ML13330A075
| ML13330A075 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 05/01/1980 |
| From: | Baskin K Southern California Edison Co |
| To: | Ziemann D Office of Nuclear Reactor Regulation |
| References | |
| TASK-08-02, TASK-8-2, TASK-RR NUDOCS 8007110401 | |
| Download: ML13330A075 (19) | |
Text
Southern California Edison Company P.
0 BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD CALIFORNIA 91770 K. P. BASKIN TELEPHONE MANAGER, NUCLEAR ENGINEERING (213) 572-1401 AND.LICENSING May 1, 1980 Director of Nuclear Reactor Regulation Attention: 0. L. Ziemann, Chief Operating Reactors Branch No. 2 Division of Operating Reactors U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Gentlemen:
Subject:
Docket 50-206 Adequacy of Electrical Distribution Systems San Onofre Nuclear Generating Station Unit 1 Mr. William Gammill's letter of August 8, 1979 requested information regarding the adequacy of the offsite power system and the onsite distribution system at San Onofre Unit 1. The requested information is provided in enclosures to this letter. provides the results of analyses of the electrical distribution system at San Onofre Unit 1. This enclosure addresses each of the items identified in the "Guidelines for Voltage Drop Calculations" which were provided as an enclosure to Mr. Gammill's August 8, 1979 letter. As described in Enclosure 1, the offsite power system and electrical distribution system have sufficient capacity to automatically start and operate all required safety loads. Mr. Gammill's letter also requested the performance of tests of the distribution system to verify the validity of the analyses summarized in. Based on our scoping of these tests, it is anticipated that preparation for these tests will take about five months. Therefore, these tests will be performed during the first available outage following completion of the detailed test procedures. Results of these tests will be provided to the NRC within one month following completion of the tests.
In addition, Mr Gammill's letter requested that we review the electric power systems at San Onofre Unit I to determine compliance with General Design Criteria (GDC) 17. The review with respect to GDC-17 is summarized in. As described in Enclosure 2, no violations of GDC-17 were discovered.
8007110 Ale)
Mr. D. L. Ziemann
-2 In addition, by letter dated July 31, 1979 you indicated that the evaluation we submitted November 4, 1977 regarding the susceptibility of San Onofre Unit 1 to sustained voltage degradation of the offsite power system was unacceptable. No basis for this finding was provided. Your letter further requested design modifications and changes to the Technical Specifications based on your letter of June 3, 1977.
As discussed with members of the NRC Staff, SCE has delayed our response to your July 31, 1979 letter pending completion of the analyses discussed in to this letter. SCE's position remains that no credible condition on the offsite power system will result in sustained degradation of voltage to the extent that safety related electrical equipment cannot perform their safety functions. This is further supported by the analyses in Enclosure 1.
However, in accordance with your July 31 letter, SCE will integrate modifications to the undervoltage protection system at San Onofre Unit 1 in accordance with Position 1 of your June 3, 1977 letter with other modifications which may be required as a result of the Systematic Evaluation Program (SEP). Consequently, the conceptual design for these modifications will be available after the integrated assessment of the SEP and will be submitted to the NRC Staff at that time.
Since in SCE's opinion the analyses submitted in our November 4, 1977 letter demonstrate that a sustained voltage degradation is not credible at San Onofre Unit 1, there is no safety hazard associated with delaying development of these design modifications to be consistent with the SEP's integrated assessment. Instead, this delay permits these modifications to be evaluated in the broader context of other changes which may be required as a result of the SEP.
Pending completion of the SEP, the draft Technical Specifications included in our November 4, 1977 letter are considered appropriate. Following review by the Regulatory Staff, we will submit a formal proposed change to the Unit 1 Technical Specifications to incorporate those specifications.
Finally, on April 24, 1980 we received by telecopy, a set of NRC comments on our November 4, 1977 submittal regarding system voltage degradation. We are proceeding to evaluate these comments and will notify your staff when responses to these comments can be provided.
If you have any questions on this information, please let me know.
Sincerely, Enclosures ADEQUACY Of' ELECTRICAL DISTRIBUTION SYSTEM SAN ONOFRE NUCLEAR GENERATING STATION UNIT 1 The auxiliary power system at San Onofre Unit 1 consists of two redundant power trains. Normally the power for these two power trains is from Reserve Auxili ary Transformer C. When Reserve Auxiliary Transformer C is out of operation, the power for these two power trains can be obtained from Unit Auxiliary Transformers A and B through the station Main Transformer. Unit Auxiliary Transformers A, B and Reserve Auxiliary Transformer C have adequate MVA ratings so that one offsite power circuit failure will not result in failure of the alternate offsite power source.
Therefore, it is concluded that the offsite power failure which occurred at Arkansas Nuclear One on September 16, 1978 during the transfer of power from one offsite power source to another, cannot occur at San Onofre Unit 1.
An analysis of the electrical distribution system as requested by Mr.
W. Gammill's letter of August 8, 1979 is provided in the following paragraphs. Each of the specific guidelines for voltage drop calculations identified in Enclosure 2 to Mr.
Gammill's letter is addressed below.
Guideline 1 Separate analyses should be performed assuming the power source to safety buses is (a) the unit auxiliary transformer; (b) the startup transformer; and (c) other available connections to the offsite network one by one assuming the need for electrical power is initiated by (1) an anticipated transient (e.g.,
unit trip) or (2) an accident, whichever presents the largest load demand situation.
Response
As described above, there are two offsite power sources at San Onofre Unit 1:
(1) Reserve Auxiliary Transformer C, and (2)\\the Main Transformer and Unit Auxiliary Transformers A and B. Separate analyses have been performed assuming that offsite power is supplied through each of these sources.
However, because of the higher impedances of Reserve Auxiliary Transformer C*, the voltage drop is higher when offsite power is from this source; therefore, only the results of this analysis are provided in this study. The analyses have been performed for two cases:
(1) unit trip, and (2) loss of coolant accident (LOCA).
The details of these cases are provided in response to Guideline 7 below.
- The existing Reserve Auxiliary Transformer C will be replaced with a new transformer during the April 1980 refueling outage. The new Reserve Auxiliary Transformer C has higher impedances than the existing one, as well as the Main Transformer and Unit Auxiliary Transformers A and B; therefore, the new Reserve Auxiliary Transformer C impedances are used throughout the study.
-2 Guideline 2 For multi-unit stations a separate analysis shoud be performed for each unit assuming (1) an accident in the unit being analyzed and simultaneous shutdown of all other units at that station; or (2) an anticipated transient in the unit being analyzed (e.g., unit trip) and simultaneous shutdown of all other units at that station, whichever presents the largest load demand situation.
Response
Currently, only San Onofre Unit 1 is operational; however, two additional units, San Onofre Units 2 and 3, are under construction and are scheduled to be operational in December, 1981 and February, 1983. With respect to voltage degradation, however, the two postulated conditions listed in response to Guideline 1 above are more severe than the two cases identified in Guideline 2.
This is due to the fact that system voltage is lower (see the Response to Guideline 6) and the auxiliary load demand at San Onofre Unit 1 is the same whether or not San Onofre Units 2 and 3 are in operation. Therefore, the voltage calculations for the two cases identified in Guideline 2 have not been performed.
Guideline 3 All actions the electric power system is designed to automatically initiate should be assumed to occur as designed (e.g., automatic bulk or sequential loading or automatic transfers of bulk loads from one transformer to another).
Included should be consideration of starting of large non-safety loads (e.g.,
condensate pumps).
Response
All loads the electric power system is designed to automatically start and operate are assumed to occur (e.g., two 3,500 HP feedwater pumps and two 700 HP safety injection pumps are assumed to be started simultaneously in the postulated LOCA condition).
Large non-safety loads are not automatically started under the two postulated conditions identified above.
Guideline 4 Manual load shedding should not be assumed.
Response
Manual load shedding has not been assumed in this study.
Guideline 5 For each event analyzed, the maximum load necessitated by the event and the mode of operation of the plant at the time of the event should be assumed in addition to all loads caused by expected automatic actions and manual actions permitted by administrative procedures.
-3
Response
For each of the two events analyzed, the maximum loads required by the events have been assumed in addition to all loads started by automatic actions.
See the Response to Guideline 7 for a discussion of the loads required and automatically initiated.
Guideline b The voltage at the terminals of each safety load should be calculated based on the above listed considerations and assumptions and based on the assumption that the grid voltage is at the "minimum expected value". The "minimum expected value" should be selected based on the least of the following:
- a.
The minimum steady-state voltage experienced at the connection to the offsite circuit.
- b.
The minimum voltage expected at the connection to the offsite circuit due to contingency plans which may result in reduced voltage from this grid.
- c.
The minimum predicted grid voltage from grid stability analyses.
(e.g.,
load flow studies).
In the report to NRC on this matter the licensee should state planned actions, including any proposed "Limiting Conditions for Operation" for Technical Speci fications, in response to experiencing voltage at the connection to the offsite circuit which is less than the "minimum expected value."
A copy of the plant procedure in this regard should be provided.
Response
In order to postulate a worst case which will result in the lowest system voltage at the San Onofre 220 kV switchyard, computer calculations were performed for nine contingencies. The computer study indicated that the lowest system voltage was 217.8 kV. This occurred for the case with San Onofre Unit 1 off line, two SCE kV lines down and two SDG&E 220 kV lines down (Case 6 in Table 1).
For conservatism this voltage was used for calculating voltages on the San Onofre Unit 1 distribution buses. The computer calculation results are tabulated in Table 1.
-4 In view of the fact that the calculated minimum voltage is greater than the minimum acceptable voltage of electrical equipment (see the Response to Guideline 9),
procedures and/or Technical Specifications are not required for this contingency.
Guideline 7 The voltage analysis should include documentation for each condition analyzed, of the voltage at the input and output of each transformer and at each intermediate bus between the connection to the offsite circuit and the terminals of each safety load.
Response
As indicated above, two cases were analyzed:
unit trip and LOCA. Each of these analyses is summarized below:
Voltage Analysis for Unit Trip Condition With respect to voltage degradation, the worst postulated unit trip condition is as follows:
- 1.
San Onofre Unit 1 trips.
- 2.
Unit Auxiliary Transformers A and B are out of operation and the offsite power source is from Reserve Auxiliary Transformer C.
- 3.
The lowest calculated system voltage of 217.8 kV is assumed (Case 6 in Table 1).
- 4.
Onsite sources of ac power (diesel generators) are not available.
- 5.
Maximum load (20 MVA) necessitated by the event is assumed.
The calculated voltages on the various bases for the above postulated conditions are as follows:
480 V 480 V 480 V Bus 1C-1A Bus 1B-20 Swgr. No. 1 Swgr. No.
2 Swgr. No. 3 3,932 V 3,975 V 438 V 443 V 438 V As can be seen from the above figures, the voltages at the 4 kV and 480 V buses are above 90% of the rated bus voltages of 4,160 volts and 480 volts, respectively.
-5 Voltage Analysis for LOCA With respect to voltage degradation, the worst postulated accident condition is as follows:
- 1.
Unit Auxiliary Transformers A and B are out of operation and the offsite power source is from Reserve Auxiliary Transformer C.
- 2.
The reactor is in the hot shutdown mode.
- 3.
A LOCA occurs.
- 4.
The lowest postulated system voltage of 217.8 kV is assumed (Case 6 in Table 1).
- 5.
Onsite sources of AC power (diesel generators) are not available.
- 6.
Maximum load (5,339 kVA on 4 kV bus 1C, 2799 kVA on 4 kV bus 2C) necessitated by the event is assumed.
In order to simplify the voltage calculation, both 4 kV buses are assumed to carry 5,339 kVA.
Thus, a conservative result is obtained.
The calculated voltages at the various buses for the above postulated conditions are as follows:
Voltage Dip Bus Regulation 4 kV Bus 1C 3,417 Volts 4,031 Volts (82.1% of 4,160 Volts)
(96.9% of 4,160 Volts) 480 V SWGR No. 1 370 Volts 440 Volts (84% of 440 Volts)
(100% of 440 Volts)
Safety Injection Pump B 3,406 Volts Motor Terminal (81.8% of 4,160 Volts)
Feedwater Pump B 3,406 Volts Motor Terminal (81.8% of 4,160 Volts)
Guideline 8 The analysis should document the voltage setpoint and any inherent or adjustable (with nominal setting) time delay for relays which (1) initiate or execute automatic transfer of loads from one source to another; (2) initiate or execute automatic load shedding; or (3) initiate or execute automatic load sequencing.
e-0
Response
A description of the undervoltage protection system at San Onofre Unit 1 along with the existing setpoints was provided in SCE's letter to the NRC dated November 4, 1977.
Guideline 9 The calculated voltages at'the terminals of each safety load should be compared with the required voltage range for normal operation and starting of that load.
Any identified inadequacies of calculated voltage require immediate remedial action and notification of NRC.
Response
The acceptable level of voltage degradation is determined by the limitations of safety related electrical equipment. Based on manufacturer's specifications, the voltage ranges over which components at San Onofre Unit 1 can operate continuously in the performance of their design functions are:
- 1.
Motors and motor-operated valves:
rated voltage +/-10%.
- 2.
Motor controllers:
rated voltage +10% or -15%.
The voltage range for motors and motor-operated valves is the most restrictive operating condition, and therefore establishes the lower limit of continuous system operation to be 90% of nominal system voltage.
As described in the response to Guideline 7 above,,the calculated voltages are greater than 90% for both cases analyzed.
With respect to starting voltages, industry standards permit minimum starting voltages of 60% of rated motor voltages. Although specific minimum starting voltages were not available for the safety injection and feedwater pump motors, based on industry standards 80% is considered acceptable. As described in the response to Guideline 7, the calculated voltages are greater than 80% for the case analyzed.
Guideline 10 For each case evaluated the calculated voltages on each safety bus should be compared with the voltage-time settings for the undervoltage-relays on these safety buses.
Any identified inadequacies in undervoltage relay settings require immediate remedial action and notification of NRC.
Response
This information is provided in the Response to Guideline 8 above. No inadequacies were identified.
Guideline 11 To provide assurance that actions taken to assure adequate voltage levels for safety loads do not result in excessive voltage, assuming the maximum expected value of voltage at the connection to the offsite circuit, a determination should be made of the maximum voltage expected at the terminals of each safety load and its starting circuit.
If this voltage exceeds the maximum voltage rating of any item of safety equipment, immediate remedial action is required and WRC shall be notified.
Response
The possibility of excessive voltage on the San Onofre Unit 1 electrical distribution system has been analyzed. The highest possible system voltage at San Onofre Unit 1 is 234.5 kV when San Onofre Units 1, 2 and 3 are energized and there is no loss of transmission lines.
At 234.5 kV, the system voltage at San Unofre Unit 1 is 102$ of the transformer rated voltage of 230 kV. Two percent higher system voltage will not result in excessive voltage at the terminals of any safety load.
Guideline 12 Voltage-time settings for undervoltage relays shall be selected.so as to avoid spurious separation of safety buses from offsite power during plant startup, normal operation and shutdown due to startup and/or operation of electric loads.
Response
See the hesponse to Guideline b above.
Guideline 13 Analysis documentation should include a statement of the assumptions for each case analyzed.
Response
The assumptions for the cases analyzed are provided in the Response to Guide line 7 above.
TABLE 1 VOLTAGE PRUFiLES AT SAN ONOFRE UNIT 1 Calculated System Voltage ase Postulated System Condition kV of 230 kV 1
1963:
San Onofre Units 1, 2 and 3 generators are 222.2 96.61 off, no auxiliary loads for San Onofre Units 1, 2 and 3 2
1983:
San Onofre Units 1, 2 and 3 generators are 219.2 95.30 off, with full auxiliary loads (161.3 MW, 73.3 MVAR) for San Onofre Units 1, 2 and 3 3
1980:
San Onofre Unit 1 off, all lines on 221.7' 96.39 4
1960:
San Onofre Unit 1 off, Chino, Villa Park, and 222.6 96.78 Santiago 1 and 2 off 5
1980:
San Onofre Unit 1 off, Encina, Talega, 220.0 95.65 Mission, and Santiago No. 1.
off 6
1980:
San Onofre Unit 1 off, Talega, Encina, and 217.8 94.70 Santiago Nos. 1 and 2 off
.7 1980:
San Onofre Unit 1 off, Chino, Villa Park, 220.8 96.00 Talega and Encina off 1980:
San Onofre Unit 1 off, Mission, Enoina,.and 216.9 95-17 Santiago Nos. 1 and 2 off 9
1980:
San Onofre Unit 1 off, Chino, Villa Park, 221.6 96.35 Encina and Mission off Review of Electric Power Systems With Respect to General Design Criteria 17 San Onofre Unit 1 An analysis of the electric power systems at San Onofre Unit 1 with respect to the provisions of General Design Criterion 17 (GDC-17), "Electric Power Systems," is provided in the following paragraphs.
Specifically, the provisions with respect to the onsite and offsite electric power systems are addressed.
Onsite Power System The onsite power system at San Onofre Unit 1 consists of two 6000 kW diesel generators and associated auxiliary and distribution equipment. The onsite system has been previously described in Amendment 38 to the Unit 1 Docket No. 50-206, which was submitted to Mr. E. G. Case by letter dated February 7, 1975. An analysis of the capacity and capability of the onsite system to mitigate the consequences of a loss of coolant accident (LOCA) or main steam line break (MSLB) is provided in Amendment 38.
The ability to handle anticipated operational occurrences is provided in Section 9.1.of the San Onofre Unit 1 Final Safety Analysis Report (FSAR).
The ability of the onsite power system, including the batteries, to perform its function assuming a single failure was analyzed and reported to-Mr. A. Schwencer by letter dated
.December 21, 1976.
Where inadequacies were identified, corrective measures were implemented as described in letters to Mr. A. Schwencer dated March 25, 1977 and Mr. V. Stello dated April 1, 1977.
Therefore, no single failure will prevent the onsite power system from performing its safety function.
Testing features of the onsite power system are described in Amendment 38 and Section 4.4 of the San Onofre Unit 1 Technical Specifications.
Offsite Power System The offsite distribution system is currently being modified as described in Amendment 90 to the Unit 1 Docket No. 50-206, which was submitted to Mr. H. R. Denton by letter dated April 4, 1980. A complete description of the modified offsite power system is provided in Chapter 8 of the San Onofre Units 2 and 3 FSAR. The capability.and capacity of the offsite power system to mitigate the con sequences of a LOCA is provided in Enclosure 1 to this letter.
The ability to handle anticipated operational occurences is provided in Section 9.1 of the San Onofre Unit 1 FSAR.
-2 As described in Amendment 90, the switchyard for San Onofre Unit 1 is connected to the SCE and SDG&E systems via either of two physically independent transmission routes composed of up to four SCE lines and up to three SDG&E lines.
Of these seven lines any one can serve as the source of power to the station auxiliaries at any time. Power for station auxiliaries is provided off of the north dead-end structure via two powerlines:
one to the main transformer and one to the reserve auxiliary transformer. Either transformer will supply all of the station auxiliaries. In the event of loss of all onsite alternating current power supplies and one of the off site electric power circuits, availability of the other circuit is not affected since there is no automatic transfer to the other circuit.,
The offsite power system is designed and located so as to minimize to the extent practical the likelihood of the simultaneous failure of the two circuits as detailed below:
- 1. Transmission Routes -
The two transmission routes (SCE and SDG&E) are physically independent leaving the switchyard at different locations.
- 2. Transmission Lines -
Each of the seven transmission lines is routed independently to the switchyard (both structurally and electrically).
- 3. Switchyard -
The switchyard is designed in a double bus arrangement so that on each side of the breakers which isolate the SCE side from the SDG&E side the required loads can be supplied from two separate buses. Although the two sets of lines from the switchyard to the station transformers share a common dead-end structure, the breaker isolation scheme ensures that the two circuits are completely independent electrically. As described in Amendment 90, the design of the dead-end structure, as part of the common switchyard conforms with GDC-17.
- 4. Buses - As noted above the station can be connected to two separate isolatable switchyard buses. A fault on one bus is isolated from the other bus by the breakers.
- 5. Breakers -
The station circuits are connected to the switchyard buses in a double breaker arrange ment.
If any breaker fails open the ability to connect that circuit to the other bus or to connect the other circuit to either bus is not affected.
- 6. Breaker Control Power -
The switchyard breakers on the two buses available to the station circuits are controlled from the DC power supply in the SCE relay house, However, in the event of failure.
-3 of the SCE batteries or battery charger, the capa bility exists to cross connect the DC bus in the SCE relay house to the batteries and battery charger in the SDG&E relay house. A short on the DC bus in the SCE relay house will not result in loss of the offsite power circuit since the breakers fail as is on loss of DC power.
- 7. Station Transformers -
Power can be provided to the station through two independent circuits:
(1) auxiliary transformer C, or (2) the main transformer and auxiliary transformers A and B. A failure of the transformer(s) in either of these circuits will not affect the other circuit since there is no automatic transfer of loads from one to the other.
Southern California Edison Company CO P.O.
BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD CALIFORNIA 91770 May 29, 1980 1
U. S. Nuclear Regulatory Cmmission Office of Inspection and Enforcement Region V 1990 North California Boulevard Suite 202, Walnut Creek Plaza Walnut Creek, California 94596 Attention: Mr. R. H. Ehgelken, Director DOCKET No. 50-206 SAN ONOFRE - UNIT 1
Dear Sir:
Reference:
- 1) Letter dated May 16, 1980 from SCE (J. M. Curran) to NRC (R. H. Engelken)
The referenced letter provided proupt notification of radiographic indications in two main steam piping circumferential welds inside containment.
This letter provides an interim follow-up report in accordance with the provisions of Section 6.9.2.a of Appendix A to the Provisional Cperating License No. DPR-13.
In connection with our current refueling outage, we are conducting radiographic examinations of main steam circumferential welds inside contain ment. These examinations are being performed in addition to those required by our Inservice Inspection Program (ISI). Initially, two welds were found to have reportable indications identified as slag inclusions.
These indica tions are in excess of the allowable standards of the original design code, ASME B&PV Code, Section 1. As a result, we expanded the inspection program to include all circumferential main steam welds inside containment that are within the scope of our ISI Class 2 program. To date 26 of the 33 welds within this scope have been examined by radiography. Of those inspected, a total of four have reportable indications.
The two welds previously reported, 1-3 and 1-5, have slag inclusions. Additionally, weld 2-2 has slag inclusions, porosity, and an approximately 3/4" long lack of penetration. Weld 2-3 also has slag inclusions. All of these welds are under evaluation per the provisions of ASME Section XI, Articles IWA-3000, IWB-3000 and IWC-3000.
U. S. Nuclear Regulatory Commission Page 2 The results of this evaluation with a revised Licensee Event Report will be provided to your office prior to our return to service.
Sincerely, H. L. Ottoson Manager of Nuclear Operations
Enclosure:
Licensee Event Report 80-024 cc:
Director, Nuclear Reactor Regulation (30)
Director, Office of Management Information & Program Control (3)
Director, Nuclear Safety Analysis Center (1)
NRC FORM 366 U. S. NUCLEAR REGULATORY COMMISSION 7
LICENSEE EVENT REPORT CONTROL BLOCK:
I 1 0
(PLEASE PRINT OR TYPE ALL REQUIRED INFORMATION) 1 6
[l] Ic lAIS O IS 11 1010 I0 1-10 10 10 1010 1- 00 LOJ3 1 111111110 1 1 7
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LICENSEE CODE 14 15 LICENSE NUMBER 25 26 LICENSE TYPE 30 57 CAT 58 CON'T 01 REPORT I'
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8 60 61 DOCKET NUMBER 68 69 EVENT DATE 74 75 REPORT DATE 80 EVENT DESCRIPTION AND PROBABLE CONSEQUENCES During the current Refueling Outage while performing radiographic examinations of I
selected main steam lines inside containment, four welds were found with indications I FOT4 I consisting of slag inclusions, porosity and/or lack of penetration. These l
FT indications are in excess of those permitted by the ASME B&PV Code,Section I. There I OT6 I were no adverse effects, oh public health or safety.
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VALVE CODE CODE SUBCODE COMPONENT CODE SUBCODE SUBCODE
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10 11 12 13 18 19 20 SEQUENTIAL OCCURRENCE REPORT REVISION LER/RO EVENT YEAR REPORT NO.
CODE TYPE NO.
REPORT SQ18U10E1 I2L OCREE REPOR RE RUMER
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1j l01 IO L 21 22 23 24 26 27 28 29 30 31 32 ACTION FUTURE EFFECT SHUTDOWN ATTACHMENT NPRD-4 PRIME COMP.
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B 113 10 33 34 35 36 37 40 41 42 43 44 47 CAUSE DESCRIPTION AND CORRECTIVE ACTIONS The indications apparently have existed in the line from original plant construction. l Indications include slag inclusion, porosity and a 3/4 inch long lack of penetration. l All indications are under evaluation in accordance with ASME B&PV Code,Section XI, Articles IWA-3000, IWB-3000 and IWC-3000.
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FACILITY METHOD OF STATUS
%POWER OTHER STATUS30I, rl_7SAU OE TE TTS DISCOVERY DISCOVERY DESCRI PTION 1_
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10 12 13 44 45 46 80 ACTIVITY CONTENT RELEASED OF RELEASE AMOUNT OF ACTIVITY LOCATION OF RELEASE E
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9 10 11 4480 PERSONNEL EXPOSURES NUMBER TYPE DESCRIPTION 0 0 0 IOLZQ N.A.
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9 11 12 13 80 PERSONNEL INJURIES NUMBER DESCRIPTION(j) 10 1 0_ 1@ N.A.
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9 11 12 80 LOSS OF OR DAMAGE TO FACILITY TYPE DESCRIPTION I Z 1@1 N.A.
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9 10 80 PUBLICITY NRC USE ONLY ISSUED DESCRIPTION @
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106 J.____M.
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(714) 4192-7700 0
NAMEMOFEPREPARER ETH DISOVRYPIOER DECTO 32
Southern California Edison Company P.O. BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD, CALIFORNIA 91770 COP May 28, 1980 U. S. Nuclear Regulatory Comission Office of Inspection and Enforcement Region V 1990 North California Boulevard Suite 202, Walnut Creek Plaza Walnut Creek, California 94596 Attention: R. H. Engelken, Director DOCKET No. 50-206 SAN ONOFRE UNIT 1
Dear Sir:
Reference:
Letter from SCE (J. M. Curran) to USNRC ( R. H. Engelken) dated May 14, 1980 The referenced letter provided prompt notification to the regional office of two failed hydraulic shock and sway suppressors (Snubbers). This letter constitutes a follow-up report submitted in accordance with the provisions of Section 6.9.2.a(9) of Appendix A to our Provisional Cperating License DPR-13.
While performing functional testing on an initial sample of ten snubbers, in accordance with Technical Specification 4.14.C., two were determined to be failed. The first had been selected based upon a visual inspection (in accordance with Technical Specification 4.14.A) to determine its operability with low reservoir level. Functional testing in this case was used to verify visual acceptability or rejection. This snubber is identified as main feedwater snubber 1-S-SW-393-1 and is located inside containment. Disassembly of the snubber revealed that it had a worn piston rod bushing, worn cylinder and was essentially empty of hydraulic fluid. It is postulated that a gradual loss of hydraulic fluid occurred, and this coupled with piping vibration eventually caused the piston rod bushing and cylinder wall to wear excessively. The damaged components and seals were replaced and the reassembled snubber functionally tested satis factorily prior to installation.
ro
U. S. Nuclear Regulato# Commission Page 2 The second failure, main steam snubber 1-S-SW-7-1 located inside containment, was preliminarily identified as a piston rod thread shearing failure similar to that seen previously in October 1978 and June 1979. However, our investigation has determined that the failure was due to operator error during functional testing. The testing machine operator inadvertently loaded this snubber to the test value for a larger capacity snubber causing it to overload and fail.
As this damage was due to a test overload, it is not considered a functional testing failure. The failed piston rod and nut were replaced and the reassembled snubber was successfully functionally tested at the rated load.
In accordance with the functional testing requirements of Technical Specification 4.14 an additional 10% sample of snubbers were functionally tested.
All snubbers in this second sample were satisfactory.
In accordance with Technical Specification 4.14.A, all hydraulic snubbers inside containment will be reinspected visually within 12 months + 90 days of May 13, 1980.
Should you have any further questions on this matter, please contact me.
Sincerely, H. L. Ottoson Manager of Nuclear Operations
Enclosure:
Licensee Event Report 80-020 cc:
Director, Nuclear Reactor Regulation (30)
Director, Office of Management Information & Program Control (3)
Director, Nuclear Safety Analysis Center (1)
NRC FOF,1 366 U. S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT CONTROL BLOCK:
I (D (PLEASE PRINT OR TYPE ALL REQUIRED INFORMATION) 1 6
[111 I clAI SI 0lS 1101 0 11-10 10 10.10 101-l0 10 0 1( 1 Jil110 7
8 9
LICENSEE CODE 14 15 LICENSE NUMBER 25 26 LICENSE TYPE 30 57 CAT 58 CON'T 1REP E LJ l0151010101210 16 0151113181010010512181810 7
8 60 61 DOCKET NUMBER 68 69 EVENT DATE 74 75 REPORT DATE 80 EVENT DESCRIPTION AND PROBABLE CONSEQUENCES o During refueling outage, while performing functional testing, two failed hydraulic SIshock and sway suppressors were found.' One exhibited abnormal wear bn the piston I
Fo 4 Irod bushing and cylinder wall. The other had failed threads on piston rod and nut.
o I The first was a support for main feedwater piping and the second for main steam OT61 I piping. Both are located inside containment. There was no effect on public safety.
(Previous similar LERs 78-11, 79-09).
7 8 9 80 SYSTEM CAUSE CAUSE COMP.
VALVE CODE CODE SUBCODE COMPONENT CODE SUBCODE SUBCODE 09 10 HI@ L B j 9 S I U1 PJ 0l RI TI L9 LJ 7
8 9
10 11 12 13 18 19 20 SEQUENTIAL OCCURRENCE REPORT REVISION LER/RO EVENTYEAR REPORT NO.
CODE TYPE NO.
REPORT 1S 10EQUENTIAL OCREE RPT REVII RUg I8O
-- j l10 12 10 1 0 l1 1i L.J 1--
L 0 L 21 22 23 24 26 27 28 29 30 31 32 ACTION FUTURE EFFECT SHUTDOWN ATTACHMENT NPRD-4 PRIME QOMP.
COMPONENT TAKEN ACTION ON PLANT METHOD HOURS SUBMITTED FORM SUB.
SUPPLIER MANUFACTURER LIA@LzJ@
LzJ@
1 @
1010 10qI I J@ LiJ@
@ 111210 II 33 34 35 36 37 40 41 42 43 44 47 CAUSE DESCRIPTION AND CORRECTIVE ACTIONS 0 Two Fig. 201 2-1/2 X 10" hydraulic shock and sway suppressors were found failed.
Excessive hydraulic fluid leakage leading to abnormal wear is the postulated cause of the first failure. Operator error during functional testing overstressed the second snubber resulting in piston rod and nut failure.
7 8
9 80 FACILITY METHOD OF STATUS
%POWER OTHERSTATUS DISCOVERY DISCOVERY DESCRIPTION 1
1 1]
101010 1029L (LJI Surveillane 7
8 9
10 12 13 44 45 46 80 ACTIVITY CONTENT RELEASED OF RELEASE AMOUNT OF ACTIVITY 5
LOCATIONOFRELEASE&
1I
[zj.@ LZJI N.A.
I I
N.A.
7 8
9 10 11
.44 45 80 PERSONNEL EXPOSURES NUMBER TYPE DESCRIPTION W ~10010 ILZ1@l N.A.I 7
911 12 13 8
PERSONNEL INJURIES80 NUMBER DESCRIPTIDNS Y
P 1 o lo1010 1@1 N.A.
1 7
849 11 12 80 LOSS OF DR DAMAGEOC TYPE DESCRIPTION
.N.A.
7 8 9 10 80 PUBLICITY INJURIES ISSUED DESCRIPTION 0 Z JO N.A.
72 8
9 11 12 1
801 1
7 8
9 10 68 69 80 &
NAMEOFPREPARERJ. M.
CURRAN (714) 492-7700 0
PHONE--
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