
Operability Check, performed January 5, February 5 and 18, 1985.
Low Pressure Safety Injection Pump Operability Test, performed March 8, 1985.
Safety Systems Response Time Test, performed October 3,
1984 (log power response time test only).
Mode 5 with Breakers Shut - Matrix and RTSG Response Time Test, performed March 2, 1985.
Plant Protection System Functional Test, performed February 24, 1985 (matrix logic and initiation logic) and February 14, 1985 (reactor trip breaker and manual trip).
HPSI Pump Operability Test, performed April 11,1985 Boron Injection Flowpaths, performed April 11,1985 Well Water/Fire Water Reserve Tanks Operational Checks, performed April 11,1985 CEAC No.
2 Calibration, performed April 11,1985 Essential Cooling Water Valve Verification, performed April 11,1985 ECCS Tri-sodium Phosphate Surveillance Test, performed April 11,1985.
During a review of the data associated with Procedure 41ST-1SIll, Low Pressure Safety Injection Pump Operability Test, the inspector noted several instances where the licensee's testing procedure differed from the specifications of Section XI of the ASME Boiler and Pressure Vessel Code.
The licensee is committed to implement the Pump and Valve Operability Program in accordance with the 1980 Edition of the Code with Addenda through Winter, 1981.
The following specific differences were identified:
Vibration velocity is measured rather than vibration displacement as described in IWP Table 3100-2.
The licensee has concluded that vibration velocity provides more useful information than. displacement measurement.
Inlet pressure before pump start is not measured and recorded as described in IWP Table 3100-1.
The licensee used the inlet pressure measured in the pump running condition to determine the differential pressure across the pump.
Discharge flow rate is not measured and recorded as described in IWP Table 3100-1.
The licensee considers the LPSI system a fixed resistance system since it is flow balanced with permanently installed orifices; thus diminishing the need to measure and record flow rat ~
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The inspector stated that the above differences between actual testing practice and the Code did not appear to affect the operability of the pump; however relief requests should be submitted to NRR for any testing practices which are not in accordance with the Code.
Further, the inspector stated that the licensee should identify and submit relief requests for all aspects of the Pump and Valve Program which differ from the Code.
The licensee acknowledged the inspector's comments and committed to submit all necessary relief requests to NRR by June 30, 1985.
b.
Portions of the following surveillance tests were observed to verify that:
1) testing was being accomplished by qualified personnel in accordance with approved, technically adequate procedures; 2) the system was properly returned to service; and 3) measuring and test equipment satisfied calibration requirements.
36ST-9SB03 36ST-9SB02 36ST-9SB47 36ST-9SA02 Plant Protection System Test observed March 18, 19, 20, and 22, 1985.
Plant Protection Systems Functional Test observed March 22, 24, 26 and April 4, 1985.
ESF Subgroup Relay Time Response Test observed March 26, 1985.
ESFAS Train "B" Subgroup Relay Monthly Functional Test observed March 26, 1985.
c ~
On March 14, 1985, with the plant in Mode 5, the inspector noted i'n the Control Room Log that the "A" High Pressure'Safety Injection (HPSI)
Pump was designated as a portion of the boration injection flow path to satisfy Technical Specification 3.1.2.l.b and 4.1.2.3 which required a boration injection flow path be operable from the Refueling Water Tank to the reactor coolant system, via either a charging pump, HPSI pump, or LPSI puIIlp.
The inspector subsequently identified that the Section XI ASME Boiler and Pressure Vessel Code surveillance testing had not.
been performed on the "A" HPSI pump as required by Technical Specification 4.1.2 '
and Station Procedure 41ST-1CH02, Boron Injection Flow Paths - Shutdown.
The licensee declared the boron injection flow path inoperable and entered the action statement precluding any core alterations or positive reactivity changes, while insuring the "A" LPSI Pump was operable, with all required surveillance tests completed.
Following that verification, the licensee declared the "A" LPSI Pump.to be a portion of the operable boron injection flow path and exited the action statement.
The inspector later noted that a procedure did not exist for using a LPSI pump as part of the injection flow path.
The licensee committed during the exit meeting on April 16, 1985, that prior to considering a
LPSI pump available for the injection flow path in the future,'
procedure for its use will be approve t
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The failure to perform the required Section XI surveillance test prior to taking credit for the "A" HPSI Pump as a portion of the operable boron flow path is contrary to Technical Specifications 3.1.2.1.b and 4.1.2.3 and Station Procedure 41ST-1CH02, and represents a Severity Level IV Violation.
(50-528/85-08-02)
5.
En ineered Safet Features S stem Malk Down - Unit
Engineered Safety Feature Systems were walked down by the inspector to confirm that the systems were aligned in accordance with procedures 410P-1SI01
"Shutdown Cooling Initiation", 410P-1DG01
"Emergency Diesel Generator A", and 410P-lDG02 "Emergency Diesel Generator B".
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 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.
The systems that were walked down on March 19, 28, and April 23, 1985 were:
High Pressure Safety Injection Trains "A" and "B" Low Pressure Safety Injection Trains "A" and "B" Containment Spray Systems Trains "A" and "B" Diesel Generator Trains "A" and "B" No violations or deviations were identified.
6.
Ineffective Corrective Action for Violations of Technical S ecification The following instances of ineffective corrective action were identified:
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As a result of various fire rated assembly penetrations being out of service, the licensee had been maintaining several hourly fire watch patrols as required by Technical Specification 3.7.12.a.
On March 23, several hourly fire patrols were missed or exceeded the hourly frequency.
Licensee investigation determined the causes of the situation included a
lack of appreciation by the individuals involved for the consequence of not completing their assigned rounds, and the lack of a clear reporting chain to the Operations staff to alert them that required rounds were not being accomplished.
The corrective action instituted by the licensee included:
reemphasizing to fire watch patrol personnel that hourly rounds must be completed or proper timely notification be made; and modifying the reporting chain to require all reports of problems in carrying out fire patrol duties to be made to the Fire Protection staff.
The staff was tasked with assuring that proper notifications were made and adequate compensatory actions were taken in the futur ~
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On April 4, inspector review of fire watch patrols from April 2 and 3 revealed that several of the tours exceeded the hourly frequency requirement.
The inspector concluded the licensee's corrective actions were not adequate, due in part to a lack of aggressive supervisory log review following identification of the initial problem on March 23.
b.
On April 10, 1985 the licensee identified that four temporary procedure changes were not reviewed by the applicable individual/organization, and approved by the PVNGS Plant Manger, or designee, within fourteen days of implementation, as required by Technical Specification 6.8.3.
Similar violations of Technical Specification 6.8.3 were identified by the licensee on February 20, 25 and March 30, 1985.
The inspector concluded that this violation could reasonably have been expected to have been prevented by the corrective action for the earlier violations.
Failure to implement effective corrective action to prevent repetitive occurrences of the above Technical Specification violations is contrary to
CFR 50 Appendix B, Criterion XVI; Technical Specifications 3.7.12.a and 6.8.3; and represents a
Severity Level IV violation.
(50-528/85-08-03)
7.
Unit 1 License Commitment Followu a.
The licensee's actions regarding the following license commitments were reviewed by the inspector and found acceptable.
The below number/letter reference in parentheses corresponds to the Operating License condition.
Target Rock solenoid valve environmental qualification (2.c.6.b prior to Mode 3).
Anchor Darling operability qualification (2.c.l8.a prior to mode 3).
Deficiency Evaluation Reports (DERs) 84-21 and 84-27 (Attachment 1: 2.a prior to Mode 6).
b.
The Target Rock solenoid qualification involved the replacement of the silicon disk rings with polymide disk rings in the eight.
safety injection tank vent valves.
The silicon ring which served as a sealing component for valve disc/stem assembly could incur deformation or excessive wear following repeated use under high pressure differential conditions, resulting in unacceptable valve gas leakage when the valve was in its closed position.
Replacement of the silicon material with polymide, a
harder seat material, was expected =to prevent gas leakage and hence maintain full safety injection tank pressure.
The inspector reviewed the design change package which included the modification requirements, work authorizations and completion, and the (}uality Control sign offs of the completed work and concluded that the solenoid valves appeared to be acceptably qualifie I
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The Anchor Darling qualification involved the replacement of the actuator cylinders on the steam generator four downcomer isolation valves with new air cylinders fitted with internal coil springs.
Air pressure intensifiers were also installed to boost the air pressure to open the valves against the increased thrusts of the springs.
The modifications were made to correct.
the deficiency of the valves not closing completely under design conditions.
The inspector reviewed the work package and test document and confirmed that the testing following the modification met the required 9.6 second design criteria closure time for the valves, and concluded that, the valves had been acceptably modified and tested.
DER 84-21 - Rosemount and Barton Transmitters Not Torqued To Specified Value.
This Deficiency Evaluation Report describes problems associated with the use of mounting bolts and nuts which did not have grade markings and could not be traced back to quality documentation, and mounting bolts and nuts which were not torqued to specified values on Rosemount and Barton transmitters.
The corrective action taken by the licensee included the inspection of the Rosemount and Barton trans-mitters installed in Units 1, 2 and 3.
The inspector observed a sampling of the inspection findings which included the problems found during the inspection.
The inspection instructions included a list of checks which were required to be made by the inspectors.
A sampling of the corrective actions taken by Bechtel to restore the installations to proper configurations and sign offs by gC were also noted by the inspector.
This item is closed.
DER 84-27 - Improperly Handled Instrumentation From the Maldinger Corporation.
This Deficiency Evaluation Report describes problems associated with irregularities in the installation of heating, ventilating and air conditioning instrumentation such as temperature, pressure and flow sensory devices which involved interchanged components',
improper instrument mountings and open conduit ports.
The action taken -by'he licensee included the reinspection of all "(}" and a sample of "R" class instrumentation installed in Units 1, 2, and 3.
Based on a sampling of the cases, the inspector concluded these inspections had been completed and reports of the findings had been written.
Problems which were found were documented in nonconformance reports and corrective actions were noted by the inspector to have been taken to restore the installations to a proper configuration.
A sampling of corrective action documents containing (}C sign offs were also reviewed by the inspector.
This item is close ~ ~
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8.
Plant Maintenance - Units 1 and
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During the inspection period, the inspector observed 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, and personnel qualifications.
The inspector verified reportability, as required by Technical Specifications for these activities, was correct.
b.
The inspector witnessed portions of the following maintenance activities:
Attempts to locate a ground on Balance of Plant ESFAS and equality Safety Parameters Display System (gSPDS)
on March 14, 1985.
Troubleshooting a boronmeter operation problem on March, 157 1985.
Installation of a plant modification that added alarms to NSSS process instrumentation per PCP 85-Ol-RC-002-00 on March 26, 1985.
Trouble Shooting a Containment Purge Valve position indication
" problem on April 4, 1985.
Rerouting wires in the NSSS ESFAS Auxiliary Relay Cabinet on April 4, 1985.
Replacement of the chemical injection valves in the Containment Spray System on March 6, 1985 (Unit 2).
Charging the Main Steam Isolation Valve Accumulators with nitrogen on April 13, 1985 (Unit 2).
No violations or deviations were, identified.
9.
Review of Prep erational Testin Activities - Unit 2 a
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Ma or Test Activities The major preoperational test activities in progress during the reporting period were associated with the testing of the Containment and Auxiliary Building Heating and Ventilating Systems, Balance of Plant Engineering Safety Features, Excore Instrumentation Plant Protection System, Essential Spray Pond System and the refill of the Reactor Coolant System.
The start of Hot Functional Testing was rescheduled for June, 1985.
b.
Prep erational Test Procedure Review'he inspector reviewed preoperational test procedure 91PE-2DF01
- Diesel Fuel Oil and Transfer System.
The inspector verified the procedure was formally reviewed and approved, formatted, and contained the information required by Administrative Control Procedure 90AC-OZZ14,
"PVNGS Startup Procedures, Preparation, Review and Approval".
A sample of acceptance criteria contained in the procedure was compared with design documents.
The inspector verified the design values and required equipment performance were consisten I
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Preo erational Test Mitnessin The inspector witnessed portions of the following tests:
92PE-2SA01 91PE-2SG01 92PE-2SB10-14 92PE-2SE05 NCR-SM-5100
- Balance of Plant Engineered Safety Features Actuation System Panel Test.
- Main Steam Isolation Valves and Bypass Valves
- Plant Protection System
- Excore Nuclear Instrumentation Safety Channel C.
- "A" Train Auxiliary Feedwater Recirculation Test.
The inspector verified that approved procedures were used, test personnel were knowledgeable of the test requirements, and data was properly collected.
Procedure changes and test exceptions were identified and significant events were recorded in the test log.
Other test related activities such as the use of calibrated M&TE and completion of test prerequisites were also verified to have been accomplished in accordance with administrative control procedures.
No violations or'deviations were identified.
10.
Communications and Interface Controls Unit 2 Following an equipment'alignment error which occurred at, Unit 1 during startup testing (NRC Inspection Report 50-528/84-33),
APS instituted a program for a multi-group review of startup testing related problems.
One member of the Startup Transition staff was assigned the responsibility to review problems which had occurred and to coordinate resolutions with other involved organizational units.
During the past eight months, eleven Unit 2 startup testing related problems caused in part by insufficient organization interface controls have been reviewed by APS.
These problems related to such activities as equipment alignments, clearance log controls and chemistry specifications were noted by the inspector to have been evaluated and resolved by the responsible parties.
The inspector confirmed that the problems reviewed by APS included those which the inspector had noted during his review of shift logs.
Implementation of the program represents a positive action taken by the startup organization to improve the interface effectiveness of organizations engaged in startup testing in Unit 2.
No violations or deviations were identified.
11.
Plant Modifications - Units 1 and
The inspector reviewed the site implementation portion of the PVNGS Plant Change Program.
Plant modification controls are discussed in part in Administrative Control procedure 73AC-OZZ15, "Plant Change Package".
This procedure describes the processing of plant modifications, listing the safety evaluations, impact reviews, implementation controls and approvals required by the progra I I
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The following two plant changes were reviewed:
PCP 85-01-PC-007 - Installation of additional supports on the Reactor Coolant Pump drain line.
PCP 85-01-PC-002-00 - Eyebolts tack welded to 3 Fuel Pool Cooling System valves to prevent the eyebolts from dropping into the fuel pool.
The inspector confirmed that the documents required by the administrative control procedure were included in the packages.
The documentation included nuclear safety reviews (10 CFR 50.59)
as well as evaluations by responsible staff for impact on such program elements as operating procedures, surveillance, testing, maintenance, training, and ALARA.
In both cases the inspector confirmed that the Plant Review Board had approved the plant changes.
Determinations that FSAR and Technical Specification changes were not required, and that drawing changes were required, was also provided in the package.
In the case of PCP 85-Ol-PC-007 the inspector observed that the modification had been installed in Unit 1.
Based on the above review the inspector concluded the two plant changes were implemented in accordance with the Plant Change Program.
No violations or deviations were noted.
12.
Nuclear Safet Grou (NSG) and Inde endent Safet En ineerin Grou ISEG Effectiveness Units 1 and 2.
NRC letter to APS, dated September 14, 1984 (T. Bishop to E. Van Brunt, Jr.) transmitting Inspection Report 50-528/84-28, documented NRC awareness of staffing difficulties for the NSG and ISEG, and the licensee's aggressive pursuit of fillingvacancies with qualified, experienced personnel prior to low power licensing.
The above letter also documented'APS's intention to arrange an independent audit to assess the effectiveness of NSG in late 1984 or early 1985.
The inspector determined that current staffing and experience levels for NSG and ISEG personnel satisfy the requirements of Technical Specifications 6.5.3.2 and 6.2.3.2, respectively.
No violations or deviations were identified.
13.
Alle ations and Ins ection Findin s a
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CHARACTERIZATION (RV-85A-008) (Closed)
On February 2, 1985, an allegation was received by the Operation Center Duty Off'icer from an anonymous caller who stated that during installation in the Unit 1 Reactor Vessel head the heated junction thermocouples (HJTC) were hit with a hammer causing damag f II
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IMPLIED SIGNIFICANCE TO PLANT DESIGN CONSTRUCTION AND OPERATION Damage to the HJTC could render the devices inoperable.
The HJTC are installed to allow detection and indication of steam voids in the Reactor Vessel Head.
Damage to the HJTC could prevent proper operation and provide an erroneous indication of the water level in the Reactor Vessel Head.
ASSESSMENT OF SAFETY SIGNIFICANCE The HJTC assembly consists of two concentric tubes that surround the thermocouples.
The outer "probe support tube" has
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protective "bullet nose" which can accept physical abuse without affecting the thermocouple.
The inner "separator tube" maintains the thermocouples separate from the probe support tube.
Each tube has small water holes arranged to allow reactor coolant to circulate.
The thermocouples are individually sealed in a sheath and the assembly is sealed at the RCS boundary.
During installation and removal the outer tube is expected to rub against the guide tube and absorb any abuse from normal movement.
Difficultywas encountered during installation of the first HJTC. Approximately one foot above full insertion, the assembly stopped moving downward.
Several attempts to cover the assembly before the HJTC was removed and inspection and checks of the bullet nose were made.
Finding no damage, the licensee contacted Combustion Engineering (CE) for additional instructions.
Interviews with licensee engineering personnel revealed that CE had recommended that the HJTC probe be lowered, then a hammer be used to tap the upper protective end. It was expected that any small weld beads partially blocking the guide would be broken off.
After this proved to be unsuccessful, the HJTC probe was withdrawn, inspected again, and a bore scope was used to determine the occlusion in the guide tube.
Following the removal of excessive weld material the probe was inspected, measured, and reinserted into the guide tube successfully.
Electrical checks; for both continuity and grounds were performed after installation.
During filling of the Reactor Vessel a functional test-of the HJTC was satisfactorily completed.
No discrepancies were noted from the tests performed.
STAFF POSITION The inspector did not substantiate the allegation.
The inspector concluded that the HJTC was installed and tested in an acceptable manner and the HJTC did not display evidence of being damaged during the installatio P I
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ACTION RE UIRED None.
b.
CHARACTERIZATION (RV-84-A-0087)
A weld on a large diameter safety injection line at Unit 2 was observed leaking during the summer, 1982 time frame.
IMPLIED SIGNIFICANCE TO PLANT DESIGN CONSTRUCTION OR OPERATION Degradation of the Engineered Safety System piping could result in failure of the systems to fulfilltheir design functions of providing coolant flow to the reactor and mitigating the consequences of an accident.
ASSESSMENT OF SAFETY SIGNIFICANCE The inspection followup included discussions with APS and Bechtel staff, a review of hydrostatic test records and direct inspection of pipe welds.
A sample of eighty welds in large diameter piping in the Low Pressure Safety Injection System (LPSI), Containment Spray System (CS)
and the Shutdown Cooling System were selected for inspection.
The piping containing the welds was located in the LPSI Pump Rooms, CS Pump Rooms, East and West Mechanical Penetration Rooms, and Containment.
Welds in the low section of piping, were chosen requiring the removal of piping insulation from six sections of pipe.
An inspection of the eighty welds disclosed no leaks, indication of corrosion or weld area degradation.
In reviewing the hydrostatic pressure records of the nine subsystems which comprise the Safety Injection, Containment Spray and Shutdown Cooling Systems, the inspector observed that the earliest hydrostatic pressure completion date was January 22, 1983.
A review of all of the nine subsystem hydrostatic pressure test documents by APS and an audit of the documents by the inspector revealed that no weld leaks were observed during the conduct of the initial hydrostatic testing of the subsystems.
During the initial test each weld in the piping system was checked for leaks while the piping is pressurized.
STAFF POSITION The'.inspector was unable to substantiate the pipe leak condition reported to the NRC.
The successful completion of hydrostatic testing subsequent to the employee's observation was confirmed, giving assurance that the pipe systems did not contain leaking welds.
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14.
Review of Periodic and S ecial Re orts Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.3 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required,to be reported by NRC requirements; test results 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.
Monthly Operating Reports for February and March 1985.
Licensee Event Reports (LERs)
a.
(Closed)
LER 85-05-01:
Automatic Actuation of Control Room Essential Filtration Actuation System (CREFAS)-
January 22, 1985.
Automatic CREFAS actuation occurred when a spurious auxiliary equipment failure alarm was received on the Control Room Radiation Monitoring Vnit. All equipment operated as required.
The cause of the equipment failure alarm and several subsequent alarms during troubleshooting were not determined, but an engineering evaluation was performed to verify that no adverse safety consequences would occur if the auxiliary equipment failure feature was removed from actuating the Engineered Safety Features Systems (ESFAS).
On February 20, a temporary modification was completed to eliminate the equipment failure portion of the ESFAS actuation circuit.
This event was similar to an event reported in LER 85-04.
This item is closed.
b.
(Open)
LER 85-07:
Automatic Actuation of NSSS ESFAS Auxiliary Relay Cabinet February 10, 1985.
r An automatic actuation of the "B" NSSS ESFAS Auxiliary Relay Cabinet occurred while transferring the Train "B" Class lE 120V AC instrument bus from the normal source to the alternate source.
During the operation of the
"break-before-make" transfer switch, the power to the system loads was believed to have been supplied by an auctioneered power supply from the Train "A" Class lE 120V AC instrument power.
However, the train "A" power supply was not functioning and power was momentarily lost to the loads as the switch position was changed.
This loss of power caused the generation of an automatic actuation signal.
No injection occurred because the high pressure safety injection pump (HPSI) breaker fuses were pulled, and power had been removed from the containment spray isolation valve breakers.
The low pressure safety injection pump (LPSI) pump deenergized from the shutdown cooling mode and was lining up for LPSI injection when it was overridden and rese I V
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The cause of the Train "A" power supply failure was determined to be a failed transformer.
About three weeks before the event, on January 10, 1985, an
"ESFAS A Control Power Supply" alarm was received in the control room.
The alarm was investigated; however, its cause could not be identified.
At the time it was believed that the alarm was spurious.
Based on this latest experience the licensee has identified that the alarm response procedure did not adequately cover all the inputs to the alarm.
The procedure has been changed to incorporate checking the power available light on the power supplies.
The inspector informed the licensee that the LER did not adequately address actions to preclude future events of a similar nature on this and other systems which use auctioneered power supplies.
The licensee stated that a
report supplement would be issued.
This LER remains open pending review of the LER supplement.
(Open)
LER 85-08:
Unanalyzed Safety Condition - Auxiliary Feedwater System - February 4, 1985.
A recent analysis of Auxiliary Feedwater (AFW) pump curves by the licensee indicated that AFW could exceed the maximum flow rate of 1750 gpm specified in the FSAR for some accidents.
It was assumed that operator action could be taken to prevent this from occurring.
During a main steam line break (HSLB) accident the pressure decrease in a steam generator is rapid enough to cause the maximum flow rate to be exceeded in less than one minute.
The licensee determined that during this type of transient, exceeding the, flow rate in the FSAR should not be assumed to be prevented by operator action.
Subsequent reanalysis has been performed using the higher AFW flow rates.
Preliminary results indicate that although flow rates are higher than assumed previously, DNBR increases at flow rates in excess of 1750 gpm',
resulting in an increase in safety margin.
The final results of the new analysis will be transmitted in a report to the NRC.
This item remains open pending review of the licensee's final report.
(Closed)
LER 85-10:
Automatic Actuation of the Balance of Plant Engineered Safety Features (BOP ESFAS), February 22, 1985.
Automatic actuation of the BOP ESFAS occurred while placing the Train "A" sequencer in manual mode from the auto mode.
During the transfer from auto to manual, Train
"A" Fuel Building Essential Ventilation Actuation Signal (FBEVAS) and Control Room Essential Filtration Actuation Signal (CREFAS)
as well as the cross trip to Train "B" FBEVAS and CREFAS were initiated.
Resetting both Train
"A" and "B" cabinets returned the system to norma ~ O I
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Investigation showed that a digital circuit is set for a short period while the FBEVAS module is being tested by the sequencer diagnostic software program.
If a transfer from auto to manual is completed at the proper instant, the circuit can be left in the set condition with no means for it to reset; this results in a valid trip condition, thereby causing the sequencer in Train "A" to actuate the appropriate equipment and also to cross trip Train "B" causing the same sequencing.
This design feature was verified by the equipment vendor.
To prevent a recurrence of this type of trip, it is required that the BOP ESFAS only be transferred from auto to manual when the sequencer is in the test mode (the test lamp lit on the sequencer).
Both Train "A" and "B" have functioned as per design since being reset during the sequencer module test portion of the auto testing sequence.
A Procedure Change Notice (PCN) to all operating and surveillance test procedures was issued to reflect the need to assure the sequence is in the test mode prior to transferring the sequencer from automatic to manual.
This item is closed.
e.
(Open)
IER 85-11:
Automatic Actuation of BOP ESFAS, February 6, 1985.
On February 6, 1985, Palo Verde Unit 1 was in Mode 5 when the Control Room Essential Filtration unit was automatically operated by a spurious alarm/actuation from the Control Room Ventilation Radiation Monitor.
All required equipment operated satisfactorily.
During investigation it was identified that the radiation alarm setpoint was greater than allowed by the Technical Specifications.
The setpoint that was in effect was the default value which is stored in the radiation monitor's microcomputer software.
The radiation monitor restores the default value for setpoints after a loss of power.
The plant's redundant radiation monitor was operable with setpoints consistent with the Technical Specifications and satisfied the minimum channels needed to be operable per the Technical Specifications.
The inspector verified that the high radiation alarm setpoint'was adjusted to be conservative with the Technical Specifications and a plant change has been generated to modify the microcomputer software default values to be consistent with the Technical Specifications.
Plant procedures are in effect to verify that setpoints are in compliance with the Technical Specification The cause of the high radiation signal was not identified.
The range of the instrument is lE-06 to lE-01 microcuries per milliliter.
The setpoint of 2E-06 is near the lower end of the range of the detector.
Subsequent random spikes of indicated radiation levels have been observed on this monitor.
Routine radiological surveys have not detected airborne activity above naturally occurring background levels.
The licensee believes that these random spikes are due to electronic circuit noise.
The licensee will continue its attempts to determine the root cause of the spurious electronic noise.
This item remains open pending completion of the licensee's troubleshooting',
and subsequent inspector review.
(Closed)
LER 85-13:
Inadvertent Start of Diesel Generator
"B", February 23, 1985.
An inadvertent start of the Train "B" Diesel Generator occurred at 1:32 A.M. while testing, the Auxiliary Feedwater.Actuation Signal (AFAS) to Steam Generator
Train "B".
The surveillance procedure required that an initial equipment status verification be performed prior to de-energizing a relay in the auto-start circuitry.
During the verification, the procedure was changed via a Procedure Change Notice that allowed the "Control Mode" select switch to be returned back to the "Remote" position so that power would be restored to the relay.
It was not realized at the time that the relay contacts actually provided a
START signal to the Diesel Generator.
A controlled document which lists all ESFAS Train "B" Subgroup Relays, the associated Actuated Equipment, and the Function which the relay performs on that equipment misleadingly contained the words
"BYP TRIPS" under the Function column. It was erroneously assumed that the only, function of these contacts was to bypass the low priority Diesel Generator inherent trips which occurs upon a full LOCA emergency actuation, AFAS and/or Safety Injection Actuation Signal (SIAS), and that the actual Diesel Generator Start Signal (DGSS)
was provided by the Balance of Plant (BOP)
ESFAS DGSS circuit. It was incorrectly concluded that by placing the "Control Mode" select switch-back to the "Remote" position that a start would not occu t
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Subsequent to implementing the PCN, the relay was then de-energized per procedure, causing the "B" Diesel Generator to start and its support equipment to operate per design.
The relay was then re-energized and the Diesel Generator
"B" and its support equipment were reset.
The surveillance test was terminated and a detailed examination of the Diesel Generator internal auto-start control electrical diagrams were performed to determine the cause of the inadvertent start.
The procedural error in the PCN was subsequently corrected by generating a second PCN which placed the Train "B" Diesel auto control disconnect'witch in the IOCAL position.
This switch physically disconnects the emergency mode auto-start contacts, and thus prevents the Diesel from starting upon closing the auto-start contacts'he second PCN also modified the procedure to initially verify the absence of voltage on the autostart contact sets and then perform a resistance measurement to verify that the contact sets were open.
The test was then satisfactorily completed.
The inspector verified that a
Plant Change Request has been issued to correct the misleading information in the document listing the ESFAS Subgroup Relays and Actuated Devices.
This item is closed.
g (Closed) Special Report - Diesel Generator Failure to Start Within Time Timits, - March 5, 1985.
This report was submitted in accordance with Technical Specification 4.8.1.1.3 to document the failures of both diesel generators to start and reach required speed and voltage within the required ten seconds.
On March 5, 1985 the "A" Diesel Generator failed to attain the required voltage, frequency, and speed within ten seconds.
On March 8, 1985 the "B" Diesel Generator failed to meet the required start time limits.
The second failure would have required an increased surveillance frequency in accordance with Technical Specification Table 4.8-1; however, in investigating the second failure to start, the testing method was determined to need further evaluation.
The testing method utilized a stop watch to manually measure time.
When the time measurement was made using an oscillograph, which was temporarily installed, the diesel generator was determined to have started, and reached the required speed and voltage within the Technical Specification time limits on three subsequent starts.
The March 8, 1985 failure to start was declared a test performance error and an increased frequency of testing was not required.
A design change has been initiated to incorporate a permanent positive indication of diesel start test performance to replace the stop watch, 'and a
procedure change has been made to reflect the use of a graphic display of the diesel generator start test performance.
This item is close p/
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No violations or deviations were identified.
The inspector met with licensee management representatives periodi-cally during the inspection and on April 16, 1985.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed with and acknowledged by the licensee representative f
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