IR 05000312/1988023
| ML20207L206 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 09/27/1988 |
| From: | Ang W, Clark C, Dangelo A, Miller L, Myers C, Qualls P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20207L184 | List: |
| References | |
| 50-312-88-23, IEB-87-002, IEB-87-2, IEB-88-001, IEB-88-1, NUDOCS 8810170224 | |
| Download: ML20207L206 (21) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
50-312/88-23 Docket No.
50-312 License No. OPR-54 Licenseo:
Sacramento Municipal Utility District P. O. Box 15830 Sacramento, California 95813 facility Name:
Rancho Seco Unit 1 Inspection at:
Herald, California (Rancho Seco Site)
Inspection conducte July 9 19 8 t rough September f>,
1988 Inspectors:
(7b 7"
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A/ J * ' Angel esident Inspector Date Signed f
hh' ~p. ni r/'enh T 2 7-88
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C/ J Myers eit' nt ispector Date Signed 7x'
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L/M. Qualls, Resident Inspector Dite Signed f/)
km b 77 SE
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W. P. Ang, Pro; ect nspector Date Signed
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'7/ YSC C. C rk, Regio 4) I pector Date Signed Approved By:
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U F' Miller, ClOef Date Signed Reactor ProjectsSection II Summary:
Inspection between July 9 through September 6, 1988 (Report 50 312/88-23)
Areas Inspected:
This routine inspection by the Resident Inspectors and in part by a Regional Inspectcr, involved the areas of operational safety verification, health physics and security observations, engineered satet)
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features system walkdown, maintenance, surveillance and testing, and followup items.
During this inspection, Inspection Procedures 71707, 71709, 71881, 71710, 61726, 72700, 72701, 62703, 41701, 93702, 37701, 92701, 92702, 92700, 92703, and 30703 were used.
8810170224 000928 DR ADOCK OS
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Results:
A significant strength observed was the root cause evaluation performed as a result of the AFW pump packing problem.
A significant weakness
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was identified in the work and design controls for the AFW pump packing effort
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itself, see paragraph S.
One violation was identified, see paragraph 8.
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l DETAILS l
1.
Persons Contacted
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Licensee Personnel
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- J.
F. Fir 11t, Chief Executive Officer, Nuclear
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- D. Keuter, Acting Assistant General Manager (AGM), Nuclear Power
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l Production l
D. Brock, Nuclear Maintenance Manager
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- B. Croley, AGM, Technical and Administrative Services
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l G. Cranston, Nuclear Engineering Manager
- W. Kemper, Nuclear Operations Manager
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- J. Shetler, Director, System Review and Test Program j
T. Tucker, Nuclear Operations Superintendent
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L. Fossom, Manager, Scheduling and Outage Management
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- T. Red han, Manager, Materials Management
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- S. Cronk, Manager, Nuclear Licensing
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- R. Bd m, Manager, Cost Control
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- J.
Vinquist, Director, Nuclear Quality
- P. Turner, Manager, Plant Performance i
- M. Bua, Manager, Radiation Protection l
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- R. Gibson, Acting Manager, Schedulig and Outage Management
Q. Coleman, Quality Engineering Supervisor i
J. Robertson, Licensing Engineer
J. Delezinsky, Supervisor, NRR Coordination, Licensing
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"G. Legner, Licensing Engineer l
l S. Rutter, Supervisor. Incident Investigation Review Group i
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(IIRG), Licensing i
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- C. Aycock, Acting Manger, Nuclear Engineering a
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S. Carmichael, Maintenance Engineer L
l B. Wilson, ICS System Engineer
L. Houghtby, Nucieer Security Manager Cther licensee employees contacted included technicians, operators, f
mechanics, security and office personnel, i
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- Attended tha Exit Meeting on September 6, 1988.
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2.
Operational Status of Rancho Seco
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During the reporting period the licensee continued plant operations in l
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a,:cordance with the restart program.
At the beginning of the period the t
plant was completing 1ts testing and operation at the 40% power plateau.
j On July 9, 1988 the iicensee increased power to 65% for the 65% power l
plateau.
Plant training and testing was continued at this power until
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i August 1, when power was increased to 80% for five days to adjust the l
l Integrated Control System (ICS) prior to beginning the P02 outage. On l
August 6, 1988 the plant was tripped from 80% power to test plant
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response from a loss of one of two main feedwater pumps followed by a
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loss of both feedwater pumps and then control of the primary system l
conditions within the post trip window using the emergency feedwater
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indication and control (EFIC) system.
The nigh power trip testing is
discussed in paragraph five.
A seven day outage was started during which the licensee inspected reactor coolant pump leakage and stad corrosion.
The plant was restarted on August 13, 1988; power was increased to 80%
for the 80% power plateau testing and training.
The plant continued to operate at this power level until the end of the inspection period.
No violations or deviations were identified.
3.
Operational Safety Verification (71707. 71709. 71881)
The inspectors reviewed control room operations which included access
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control, staffing, observation of system alignments, procedure adherence, and logkeeping.
Discussions with the shift supervisors and operators
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indicated understanding by these personnel of the reasons for annunciator indications, abnormal plant conditions and maintenance work in progress.
The inspectors also verified, by observation of valve and switch position indications, that emergency systems were properly aligned as required by techa al specifications for plant conditions.
Plan'. startup was observed by the inspector on August 13, 1988.
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inspector also verified the licensee's Estimated Criticsl Position (ECP)
j calculation used during the startup.
The operators were knowledgeable about the procedure and ECP.
They showed good procedural adherance, i
Criticality was observed and declared at the proper time and well within the ECP limits.
The licensee's nuclear engineer was available in the control room during startup to provide assistance, if needed.
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During this insoection period several housekeeping discrepancies were
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identified by the inspectors which were promptly resolved by the j
licensee.
These included:
on July 28, several items in the vital
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switchgear rooms on rollers which could have become missiles if a seismic t
l event had occurred; on August 2, some 55 gallon drums were bing used as trash cans in the switchgear rooms; and on August 15, some large items of plastic sheeting in tne tank farm area were left by the painters.
The i
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inspector noted that the licensee had taken prompt action to remove these materiai discrepancies when notified by the inspector, and stated that increased management attention would be placed on plant tours to detect
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those conditions.
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During work activities it appeared that the health physics managers were conducting plant tours and monitoring the work in progress.
They appeared aware of significant work which occurred during this period.
The inspector's Radiation Work Permit (RWP) review revealed that the RWP i
did includt:
job description, radiation levels, contamination, airborne radioactivity (if expected), respiratory equipment, protective clothing,
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j dosimetry, special equipment, RWP expiration, health physics (HP)
coverage and signatures.
The RWP radiation and contamination surveys were kept current.
Employees understood the RWP requirements.
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The inspectors observed that personnel in the controlled areas were
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wearing the proper dosimetry and personnel exiting the controlled areas l
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were using the rnonitors properly.
Labeling of observed containers appeared appropriate.
The inspectors walked down portions of the protected and vital area boundaries to ensure that they were complete and that security personnel were proporly posted where known deficiencies existed.
The inspectors also observed protected area access control, personnel i
screening, badge issuing and maintenance on access control equipment.
Access control was observed.
Personnel entering with packages were properly searched and access control was in accordance with licensee procedures.
The inspectors observed no obstructions in the isolation zone which could conceal a person or interfere with the detection / assessment system.
Protected area illumination appeared adequate.
No violations or deviations were identified.
i 4.
ESF System Walkdown (71710)
During the inspection period the inspectors walked down the Bruce-GM
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diesel generators, the "B" Decay Heat System, vital switchgear rooms in both the Nuclear Service Electrical Building (NSEB) and Auxiliary i
Building, and the Auxiliary Feedwater (AFW) System.
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1 The inspectors concluded that:
l All observed hangers and supports were properly madeup and aligned.
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Housekeeping was adequate except as noted above.
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No excessive packing leakage was observed on valves.
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No prohibited ignition sources or flammable materials were observed.
Major system components were properly labeled, lubricated and
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cooled.
No excessive leakage was apparent.
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l The instrumentation appeared to be properly installed.
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f One out of calibration local gauge was identified on the auxiliary
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j feedwater pump.
However, an alternate means to determine the
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i parameter (pressure) was being used per the procedure for l
surveillances.
The local gauge was determined to be within limits, I
and a review had been conducted by the licensee to determine if j
other similar conditions existed.
Flow path components appeared to be in the correct position.
O Required support systems were available, a
Proper breaker and switch positions were verified.
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4 No violations or deviations were identified.
i 5.
Monthly Surveillance Observation / System Review and Test Proaram (SRTP)
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j Technical Specification (TS) required surveillance tests were observed and reviewed to ascertain that they were conducted in accordance with TS requirements.
The fcilowing surveillance activities were observed:
"A" GM Diesel Surveillance l
SP.20 AFW Monthly Surveillance t
The following items were considered during this review:
Testing was in accordance with adequate procedures; test instrumentation was calibrated; I
limiting conditions for operation were met; removal and restoration of
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the affected components were accomplished; test results confirmed with TS
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and procedure requirements and were reviewed by personnel other tnan the individual directing the test; the reactor operator, technician or engineer performing the test recorded the data and the data were in
agreement with observations made by the inspector, and that any deficiencies identified during thn testing were properly reviewed and resolved by appropriate management personnel.
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On August 25, 1988, AFW isolation valve HV-20578 was declared inoperable l
during the performance of SP-7a, "AFW Pump and Valve Monthly Inspection".
The surveillance procedure required that the valve be cycled. When valve
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operation was attempted, no motion took place and the valve motor
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operator failed.
The licensee considered that they had only entered a i
i 7 day technical specification (TS) limiting condition for operation (LCO)
under TS 3.5.1.2.
The next day the licensee decided to jack open and block open the valve.
The inspector noted that the inoperability of the
valve required the plant to be on decay heat system cooling within 72
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hours (TS 3.4.1).
Subsequently, NRR directly advised the licensee of this Technical Specificetion interpretation.
The valve was restored to operable service within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as required, During this period Special Test Procedure, STP-1023 "Feedwater Pump Trip i
from Power", STP-660, "ICS Tuning", STP-1082B, "Reactor Trip from 80%
I Power", and STP-668, "The EFIC Flow Test" were performed with the following observations by the inspectors:
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STP-1023, Feedwater Pump Trip
On August 5, with the reactor operating at about 80% power with both
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Boiler Feed Pumps (BFP) operating in automatic, the licensee tripped the "B" 8FP to observe plant response including the Integrated
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response of the "A" BFP to increase its speed and flow in response to increased demand.
The plant responded as required, with the exception of the "A" BFP which did not respond to the ICS signal to i
l increase flow.
The operators took manual control of the BFP and
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maintained steam generator level. A failed component in the
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controller for the pump was identified as the cause of the failure to maintain feedflow automatically.
During recovery of the "B" BFP the speed rate controller in the circuitry also failed resulting in several hours of maintenance required to restore the pump for continued testing.
The licensee committed during a meeting at the Region V office on August 11, 1988 to evaluate the equipment history of similar components in the
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feedwater system and develop a plan to replace components before they caused challenges to the plant safety systems.
STP-1082B, Reactor Trip from 80% Power
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With the reactor at 87% on August 6, 1988, the plant was tripped to monitor plant response to the trip.
The ICS system responded as desired to maintain steam generator water level in the desired band.
A steam generator safety valve opened during the trip, but failed to reseat at the proper pressure.
Subsequent to the test, the licensee identified that technical specifications allowed operation with one
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safety valve gagged shut.
The safety valve was, +.herefore, gagged
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shut by the licensee.
During the post-trip transient both auxiliary boilers tripped due to the steam demand transient and operator i
inability to control them in their roanual mode during this i
The licensee identified that the auxiliary boiler control problem was an ongoing concern and was evaluating methods to make the auxiliary boilers more reliable.
At the August 11, 1988 meeting in Region V between SMUD and the NRC
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the licensee agreed to reevaluate the preventive maintenance history of these valves, and simlar ones at other facilities as recommended i
by the B&W Owner's Group Safety Program Improvement Project (SPIP),
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and to evaluate the procurement of spare safety valves.
STP-668, EFIC Flow Test i
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This test was performed to te:t the ability of the Emergency
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feedwater Initiation System (EFIC) to control steam generator level with a significant decay heat load in the core. About five minut3s
after the reactor trip, after the ICS system had stabilized the steam generator level, the EFIC system was manually initiated.
The EFIC system performed as desired.
A problem identified during this
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test was the overhssted packing on P-318, the steam driven AFW pump.
This issue is discussed in paragraph 8 of this report.
STP-660, ICS Tuning I
Various activities involving ICS tuning were observed during the
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inspection period, including the ICS response to the above listed plant transients.
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l The inspector concluded that all test acceptance criteria previously established had been met and all identified test deficiencies were being l
adequately resolved by the licensee.
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No violations or deviations were identified.
j 6.
Monthly Maintenance Observation (62703)
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Maintenance activities for the systems and components listed below were
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observed and reviewed to ascertain that they were conducted in accordance
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with approved procedures, regulatory guides, industry codes or standards,
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and the Technical Specifications.
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j The following items were considered during this review:
The limiting
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conditions for operation were met while components or systems were
removed from service; approvals were obtained prior to initiating the
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work; activities were accomplished using approved procedures and were'
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inspected as applicable; functional testing or calibration was performed
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prior to returning components or systems to service; activities were i
i accomplished by qualified personnel; radiological controls were l
l implemented; and fire prevention controls were implemented.
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l Maintenance activities observed included repair of the "B" MFP j
controller, repair of the "B" Decay Heat System (DHS) Pump, main;.enance j
activities on the "A" Bruce GM and A2 Transamerica DeLaval Industries
(TDI) diesel generators, and repair of the steam driven AFW pump, P-318, f
packing.
Except as noted elsewhere in this report in the section
concerning P-318 packing problems, no siglificant deficiencies were
observed.
I During the outage following the August 6, 1988 planned shutdown, the f
l licensee entered the reactor building to inspect the studs on the
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j reactor coolant pump (RCP), which were known to be corroding due to boric L
acid corrosion from a small leak identified during the previous outage.
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The licensee found no additional significant stud degradation of the "C"
j RCP.
The leak was stopped using a sealing compound injected between stationary surfaces of the pump case and the pump stuffing box.
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boric acid crystals were cleaned up and no additional problems were
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I The inspectors also followed up the licensee corrective actions on the
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l failure of the "B" control room / technical support center (CR/TSC)
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heating, ventilation and air conditioning (HVAC) on July 17, 1988.
The l
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licensee identified that the unit failed due to the failure of a
y controller and that this controller had a history of failure.
Utility i
j personnel were considering tracking this item to identify whether an l
l unusual number of failures had been occurring.
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j Maintenance activity observed appeared to be adequately convolled, t
planned, executed and inspected by quality department personnel, a
J No violations or deviations were identified, i
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7.
Licensed Operator Training (41701]
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On May 4, 1988 a transient occurred (described in inspection report l
50-312/88-15) which involved a relief valve opening and failing to reseat
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at the correct pressure on the "A" letdown cooler following a planned reactor trip.
This event required the operators to identify a loss of inventory from the reactor coolant system, and take action to isolate the letdown system and terminate the t. vent.
The inspector reviewed operator response to this event and previously concluded that the operator's pre-event and simulator training was effective in allowing them to mitigate the effects of the event.
The personnel involved were well qualified.
In this inspection, the inspector interviewed a number of licensed operators in the control room about training for specific tasks assigned, and attended a number of the briefings performed prior to performing complicated evolutions and testing.
Operator knowledge was good concerning the activities which they were required to perform.
A number of licensed operator records were reviewed and the inspector ascertained that they contained, a copy of the most recent exam and responses, documentation of attendance at required lectures, documentation of required control manipulations, documentation of required procedure reviews and self-study, and documentation of completed required reading.
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The licensee's pass rate for R0 tests in 1987 was 88% and was 100% for l
SR0s.
In 1988 the rate was 100% for both R0s and SRO.
The licensed i
j operator INPO accreditation was completed in the spring of 1986 and full INPO accreditation was in April of 1988.
No violations or deviations were identified.
l 8.
Onsite Followup of Events (93702, 37701)
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Overheating of Auxiliary Feedwater Pump Seal j
Following the manual reactor trip test from 80% power on August 6, 1988, the plant conducted a test of the emergency feedwater initiation and l
control system (EFIC) under special test procedure STP-668.
The test
j consisted of manually initiating both trains of auxiliary feedwater (AFW)
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and allowing the EFIC system to control steam generator (SG) level and
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I pressure for twenty minutes.
Twelve minutes into the test, however, the
outboard seal of the turbine driven auxiliary feedwater pump (AFP),
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P-318, began to smoke due to overheating causing the control room l
operators to stop the pump to prevent further damage.
The performance of STP-668 was not affected by securing this AFP, and the test was completed
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i utilizing the remaining full capacity electric motor driven AFP, P-319.
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The inspector observed the conduct of the licensee's troubleshooting and corrective maintenance activities dealing with the P-31tl packing problem.
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The following was the sequence of events which evoived during the
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j licensee's investigation:
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8/6/88 During STP-668, control room personnel secured P-318 -
after 12 minutes of operation when mechanics reported.the I
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outboard seal packing to be smoking and throwing off small particles.
The packing was found to be partially extruded j
out of the packing gland.
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Work request WR-160121 was written to repack the outboard
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seal on P-318 in accordance with maintenance procedure
M.22 using the same size and type seal package as removed.
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l The mechanics encountered difficulty in installing all 6
rings of the new seal package and the procedure was l
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'ow installation of only'5 of'the 6 rings of
packing
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The pump., subsequently operated to run in the packjng.
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J Packing temperatures were measured to stabilize at 90 F.
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After conducting surveillance cesting SP-20, P-318 was i
declared operable.
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8/8 The licensee initiated a root cause evaluation of the i
f P-318 seal packing failure,
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8/9 P-318 was operated for two~ hours to obtain additional seal i
temperature data. The outbgard seal temperature was found
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j to steadily increase to 136 F until the pump was stopped.
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I 8/10 P-318 was taken out of service for disassembly and
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inspection of the outboard packing.
The licensee determined that the packing rings of the seal i
i package were oversized causing the lantern ring to be j
mispositioned axialy with the stuffing box.
The axial
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position of the lantern ring within the stuffing box was j
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considered to be critical to direct seal cooling water
within the seal package.
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8/11 The licensee machined one packing ring of the seal package.
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to adjust the assembled position of the lantern ring and i
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installed the modified seal package.
Subsequent packing
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run-in operation of the pump was stopped after.only five
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minutes due to excessive packing temperature.
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8/12 P-318 was repacked with an alternate type packing.
The replacement packing was the same size (5/8") as the style
removed, but consisted of a different material.
I Subsequent packing run-in operation of the pump was again stopped due to packing overheating.
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The plant determined that inadequate shaft-to packing radial clearance existed to properly cool the packing due to use of the wrong packing size (5/8").
P-318 was repacked with a smaller size (9/16") packing.
8/13 P-318 was declared operable after surveillance test runs during which gacking temperatures were monitored to be less than 100 F.
The inspector reviewed the procuremer.t records for the discrepant seal material.
Four seal packages had been procured in February,1987 under purchase order RQ-87-01-54717.
The material had been procured as commercial grade, specified only by part number its and a Certificate of l
Conformance to that part number from the vendor.
Since the material had been procured by part number only, packing size was not a specification of the purchase order.
As such, verification of size could not be performed during receipt inspection.
Furthermore, since the pump vendor (Hayward-Tyler) considered the dimensions of the packing to be proprietary information, no vendor catalog information was available to verify proper packing size.
The material had been evaluated by Nuclear Engineering for Quality Class 1 application using a generic commercial grade item dedication (CGID) procedure GEN-0007.
The CGIO identified that the packing size, material and sealing ability were critical characteristics and designated three methods of verifying these characteristics:
Receipt inspection, vendor catalogs and post insta11ction functional testing.
Determination of critical characteristics was permitted to be determined by post-installation functional testing.
Post installation functional testing was performed but was ineffective in
detecting the oversized packing prior to in-service failure.
The I
specified post installation test on the work request required the monthly AFW pump surveillance test (SP.20) which did not require measurements of j
packing temperature (which had been determined by the licensee to be a i
f actor in evaluating packing performance).
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l The inspector reviewed Maintenance Procedure H.22, "Auxiliary Feedwater Pumps and Turbines" and fcund that general directions were included for
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adjusting pump packing.
The procedure specified 1 gal /hr/ gland as the correct leakoff to be achieved during adjustment to minimize packing
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leakage while checking for possible heating of the stuffing box.
The inspector noted, however, that the procedure did not include specific guidance on acceptable packing temperatures, nor did it specify the
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method of determining excessive packing temperatures.
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However, the licensee personnel who had installed the packing had measured packing temperature during pump operation and informally evaluated the results.
THe inspector observed that no requirement had a
been established on the work request to take, record and evaluate packing
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temperatures for correct packing performance (and, thereby, packing
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suitability).
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Licensee management agreed with-this observation and were evaluating it
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for corrective action at the and of this inspection.
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Through discussions with licensee personnel, the inspector also
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determined that maintenance personnel had rolled and hammered the
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apparent oversized packing rings to reshape the rines to allow them to be
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I installed in the pump stuffing box.
The inspector reviewed licensee
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maintenance procedure, M.22 "Auxiliary Feedwater Pumps and Turbines" for
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repacking the pump seal and found no direction for performing any
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alteration'of the packing ring dimensions.
The licensee concluded that
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alteration of the packing rings resulted in sufficient deformation of the l
packing rings to contribute to overheating of the outboard seal.
The
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inspector concluded that the alteration of the packing was a questionable
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Licensee management agreed with this observation and were l
' evaluating it for corrective action at the end of this inspection.
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i As part of the licensee's troubleshooting activities to determine the r
I cause of the overheating packing on the outboard seal of auxiliary
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feedwater pump P-318, the licensee issued procedure temporary change
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notice PTCN-003 to maintenance procedure M.22 to repack the seal using
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only 5 of the specified 6 packing rings in the assembly.
This change was
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j considered to be necessary by maintenance personnel to adequately adjust
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the packing follower.
However, at the time it was apparently not
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recognized that the change constituted a minor design change since the
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i number of packing rings was specified on the vendor drawing for the pump,
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M.5.06-53.
The change to the maintenance procedure did not receive l
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engineering review and approval of the design change.
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According to licensee representatives, the use of a PTCN indicated that l
the change was considered to be temporary and not to be incorporated as a i
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permanent procedure change.
However, the change was not documented and
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controlled according to AP.26A "Temporary Modifications" as required for j
temporary modifications during troubleshooting which are not removed
j before returning the equipment to service.
Procedure AP-26A requires i
l that temporary modification be approved by Nuclear Engineering prior to f
placing the modification in service.
The removal of one packing ring was accomplished using only a procedure change document which did not receive
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the engineering review received by a temporary modification.
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This is an apparent violation.
(88-23-(
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Through discussions with licensee representatives, the inspector l
determined that the root cause evaluation initiated by the licensee f
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included extensive review of maintenance history, procurement records,
i and vendor interface aspects of this problem.
Through this evaluation, l
the licensee determined that the root cause of the problem was the
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inadvertant use of oversized seal rings during repacking of the pump
seal.
Although the licensee's evaluation was not completed at the end of
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the report period, in discussions with licensee representatives, the l
inspector found the extent of the evaluation to be thorough and self
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i critical.
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9.
Containment Leak Rate Test Results Evaluation (70323)
The inspector reviewed the Rancho Seco Unit I report entitled "Primary Reactor Containment Integrated Leakage Rate Test" (Final Report, September 1987).
This review was parformed to verify that the licensee had adequately performed, reviewed, and evaluated the latest operational type A containment test [ containment integrated leak rate test (CILRT)]
and type B or C containment tests [ local leak rate test (LLRT)] for Unit 1.
,
The performance of the Unit 1 CILRT on September 2 and 3, 1988 was reported in Inspection Report No. 50-312/87-23.
The licensee appears to have conducted the CILRT correctly, reviewed the data satisfactorily, and evaluated the results in a proper manner.
The test results were reported in accordance with the requirements of 10 CFR
50, Appendix J Section V.
No violations or deviations were identified.
I 10.
Followup on NRC Open Items
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l a.
NRC Bulletins (NRCB) (92701)
1)
NRCB 88-01 (Closed), "Defects in Westinghouse Circuit Breakers"
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The subject bulletin provided licensees with information on Westinghouse Series 05 circuit breakers and provided safety
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concerns associated with their use.
The bulletin requested licensees using these breakers in Class 1E service to perform i
and document certain inspections related to the breakers, i
l The licensee responded to the bulletin concerns and requests by letter GCA 88-161 dated March 28, 1988.
The letter stated that
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the licensee reviewed its plant equipment and confirmed that
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Westinghouse Series DS breakers are not used at Rancho Seco and
therefore the bulletin actions were not applicable to Rancho
Seco.
The inspector, with assistance from the licensee
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purchasing department, reviewed the licensee's material equipment lists (MEL and NUCLEIS) and confirmed that Rancho
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Seco aid not have Westinghouse Series DS circuit breakers in
Class 1E applications.
The bulletin was closed.
2)
NRCB 87-02 Supplement 1 and 2 (Closed) - Fastener Testing to Determine
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j Conformance with Applicable Material Specifications NRC8 87-02 Supplement I requ*sted licensees to provide a list i
of the suppliers and manufactorers from which safety-related
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and non-safety related fastenors have been purchased in the
last 10 years, including addresses, and the type of fasteners
purchased (i.e., the material specifications).
For those fastener purchases made from fastener suppliers and/or original
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equipment manufacturers, any available information concerning
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l the manufacturer or sub-tier _ supplier of the fastener was also
requested, j
NRC8 87-02 Supplement 2 revised Supplement 1 to clarify its intent.
The type of fasteners for which vendor / supplier names and addresses requested was limited to ferrous fasteners %" in diameter or greater, in addition, the list of suppliers /
vendors for nonsafety related fasteners was limited to the past 5 years.
The licensee responded to NRC8 87-02 Supplements 1 and 2 via letter AGM/TA 88-203 dated July 26, 1988 and provided the information required by the bulletin.
The licensee's response was discussed with the Material Control Manager.
During the discussion, the Material Control Manager stated that the i
following was accomplished for NRCB 87-02 Supplements 1 and 2'
(1) Stock codes for %" diameter and greater ferrous fasteners were identified.
(2) Purchase Orders were researched for all purchases of the identified stock codes to identify all suppliers and l
manufacturers that may have provided fasteners for the i
last 10 years for safety related and five years for i
non-safety related fasteners.
I (3) A database was developed for all identified stock codes l
and all identified suppliers and manufacturers who supplied fasteners as noted in (2) above.
In some cases,
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identity of manufacturer could not be established and
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consequently could not be provided.
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The licensee appeared to have been responsive to the bulletin
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requests.
The licensee's response may be subject to further l
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NRR review.
Based on the licensee's response, the bulletin
supplements were closed.
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i b.
Enforcement items (92702)
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87-37-01, 87-37-02 (CLOSED), "Failure to Follow Wa Request
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j Procedure" These two violations resulted from work being performed on the control room / technical support center essential HVAC system.
87-37-01 concerned the failure of craftsman to follow the work
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j request procedure.
87-37-02 concerned the failure 6f craftsmen to i
j write a nonconformance report (NCR).
The licensee corrective action involved a significant modification to their problem identification
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program.
The previous system of NCRs had been completely replaced
with a potential deviation from quality (P0Q) system.
Revisions had l
been made to the screening and 10 CFR 50.72/73 reportability reviews and evaluations made by the Quality and Nuclear Engineering
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departments. The inspector cuncluded that licensee corrective
j actions appeared adequate to ensure that craftsmen follow
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maintenance procedures and the new P0Q program should prevent a failure to adequately identify discrepancies as noted in 87-37-02.
These items are closed.
c.
Inspector Followup Items (92701)
(Closed) Inspector Follow-up Item (IFI) 85-14-01 - Rockbestos Firewall SR and Firewall III Cable Inspection Report 50-312/85-14 documented the results of a special NRC team inspection that reviewed the licensee's 10 CFR 50.49 program that established and maintained environmental qualification of electric equipment important to safety.
The inspection also followed-up on equipment qualification (EQ) cerrrative action commitments resulting from deficiencies identifi*d in a January 17, 1983 NRR Safety Evaluation Report.
One of the concerns identified during the inspection, IFI 85-14-01, concerned the licensc?'s lack of documentation to support the qualification of Rockbestos Firewall SR and Firewall III cable.
The Rockbestos Firewall SR concern noted by IFI 85-14-01 related to quality assurance deficiencies in the Rockbestos test program as noted in Information Notice 84-44.
As a result of the generic concern, Rockbestos reperformed testing for Firewall SR.
The results of the testing was documented on Rockbestos report QR 7802 dated January 26, 1988.
The report was evaluated by Impell for
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SMUD, and documented in the EQ file.
Both the report and the Impe11 evaluation noted anomalies '
the testing performed.
During LOCA testing, sample leads fallet to maintain voltage.
The leads were subsequently found to be badly deteriorated and showed signs of surface crazing.
This was attributed to excessively high temperatures.
Post LOCA electrical tests were not performed.
The LOCA tests were not subsequently re performed.
The SMUD evaluation of the anomalies stated that (1) the LOCA temperatures were excessive compared to Rancho Seco LOCA temperatures, (2) continuous application of voltage during LOCA testing was demonstrated. (3)
voltage applied during LOCA testing exceeded normal service voltage and (4) credit could be taken with installed SR cable for periodic maintenance functional megger testing to detect cable insulation breakdown.
The Rockbestos Firewall 111 concern noted in IF! 85-14-01 related to SMUD's equipment qualification documentation, which was based on Rockbestos test reports, but lacked a cross link or similarity confirmation between the Rockbestos test sarples and the licensee's Firewall !!! cables.
In response to the concern, the licensee sent Rockbestos samples of its Firewall !!! KXL-760-5 (cables installed in EQ applications) and Firewall !!! KXL-780 and KXL-760 (cables being qualified for future use in EQ applications) for testing to establish similarity with Firewall !!! KXL-760-0 (cable previously tested and EQ qualified by Rockbestos).
Testing was performed by Rockbestos and documented on test report TR 6801 dated July 31, 198._
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The Rockbestos test report noted various test anomalies, attributed the anomalies to the aged conditions of the samples and considered the test results acceptable without providing a basis for the acceptability of the cables for their intended applications.
The test report was evaluated for SMUD by Impell and the evaluation confirmed similarity of the test cables to the previously EQ Qualified Firewall III KXL-760-0 cable.
The Impell evaluation
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j (calculation number 124-006) contained in the EQ file further stated
that:
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"Similarity analysis performed by Rockbestos via".... "between pre
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1979 "KXL-760-5" formulated and post 1979 "KXL-760D" formulated chemically XLPE Firewall III cables.
The tested physical and electrical properties for both Firewall III formulations yielded excellent agreement with the slight differences in values being
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statistically insignificant.
All relevant ICEA requirements were
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satisfied, especially the aging and wet electrical characteristics i
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which significantly exceeded the ICEA requirements."
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i THe inspector's review of the test results indicated the following:
(1) Tensile strength of one sample of cable KXL-780, as-received,
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did not meet Insulated Cable Engineers Association (ICEA)
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standards (1760 LB/IN actual vs 1800 LB/IN minimum
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specification).
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(2) Elongation at rupture, as percent of as received length, after
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heat aging, for a sample of cable KXL-780 did not meet ICEA
standards (72% actual vs 75% minimum specification).
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(3) Cable sample for KXL 760-5 and KXL 760, when tested for accelerated water absorption (aged samples) exceeded the ICEA
standard for capacitance increase 1 to 14 days (3.47% and 5.02%
l vs 3% maximum specification) and exceeded the ICEA standard for f
capacitance increase 7 to 14 days (1.81% and 1.92% vs 1.5%
i maximum specification).
i The above noted test anomalies, although alluded to in the Rockbestos test report, were not corrpletely resolved in the SMUD EQ l
evaluation of the test report.
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In both EQ evaluations for Firewall SR and Firewall III, documentation of a thorough review of the ttst anomalies was lacking.
The evaluations lacked a determination of the relevance of the test anomalies to the specific performance characteristics for the installed cable that would envelope the applications and environment for the installed cables.
Pending documentation of the above noted evaluations, this item was 16 ntified as Unresolved Item 50-312/88-23-02.
Inspector Follow-up item 85-14-01 will be resolved by closure of the new Unrssolved IN m and consequently the IFI will be closed.
87-37-03 (CLOSED), "!tems on LR$L Require Fucther Justification"
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This open item concerned three Long Range Startup List (LRSL) items which the inspectors felt required further justification.
1)
The first issue concerned control of vendor technical manuals.
The licensee issued RSAP 0309, "Vendor Equipment Technical Information Program (VETIP)", on 2/1/88 and RSAP 0310. "VETIP Backfit/ Upgrade Program", on 1/4/88 to improve control of these manuals.
These procedures appeared adequate to address this Concern.
2)
This second issue concerned "as-built drawin2s for the battery chargers.
Detailed wiring draw' qs of the battery chargers were not available on site.
Should technicians have needed to
work on the chargers, troubleshooting would have been difficult
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l without internal wiring drawings.
The battery chargers were operable with preventive maintenance complete and wiring diagrams completed prior to startup.
P&ID changes were requested as required.
3)
The third item concerned discrepancies in surveillance
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procedure SP-C21.
The licensee subseauently performed the test eatisfactorily.
Item 87-37-03 is closed.
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87-47-02 (CLOSED), "Con,parison of E0Ps to TOD" This item concerned an action statement in the Technical Basis
Document (TBD) which was not included in the associated Emergency Operating Procedure (EOP).
The licensee committed to review all i
I E0Ps to ensure that all action statements from the TBDs were
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included.
By memorandum dated February 12, 1988 the licensee J
documented that a review of the E0P/TBD comparison documentation was I
completed to ensure that all sections of the TBD containing action I
statements was included.
This item is closed.
j 88-05-01 (CLOSED), "SSEMs Used for Other Than Plant Emeroencies"
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This item resulted from the licensee's use of Shift Supervisor Emergency Maintenance (SSEM) work orders being issued to expedite
important work rather than for plant emergencies.
The concern was l
that SSEri work did not recieve the same level of review prior to l
work being performed as did normal or expedited maintenance, and
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whether this was appropriate for bonafide plant emergencies, j
Revision 4 to RSAP-0803, "Work Request", adds a definition of SSEM
limiting its use to energencies related to nuclear safety or public well being, The inspector concluded that this revision
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satisfactorily resolved this item.
This item is closed.
d.
Part 21 Reports (92701)
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87-19-P (CLOSED), "Cracks Identified on the TDI Diesels" i
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This 10 CFR 50, Part 21 report was issued as a result of cracks identified at Rancho Seco on the Transamerica DeLaval Industries (TOI) diesels due to vibrations during the diesel startup testing.
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The cracks were subsequently repaired during the startup testing.
The licensee has reduced the TOI vibration to an acceptable level but continued to monitor the diesels for additional problems.
This item is closed, t
1)
10 CFR 21 Report 88-12P (Licensee Report 88-04) (0 pen) - Manufacturino Defect with Gould PD 3200 Pressure Transmitters
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On August 8, 1988 the licensee submitted a 10 CFR 21 report stating the following-i
"Shortly after the restart of Rancho Seco, two of the eight j
newly installed Gould P03200 Emergency Feedwater Initiation and Control (EFIC) steam generator low range level transmitters wore observed to be drif ting low at a rate in excess of the
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manufacturer's claimed stability.
A replacement transmitter
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also exhibited the same drifting characteristics as the two failed units.
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1he three failed units were returned to Statham/Gould for i
inspection and identification of the failure mechanism.
Internal inspection revealed that each unit had a leak of the
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filler fluid at the tip of an electronics pin.
Statham/Gould
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stated that they had experienced some problems with the
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manufacturing processes during the time the failed units were
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built."
The report further stated that:
"Rancho Seco has 32 transmitters from the suspect lot.
Nine of
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the transmitters are in stock, three were returned to
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Statham/Gould, and 20 are currently in use as follows:
6 EFIC steam generator low range level transmitters J
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J 2 Decay Heat cross-tia flow transmitters
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i 4 Reactor Coolant Hot leg level transmitters
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8 EFIC steam generator wide range level transmitters
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One EFIC low range level transmitter and one EFIC wide range
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level transmitter appear to be exhibiting a similar drif t problem at a very low rate; however, this has not been clearly
determined.
Rancho Seco has an additional 29 Could transmitters of a similar type which were not manufactured with the suspect lot.
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These transmitters have not exhibited any unusual characteristics."
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The discrepancy identified by the 10 CFR 21 report started to manifest itself approximately in March, 1988.
However, the manufacturing defect was not confirmed until the failed transmitter had been removed, returned, tested and examined by
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the manufacturer, and a report istued by the manufacturer.
The manufacturer, Stathan Transducer Division of Schlumberger Industries, telecopied a preliminary copy of the failure
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analysis report to SMUD on June 17, 1987.
SMUD subsequently performed a 10 CFR 21 reportabiitty evaluation using RSAP 0912, 10 CFR 21 reporting cf Nuclear Plant Defects or Noncompliances.
The licensee stated dat the defect was determined to be 10 CFR
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21 reportable on August 8, 1988.
The SMUD CEO, Nuclear was informed on the same day and a written report was submitted to the NRC on the same day.
The report was received in Region V
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on August 10, 1988, i
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An evaluation of the timeliness of reporting the defect
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determined that the licensee met the 10 CFR 21 reporting i
requirements.
The evaluation also determined that the licensee i
reportability evaluation period was reasonable.
A review of
RSAP 0912 confirmed that the procedure contained the 10 CFR 21 i
reporting time limits.
The procedure also outlined the
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licensee's reportability evaluation process.
However, the (
procedure did not specify any time limits or guidelines for the
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j evaluation process to assure timely notification of the CEO, I
Nuclear.
During discussions with the licensing manager i
regarding the subject, the licensee committed to evaluate the
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I need to provide RSAP 0912 guidelines regarding the evaluation
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process to assure timely notification of the CEO, Nuclear.
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A review of the licensee's corrective actions confirmed that an
operability evaluation had been performed on the three failed
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transmitters.
In addition, the ifcensee stated that tnt EFIC
j low range level transmitter and EFIC wide range level transmitter that were exhibiting similar drif t problems had I
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been replaced during the recent P02 outage and none of tne 20
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installed Gould PD 3200 transmitters were showing signs of similar problems.
However, no documented engineering
evaluations had been performed for those 20 transmitters in j
relation to the known condition that they were manufactured
r during the same time period that the defective transmitters were manufactured, that they were manufactured using the same
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processes that resulted in the defects of the defective
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transmitters, arid that they poteatially could be susceptible to
similar failures or other potential failures resulting from the t
same types of defects. The licensee stated that as part of its
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corrective action, the trarismitters were being subjected to an
intense monitoring program and considered that if the
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transmitters contained the same defect, it would have already l
i manifested itself.
The licensee committed to document an l
engineering evaluation for all installed Gould PD 3?00
transmitters manufactured during the same time period as the
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def.ctive transmitters.
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Pending completion of the licensee's corrective actions and completion of its engineering evaluations, the item was left open.
c.
Licensee Event Reports (92700)
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I LER 87 24-01 (CLOSED), "Overweiaht Cable Trays"
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This LER concerned cable trays which could be filled beyond the USAR
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limit of 50 lb/ft.
The LER identified problems with the design
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l control process which did not prevent the possibility of this
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l occurrence.
The licentee subsequently changed the program to
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l preclude this from occurring.
Licensee evaluations initially i
j thought that 7 trays exceeded the limit.
Further analysis
,
determined that only 1 tray exceeded the limit.
This tray was a class 2 tray and weighed in at 51.6 lb/ft.
This item is closed.
An
engineering evaluation was completed to authorize this deviation.
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The inspector conclu1ed that the licensee's corrective action was t
adequate.
i LER 88-02 (CLOSED), "Inadventant Actuation of the "A" Emergency
Diesel Ger.erator"
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This event occurred during the loss of offsite power testing, STP.961 on February 3, 1988.
The diesel started inadvertently when
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the respective vital bus was de-energized.
Licensee personnel had
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failed to perform the procedural step which would have disabled the
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ri t e sel.
Subsequent to this occurrence, the licensee had a series of
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testing problems performing this test.
These are documented in inspection Report 50-312/88-05.
The licensee suspended restart
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testing activities for about a week, retrained operators on
procedural compliance, and simplified procedures to preclude this type of problem during testing.
The licensee's corrective actions L
were effective and the testing was completed.
This item is closed, f.
Special Reports p 2700)
88-07-X0 (CLOSED), "!noperable Deluge System" On Hirch 15, 1988, the licensee placed the deluge system in the area of the Auxiliary Feedwater (AFW) pumps out of commission due to a concern that inadvertant actuation could render the AFW pumps inoperable, On August 6, 1988 the licensee had completed modifications to the system to prevent water damage to the motor i
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driven pumps by the deluge system, and the deluge system was I
restored to operation.
This item is closed.
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No v.olations or deviations were identified.
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I 10.
Exit Meetino (30703)
The inspector met with licensee representatives (noted in Paragraph 1) at
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various times during the report period and formally on September 6, 1988, i
The scope and findings of the inspection activities described in this j
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report were summarized at the meeting.
Licensee representatives r
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acknowledged the inspectors' findings.
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