Insp Repts 50-528/86-20,50-529/86-20 & 50-530/86-14 on 860527-0630.Violation Noted:Failure to Perform Hourly Fire Patrols| ML17300A308 |
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| Site: |
Palo Verde  |
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| Issue date: |
07/21/1986 |
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| From: |
Ball J, Bosted C, Fiorelli G, Jim Melfi, Miller L, Zimmerman R
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
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| To: |
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| Shared Package |
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| ML17300A307 |
List: |
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| References |
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| 50-528-86-20, 50-529-86-20, 50-530-86-14, IEB-85-001, IEB-85-1, IEIN-85-049, IEIN-85-091, IEIN-85-49, IEIN-85-91, NUDOCS 8608060135 |
| Preceding documents: |
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| Download: ML17300A308 (52) |
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Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
50-528/86-20, 50-529/86-20, 50-530/86-14 50-528, 50-529, 50-530 License Nos:
NPF-41, NPF-51, CPPR-143 Licensee:
Arizona Nuclear Power Project P. 0.
Box 52034 Phoenix, AZ. 85072-2034 Inspectors:
R. Zi hrman, io i ent Inspector G.
r lli, ge e
n ector C.
B s ed, Re ns ctor esid n
e or J.
lfi, Re to nspector Approved By:
I Ins ection Conducted:
M y 27,
J ne
,
1986 7- < /-y(.
Date Signed
- z /'-g0 Date Signed z/-yC Date Signed 7-z (-gt'ate Signed 7-Z/-g 4 Date Signed 7-LIQ Miller, Ch
, Reactor Projects Section
Date Signed Summary:
Ins ection on Ma 27, 1986 throu h June 30, 1986 (Re ort Nos. 50-528/
86-20, 50-529/86-20, and 50-530 86-14)
Areas Ins ected:
Routine, onsite, regular and backshift inspection by the four resident inspectors and one Region V reactor inspector.
Areas inspected included: followup of previously identified items; review of plant activities; engineered safety system walkdowns; surveillance testing; maintenance; construction activities; preoperational and power ascension test witnessing; preoperational test procedure review; power ascension test results review; diesel generator bridge crane seismic qualification review; allegation followup; reactor coolant pressure isolation valve leak test; Licensee Event Report followup; Construction Deficiency Report, Part 21 report, and IE Bulletin and Information Notice followup; periodic and special report revie~;
and plant tours.
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During this inspection the following Inspection 'Procedures were covered:
30703, 52053, 61726, 62703, 70350, 71302, 71707, 71710, 72301, 72302, 72600,'0712, 90713, 92700, 92701, 92702, 92703, 92717, 93702 and 94703.
Results:
Of the 16 areas inspected, one violation was identified'"in one area.
(Failure to perform required hourly fire patrols paragraph 3.d.6.b)
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DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro ect (ANPP)
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- O, Adney, Allen, R. Bynum, Cederquist, Dennis, Fernow, Grove, G. Haynes, E. Ide, Jump, Kirby, McCabe, Meyer, Minnicks, Nelson, Nelson, Perkins, Pollard, Shriver, Souza, E. Van Brunt, Younger, Zeringue, Operations Superintendent, Unit 2 Operations Manager PVNGS Plant Manager Chemical Services Manager Operations Supervisor, Unit
Training Manager I&C Supervisor Vice 'President, Nuclear Operations Corporate Quality Assurance Manager Startup Manager, Unit 3 Project Transition Manager Assistant Startup Manager, Unit 3 Fire Protection Supervisor I&C Superintendent Operations Security Manager Maintenance Manager Radiological Services Manager Operations Supervisor, Unit 2 Compliance Manager Assistant Quality Assurance Manager Jr., Executive Vice President Operations Superintendent, Unit
Technical Support Manager Bechtel Power Construction (Bechtel)
D. Anderson, D. Freeland, D. Hawkinson, G. Hierzer, T. Horst, W. Murphy, S. Nickell, H. Thornberry, Chief Resident Engineer Engineering Group Supervisor Plant Design Project Quality Assurance Manager Field Construction Manager Project Field Engineer Project Superintendent, Unit 3 Project Superintendent Area Project Field Engineer The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Attended the Exit Meeting on July 1, 1986.
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Previousl Identified Items a.
(Closed)
Followu Item 50-529/86-'09-02:
"Review Procedure'ontrollin EERs '.
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This item relates to a previously identified need for the Engineering Evaluation Request (EER) procedure to be revised to include improved tracking controls.
The inspector reviewed procedure 73AC-OZZ29, "Engineering Evaluation Requests" and confirmed that the procedure had been revised to require that all EERs be submitted to an EER coordinator who will log them in and assign a tracking number to the EERs before forwarding them to the Operations Engineering staff for resolution.
This revision was considered by the inspector to significantly improve the tracking control, in that previous procedure instructions allowed forwarding the EERs directly to the Operations engineers who would not always put the receipt of the EER into the system.
This item is closed.
(Closed)
Followup Item 50-530/86-07-01:
"Licensee Investi ation into Cut Wire in Instrumentation Cabinet The licensee completed investigation into the April 23, 1986, incident and concluded that the wire was apparently cut accidentally 'during the performance of approved work activities.
In addition to direct observations, personnel interviews, and a review of related work documents in an effort to recreate the situation, the licensee sent the cut wire and a pair of wire cutters, believed to have been used, to an independent local laboratory for evaluation as to whether a
match existed.
The wire cutters had been used as part of an approved work activity to cut tie wraps for the wire bundle which included the cut wire.
The laboratory reported that based on a scanning electron microscope examination, the wires were probably cut with the supplied wire cutter, although an exact match was not possible.
The inspector considered the licensee's investigation thorough, and the conclusion to be reasonable.
This item is closed.
(0 en) Unresolved Item 50-528/86-09-01:
"Pi e Su ort Desi n Control".
This item relates to a lack of proper consideration of certain
'effects in the design of a number of pipe supports.
The problem is discussed in additional detail in paragraph 14 of this report.
The inspector reviewed the Bechtel Pipe Support Design Manual, Revision 14, and in particular Article 4.0,
"Rules and Methods For Various Detail Designs" to determine if sufficient information existed to direct the designer in the consideration of the particular effects of localized flange bending and pipe support swing 'angle/thermal offset.
The inspector found information contained under the headings
"Swing Angle and Offset" Section,5, which includes Pipe Support Manual (PSM) 4.2.1,
"Rod Hangers"
'and PSM 4.26.1, "Stiffener Plates For Wide Flange Beams" to provide the necessary instructions for consideration of the two effects which contributed to the original pipe support design problem.
This item remains open pending additional review of the safety significance of the
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effect of the support failure on the integrity of the feedwater system piping under certain conditions.
The NRC's concern regarding the adequacy of design reviews conducted by Bechtel is discussed in NRC Inspection Report 528/85-31.
As a result of this concern, the licensee issued Corrective Action Request (CAR) CA85-0252 at the time of the inspection to address the conformance of Bechtel's program for design verification to the provisions of ANSI N 45.2.11.
During this inspection period, the inspector reviewed the status of this CAR.
The CAR remained open at the conclusion of this inspection (with an estimated completion date within the coming month).
This issue will be reviewed further in the close out of items identified in 'NRC Inspection Report 528/85-31.
3.
Review of Plant Activities a ~
Unit
At the start of the inspection period, the unit was operating at full power.
A turbine trip and reactor cutback occurred on June 6.
A failed weld on the high pressure electro-hydraulic control (EHC) oil supply, line to the main turbine control and stop valves caused EHC oil pressure to drop and the turbine to trip.
The turbine trip activated the steam bypass control and reactor cutback system.
Control rod groups 4 and 5 were dropped and reactor power was automatically reduced to approximately 25X.
Plant power was reduced to 10X during repairs of the EHC oil line.
EHC repairs were completed and the unit was paralleled to the grid on June 7.
Power was raised to 100X on June 8.
On June 17, a reactor trip occurred on low DNBR during the performance of control element assembly (CEA) surveillance testing.
One of the shutdown CEAs was inadvertently inserted to a position which resulted in an excessive deviation (8.1 inches)
between itself and another CEA in the group.
This condition generated a DNBR penalty factor, which when applied to the actual DNBR exceeded the DNBR trip setpoint.
The unit was taken critical and reached full power on June 18 and 19, respectively.
On June 23, power was reduced to 93% in accordance with Technical Specification 3.2.4 for when the Core Operating Limit Supervisory System (COLSS) is taken out of service due to erroneous
"T" cold input signals.
The power r'eduction was required to maintain the required minimum DNBR margin with COLSS out of service.
The unit was returned to full power on June 25, and remained at 100X through the remainder of the inspection period.
Unit 2
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Power ascension testing was completed at the 20, 30 and 40X power plateaus.
On May 31, with the reactor at 35X power, a
reactor trip occurred from high pressurizer pressure.
The high pressurizer pressure was caused when the steam bypass control system (SBCS) did not quick open because the master controller was inadvertently left in the "local auto" instead of "remote auto" position.
The reactor trip was proceeded by a main, generator/turbine trip caused by an actuation of the main generator negative sequence relay which protects the generator from a phase current imbalance.
The problem was ult'imately determined to be a defective negative sequence relay.
The reactor was restarted on June 2 and= 50% power was reached on June 4.
At this time steam generator secondary chemistry had deteriorated to the point where normal administrative limits were exceeded, requiring a power reduction to less than 25X.
Upon determining that improvements in steam generator water quality were ineffective because steam generator blow-downs were erroneously being made through the cold leg blowdown line instead of the hot leg blowdown line, as a result of mislabeled valves, the steam generator blowdown paths were changed.
This resulted in an immediate "improvement in the steam generator secondary water chemistry.
In-addition,. three tubes in the 1A Condenser were found leaking were plugged, remedying the chemistry problem.
During the increase in power following the restoration of steam generator water quality, the reactor tripped from a power of 40X on June 10.
The trip was again caused by high pressurizer pressure which occurred as a result of the failure of the SBCS to quick open.
This failure of the SBCS to quick open was determined to have resulted from a circuit card which was not completely inserted.
The reactor trip was proceeded by a generator/turbine trip which was caused by the actuation of the main generator exciter protection system due to a drop in voltage in its power supply.
The system normally operates with a dual power supply; however, at the time of the trip the backup power supply was deenergized due to a problem with the inverter.
The reactor was taken critical on June ll and was again in-creased to 50X on June 13, 1986.
On June 18, steam generator water quality again deteriorated necessitating the plugging of l,leaking condenser tube and 14 others as a precaution.
On June 20, while preparing for the conduct of power ascension test, 72PA-2RX18,
"CEA Shadow/Radial Peak Factor",
partial-length control element assembly (CEA) No.
48 dropped into the reactor when engaged to be moved.
The cause of the problem was determined to be due to a bad timing card.
The reactor was shutdown when attempts to remove the CEA were, unsuccessful.
The CEA was finally withdrawn and power returned to 50X on June 2 >>
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On June 25, a planned reactor, trip occurred as a result of the performance of a loss of offsite power test.
Following the trip, while the reactor was in Mode 3, the licensee identified two plant water leaks to the Equipment Drain Tank, which were subsequently repaired.
One leak, of approximately 10-15 gpm involved a stuck open relief valve in the. letdown 3.ine.
The second leak of approximately 30 gpm was caused by a malfunctioning valve in the reactor makeup system (outside the NSSS) which was also flowing to the Equipment Drain Tank.
Coincident with these leaks was an increase in Reactor Drain Tank level which was confirmed to be from the 2B Reactor Coolant Pump vapor seal.
The identified leakage was within Technical Specification limits and the unit was taken critical on June 30.
Unit 3 During this report period, system prerequisite and preopera-tional testing continued.
Activities included completion of portions of the safety injection/shutdown cooling system flush and continuation of flushing of the auxiliary feedwater system, preoperational testing of the chemical and volume control system, reperformance of portions of the Balance of Plant Engineered Safety Features Actuation System Panel test, and initial load testing of the "A" Diesel Generator.
Construction activities in Unit 3 were estimated to be 99 percent complete by the licensee.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspector during the course of the inspection:
Auxiliary Building Containment Building Control Building Diesel Generator Building Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter I
,The following areas were observed during the tours:
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0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative control pro-cedure requirements.
2.
Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for con-formance with Technical Specification requirements."
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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 administrative 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 4.
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 equ'ipment in the co'ndition specified.
6.
Fire Protection.
Fire fighting equipment and controls were observed for conformance with Technical Specifica-tions and administrative procedures'.
a.
The Fire Department response to the main turbine EHC oil supply line failure at Unit 1 on June 6 was witnessed by the inspector, and was considered noteworthy.
Department personnel, including supervision,, responded quickly, assessed the situation, and oversaw containment and cleanup of the oil leak.
Fire fighting equipment, and personnel protective clothing were available, and proper communication lines were established to ensure swift transfer of information.
b.
During followup of an observation made while on a plant tour, the inspector determined that a required, hourly fire watch patrol of the Unit 1, "B" Low Pressure Safety Injection (LPSI)
Pump Room had not been performed.
Rather, fire watch personnel made observations on a remote television camera located outside the pump room.
The hourly fire watch patrol was required by Technical Specification (TS)
3.7.11.2.a because the fire protection sprinkler system for the "B" LPSI Pump Room was valved out of service, and declared inoperable.
The inspector informed licensee management that the use of a remote camera instead of an actual, tour of the affected area failed to satisfy the above Technical Specification requirement.
The licensee immediately responded to the inspector's statement, and initiated hourly fire watch patrols inside the "B" LPSI Pump Room.
Based on discussions with plant personnel and a review of plant records, the inspector determined that the improper use of the television camera to satisfy the fire watch requirement had occurred from April 28, 1986, through June 19, 1986.
Failure to perform an
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hourly fire watch patrol of the "B" LPSI Pump Room is contrary to TS 3.7.11.2.a and is a violation (528/86-20-01).
The licensee stated that the decision to use the remote camera to satisfy the above TS was made at a
low supervisory level, and was based on minimizing personnel exposure due to the radiation levels in the room.
The inspector reviewed survey maps completed by the licensee at the end of April and early May for the "B" LPSI room and noted the highest dose rate to be a contact reading on a portion of the LPSI pump of 1.5 rem/hour.
However, general area dose rates during the entire period the remote camera was in use which would have been, encountered by a fire watch patrol, had it been conducted similarly to the room tours implemented on June 19, averaged about
millirem/hour.
The inspector noted that no review by the ALARA group had been performed prior to the decision to use the camera.
Additionally, no reevaluation of the use of the camera was performed following removal of contaminated piping insulation, and installation of temporary shielding material during May 1986, which had a significant effect on reducing localized "hot spots".
The inspector also made the following observations while reviewing the hourly fire watch logs for the above period:
The fire watch patrols appeared to be conducted swiftly.
For example, tours of the entire Auxiliary Building and portions of the Fuel Building and Radwaste Building were routinely conducted in 17.minutes.
Further, tours of the six pump rooms, including the "B" LPSI Pump Room, on the 51'levation of the Auxiliary Building were conducted in two minutes.
The inspector informed plant management that consideration should be given to performing the tours more deliberately.
Fire watch patrols and associated log keeping will continue to be reviewed as part of the routine inspection program.
Enhancement to the logs to add specificity, detailing individual rooms and areas patrolled, appeared warranted to clearly document compliance with Technical Specifications.
The licensee stated that additional detail would be added to the forms by August 1, 1986.
This item will remain open pending review of the revised logs (528/86-20-02).
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Plant Chemist
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Chemical analysis results were reviewed for conformance with Technical Specifications and admin-istrative control procedures.
Unit 2 steam generator water chemistry exceeded normal licensee administrative limits on several occasions during the period.
On three occasions, condenser tube plugging was performed due to leaks.
A total of 21 tubes were plugged in the 1A condenser, 7 leaking tubes and 14 other fringe tubes having, potential for leaking:
The cause of the tube leaks was determined to be the result of direct impingement on the tubes by flow from the heater drain tanks, causing tube wear from the tube stiffeners recently installed on the fringe tubes.
Flow baffles were installed to correct the 'problem.
I 8.
~Secnrit
.
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, material and equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
10.
Radiation Protection Controls Areas observed included control point operation, records of license's surveys within the radiological controlled areas, posting of radiation and high radiation areas, compliance with radiation exposure permits, personnel monitoring devices being properly worn, and personnel frisking practices.
4.
En ineered Safet Feature S stem Walk Down Units 1 and 2.
Selected engineered safety feature systems (and systems important to safety)
were walked down by the inspector to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, i.tems such as hangers, supports, electrical cabinets, and cables were inspected to determine that they were operable, and in a condition to perform their required functions.
The inspector also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Unit I
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Portions of the following systems were walked down on June 4, 9 and 10$
1986.
Unit High Pressure Safety Injection, Trains "A" and B" Low Pressure Safety Injection, Train "B" Containment Spray, Trains drAn and 22B22 L
Diesel Generators, Trains "A" and "B" 4160/480 VAC Vital Breaker Panels, Trains "A" and "B" 125 VDC Breaker Panels and Battery Rooms, Trains "A", "B", "C" and "D" Main Feedwater Economizer Isolation Valves, Trains "A" and "B" (included associated actuating system)
d 2'ortions of the following systems were walked down on June 3,
4 and 13, 1986.
Safety Injection Tanks Diesel Generators, Trains "A" and "B" (Included Lube Oil and Cooling Water Subsystems)
High Pressure Safety Injection, Trains "A" and B" Low Pressure Safety Injection, Trains "A" and B" No violations of NRC requirements or deviations were identified.
5.
Surveillance Testin Units 1 and 2.
a.
Surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that:
1) the surveillance tests were correctly included on, the facility schedule; 2) a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillances were observed by the inspector on the dates shown:
Unit
Procedure Descri tion Dates Performed 36ST-9SE02 Plant Protective System May 28, 1986 June 2,
1986 36ST-9SE12 Excore Safety Channel Calorimetric June 2,
1986 Unit 2 Ptccednte Dates Performed 42ST-2RC02 RCS Water Inventory Balance June 5,1986
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10 36ST-9SB02 Plant Protection System Functional Test June 10, 1986 June 11, 1986 42ST-2ZZ23 CEA Position Data Log 74ST-2SS04 Pass Functional Test (SI Sample)
June 13, 1986 June 17, 1986 c.
The following completed surveillance test was reviewed by the inspector:
Unit
Procedure 41ST-lAF03 Description h
Auxiliary Feedwater Pump AFB-POl Date Performed May 31, 1986 No violations of NRC requirements or deviations were identified.
6.
Startu Testin Unit 2.
a.
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 measuring and test equipment and completion of test prerequisites were also verified to have been accomplished in accordance with administrative control procedures.
Dates Performed The inspector witnessed portions of the following tests:
Unit 2 Procedure 420P-2MT02 Turbine Overspeed Trip
- 10X May 26, 1986 72PA-2RX06 Nuclear and Thermal Power June 6,
1986 Calibration 50X 72PA-2ZZ01 Power Level Increase to 50X June 17, 1986 72PA-2RX18 CEA Shadowing Factor/Radial Peaking Factor Verifica-tion 50X June 20, 1986 72PA-2RX19 Shape Annealing Matrix and Boundary Point Power Correlation 50X June 24, 1986 73PA-2NA01 Loss of Offsite Power 40X
.June 26, 1986
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On June 25, a loss of offsite power test was conducted from 40Z power.
Prior to initiating the loss of offsite power, the test included verification of the fast transfer feature in shifting house loads, such as the reactor coolant pumps, to offsite power.
This step, although not part of the acceptance criteria, was included in the procedure to test a newly installed fast transfer scheme, after problems were identified during Unit 1 power ascension test program.
During the test, the transfer of electric power from the main generator to the offsite power supply did not occur as expected because the 13.8KV electrical buses were prematurely tripped off before the transfer could be accomplished.
House loads will be continued to be supplied from offsite power at Units 1 and 2 until the fast transfer scheme is satisfactorily tested.
Following a manually initiated turbine trip and opening of the normal offsite power supply breakers, primary parameters stabilized as expected after natural circulation was established.
Several equipment problems were encountered during the test which were identified by the licensee and
, incorporated in the post trip review report.
The more significant problems involved whether the non-operation of the steam bypass control system was proper, the inability to close three 13.8KV breakers during power restoration, and a momentary voltage drop in the "C" Instrument Bus power supply which caused a one-half trip of the engineered safety features systems.
The licensee's evaluation and corrective actions associated with the above problems, as well as other less significant items, was considered adequate.
Although preliminary, plant performance appeared to indicate that the test was successfully accomplished.
The inspector will review the test data after it is compiled by the licensee, as part of the routine inspection program.
The inspector reviewed startup test results to confirm that the tests were properly completed, test exceptions were properly addressed and resolved, data acquisition was completed as required, proper approvals had been made authorizing power level increase from 20Z to 50Z, and test results were submitted to the test results review group.
The following test packages were reviewed:
72PA-2RXOl
,Steady State Core Performance Test 20Z 72PA-2RX04 Shape Annealing Matrix and Boundary Point Power Correlation 20Z 72PA-2RX06 Nuclear and Thermal Power Calibration 20Z 72PA-2RX07 'SSS Calorimetrics 20%
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No violations of NRC requirements or deviations were identified.
7.
Preoperational Testin Unit 3.
a.
Test Procedure Review The inspector reviewed the following preoperational test procedures for technical and administrative adequacy:
92PE-3SV01 Loose Parts and Vibration Monitoring System Preoperational Test.
91PE-3CH04 Chemical and Volume Control System Charging Test.
The inspector found the 'procedures provided a clear explanation of the purpose, prerequisites for performance, appropriate sign-off steps, and quantitative or qualitative acceptance criteria as required.
The inspector witnessed the performance of preoperational testing to verify that the procedure in use was properly approved and adequately detailed to assure satisfactory per-formance; test instrumentation required by the procedure was calibrated and in use; work was performed by qualified per-sonnel; and results satisfied procedural acceptance criteria or were properly dispositioned.
E The inspector witnessed the performance of portions of the following system testing activities:
Procedure Descri tion 92PE-3SAOl Balance of Plant Engineered Safety Features Actuation System Panel Test.
No violations of NRC requirements or deviations were identified.
8.
Plant Maintenance Unit 1 and
a ~
During the inspection period, the inspector observed and re-viewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements, compliance with administrative and maintenance
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procedures, required QA/QC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectoi verified reportability for these activities was correct.
b.
The inspector witnessed portions of the activities:
n Unit
1 Time Constant Reset on Steam Generator Differential Pressure Bistable Trips.
following maintenance Dates Performed June 2,
1986 June
'3, 1986 Replacement of Letdown Filter CHN-19.
June 4, 1986 Troubleshooting Log Current Channel "B".
June 6,
1986 Unit 2 Descri tion o
Troubleshooting a Smoke Detector Alarm In Control Room Area.
Dates Performed May 29, 1986 o
Seal Injection Filter Seal Repair.
o Repair of Radiation Monitoring Unit 37.
Hay 29, 1986 Hay 30, 1986 o
Replacement of Indicating Lights on June 3,
1986 Valve SG-UV270.
o Replacement of "A" Motor Generator Set Bearings.
June 12, 1986 On Hay 29, at Unit 2 the inspector observed a maintenance craftsman grinding on the "B" Reactor Coolant Pump seal injection filter housing.
The craftsman was not wearing any protective clothing or respiratory protection.
The inspector was accompanied by a Radiation Protection representative who upon observing the work directed the individual to stop the gob.
A review of the work authorization revealed a radiation
,: exposure permit (REP)
had not been issued for the grinding operation.
'
review of the work order revealed it consisted of two parts; the original work order and an amendment.
The original work order authorized inspection and the checking of measurements of the seal housing and identified the need for a REP which had been issued.
The amendment which changed the work scope and identified the need for grinding had not been
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reviewed by Radiation Protection for a change in radiation controls.
The survey, which was taken by Radiation Protection following the work stoppage confirmed radiation levels were essentially background, with an absence of loose contamination on the tools and filter housing.
This condition did not require any special controls.
However, a review of the matter by the inspector indicated confusion in the communication between Maintenance and the Radiation Protection staff regarding radiation controls involved in the new work.
Although administrative procedure 75AC-9ZZ01, "Radiation Exposure and Access Control", adequately addressed the need for Radiation Protection review of revised work orders, the administrative procedure governing maintenance, 30AC-9ZZ01,
"Work Control", did not address the need for this review.
The licensee committed to revise 30AC-9ZZ01 by June 30, 1986.
The inspector will review procedure 30AC-9ZZOl after it is revised (529/86-20-01).
This matter was also discussed with licensee management in reference to a concern regarding procedure compliance which was recently in NRC inspection Report 50-529/86-17, dated June 13, 1986.
The issue of procedure adherence will be evaluated in followup to the licensee's response to the above violation, when submitted.
No violations of NRC requirements or deviations were identified.
9.
Diesel Generator (D/G) Brid e Crane Seismic Qualification Licensee followup to a request from the inspector to provide supporting documentation of the D/G crane seismic qualification revealed a discrepancy between the inputs used in the seismic calculation by the supplier, and those required by the design specification.
Specification Number 13-MM-066, includes the technical design requirements for "miscellaneous bridge cranes and hoists for Units 1, 2 and 3.
.Revision '1 to the specification, dated
'ovember 1,
1977, included the Diesel Generator Building safe shutdown eaithquake (SSE) verti'cal and horizontal acceleration response spectra for tha flook elevation (100') rather than the crane elevation (117.7')
response spectra'ecause it had not yet been developed.~
Although the proper.', response spectra was provided to the supplier 'in a'later revision '>to the specification, the seismic data report develope'd by t'e supplier used the incorrect 100'esponse spectra 'for'he" crane, "resulting in an inaccurate SSE loading calculation.
As 'a result of this determination, the licensee immediately per'formed a static loading calculation to ensure the D/G bridge, cranes
'met Seismic Category IX criteria.
The calculations, reviewed by Bechtel Engineering and documented on Engineering Evaluation Request 86-Z6-002, confirmed the seismic qualification of the cranes.
The insp'ector noted
'a similarity between the above failure on the part of the licensee or the'primary contractor to assure equipment procured satisfied the design specification, and a recent violation
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issued in NRC Inspection Report 50-530/86-03 conducted by a NRC Construction Appraisal Team.
The violation provided several several examples of instances where vendor supplied components did not conform to design specifications.
The licensee agreed to include this most recent example of failure to assure that procured equipment satisfies design specifications in the response 'letter being prepared to address the violation documented in 50-530/86-03.
10.
Installation of Instrument Com onents Unit 3 The inspector observed the installation of two pressure transmitters in Unit 3 to determine if instrument installations were accomplished in accordance with the latest specifications, drawings and procedures and that appropriate inspections were conducted and documented.
The following instrument installations were selected for inspection:
Instrument Transmitter
~Nerem Number Channel Plant Pro'tection System
'3JRCAPT101A 3JRCBPT101B Pressurizer Pressure Pressurizer Pressure The following specifications and Work Plan Procedures/Quality Control Instructions (WPP/QCI's) were used as a.basis for this inspection activity:
13 JM 702
. WPP/QCI 262.0
. WPP/QCI 302.0 Installation Specification for Instrumentation and Controls.
Installation of Vendor Supplied, Components.
Instrumentation Installation.
Based on the inspector's observations, the instruments were found to have been installed as specified by design documents and in accordance with approved procedures.
No violations of NRC requirements or deviations were identified.
Reactor Coolant S stem Pressure Isolatio'n Valve Leak Test Unit 2 On May 25, a safety infection actuation occurred at Unit 2.from a low pressurizer pressure condition caused by overfeeding of the steam generators subsequent to a reactor trip (NRC Inspection Report 50-529/86-17).
Technical Specification paragraph 4.4.5.2.2 requires that each reactor coolant system pressure isolation valve specified in Table 3.4-1 be demonstrated operable by verifying leakage to be within its limit within 24 hours following valve actuation due to automatic or manual action or flow through the valve, and within 72 hours following a system response to an engineered safety feature actuation signal.
A footnote associated with these conditions states that the provisions of Specification 4.0.4 are not applicable for entry into Mode 3 or 4.
At the time of the safety injection
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actuation, the licensee's interpretation of the Technical Specifica-tion required only that surveillance of the pressure isolation valves be performed within 72 hours of the actuation.
The licensee's interpretation of the Technical Specification did not prohibit entry into Mode 2 prior to completion of the surveillance test.
The reactor was taken to Mode 2 before the surveillance test was completed.
With respect to the 24 hour surveillance requirement, the licensee did not consider that water had flowed through the valve even though pressures downstream of one set of isolation valves (check valves)
had increased from approximately 600 psig to 1800 psig from high pressure safety injection (HPSI)
pump operation.
No flow into the reactor system was believed to have occurred because primary coolant pressure remained slightly above the HPSI pump shutoff head.
A review of the surveillance test by the inspector confirmed the test for pressure isolation valve leakage was completed within 72 hours and that the leakage measured was acceptable.
The licensee's action in taking the reactor to Mode 2 before completing the surveillance test on the pressure isolation valves, and the non-performance of leakage checks within 24 hours on several check valves through which HPSI pressure had been transmitted is considered an unresolved item and will be evaluated during a subsequent inspection (529/86-20-03).
No violations of NRC requirements or deviations were identified.
12.
Fire Protection Panel Miswirin Unit 3 On June 18, 1986, the licensee's Instrumentation and Control (I6C)
technicians were performing initial system checks of the Unit 3 Fire Detection System and discovered during energization of one of the
panels in the system that it had been miswired causing damage to the internal components of the panel.
Upon inspection of the remaining 17 panels, two additional panels were found to be similarly miswired.
No damage to these panels occurred in that neither had been energized.
Review of construction records associated with the three panels revealed all were apparently miswired during field reinstallation of vendor supplied circuit boards which had been removed to support Unit 1 operations.
Due to a number of previous instances of potential tampering ad noted in NRC Inspection Report 50-530/86-07, the licensee did'ttempt to determine if this instance represented an additional case of vandalism.
The licensee concluded there was no evi'dence that the wiring in, these panels was installed to intentionally cause damage.
All indications were that the panels were wired in error when vendor supplied 'components were installed.
Although somewhat isolated in nature, licensee construction management did emphasize to Bechtel supervisory personnel, the need to ensure craft workers maintain a high level of quality while performing construction activities.
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13.
Licensee Event Re ort (LER) Followu Units 1 and 2.
a.
The following LERs were reviewed and closed.
The inspector verified that reporting requirements had been met, root causes had been identified, corrective actions were appropriate and violations of Technical Specifications had been identified.
Unit
Descri tion LER 85-06 Loss of Offsite Power (LOP) Due to Inadvertent Tripping of Circuit Breaker.
LER 85-21 LER 85-23 Fire Protection Header Isolated to Containment.
Inadvertent Actuation of Emergency Safety Feature System.
LER 85-26 Diesel Generator Failure to Attain Required Frequency Within 10 Seconds.
LER 85-29 LER 85-34 Failure to Inspect Automatic Fire Doors.
Failure to Record Pressurizer Cooldown Rates.
LER 85-39
,
Operator Error in Performance of Safety Surveillance.
LER 85-48 LER 85-49 ECCS Throttle Valves Missed Surveillance.
Reactor Trip Due to Failed Control Element Assembly Calculator.
Unit 2 Description LER 86-06 LER 86-09 LER 86-10 ESF Actuation Caused by Personnel Error During
, Troubleshooting of a Radiation Monitor.
N Main Steam Isolation System Inadvertent Actuation Due to Incorrect Amperage Fuse.
1y Inoperable Containment Isolation Valve Due to Personnel Error.
LER 86-20 Inadvertent Actuation of Balance of Plant Engineered Safety Feature Actuati'on System.
b.
The following LERs remain open or were reviewed in more detail.
Unit
(0 en)
LER 85-38 "Ino erable Fire Detectors".
This LER, dated July 5, 1985, addressed the fact that on May 30',
1985, Containment hourly temperatures were not recorded
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The fire detectors in Containment had been declared inoperable at the time.. The licensee considered this event to be a "potential Technical Specification deviation" and stated that a supplemental LER would be submitted following further evaluation of the facts.
The inspector informed the license that no supplemental report was ever submitted.
The licensee acknowledged the inspector's comment and has initiated steps to prepare and submit a followup report.
The inspector's review of the LER, as well as the administrative difficulties associated'with preparation of a timely supplementa1 report will be, addressed in the final closeout of this LER.
(Closed)
LER 85-50 "Isolation of Plant Protection Channel".
On July 17, 1985, a containment pressure transmitter isolation valve was discovered closed.
This transmitter p'rovided one channel of the two out of four logic used to activate the containment spray portion of the engineered safety features actuation system.
The licensee investigated to determine when the channel was isolated and if any of the other channels had been isolated.
The actual date the channel was isolated was indeterminate.
The other channels were found to be operable.
The licensee took corrective action by revising appropriate calibration procedures to include more specific steps regarding the restoration to service of instrument channels.
Other corrective action taken included retraining of workers.
This LER is closed.
Unit 2 (0 en)
LER 86-02 "MSIS Actuation Due to an Incorrect Am era e
Fuse '.
On February 20, 1986, a Train "A" Main Steam Isolation System (MSIS) actuation occurred.
The actuation occurred during initial performance of a surveillance test.
The cause of the event was an undersized fuse.
The installed fuse was a four amp fuse, whereas the design calls for an eight amp fuse.
The correct size fuse was installed, and an investigation to verify the installed fuses were as required by design in other ESF actuation systems in Unit 2 was completed.
Three additional incorrect fuse sizes were identified.
An investigation was also initiated for Unit 1, to verify that the fuses in the system were as designed.
There were no incorrectly sized fuses found in Unit 1.
A similar event is reported in LER 86-09.
The licensee has not yet completed a review into the cause of how and when the incorrect fuses were installed.
Further corrective action by the licensee included a training session about fuse installation.
This item will remain open until the root cause is adequately researched.
This LER remains ope I ) I I'h*(
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14.
Review of Licensee Action on
CFR Part 21 and 50.55(e)
Construction Deficienc Re orts.
The following potential
CFR Part 21 and 50.55(e)
item was re-viewed by the inspector for reportability and to determine the thoroughness of the licensee's corrective actions.
(Closed)
DER 86-14 "Veld Failure of Pipe'u ort,Structure".
ti During a snubber surveillance inspection on March 13, 1986, the licensee identified a failed pipe, support (1SG-005-H008)
on a 24 inch main feedwater line in Unit 1.
The root'ause of the failure was evaluated by the licensee to have been inadequate consideration of the effects of localized flange bending and thermal displacement of the piping system in the original design of the support.
During the review of similar pipe 'supports, ten additional supports were identified as being underdesigned due to a failure to adequately account for one or the other of the effects that attributed to the support failure in Uni't 1.'
review by the NRC Office of Nuclear Reactor Regulation of the licensee's root cause analysis and subsequent corrective actions is documented in Supplement No.
10 to the Safety Evaluation Repo'rt for Palo Verde Units 1, 2 and 3.
The licensee's assessment of the root cause item and corrective actions have both been found to be acceptable.
This item is closed.
15.
IE Bulletins and Information Notices a.
(Closed)
IE Bulletin 85-01:
"Steam Bindin of Auxiliar Feed water (APW)
Pum s '
Units 1 and 2.'his Bulletin discusses the potential for AFW pumps to become inoperable as a result of steam binding.
The inspector reviewed the actions taken by the licensee and confirmed that the recommendations noted in the Bulletin were considered by the licensee.
The actions involved the installation of temperature sensitive tape on the discharge pipe of the "N" pump, and a revision to procedures requiring shiftly monitoring of the pipe temperature.
The licensee does not consider the "A" and "B" safety related pumps to be susceptible to steam binding because of two normally closed valves plus three check valves on each discharge line which isolate main feedwater from the pumps.
,The actions taken by the licensee were formally communicated to the NRC as requested in the Bulletin.
NRC Inspection Report 528/85-21 also documents inspector followup efforts regarding this Bulletin, in accordance with NRC Temporary Instruction 2515/67.
This Bulletin is closed for Units 1 and (EKI ) gr
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(Closed) Information Notice 85-91
"Load Se uencers for Emer enc Diesel Generators
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Units 1, 2, and 3.
The Information Notice was provided to advise licensees of potential design deficiencies that could bypass load sequencers during simultaneous loss of offsite power with an ESFAS.
The Information Notice addressed a condition in which an actuation signal 'combined with the loss of the unit auxiliary transformer:could cause the engineered safety feature equipment to be loaded in a single block, rather than sequenced on to the emergency diesel generators, which could result in a loss of the diesel generators.
The licensee has determined that the logic associated with the loss of voltage on the ESF -electrical busses, and the load sequencer are different than those associated with the Information'Notice,
'and the potential to overload the diesel generators in the fashion stated does not exist.
C ~
(Closed) Information Notice 85-49 "Rela Calibration Problem"-
Units 1, 2 and 3.
This Notice provided information on calibration problems of an Agastat Time-DelayRelay.
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This Notice dealt with the specific problem of calibrating the Agastat in a different position than it is installed.
This problem may result in'ignificantly different times (calibrated vs. installed) to engage the relay.
The licensee initially addressed the problem with Electrical Maintenance Procedure 32MT-9ZZ75.
This procedure was cancelled by the license'e on May 30, 1986.
The procedure was replaced for the operating units by periodic maintenance (PM) work orders, which are based on equipment number.
For Unit 3, which is still under construction, this notice is addressed by Startup Procedure 93EG-OZZ23.
Both the PMs and the Startup Procedure note the need for determining the relay times in the installed position. If the Agastat is to be bench calibrated, the PMs specifically state that the relay must be tested in a position identical to its mounted position and the Startup Procedure also states that the relay must be tested in its installed position.
These procedures adequately address the concerns of the notice.
This item is closed.
16.
Review of Periodic and S ecial Re orts.
Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.2 were reviewed by the inspecto c I t d
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This review included the following considerations:
the report contained the information required to be reported by NRC require-ments; test results and/or supporting information were consistent with design predictions and performance specifications; and the validity of the reported information.
Within the scope of the above, the following reports were reviewed by the inspector.
Unit
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o Monthly Operating Report for April 1986.
No violations of NRC requirements or deviations were identified.
17.
Alle ation RV-85-A-032 Characterization On May 31, 1985, a former contract Startup engineer expressed a
safety concern related to the radiation monitoring system (RMS) at Units 1 and 2.
Although no specifics were provided, the individual stated that he had provided his detailed concerns to the licensee's Quality Assurance (QA) Hotline organization, and the ensuing investigation was mishandled by 1) allowing Startup management to
'attend interviews of Startup personnel, and 2) the use of a tape recorder, both of which prevented a candid interview.
Additionally, the individual stated that Startup engineers are afraid to raise problems to management because of schedular pressures; and principal engineers responsible for RMS are not adequately knowledgeable.
Im lied Si nificance to Plant, Desi n, Construction or 0 erations.
At the time the concern was raised, Unit 1 was operational, Unit 2 was in the preoperational testing phase, and Unit 3 was in construction.
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Problems associated with the RMS, as well as a lack of knowledge on the part of responsible engineers could affect the operability of the equipment, a portion of which is safety related.
o Mishandling of the allegation followup by the licensee's Hotline staff could indicate a degree of insensitivity toward investigating worker concerns.
o Excessive schedular pressure within Startup, which prevented problems from being surfaced to management could affect the adequacy of the testing program, and could ultimately have an impact on the reliability and operability of safety related equipmen ) tj"j 4
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Assessment of Safet Si nificance a.
RMS Technical Concerns The inspector reviewed, in detail, the licensee QA Hotline investigation (Hot 85-33) into the alleger's concerns.
The concerns were first presented to the licensee, in April, 1985, with the investigation being concluded in January, 1986.
The licensee sent a certified, return receipt letter to the alleger documenting the Hotline findings on January 21, 1986.
The letter was returned unclaimed on January 27, 1986, and no further communication between the licensee and the individual has occurred.
The inspector found the licensee's investigation to be very thorough, having involved approximately 800 man-hours.
Eighteen technical concerns associated with RMS at'nits 1 and 2 were provided by the alleger to the licensee.
The concerns dealt with events during the prerequisite and preoperational testing phase at each unit, covering the period June, 1984 through April, 1985.
Of the 18 technical concerns, eight were at least partially substantiated.
In almost each case, the concerns which were found to be valid had already been identified and documented in an appropriate method for resolution; such as entry on the test exception log.
None of the substantiated concerns were found -to have more than minor significance.
The inspector independently reviewed the majority of technical concerns, and concurred with -the licensee's assessment.
As a result of the Hotline investigation, a counseling session was conducted by the licensee with one Startup individual to reconfirm mandatory adherence to the licensee's quality assurance policies.
Additionally, the'icensee's QA Monitoring Department significantly increased its'bservations of RMS testing activities from August, 1985 through March, 1986.
No significant problems were identified.
j Due to difficulties encountered during the preoperational testing phase, the RMS at Unit 2 was turned over to Operations in October, 1985,in an effort to improve the licensee's effectiveness in resolving hardware and testing problems.
All of the previous preoperational tests were reperformed under Operations jurisdiction.'he inspector reviewed the following completed preoperational tests, and confirmed all Technical Specification required radiation monitors were operable prior to initial criticality.
o 73PE-2SQ02
"Post Accident Radiation Monitoring Test Procedure".
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Operability of radiation monitors at "Unit 1 has been demonstrated'hrough the performance of surveillance testing on regular intervals.'he'nspector did not identify any link between instances of RMS inoperability during 1985 and the alleger's concerns during the preoperational testing phase.
b.
En ineer Qualification
- I A concern regarding the qualification of, one,Startup engineer was provided to the Hotline.
That individual was found through th'e licensee's investigation to be a qualified engineer holding a Master's 'degree in electrical engineering with ten years nuclear instrumentation and control experience.
The inspector verified the individual's'education and experience.
c.
En ineers Hesitant to Raise Problems to Mana ement The licensee conducted interviews of 10% of the certified Startup engineers (39 individuals) to determine whether the engineers felt hesitant to raise problems to management due to schedular pressures.
These interviews were conducted confidentially, with no Startup management present.
No engineers stated any reluctance to raise concerns to their management.
The inspector reviewed the interview sheets for each individual.
d.
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Hotline Handlin of Investi ation The inspector confirmed that Startup management was allowed to attend the initial investigative interviews of Startup engineers, and that a tape recorder was in use.
Subsequent to the initial set, interviews were conducted confidentially and a
tape recorder was not used.
Many of the initial interviews were reconducted after several engineers criticized Startup management's presence.
Staff Position The allegations associated with 1) engineer qualification, and 2)
engineer hesitancy to raise concerns to management, were not substantiated.
The technical concerns were substantiated, in part; however, the safety significance was minimal.
The licensee's actions as a result of the substantiated concerns, consisting of personal counselling and increased QA monitoring, were considered appropriate.
The concern over Startup management's,'presence at the interviews was substantiated.
The inspector informed QA management that the decision to allow Startup to attend could clearly have had a
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chilling effect on the engineers, considering the type of questions that were asked.
Further, the inspector stated that the credability of the Hotline program could be damaged by,the perception that QA was not sufficiently sensitive to the alleger's concerns.
The inspector has performed reviews of many Hotline staff investigations, and has concluded that, in general,'heir followup'f worker concerns is thorough and objective.
QA management stated that all subsequent Hotline interviews will be confidential, unless good cause is shown to deviate from that intent.
Action Re uired None.
18.
Unresolved Items Unresolved items are matters about which more information is re-quired to determine whether they are acceptable, violations or
.deviations.
An unresolved item is addressed in this inspection in paragraph 11 of this report.
The inspector met with licensee management representatives period-ically during the inspection and held an exit on July 1, 1986.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee representative E
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