IR 05000397/1989023
| ML17285A799 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 09/21/1989 |
| From: | Crews J, Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A796 | List: |
| References | |
| 50-397-89-23, NUDOCS 8910240351 | |
| Download: ML17285A799 (44) | |
Text
Report No:
Docket No:
Licensee:
Facility Name:
Inspection at:
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
50-397/89-23 50-397 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
WNP-2 Site near Richland, Washington Inspection Conducted: July 10 - August 23, 1989 Inspectors:
C. J.
sted, Senior Resident Inspector R.
S e
, Resident Inspector J.
J ly12 s
Sensor Reactor Engineer 13, 1989 (Paragraphs 11 - 16)
DteSgn D. F. Kirsch, Chief Reactor Safety Branch July 12 - 13, 1989 (Paragraphs 11 - 16)
Approved by:
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son, se Reactor rojects Section
ate
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Summary:
I I'ns e'ction on Jul 10 - Au ust 23,'1989 50-397/89-23 Two non-ected v~olat>on dy t
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room operations,'",licensee action on previous inspection findings, engineered safety feature (ESF) status, surveillance program, maintenance program, licensee event reports,special, inspection topics, procedural adherence, and review'of,, p'eriodic reports.
Also included region-based inspection of design engineering activities and the root cause assessment program.
During this inspection, Inspection Procedures 30703,'61726, 62703, 71707, 71710, 90712, 90713, 92700, 92701 and,92702',were covered.
I Results:
One violation was identified --'ailure to follow work procedure when tightening compression fittings; on instrumentation tubing (paragraph 6.c).
s were identified by the licensee (paragraph 10).
89i024035i 89i005 PDR ADOCK 05000397
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-2-Two previously identified items, and four LERs were closed:
one new enforcement item,was'pene I
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1.
Persons Contacted DETAILS 2.
D. Mazur, Managing Director L. Oxsen, Assistant Managing Director for Operations D. Bouchey, Director, Licensing and Assurance J. Burn, Director, Engineering L. Harrold, Manager, Generation Engineering C. McGilton, Manager, Safety and Assurance L. Grumme, Manager, Engineering Assurance
- C. Powers, Plant Manager J. Baker, Assistant Plant Manager K. Cowan, Nuclear, Safety Assurance Manager C. Edwards, Quality Control Manager R. Graybeal, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager
- D. Kobus, Quality Assurance Manager
- R. Koenigs, Technical Manager S.
McKay, Operations Manager J. Peters, Administrative Manager W. Shaeffer, Assistant Operations Manager R. Webring, Assistant Maintenance Manager N. Wuestefeld, Assistant Technical Manager J. Tellefson, Manager, Engineering Administration R. Vosburgh, Engineer, Safety Reliability Analysis W. Roberts, Principal Engineer (Electrical)
J. Civay, Principal Engineer (Electrical)
G. McHenry, Designer The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality assurance, and management personnel.
+Atternded the Exit Meeting on August 11, 1989.
Plant "Status At the s'tart of;the inspection period, the plant was operating at 100%
and remained at that power level until August 6.
On that. date the reactor,,",tripped on" low reactor vessel level following a trip of the "B" react'or feedwater'pump 'during a monthly preventive maintenance test (see paragraph, 8 for,, additional details).
The plant was placed in cold
, shutdown (Condition 4) to repair several steam leaks and perform other
, maintenance during restart 'efforts.
The plant was restarted August 8,
'nd thegenerator was synchronized to the grid on August 9.
The plant was increasing power, on the fuel preconditioning limits on August
, when'Divisions. I 5 II of the electrical distribution system were declared>inoperable because of fuse-breaker coordination problems.
, Technical Specification 3.0.3 was entered, an Unusual Event was declared, and the plant.was shut down (see paragraph 10 for-details).
Necessary inspections and corrective action were completed on motor-t
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The unit was restarted on August 16 and synchronized to the grid that same day.
On August 17, during a power level increase, the reactor scrammed from 68K power due to an inadvertent trip caused by an instrumentation and control technician error (see paragraph 8 for additional details).
The plant was restarted later that day.
During the ensuing power increase on August 18, the "B" reactor feedwater pump (RFP)
was taken out of service due to high vibra'tion. It was later determined that the RFP had "wiped" the main thrust beating.
Reactor power was limited to 71% while operating on the single "A" RFP.
Power remained at this level through the end of the reporting period.
3.
Previousl Identified NRC Ins ection Items 92701 92702
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The inspectors reviewed,.records, interviewed personnel, and inspected plant conditions'relative. to,licensee actions on previously identified
'finspectioh finding's k',
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Closed Deviation 397/88-32-02:
Failure to Complete Calibration of Diese Generator Tan Leve per Commitment Date.
In'esponse toa 'Notice of Violation (IR 397/87-19)
the licensee stated that to me'et the Date of Full Com liance, the calibration of diesel generator fuel oi tan eve instrumentation would be accomplished by July 20,'988.
On September 21, 1988, it was determined that these instruments had not been calibrated.
The licensee determined that the cause for the missed calibration was a failure in communicating the requirement to the proper department.
All the level instruments were calibrated by October 1, 1988, and the compliance organization commenced computer tracking the commitments and issuing a monthly and weekly look ahead notice for all commitments.
This item is closed.
b.
Closed Unresolved Item 397 89-08-01:
Rod Drift Root Cause.
The root cause report for the, control rod drift event on March ll, 1989 was reviewed and concerns were addressed in IR 397/89-11.
The licensee was requested to correct or provide additional information on the identified items within 30 days of the report issue date.
The licensee provided a revised report dated July 27, 1988 which addressed the concerns of IR 397/89-11.
This item is closed.
4.
0 erational Safet Verification 71707 a.
Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room
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whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Exposure Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
(10) Plant Housekee in
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Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.,
Dates (11) ~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plans was in accordance with site procedures, that the search equipment at the access control points was operational, that the vital area portals were kept locked and alarmed, that personnel allowed access to the protected area
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En ineered Safet Feature S stem Walkdown 71707 71710)
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During the walkdown oftthe,systems;,
item's such as, hangers, supports, electrical power
upplies';'cabinets;-'nd cables were inspected to determine that they
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', The in'spe'ctors also verified that the system valves were in the required
". 'osition and locked as 'appropriate.
The local and remote position
, indi'cation and controls were also confirmed to be in the required
"position 'and operable.
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Accessible-portion's of,.".'the following systems were walked down on the indicated dates.
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~Ss tee Diesel Generator Systems, Divisions 1, 2, and 3.
Hydrogen Recombiners Low Pressure Coolant Injection, (LPCI)
Trains "A", "B", and "C" Low Pressure Core Spray (LPCS)
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'Scram Discharge Volume 'System Standby Liquid Control (SLC) System
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Standby Service Water System 125V DC Electrical Distribution, Divisions 1 and
250V DC Electrical Distribution No violations or deviations were identified.
July 21, August 3 July 21, August
July 17, July 17, August 2 July 17, August 2 6.
Surveillance Testin 61726 a ~
b.
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.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
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~d 7.4.3.6.20 Control Rod Block RRC (Reactor Recirculation)
Flow B
Dates Performed July 20 7.4.4.1.1 RRC Flow Control Valve Operability July 27 7.4.3.10.3 Loose Par ts July 30 co 7.4.4.1.2 Jet Pumps July 30 7.4.8.1.1.2.1 Diesel Generator Operability July 30 7.4.1.3. 1.2 Control Rod Operability August
While observing a surveillance test on reactor recirculation control instrumentation on July 20, the inspector noted that one of
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,%e the test connection valves rotated when the technician tightened the fitting on the test connection.
This valve was attached to the instrumentation piping by a swaged fitting.
When questioned about the movement of the valve the technician manually rotated the valve back into the correct position and rotated another valve to provide additional clearance.
When the technician completed the surveil-lance test he tightened the swaged fitting using an adjustable wrench on the valve body and a fixed wrench on the connecting nut; the technician told the inspector that he had tightened the fitting one flat.
When questioned by the inspector, the technician stated that he did not consult the procedure before tightening the fitting.
Plant Procedures Manual (PPM) procedure 10.24.12,
"Instrument Tubing and.Fitting Usage Instructions," specifies that two "proper sized" wrenches be used, one on the "connector of the fitting" - not the valve body - and the other on the "connecting nut".
For the type of fitting used in this application, the procedure specifies that when retightening the fitting, it should be advanced past the original position by only 10-20 degrees (less than one-third of a flat).
Over-tightening of the compression fitting can cause failure of the tubing.
Manufacturers instructions and the licensee's procedures specify the maximum turns that the connecting nut may be 'applied to the fitting.
In conversations with other maintenance technicians, the inspector determined that the above procedure was not very well understood by the technicians.
This was discussed with maintenance supervision and management.
The above failure to follow the maintenance procedure in the restoration of the equipment following the Technical Specification surveillance procedure is considered a
violation of Technical Specification 6.8.1 (Enforcement Item 89-23-01).
One violation was identified.
Plant Maintenance 62703 a.
During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required gA/gC involvement, proper use of safety tags, proper equipment alignment and use of ju'mpers, personnel qualifications, and proper retesting.
The inspectors ver ified that reportabi lity for these activities was correct.
1, 1'.
'he inspectors witnessed portions of the following maintenance activities:
I'eplace Main Steam Line Rad Monitor Drawer per AV 2029 Dates Performed July 20
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Replace Diesel Starting Air Compressor, Solenoid per AS 1281 Reactor Feedwater Pump "B" Wiring Replacement for Vibration Trips Repair of standby service water valve motor operator SW-V-MO-2A Installation of fused circuit around MC-8BA feeder breaker per AS 1836 Disassemble/Reassemble SW-V-MO-2B per AS 1856
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t 8.
Reactor Tri s 93702 July 28 August 9 August
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On, August 6, 1989, at 8:27 p.m., the reactor tripped from 100Ã power on low reactor pressure vessel water level (Level 3).
A monthly preventive maintenance (PM) test was in progress on the "B" reactor feedwat'er pump (RFP) oil system.
The operator was testing the automatic start features of the auxiliary and emergency oil pumps when lubrication oil pressure dropped below the RFP trip setpoint.
Following the feedpump trip, the reactor recirculation control system attempted to run back reactor power to approximately 74K.
A mismatch between reactor power and feedwater flow resulted in the low reactor vessel level.
.'I The monthly PM test had been performed successfully on July 7, with plant power at 97K.
Investigation into the causes of the low oil pressure and the mismatch between recirculation flow runback and feedwater flow was conducted by the plant staff before restart.
No other abnormal conditions were noted.
Plant engineers and techni-cians determined that the cause for the low oil pressure was entrapped air in the instrument lines being released during the test.
The monthly PM test starts the standby oil pump by simulating a low pressure condition for the pressure sensor.
This is accomplished by opening a solenoid valve downstream of an orifice and allowing the pressure at that point to be reduced to near zero.
The actual system pressure is maintained by the orifice, but the pressure sensor is activated by the reduced pressure.
During this test, an ait bubble, thought to be due to incomplete venting of the oil system (following bearing maintenance just prior to the plant startup from the outage),
was believed by the licensee to have migrated through the instrumentation system.
Once this air bubble reached the orifice and solenoid valve, the change in density of the fluid through the orifice caused an actual drop in oil pressure at the remaining instruments which monitor pressure upstream of the orifice, resulting in the RFP tri u(
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When the RFP tr'ippe'd, the recirculation control system initiated a power reduction to about 74K power.
This reduction was accomp-lished by closing the, flow control valves to approximately 30%
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The remaining RFP was limited to about 73K feedwater flow due to its high speed limit being set at 5200 rpm.
The licensee's investigation into the feedwater flow and steaming rate determined that the mismatch was due to independent changes made to both systems.
The RFP upper speed was limited due to speed controller span limitations.
The low r pm limit was reduced to correct an overfilling condition of the reactor pressure vessel following a scram.
When the low limit was reduced, it also reduced the upper speed limit because the controller has a fixed span (approximately 3400rpm).
This reduction in the upper speed limit of the RFP was evaluated as being satisfactory because it also increased the margins for the critical power ratio for a failed-open speed con-troller.
The runback position for the flow control valve was determined to have been set at about 20Ã open during initial startup testing.
The reason for the change to about 30K open was determined to be an error during transposing of test data to the instrumen-tation calibration procedure in 1986.
Prior to resumption of power operations, the flow control runback was reset to 20K open, which will correspond to a reactor power level of approximately 64K, and the feedpump high speed limit remained at 5200 rpm.
The inspector discussed the apparent incomplete work procedure with management.
The work control procedure did not recognize the venting of the instrumentation line following maintenance; members of the licensee's staff told the inspector that the procedure would be revised.
On August 17, 1989 at 8:19 am, the reactor scrammed from approxi-mately 67K power on an indicated low reactor pressure vessel (RPV)
water level (Level 3).
Surveillance test PPN 7.4.3.3.1.22, Auto-matic Depressurization System (ADS) Trip System
"A" Reactor Water Level Low-Level 3 CFT/CC, was in progress at the time.
The test was being performed on NS-LIS-38A, which shares a common variable leg with NS-LIS-24A and NS-LIS-24B.
These latter two switches provide RPV Level 3 scram signals to the Reactor Protec-tion System (RPS) for both trains of RPS.
Two instrumentation and controls ( ISC) technicians were performing the procedure, in a high noise area, with one technician reading procedure steps to a second technician located inside a radiological barrier.
Step 32 of the procedure had just been completed when the technician performing the valve manipulations thought he was told, by the technician reading the procedure,,
to open valve V-52, the variable leg isola-tion valve.
What had really been said was that step 32 had just been completed.
~r'hen V-52 was'pened into 'the depressurized NS-LIS-38A, it caused a
pressure pulse that'influenced NS-LIS-24 A and B through their com-mon variable leg.
This caused them both to momentarily sense low RPV water level, below the Level 3 scram setpoint, and a reactor
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scram ensued.
The shared variable leg design is common in General Electric BWRs.
The scram had no complications and was handled well by the Opera-tions staff.
Actual RPV level did not go below 22 inches, and no engineered safety features were actuated.
A Restart Decision Committee meeting was convened at I:00 p.m.
on August 17 to discuss: (I) plant response and behavior during and after the scram and (2) the root cause of and corrective action for the initiating event.
The licensee concluded that the plant and operators responded as expected and instituted a number of interim corrective actions including:
Placing a temporary hold on the performance of 'all I&C surveil-lances that involve valving instruments in and out of service.
Designating certain I&C technicians to perform critical surveillances.
Providing supervision for critical surveillances that involve valving instruments in and out of service.
A requirement that all persons involved in a surveillance test have a copy of the procedure.
Use of confirmation actions such as "repeat backs."
n Possible'isciplinary action.
f Long term corrective actions will include formation of a dedicated surveillance, crew, increased training, and any interim corrective action,,that proves to be beneficial.
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I'I 9.
Reactor Power Limits 61702 61705, 61706, 61707
,I Following the power escalation to 100% and the achievement of equi-librium xenon, the reactor power calculations were performed to routinely assess core parameters.
The 'local power range monitors were calibrated through the traversing incore probes (TIPs) using the on-demand computer program (OD-1), and the various average power range monitors (APRMs) were used to calculate the local in-core conditions.
The inspector reviewed the computer outputs for the various hourly calculations using the calibration values obtained from the OD-1.
No discrepancies were noted.
10.
Plant Shutdown and Unusual Event 93702 On August 8, a feeder breaker to a non-safety related motor control center (NCC) tripped as a result of a fault on a hoist, causing the loss
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of all loids on the MCC, coincident with the blowing of the hoist fuse.
The licensee s investigation into this event indicated that a coordi-nation problem, existed between circuit breaker and fuse response timing.
Further licensee investigation indicated that feeder breakers for some safety-related NCCs had instantaneous trip characteristics that were not coordinated'ith the fuses on the individual loads fed by these NCCs.
The licensee determined that a separation problem existed between Class
'E loads and non Class 1E loads powered from these NCCs, in that a fault
'on a non-Class lE load could cause the MCC feeder breaker to trip and cause a loss of all Class 1E loads associated with that NCC.
Upon'aking this determination, on August ll, the licensee declared Divisions I and"II,of,the electrical distribution system inoperable and entered Technical Specification 3.0.3.
A plant shutdown was initiated and an Unusual Event.was,declared as required by Emergency Plan imple-menting procedures.
Cold shutdown was reached about 2:00 a.m.
on August 12 and the Unusual Event was terminated.
Six safety related MCCs were affected by this design deficiency.
Five of them were corrected by installing jumpers around the feeder circuit breaker, effectively removing the breaker from the circuit.
On the sixth MCC, credit for the feeder breaker had been taken to ensure con-tainment penetration conductor overcurrent backup protection, and was so required by the Technical Specifications.
Therefore, a fused circuit was installed in place of the feeder breaker on this MCC to ensure positive backup protection for containment conductor overcurrent.
A Technical Specification amendment to permit this change was sought by the licensee and was received from the NRC on August 16, 1989.
Two other issues arose during the outage to correct the above problems.
One involved other electrical separation problems that were discovered as the result of an Operating Experience Report (OER) review.
WNP-2's electrical separation design criteria require non-Class lE loads to have double fuses to provide adequate electrical separation from Class 1E equipment.
An exception is provided for "prime" circuits, which are controlled to ensure routing with only one train of Class lE circuits.
Six potential problem areas were identified involving loads on inverter IN-3 and power panel PP-8AE.
Three of these potential problems were later resolved as either being prime circuits or actually having double fuses.
The remaining three circuits were found to have only single fuse protection.
One circuit in the Digital Electrohydraulic Control (DEH)
system was never upgraded to a prime circuit as originally intended.
Another circuit associated with Loose Parts Detection was not downgraded from a prime circuit 2 1/2 years ago when it was split and wide range neutron monitoring circuitry was added.
The third circuit, associated with radiation monitoring equipment, could not be readily determined to be a prime circuit. Extra fuses were added to the load side cabling for each of the latter three problems.
The second issue resolved during this short duration outage concerned motor operators on motor operated valves (NOVs).
Standby service water valve SI4-V-2A would not fully open as designed when the associated standby service water pump was started.
The "A" train of standby
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reviewed and approved by senior licensee management, and issued by the Director, Engineering on December 16, 1988.
The plan included what senior licensee management characterized as
"an ambitious schedule" for the completion of essentially all tasks during a three-year period ending in 1991.
A review of the progress of individual tasks of the EIP revealed that significant progress had been made in, most areas.
Areas in which significant progress had been made included:
a.
Technical leadership - The position of Group Supervisor has been reestablished and all (12) positions have been filled through internal selections.
This has substantially reduced the span of control (to approximately 7 to 10) of first level supervision.
The organizational structure within engineering has been changed to im-prove work assignments on a common basis in terms of work scope and performance of work.
A Design Review Board has been established to
'ontrol top tier design criteria and engineering standards, and to perform technical reviews of engineering work.
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b.
Scheduling and Planning - Scheduling and planning personnel have been assigned 'to each discipline group within Generation Engineer-ing.
Work schedules have been developed to the individual engineer level.
Increased resources (50K of original design effort) have been allocated for design review, and the Generation Engineering Department has gained access to the Project-2 computer for work planning'nd schedul.ing.
Plant modification priorities and schedules by engineering have been made a part of the plant-wide integrated schedule process.
c.
Interorganizational interfaces - The licensee has implemented a
Problem Evaluation Report (PER) mechanism to identify problems for prompt evaluation and initia'tion of corrective action.
These reports are discussed on a daily basis at both the morning meeting and a subsequent Management Review Committee (MRC) meeting.
A representative of the Gener ation Engineering Department attends the morning meeting and is a member of the recently established MRC.
The MRC serves as a daily interface mechanism for the coordination of actions or problems identified through the PER program.
quar-terly meetings have been established between plant management and engineering management to address interface needs, interface requirements, and performance issues.
A Modification Review Committee has been established to provide a vehicle for the coordination of plant modifications.
The committee is headed by the responsible design engineer for the proposed modification, and committee membership includes representatives from Plant Opera-tions, Maintenance, Outage Planning, gA and other departments affected by the proposed change.
The committee is established prior to conceptual design and continues through final installation and testing.
A recent decision was also made to transfer dedica-tion activities for commercially procured spare and replacement parts from the Plant Technical Support staff to the Engineering staff to improve interface effectiveness in the area of procuremen \\
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Design Process
- Revisions have been made to thirteen engineering procedures most often used.
Procedures have been issued to more clearly define checking and verification requirements, an area in which significant weaknesses have existed in the past.
A Design Review Board (DRB) and Procedure Advisory Committee (PAC) have been established to develop engineering standards that define and con-trol top level criteria for plant systems (DRB) and recommend and/
or implement changes to improve the effectiveness of engineering procedures (PAC).
A significant effort by the DRB has been the development of a Nuclear Operations Standard covering configuration contr ol.
Numerous procedures have been revised and checklists developed covering design review and drafting and engineering work practices.
As previously discussed, commercial grade dedication responsibili-ties have been assigned to Engineering.
Engineering management stated that procedures covering this activity are to be revised to be consistent with guidelines developed by the Electric Power Research Institute (EPRI).
Licensee management stated that budget levels for implementation of the EIP will be reduced for FY 1990, due to unusual expenditures in such areas as replacement of the plant training simulator and the purchase of replacement turbine rotors.
The extent of such reductions in terms of schedule impact on implementation of the EIP and on related engineering initiatives such as the Design Basis Documents (DBD) program will be discussed with the NRC staff in a meeting to be scheduled in the near future, according to licensee management representatives.
No violations or deviations were identified.
12.
Electrical Wirin Dia ram U
rade Pro ram
.
The licensee has initiated a program to upgrade electrical wiring diagrams (EWDs) for the plant.
The scope and implementation of this program were examined.
Discussions were held with Generation Engineer-ing staff engineers involved in the program and facility records were reviewed, from which the following information was obtained.
Through a joint effort by Plant Operations, Plant Technical and Elec-trical Engineering representatives, plant system EWDs were assigned to priority I,. 2, and 3 groups.
Priority I EWDs include those (690 total)
associated"with twelve safety-related plant systems, and are scheduled
'for revision/upgrade during 1989.
FaciIity records showed that to date, through June 30, a total of 428 priority I EWDs had undergone upgrade and revision.
Electrical engineering representatives were confident all priority 1 EWDs would be completed during 1989.
Facility records showed that a total of 1547 priority 2 EWDs and approximately 1300 priority 3 EWDs had been identified within the upgrade'program.
Although a firm schedule had not been established for the completion of priority 2 and
EWDs, licensee representatives estimated that the upgrade program would continue through 1992.
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Discussions with licensee personnel revealed that a substantial reduction in the number of EWDs had resulted during the upgrade program to date through the consolidation of NSSS, A-E, and contractor drawings.
No violations or deviations were identified.
Individual Plant Examination Pro ram Discussions were held with licensee personnel involved in the Individual Plant Examination (IPE) program for severe accident vulnerabilities.
This program has been initiated in response to NRC Generic Letter No.
88-20, issued on November 23, 1988.
The purpose of these discussions was to gain an understanding and appreciation of the licensee's plans for responding to the Generic Letter.
The licensee, commenced the IPE program in July 1988.
The program staff includes representatives from Engineering (system design and analysis),
Plant Technical (Operations, maintenance and testing), Licensing and Assurance (quality assurance/control, plant experience reports, etc.)
and a Senior Licensed Operator (operational practice and completeness).
It is the intent that the 'IPE program be implemented by Supply System personnel, with contractor support for the training of licensee personnel and for technology transfer throughout the estimated three
,'year term of the project.'
level of effort of approximately 7 staff-years is estimated by the Licensee during FY 1990, commencing July 1989.
The licensee has commenced the 'compilation of system notebooks contain-ing,system descriptions, operation, maintenance, and testing information for 30,."frontline/support" systems of the plant.
A task of reviewing LERs, scram peports, operating'ogbooks and other plant records has commenced to identify and quantify accident initiators.
The licensee has determined that a probabilistic risk assessment (PRA)
approach will be followed in conducting the IPE program.
To date, initial event trees (approximately 16) and five system fault trees have been completed.
't was concluded from discussions held that the licensee has initiated a
timely and substantive effort in response to Generic Letter 88-20.
No violations or deviations were identified.
Event Evaluation Pro ram This program was discussed with appropriate licensee staff to determine the licensee's status and progress in establishing an effective root cause assessment program.
The licensee has conducted formal root cause analysis training for 33 of their staff, an abbreviated root cause analysis training for another 140 persons, and management overview training for 19 persons.
The licensee was in the process of developing and implementing an in-house root cause analysis training progra Vb l
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'bout 26K of the problem reports, and anticipates performing a formal
'oot cause analysis on abo'ut 300 problem reports per year.
The licensee was in the process of staffing the Events Assessment Group with a dedicated cadre of about, four people, each responsible for the
- overview, of each plant department, to assure consistency, quality, depth and scope of root cause assessments.
The licensee demonstrated a sensitivity for self-critical behavior in this. area in th'at certain lessons were stated to have been learned, for which the licensee is developing a resolution plan.
The lessons learned are, in the areas of improvement of:
assessment and
, report timeliness; staff numbers and knowledge; assessment consistency; and methods for documenting assessment findings clearly and concisely.
Overall, the licensee has developed and implemented a viable root cause assessment program, and needs to closely monitor the implementation to maximize the program usefulness as a management tool.
No violations or deviations were identified.
15.
En ineerin Assurance Assessments The inspector examined the program, procedures, and staffing of the engineering assurance organization and found these to be generally sufficient to accomplish the chartered purpose.
The engineering assurance organization has conducted independent design reviews of several modifications performed during the recent outage, SSFI-type assessment of the Low Pressure Core Spray System, and assessment of the Supply System's
CFR 50.59 compliance and Top Tier Drawing Redline System, among others.
These assessments were substan-tial in nature and resulted in several significant findings.
The inspector considered that the engineering assessment organization was contributing to the licensee's improving engineering performance.
No violations or deviations were identified.
16.
Safet S stem Functional Ins ections The licensee conducted their own Safety System Functional Inspection (SSFI) of the Low Pressure Core Spray System.
The inspectors reviewed the draft report and found the licensee's efforts to be both creditable and substantial.
The report documents 16 level I findings, for which nonconformance reports were issued.
In addition, 71 level II and
level III findings were documented.
The licensee has established a
tracking system to assure closure of the findings.
The report, however, documents several management level questions which need to be resolved by senior licensee management.
These are:
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The licensee documents that 51 of the findings may be applicable to other systems and 90 other findings have a high probability of being applicable to other systems.
Even so, the licensee currently plans only one other SSFI, currently underway, on the plant elec-trical power system.
The licensee needs to consider how this issue will be resolved.
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The licensee documents that 75% of the level 1 findings were re-lated to configuration control weaknesses.
However, the licensee's configuration control program is still in the formative stages.
The licensee needs to assess resolution of the configuration control issues expeditiously, perhaps before the establishment of their configuration control program.
The licensee found that Plant Tracking Systems/information systems are cumbersome to use, redundant to some degree, and that many items cannot be sorted by plant system.
The plant tracking-system backlog is high and increasing.
The NRC has previously observed problems in this area, as documented in the last SALP report.
'vidently, the licensee has not fully corrected or resolved this issue
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not always test all functions in a manner to verify,important functions, and contain human factors deficiencies.
Maintenance procedures are, at times, changed by maintenance department personnel, without conducting the necessary levels
'f re-review.
This was also a finding of the recent NRC SSOMI team inspection.
The licensee documents that significant maintenance actions are frequently performed using the Vital Maintenance Work Request process with minimum attention to procedural detail, documentation and post maintenance testing.
The licensee documents that a large backlog of drawings needing revision exists.
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3 fi A meaningful resolution of these issues is predicated upon a clear management statement of expectations in these areas.
Management needs to'learly define its expectations, particularly in the areas of surveil-lance depth and scope, technical review expectations, vital NWR-'sage, and necessary detail and compliance with the details of maintenance work orders.
No violations or deviations were identified.
17.
Review of Environmental Oualification E
of E ui ment 92700 A followup review of safety related cable splices was conducted to understand the methods used by the licensee to qualify the electrical splices used for containment fan motors and motor operated valves, as discussed in LER 86-19.
This review included examination of licensee records and test results, and interviews with key licensee engineering and technical personnel.
During the construction phase of the WNP-2 Plant, low voltage cables were spliced with different types of cable splices.
For applications requiring environmental qualification, the "Electrical Test Guide" approved taped splices using only Scotch, Bishop, and Okonite tape.
Engineering corporate memory is that nearly all of the 480 volt and lower voltage splices were Okonite.
Licensee representatives stated that at the time the splices were installed, test data were not avail-able from Okonite for voltages less than 5000 volts, so engineering personnel determined, based upon engineering judgment and extrapolation of available test data, that the Okonite splices were acceptable for use in 480 volt applications.
These licensee representatives also stated that these taped splices were made by using an initial wrap of T-35 insulating tape, at least two wraps of type T-95 tape (as needed to provide a smooth surface),
and two final wraps of type T-35 tape for the 480 volt splices, versus the five or six wraps of each insulation type used for the 5000 volt splices.
The inspector reviewed the Electrical Test Guide, Rev. 5, dated November 30, 1982, which the licensee stated was used in 1978 to perform the 480 volt Okonite splices.
He noted that it referenced test report N(}RN-3, which established that 5000 volt Okonite splices were qualified for post-LOCA conditions.
The Guide did not include specific documenta-tion of the analysis or engineering basis for using Okonite at lower voltages.
However, it did provide (on a graduated basis) for using fewer layers of Okonite tape at lower voltages in a manner which indicated that engineering judgment had been applied.
The procedure for connections from 300 to 600 volts provided:
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Remove any corrosion, oxidation, grease or dirt.
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Table 1, half-lapped, over bolted connection, stretching 1 ightly.
Voids and irregularities may be filled as necessary to form a smooth surface with product selected from ETG Attachment 6 Table k
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The referenced tables specify the designated tapes manufactured by Bishop, 3M and Okonite.
For Okonite, Table 1 specified No. 35 or T-95, Table 2 specified T-95, and Table 3 specified No.; 35.
Pl The judgments in 1978 were made by Startup Test Engineering personnel.
Generation'ngineering personnel at that time served in an advisory role, and had recommended the use of Raychem sp]ices, but Startup Test Engineering consideIed the, Okonite splices 'to be'cceptable.
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.on their initial recommendation to the startup organization, they believed until May 1986 (when the components were opened for inspect'ion)
that'aychem splices had actually been installed. 'owever, 'tape slices were used.
The licensee stated that the acceptability of the Okonite splices was not subsequently documented further., since the decision wa's'made (in a precautionary way, as discussed further below) to replace the splices with Raychem splices when the components'ere inspected in May 1986.
The licensee acknowledged that if qualification of the splices had been examined during the 1986 inspection, the inspectors and the licensee might have disagreed about the licensee's conclusion (in 1978 and at the time of the 1986 inspection),
based upon engineering judgment and extrapolation of data, that the Okonite splices were acceptable for 480 volt use.
To support their view, licensee representatives noted that tests performed in 1987 for Commonwealth Edison (Wyle Laboratory Report 17859, March ll, 1987) demonstrated that splices of the type used could be environmentally qualified.
While licensee personnel acknowledged that they could take no credit for these subsequent tests to establish Eg of the splices at the time of the NRC's 1986 inspection, these data did support the licensee's view at that time, based upon engineering judgment, that the splices were qualified for 480 volt applications.
The licensee opened the MOVs and fan coolers for inspection during the 1986 refueling outage.
At that time, according to the licensee, engi-neering staff personnel considered the Okonite splices to be qualifiable.
Recognizing the potential for different technical opinions, however, and with the encouragement of the Operations staff, the licensee decided to replace the Okonite splices with Raychem materials.
The licensee believed this to be a conservative act to avoid the possibility of having to reopen affected equipment at a later date for replacement.
In the event the NRC or another group disagreed as to the splices'ualifiability, Licensee engineers stated to the inspector that they believe they could have assembled sufficient data, available in licensee files at the time of that outage, to have qualified the originally installed splices.
The inspector reviewed Eg data for the following containment air recirculating fan motor splices:
CRA-M-FN-3 A, B, C
CRA-M-FN-4 A, B
CRA-M-FN-5 A, B,C, D
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The inspector confirmed that the same splice procedures used for the fan motor splices were used for the motor operated valves in the drywell and in the steam tunnel.
18.
Licensee Event Re ort LER Followu 90712, 92700 The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the reports it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
'I LER NUMBER LER 89-13 LER 89-28 DESCRIPTION LER 89-10 Loss. of Power,.to Reactor Protection System RPS)
Bus "A" and Nuclear &team Supply System NSSS) Isolation
'otent'ial Inoperability of Redu'ndant 120 VAC Safety Related Devices', Due to Degraded Voltage Conditions'ER 89-24 Secondary'ontainment'Bypass Leakage Greater Than Design Basis
N React'or Water Cleanup and" Reactor Core Isolation Cooling Isolations-Caused by
'Inadequate Procedure I
No violations or deviations were identified.
19.
Review of'eriodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the'eport contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the reported information was valid.
Within the scope of the above, the following reports were reviewed by the inspectors.
o Monthly Operating Reports for June and July 1989.
No violations or deviations were identifie II h
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Exit Neetin 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status, and an exit meeting was conducted with the indicated personnel (refer to paragraph 1) on August ll, 1989.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspector during the inspection.
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