ML13330A025
| ML13330A025 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 03/25/1980 |
| From: | Haynes J Southern California Edison Co |
| To: | Ziemann D Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML13330A026 | List: |
| References | |
| RTR-NUREG-0578, RTR-NUREG-578, TAC-44128 NUDOCS 8003280456 | |
| Download: ML13330A025 (26) | |
Text
Southern California Edison Company P. 0. BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD. CALIFORNIA 91770 March 25, 1980 Director, Office of Nuclear Reactor Regulation Attention:
Mr. D. L. Ziemann, Chief Operating Reactors Branch #2 Division of Operating Reactors U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Gentlemen:
Subject:
Docket No. 50-206 Implementation of Category A Lessons Learned Requirements San Onofre Nuclear Generating Station Unit 1 During meetings held at San Onofre Unit 1 on March 10 and 11, 1980,.the NRC reviewed the equipment, procedural and administrative changes we made to implement the Category A Lessons Learned requirements.
Based on this review, the NRC indicated at the meeting that additional information/actions are necessary to complete the imple mentation of the Category A requirements.
The necessary additional information/actions were forwarded to us as an enclosure to your March 13, 1980 letter which requested that we provide a written response to each item by March 18, 1980. During telephone discussions with members of your staff, we indicated that our responses would be submitted by March 28, 1980.
Submitted herein is the report entitled "Additional Information/Actions to Implement Category A Lessons Learned Requirements."
The report contains our responses to each of the items required by the NRC.
The organization of the enclosed report is such that each item of the enclosure to your March 13, 1980 letter is stated followed by our re sponse.
If you have any questions, or desire additional Od information concerning the enclosed report, please contact me.
Very tru y yours, J. G. Haynes Chief of Nuclear Engineering Enclosure 800032 80
I*
ADDITIONAL INFORMATION/ACTIONS TO IMPLEMENT THE CATEGORY A LESSONS LEARNED REQUIREMENTS SAN ONOFRE NUCLEAR GENERATING STATION UNIT 1
- MARCH, 1980
SECTION 2.1.1 Item:
Provide statement of qualification for modifications made to backup nitrogen pneumatic supply to PORV's and block valves.
Response
The modifications made to backup the pneumatic supply to the Power Operated Relief Valves and their associated block valves consisted of the installation of pipes, tees, elbows, couplings, reducers, connectors, check valves and plates.
All the material used will withstand the Loss-of-Coolant Accident environment of at least 3000 F, 65 psia, 0-100% relative humidity and 2 x 108 Rads.
SECTION 2.1.3.a Item:
Provide statement of qualification for valve position indication modifications.
Response
The valve position indication modifications consisted of installation of limit switches (Model EA 180 by NAMCO) with CONAX conductor seal module assemblies at each switch connector on the Power Operated Relief Valves, their associated block valves and the safety valves. The limit switches and conductor seal module assemblies have been environmentally qualified, by test, to 340 0F, 70 psig, and 2.04 x 108 Rads and 340 0F, 65 psia and 1.5 x 108 Rads, respectively.
2
SECTION 2.1.3.b Item:
Clarify your position regarding the need for additional instrumentation for inadequate core cooling (e.g., level meter).
Response: Our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut provided a description of existing instrumentation, including the new primary coolant saturation recorder, which will be used to recognize the existence of inadequate core cooling. This instrumentation is sufficient, when used in conjunction with our procedural guidelines, to provide an unambiguous and easy-to-interpret indication of inadequate core cooling. Furthermore, our procedural guidelines and operator training are sufficient to provide reasonable assurance that core cooling can be restored using the existing instrumentation.
Therefore, additional instrumentation (e.g., level meter) to detect inadequate core cooling is not warranted.
Item:
If your position is that additional instrumentation should be installed, provide the schedule for submitting the design of such instrumentation.
As discussed above, additional instrumentation (e.g., level meter) is not warranted. However, we are participating in additional evaluations to determine if additional instrumentation will provide a more direct indication of inadequate core cooling than that available with the existing instrumentation.
If any additional instrumentation is identified which would provide a more direct indication of inadequate core cooling and can be implemented at San Onofre Unit 1, we will reevaluate the need for.additional instrumentation at San Onofre Unit 1. We will advise you as soon as is practicable following completion of our reevaluation regarding whether additional instrumentation should be installed at San Onofre Unit 1.
Item:
Provide statement of qualification for subcooling meter and inputs.
Response: The subcooling meter and inputs are qualified as discussed below:
3
0 Subcooling Meter The subcooling meter recorder and electronic calculational components are located in the Control Room. For new instrumentation installed in the Control Room, the environmental design conditions are 36-1200F, 14.7 psia, 0-100% relative humidity and 5.x 102 Rads as discussed in Appendix 1 to our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut.
These design conditions represent the worst case expected environment in the Control Room with normal ambient conditions being less severe.
The subcooling meter recorder and electronic calculational components were purchased "off the shelf" as controls grade without certification documents. High quality, reliable components were purchased as discussed in our November 21, 1979 letter from K. P. Baskin to D. G. Eisenhut. There is reasonable assurance that the subcooling meter recorder and electronic calculational components will not be adversely affected by either the normal or the worst case environmental conditions expected in the Control Room.
o Primary Coolant System Pressure Input The pressure transmitter utilized for this application is a Foxboro E11GM. This transmitter has been environmentally quglified to 300 0 F, 75 psia, 100% relative humidity and 2.2 x 100 Rads by test and analysis as discussed in our February 13, 1979 letter from K. P. Baskin to D. L. Ziemann.
o Primary Coolant System Temperature Input The RTD's utilized for this application are Weed #2004.
These RTD's have been environmentally qua ified to 2910 F, 64 psia, 100% relative humidity and 3.5 x 10 Rads by Certificate of Compliance from the supplier as discussed in our February 13, 1979 letter.
Item1:
Propose a method (with schedule) to provide redundant loop temperature and system pressure inputs.
Response: By letter dated October 30, 1979, the NRC provided clarification of the NRC staff requirements for installation of a subcooling meter.
the NRC letter indicated that either of the following methods could be utilized:
- 1..Safety grade calculational devices and display (minimum of two meters), or
- 2.
A highly reliable single channel environmentally qualified, and testable system plus a backup procedure for use of steam tables.
Our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut indicated that a single channel meter was installed to be used in conjunction with a backup procedure using curves based on steam tables. The meter is provided with a pressure input (one) and three loop temperature inputs (one per loop).
The meter is also provided with a manual switching capability to allow the operator to select any of the three loop temperature inputs. In addition, the pressure and temperature (incore thermocouples) inputs for the backup procedure are independent from those used for the meter. Therefore, since no single failure (e.g., either in the single channel subcooling meter system or backup procedure) can result in loss of our ability to determine subcooling, redundant pressure and loop temperature inputs to the subcooling meter are not warranted.
11&m-:
Propose a method (with schedule) for automatic selection of the most limiting temperature and pressure inputs.
Response: As discussed above, a single channel subcooling meter system has been installed. The subcooling meter is provided with one pressure input and three loop temperature inputs (with manual switching capability).
Station procedures on the use of the subcooling meter require that each of the loop temperature inputs be manually monitored once per shift and that the most restrictive (highest) loop temperature input be selected. Since station procedures also require that curves based on steam tables be administratively used, in conjunction with the subcooling meter, the manual switching capability provided for the subcooling meter is consistent with the operational/procedural method of determining the margin to subcooling. Therefore, automatic selection of the most limiting temperature inputs is not warranted.
ItaQm:
Propose a method (with schedule) to provide a range of subcooling margin display covering inputs of 300-700oF and 15-2500 psia.
Respgn: As discussed in our November 21, 1979 and February 13, 1980 letters from K. P. Baskin to D. G. Eisenhut and D. L. Ziemann, respectively the range of inputs to our subcooling meter are 400 to 2400 psia and 450 to 7000F. The basis for these ranges is discussed below:
o Pressure input - 2000 psi of span was chosen to provide an easy to interpret scale which would include the entire range of pressures where subcooling indication would be useful to the operator. Pressures below 400 psig during post accident conditions would only occur with safety injection taking place at maximum rate. Thus, no corrective actions can be taken to improve core cooling beyond those included by system design (i.e., safety injection) and specified in station procedures (i.e., safety injection termination criteria of at least 2000 psig).
Pressures above 2400 psig are more than 200 psig above the Power Operated Relief Valve set point. Thus, no corrective actions can be taken to improve core cooling beyond those included by station design and specified in station procedures (i.e., primary system relief),
5
I o
Temperature input - The lower end of the temperature band was chosen to be compatible with the pressure range discussed above (i.e., saturation temperature at 400 psig is about 450 0F).
In addition, temperatures below 450O0F during post accident conditions will only occur (1) with safety injection taking place at maximum rate due to low Reactor Coolant System pressure, or (2) with well over 100 0F of subcooling based on the minimum safety injection termination criteria of 2000 psig. In either case, no operator actions to improve core cooling will be necessary beyond those included by station design and specified in station procedures.
o Ranges for both pressure and temperature inputs were limited, as practical, to improve the accuracy of the subcooling indication.
Our February 13, 1980 letter provided documentation of all errors (and their source) associated with subcooling determination. That letter indicated that the maximum errors associated with the subcooling meter are.+/-17.50F for the spans chosen. Wider spans will increase the maximum errors such that 20oF of actual subcooling can not be provided based on the current safety injection termination criteria. In addition, it would be necessary to raise the subcooling alarm setpoint above the full load subcooling value, resulting in a continuous alarm condition during normal operation.
o As indicated in our February 13, 1980 letter, the backup procedures for subcooling determination can be determined over ranges of pressure inputs from 0 to 3000 psig and temperature inputs from 32 to 24950F (although spans of 2500 psi and 600 0F were assumed for purposes' of the subcooling error deter mination). These inputs are independent from those used for the subcooling meter. Therefore, the ability to administratively monitor subcooling over wider ranges than those requested is currently provided.
6
SECTION 2.1.4 Item:
Describe the valve control circuit modifications you will make to provide individual valve reopening capability (include schedule).
Response: The valve control circuit modifications that will be made to provide individual valve reopening capability will consist of the following:
- 1.
Containment isolation actuation signal.
- 2.
Containment isolation control logic.
- 3.
Control Room control panel.
- 4.
Isolation valve control circuit and override feature.
- 5.
Power supplies and annunciation.
A summary description of each of these modifications is provided below:
Containment Isolation Actuation Signal Individual containment isolation system train actuation will be generated based on either a two out of three high containment pressure or a safety injection signal. The containment high pressure signal for each train will be generated from three pressure transmitters per actuation train. The safety injection signal is generated by each safeguard load sequencing system. One sequencing system will provide the actuation signal for each train.
The containment isolation actuation signal cannot be reset unless the two out of three containment high pressure is below 2 psig and the safety injection system is reset. Therefore, in order for the operator to open a single valve or a group of valves during this period, override switches will be provided.
Figure 1, "System Logic Diagram", schematically shows the containment isolation actuation system.
Containment Isolation Control Logic The actuation logic for each train will be generated in a new logic nest to be installed in the Control Room. The logic nest associated with each train will include logic level integral power supplies powered by the vital buses. Each logic nest will contain signal conditioning and logic modules which will be arranged in a two out of three logic configuration for the containment high pressure signal and combined in an either/or configuration with the safety injection signal to provide a containment isolation actuation signal to the relay panel. A containment isolation signal to each valve circuit will be generated in the relay panel.
Figure 1, "System Logic Diagram", schematically shows the containment isolation control logic.
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Control Room Control Panel All automatic containment isolation valve control, valve position indication and test functions will be provided for each valve train on separate and independent train aligned subpanels to be located in the existing Control Room control panel. Each subpanel will consist of:
- 1.
Individual valve back lighted control push-button switches.
- 2.
System level manual initate controls and indication.
- 3.
Containment isolation signal system reset.
- 4.
Channel test function push buttons.
- 5.
Subsystems level containment isolation signal override function.
Isolation Valve Control Circuit and Override Containment isolation system relay panels will be installed to multiply the containment isolation actuation signal for individual valve control. Each valve control circuit will consist of a latching relay control and override control in addition to the valve position indication circuit. The latching control scheme prevents automatic reopening of the isolation.valve on containment isolation actuation signal reset.
The override feature allows the operator to bypass the containment isolation actuation signal, if present, in order to open the desired valve or penetration. If a containment isolation actuation signal is present and the operator desires to open an isolated valve, he has to operate the assigned override switch for the subsystems with which the desired valve is associated. Once the override switch is operated, a common annunciator in the Control Room will be energized indicating that the containment isolation actuation signal for that particular subsystem is being overridden. After acknowledging the alarm, the operator will have to go to the Control Room control panel and operat6 the individual valve control switch in order to open the isolated valve.
The automatic containment isolation valves on process lines are identified in Table 1. Table 1 also shows the subsystem grouping of valves and their associated overide switch.
Power Supplies and Annunciation The actuation and reset circuitry, including pressure sensors and logic nests, will be supplied from the vital buses. All of the isolation valves which are powered from 125 volt DC Systems will be aligned to the independent 125 volt DC Systems to meet redundancy and separation criteria.
The isolation valves which are powered from 120 volt AC will be train aligned with power supplied by redundant 120 volt AC power sources.
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Annunciation will be provided on a train basis to indicate that containment isolation actuation has occurred or that the actuation has been overridden.
The modifications discussed above will be completed prior to resump tion of power operation following the refueling outage scheduled in April, 1980.
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TABLE 1 SUBSYSTEM OVERRIDE GROUPING FOR AUTOMATIC CONTAINMENT ISOLATION VALVES Valves Override Valves Override Description Inside Sphere Switch Outside Sphere Switch Sphere Sump Discharge CV-102 (SV-108) 1A CV-103 (SV-109) 1B RCS Dr Tk Discharge CV-104 (SV-110)l 2A CV-105 (SV-111) 28 RCS Dr Tk Vent CV-106 (SV-112)
CV-107 (SV-113)
N2 to RCS Drain Tank GV-536 CV-535 ORMS 1211/1212 Sphere Sample Supp CV-147 (SV-1212-7),
3A SV-1212-9 3B ORMS 1211/1212 Sphere Sample Ret CV-146 (SV-1212-6))
SV-1212-8 I
A Stm Gen Stm Sample CV-117 (SV-119)
B Stm Gen Stm Sample CV-118 (SV-120)
C Stm Gen Stm Sample CV-119 (SV-121)
A Stm Gen Blowdown Sample CV-121 (SV-123) 4 B Stm Gen Blowdown Sample CV-120 (SV-22)
C Stm Gen Blowdown Sample CV-122 (SV-24)
Service Air to Sphere CV-123 (SV-25) 5 Loop B Cold Leg Vent SV-702B 6A SV-702A 6B Loop C Cold Leg Vent SV-702D SV-720B Service Water to Sphere CV-537 7A CV-115 (SV-126) 7B Sampling ISO Valves CV-949 (SV-949)
Sampling ISO Valves CV-957 (SV-957) 8 Sampling ISO Valves CV-992 (SV-992)J Sphere Purge Air Supply POV-9 (SV-29) 7 9
Sphere Purge Air Outlet POV-10 (SV-30) )
Sphere Equalizing CV-116 (SV-27) 10A Inst. Air Vent CV-40 (SV-19)
Sphere Vent CV-10 (SV-28) 1OB Primary Makeup to Press Rlf Tk CV-533 11A CV-534 11B 10
SECTION 2.1.5 Item:
Describe those systems installed that can be used for post accident H2 control.
Response: Post accident hydrogen control using installed equipment can be achieved by overriding certain containment isolation valves and venting the containment to the station stack via the high efficiency filters. In order to promote the containment venting operation at atmospheric or near atmospheric containment pressures, air can be supplied to the containment from two sources:
- 1.
Instrument air via the containment integrated leak rate test pump back system, and
- 2.
Containment purge fan, A-21, via purge valves 9 and 9A. Purge Valve 9A is a manual valve and would be throttled to provide for a controlled air supply.
Gases can be removed from the containment and vented to the station stack from two locations:
- 1.
Normal containment vent line via control valves 116 and 10, and
- 2.
Containment purge line via purge valves 10 and 10A.
Purge valve 10A is a manual valve and would be throttled to control the exhaust rate from containment once the air supply valves to the containment and the return valves to the station stack have been positioned. Stopping and restarting of the effluent can be accomplished from the Control Room.
Item:
Show how these systems can accommodate a single failure without jeopardizing H2 control or containment integrity.
Response: As described above, two separate air inputs to the containment and two separate return lines to the stack are provided.
Air supplies to the containment are diverse in that station instrument air and containment purge fans can both be used as a source of supply air.
In addition, Power Operated Valves 9 and 10 can be manually operated (locally) upon the loss of electric power or loss of instrument air.
Therefore, no single line or valve failure can prevent the introduction of air to the containment or the removal of hydrogen from the containment.
Item:
Provide schedule for implementing procedures to use these systems for H2 control.
Response: Station procedures will be prepared to use the above described systems for hydrogen control. The procedures will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
__________________11
SECTION 2.1.6.a Item:
Provide a schedule for implementation of plant modifications which have been found necessary as a result of the systems integrity review (including North Anna vent review).
If modifications are to be deferred pending completion of SEP, provide detailed justification to support this delay for each modification.
Response: As discussed in our January 17, 1980 letter from K. P. Baskin to D.
G. Eisenhut, only one station modification has been found necessary as a result of the systems integrity review (including the North Anna vent review).
The station modification involves rerouting the Waste Gas Surge Tank relief valve vent to the station stack via the filters since failure of the venting pathway could result in a direct release of high radioactive fluids to the atmosphere similar to the incident at North Anna.
The implementation of this station modification has been deferred pending completion of the SEP as discussed in our January 17, 1980 letter. The justification to support this delay is provided in our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut. We also indicated in our January 17, 1980 letter that four station modifications were being evaluated in conjunction with the shielding review to limit the extent of the systems potentially containing high level radioactive fluids. However, none of these modifications are necessary based on our systems integrity review to reduce leakage from systems outside containment.
12
SECTION 2.1.6.b Item:
Provide a commitment to implement plant modifications resulting from the shielding and environmental qualification review by 1-1-81.
If modifications are to be deferred pending completion of SEP, provide detailed justification to support this delay for each modification.
Response: The Station modifications resulting from the shielding and environmental qualification review have been deferred pending completion of the SEP as discussed in our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut.
The justification to support this delay is provided in our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut.
As discussed in our January 17, 1980 letter, post accident radiation levels meet the dose limits established in General Design Criterion 19 and additional shielding to the north and west walls of the Control Room is required to maintain the dose level equal to, or less than 15 mr/hour immediately following an accident. Based on our continuing review of the shielding requirements, limiting the post accident radiation levels to meet the dose exposure limits estab lished in General Design Criterion 19 is adequate to assure habitability of the Control Room. Therefore, additional shielding to the north and west walls of the Control Room is not warranted.
13
SECTION 2.1.7.b Item:
Provide, in writing, the accuracy of your AFW flow instruments.
Response: We have installed three-inch and ten-inch Auxiliary Feedwater System flow measurement systems. Each of these systems consist of a sensor, signal conditioning and converter module and flow indicating device with a range of zero to three hundred gallons per minute. The root-mean-square accuracy of the three-inch system is 4.12 percent of full scale.
The accuracy of the ten-inch system must be established by actual testing of the system. The testing will be completed and the results submitted prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
Item:
Provide schedule for safety grade qualification of the AFW flow instruments.
Response: Based on our current schedule, the qualification of the Auxiliary Feedwater System flow measurement systems will be completed by January 1, 1981.
This schedule is consistent with the schedule for qualification of other Category A requirements as discussed in our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut.
Item:
The adequacy of circuit breaker isolation of "control grade" AFW flow instruments from vital buses must be determined.
Response: As discussed in IEEE-384, circuit breakers provide adequate protection against electrical faults. Under electrical fault conditions, the vital buses supplying power to the Auxiliary Feedwater System flow measurement systems and other instruments on the vital buses will be isolated by the circuit breakers.
1~4
SECTION 2.1.8.a Item:
Incorporate criteria into existing emergency procedures to provide for onsite analysis of reactor coolant and containment air samples.
The reactor coolant sample must be analyzed for radioisotopes, dissolved hydrogen and boron concentration. The containment atmosphere should be analyzed for radioisotopes and hydrogen concentration.
Response: Existing station procedures will be revised to incorporate criteria to provide for onsite analysis of reactor coolant and containment air samples. The procedures will explicitly require that the reactor.
coolant sample must be analyzed for radiostopic dissolved hydrogen and boron concentration, and that the containment atmosphere should be analyzed for radioisotapes and hydrogen concentration. The procedures will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
Item:
The dose criteria in GDC 19 should be met, i.e., 5 Rem whole body and equivalent to any part of the body (30 Rem-thyroid, 75 Rem-extremities).
Response: Existing station procedures will be revised to explicitly limit post accident radiation levels to meet the dose exposure limits established in General Design Criterion 19 (i.e., 5 Rem whole body and equivalent to any part of the body-30 Rem thyroid, 75 Rem-extremities).
The procedures will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980..
Item:
Provide schedule for submitting the design details of proposed sampling station and radiological analysis facility. If these modifications are to be deferred pending SEP completion, provide detailed justification to support this position.
Response: We are currently evaluating conceptual designs associated with the proposed sampling station and radiological analysis facility as discussed in our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut. The design details for the sampling station and analysis facility are not expected to be completed prior to June 1, 1980.
The design details will be submitted in a timely manner subsequent to that date when available.
The installation of the sampling station and analysis facility has been deferred pending completion of the SEP as discussed in our January 17, 1980 letter. The justification to support this delay is provided in our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut.
15
SECTION 2.1.8.b Item:
Incorporate procedures for using the Technical Associates remote readout monitor for determination of noble gas release rates from the plant stack (as per your 1-17-80 letter) these procedures should be implemented within 30 days of the date of this letter.
Response: Station procedures will be revised to describe the use of the Technical Associates remote readout monitor for determination of noble gas release rates from the station stack. The procedures will be implemented prior to April 14, 1980.
16
SECTION 2.1.8.c Item:
Incorporate into the plant procedures that one of the two existing Geli systems will be dedicated to analysis of air samples until the new cart mounted sampler is available and appropriate procedures for its use are in effect.
Response: Station procedures will be revised to require that one of the two existing GeLi systems will be dedicated to analysis of air samples until the new cart mounted sampler is available and appropriate procedures.for its use are in effect.
The procedures will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
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NUCLEAR REACTOR REGULATION REQUIREMENTS Itm:
Provide design details of RCS vents.
Response: We are currently evaluating conceptual designs associated with the Reactor Coolant System vents. The design details are not expected to be completed prior to June 1, 1980.
The design details will be submitted in a timely manner subsequent to that date when available.
Item:
Commit to install (RCS vents) by 1-1-81 or propose a schedule with justification.
Response: The implementation of the Reactor Coolant System vents has been deferred pending completion of the SEP as discussed in our January 17, 1980 letter from K. P. Baskin to D. G. Eisenhut.
The justification to support this delay is provided in our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut.
18
SECTION 2.2.1.b Item:
Describe your current program to satisfy the STA operation assessment function of NUREG-0578 (and 10-30-79 Denton letter).
Response: The Operations Assessment Program consists of review of such items as Station Incident Reports, station reports on Technical Specification Violations, Station Licensee Event Reports, responses to IE Bulletins, Circulars and Notices, information of incidents at other facilities, Licensee Event Reports at other facilities, etc.
1m:
Describe how the STA is kept appraised of the work performed by the group doing the operations assessment function.
Response: Information, analysis and feedback on such items will be reviewed by the STA. Station procedures will be revised to describe the content of the Operations Assessment Program and the administrative process to assure that all STA's review the material. The procedures will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
19
SECTION 2.2.2.b Item:
Modify your procedures to require that an individual be stationed in the control room (when TSC is activated) to supply data to the TSC.
This function should not be assigned to the STA.
Response: Station procedure S-VIII-1.21 will be revised to require that an individual (not the Shift Technical Advisor) be stationed in the Control Room when the Technical Support Center is activated to supply information via telephone or via the pass through message box.
The procedure will be implemented prior to resumption of power operation following the refueling outage scheduled to commence in April, 1980.
11Efm:
Provide your long term plan to upgrade the TSC to monitor plant data.
Response: We are currently evaluating conceptual designs associated with the installation of data acquisition systems in the Onsite Technical Support Center. As a minimum, we are considering the following:
- 1.
The system will interface with the existing critical station parameters with some being displayed in the Onsite Technical Support Center by means of a trend type recorder.
- 2.
The system will be actuated automatically in the event of an accident or manually for acquisition of desired data for the evaluation of station status.
- 3.
The critical station parameters to be monitored will be consistent with those recommended by the Westinghouse Owner's Group.
The design details for the data acquisition system are not expected to be completed prior to June 1, 1980.
The design details will be submitted in a timely manner subsequent to that date when available.
The schedule for installation of the data acquisition systems in the Onsite Technical Support Center is provided in our October 17, 1979 letter from K. P. Baskin to D. G. Eisenhut.
RKrieger:mpk 20
Southern California Edison Company P.O. BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD, CALIFORNIA 91770 March 24, 1980 U. S. Nuclear Regulatory Camuission Region V Office of Inspection and Enforcement Walnut Creek Plaza, Suite 202 1990 North California Boulevard Walnut Creek, California 94596 Attention:
Mr.
R. H. Engelken, Director
Dear Sir:
Docket No. 50-206 San Onofre - Unit 1 This letter describes a reportable occurrence involving certain components in the salt water cooling system which are required to be operable under San Onofre Unit 1 Technical Specification 3.3.1.
Submittal is in accordance with the reporting requirements of Technical Specification 6.9.2.a.
At 2115 hours0.0245 days <br />0.588 hours <br />0.0035 weeks <br />8.047575e-4 months <br /> on March 10, 1980 with the unit operating at 100 percent power and with the south salt water cooling pump (G-13B) in operation, salt water cooling pump low flow and low discharge pressure alarms were received on the main control roan auxiliary board annunciator panel.
Concurrently, the north salt water cooling pump (G-13A) autmatically started due to low pressure in the discharge line of south pump G-13B and pump G-13B motor anperage was observed to be indicating low.
Operators were then dispatched to the salt water cooling pump area and reported that both pumps were running with discharge pressures of 0 and 40 psig indicated at the south (G-13B) and north (G-13A) pumps, respectively.
The operators further reported that the pneumatically operated discharge valves (POV's 5 and 6) of each pump were in the closed position.
Under the conditions observed, POV-5 (discharge of north pump G-13A) should have been open while POV-6 (discharge of south pump G-13B) should have been closed.
Efforts were then initiated to open POV-5.
U. S. Nuclear Regulatory Cbmmission Page 2 At 2120 hours0.0245 days <br />0.589 hours <br />0.00351 weeks <br />8.0666e-4 months <br />, the auxiliary salt water cooling pump, G-13C, was manually started from the control room.
However, a low flow condition as indicated by low pump motor amperage was observed.
Investigation of the auxiliary pump and piping system indicated that the low flow condition was due to apparent insuf ficient pump priming and the auxiliary pump was then stopped.
In order to re-establish salt water cooling flow, the screen wash pumps were started from the local panel and valves manually aligned to discharge to the bottom ccmponent cooling water heat exchanger, E-20B, normally served by the north salt water pump, G-13A.
At 2130 hours0.0247 days <br />0.592 hours <br />0.00352 weeks <br />8.10465e-4 months <br />, salt water cooling flow to E-20B was observed to be about 2000 gpm and component cooling water temperature exiting E-20B was decreasing, having reached a peak value of 82*F.
At 2156 hours0.025 days <br />0.599 hours <br />0.00356 weeks <br />8.20358e-4 months <br />, adequate priming was restored to the auxiliary salt water pump, G-13C, and the pump was placed in service.
During the period described above, a limiting condition for operation of Technical Specification 3.3.1.A was not met.
Consistent with the requirement of the specification that the reactor shall not be maintained critical unless the specified limiting conditions are met, preparations were made to commence an orderly shutdown of the unit.
However, at 2200 hours0.0255 days <br />0.611 hours <br />0.00364 weeks <br />8.371e-4 months <br /> with the auxiliary salt water pump restored to operation and consistent with the provision of Technical Specification 3.3.1.B, the unit shutdown was terminated after a slight load reduction and full power operation was resumed while maintenance efforts to open POV-5 continued.
At 0005 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on March 11, 1980, POV-5 was opened and the north salt water pump G-13A placed in service.
At 0010 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, with the north salt water pump and the auxiliary pump determined to be operable, the auxiliary pump was stopped and unit operation proceeded in accordance with the limiting conditions for operation of Technical Specification 3.3.1.A.
Throughout the above incident, adequate cooling was maintained to equipment normally served by the component cooling water system during power operation.
The peak ccnponent cooling water heat exchanger exit temperature of 82*F was well below the alarm condition setpoint of 97 0F.
Temperatures of pump bearings cooled by the component cooling water system were monitored during the incident and no significant changes observed.
Investigations conducted to date have revealed that the south salt water cooling purp, G-13B, shaft failed due to apparent excessive vibration resulting from worn bearings.
The pump shaft and bearings have since been repaired and the pump returned to service.
The failure of POV-5 to open automatically and the problem of insufficient priming of auxiliary salt water purp G-13C are presently under investigation.
Pending the results of these investigations and implementation of appropriate long term corrective actions to prevent recurrence, the following measures are being taken to assure availability of required salt water cooling:
(1)
POV-5 is being maintained open with the
4..
0 U. S. Nuclear Regulatory Cormission.
Page 3 north salt water pump running, and (2) the auxiliary salt water pump surveillance testing will be increased fran once per week to once daily during low tide conditions.
It is planned that long term corrective action to prevent recurrence will be identified and implemented during the forthcoming Cycle 8 refueling outage prior to returning San Onofre Unit 1 to service.
It was concluded that actions taken during this incident were consistent with the requirements of the San Onofre Unit 1 Technical Specifications and that plant conditions were maintained such that there was no effect on the public health and safety.
An investigation is being carried out to review the adequacy of procedures governing operation of the salt water cooling system.
If you have any questions, please contact me.
Sincerely, H. L. Ottoson Manager, Nuclear Generation
Attachment:
Licensee Event Report 80-006 cc:
Director, Nuclear Reactor Regulation (40)
Director, Office of Management Information & Program Control (3)
Director, Nuclear Safety Analysis Center
- RC FORM 366 U. S CLEAR REGULATORY COMMISSION ICENSEE EVENT REPORT CONTROL BLOCK:
I I
(PLEASE PRINT OR TYPE ALL REQUIRED INFORMATION) 1 6
I ClAi SlOS1 11G1 01 01-1 010 01 01 0 -100 4 1 11111 7
8 9
LICENSEE CODE 14 15 LICENSE NUMBER 25 26 LICENSE TYPE 30 57 CAT 58 CON'T REFO5l0O2 6
0 10 0OT2 8
OREORT E Llil@j1 01 51 01 01 01 21 01 0 01 31 11 01 81 0 1G)101 3 1 2 1 41 8!1 0I1 7
8 60 61 DOCKET NUMBER 68 69 EVENT DATE 74 75 REPORT DATE 80 EVENT DESCRIPTION AND PROBABLE CONSEQUENCES O
2 During normal operation, the south salt water cooling pump (SSWCP) discharge pressure dropped sharply. The north salt water cooling pump (NSWCP) automatically O 4 started on low pressure. However, its discharge POV failed to open. The O 5 auxiliary salt water cooling pump (ASWCP) was then started but flow could not be O-6-1 Iestablished.
There was no effect on public health or safety.
F071 7
8 9
80 SYSTEM CAUSE CAUSE COMP.
VALVE CODE CODE SUBCODE COMPONENT CODE SUBCODE SUBCODE EID
~WI1 1 EB (Mj)j NE 098 10~J
__( [IJ03 IMjFIU j0 (9i 5 1 zi 7
8 9
10 11 12 13
.18 19 20 SEQUENTIAL OCCURRENCE REPORT REVISION LER/RO EVENT YEAR REPORT NO.
CODE TYPE NO.
110 REP RT 81 0 0 101 61 0 11 NUBEP L-L.1 LJ 006 1d L JJ Li Li LL]
21 22 23 24 26 27 28 29 30 31 32 ACTION FUTURE EFFECT SHUTDOWN ATTACHMENT NPRD-4 PRIME COMP.
COMPONENT TAKEN ACTION ON PLANT METHOD HOURS (22 SUBMITTED FORM SUB.
SUPPLIER MANUFACTURER o a I
Lo j 0e JO o
o 0ue 14J 1O151 33(734(1 35 36 37 40 41 42 43 44J 47Lj J11 CAUSE DESCRIPTION AND CORRECTIVE ACTIONS As a result of (1) excessive vibration, the shaft of the (SSWCP) sheared; (2) mechanical failure, the (NSWP) 1OV did not open; (3) apparent inadequate prime, the (ASWCP) lost suction.
The POV on the (NSWCP) was manually opened and the (ASWP) regained suction.
Design of the POV and (ASWP) is under investigation.
Shaft of (SSWCP) being replaced.
7 8
9 80 FACILITY METHOD OF STATUS
% POWER OTHER STATUS DISCOVERY DISCOVERY DESCRIPTION 1I ll O IL N.A 2alarms 7
8 9
10 12 13 44 45 46 ACTIVITY CONTENT
.MOUNT4O 80 RELEASED OF RELEASE AMOUNT OF ACTIVITY LOCATION OF RELEASE I~ Z 1@ 110N.A.
N.A.
7 8
9 10 11 44 45 80 PERSONNEL EXPOSURES NUMBER TYPE DESCRIPTION 7
8 9
11 12 13 PERSONNEL INJURIES 80 NUMBER DESCRIPTIONS 1]
1010 10 11 N.A.
7 8
9 11 12 80 LOSS OF OR DAMAGE TO FACILITY TYPE DESCRIPTION 7
8 9
10 PUBLICITY ISSUED DESCRIPTION NRC USE ONLY 7
8 9
10 I
68 69 80 NAME OF PREPARE C
PHONE.
(714) 492-7700