ML19260C541
| ML19260C541 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 12/31/1979 |
| From: | Mayer L NORTHERN STATES POWER CO. |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| RTR-NUREG-0578, RTR-NUREG-578 TAC-12428, TAC-12429, NUDOCS 8001070385 | |
| Download: ML19260C541 (43) | |
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MSE3 NORTHERN STATES POWER COMPANY M IN N E A PO LI S. M I N N E S OTA 5 5401 December 31, 1979 Director of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D.C. 20555 Prairie Island Nuclear Generating Plant Docket Nos. 50-282 License Nos. DPR-42 50-306 DPR-60 Lessons Learned Implementation References (1) NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short Term Recommendations", July, 1979 (2) Letter, D. Eisenhut (NRC) to L. O. Mayer (NSP), dated September 13, 1979 (3) Letter, H. Denton (NRC) to L. O. Mayer (NSP), dated October 30, 1979 Reference (1) identified areas in which the NRC Lessons Learned Task Force felt that safety improvements should be made based on the Three Mile Island-2 experience. Reference (2) defined implementation schedules for the " Lessons Learned" requirements for the operating reactors.
Reference (3) provided clarification of the " Lessons Learned" requirements and recommendatiens. On December 3,1979, the NRC Project Manager notified this office that descriptions of how Northern States Power Company was meeting the Reference (1) requirements were to be provided for all
" Lessons Learned" items. This letter, in addition to previous NSP letters, dated October 17, 1979, November 20, 1979, December 14, 1979, and December 28, 1979, serve to meet that objective. Enclosure (1) addresses each item.
L. O. Mayer, P.E.
Manager of Nuclear Support Services cc: J. G. Keppler G. Charnoff 1696 116 Attachment 8001070 M
Enclosure (1)
Lessons Learned Implementation Prairie Island Nuclear Generating Plant December 31, 1979 1696 117
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1.
2.1.1 EMERCENCY POWER SUPPLY Testing has shown that one group of pressurizer heaters (192 KW) is more than sufficient to maintain natural circulation. The Backup Group "A" Pressurizer Heaters are connected to the 480V Train A Safeguards Buses and are sequenced on by the voltage restoration scheme after loss of offsite power. The Backup Group "B" Pressurizer Heaters are normally energized by a non-safeguards bus but may be transferred to the "B" Train Safeguards bus by a manual transfer switch located in the Rod Drive Power Supply Room which is located within 1 minute of the control room.
For this reason, we do not feel it is necessary to move the transfer switch to the control room.
The PORV's are pneumatic valves operated by instrument air. They fail closed upon loss of air. They are controlled by D.C. solenoid valves which fail closed and vent upon loss of power. Each solenoid valve (two per pressurizer) is supplied by a separate train of D.C. Safeguards power.
The PORV blocking valves are motor valves each supplied by a separate train of 480V Safeguards power. They are cross-trained to the PORV they block so that loss of one train of safeguards power will not prevent closing of the pressurizer relief line.
Pressurizer level instrument channels are powered from the vital instruments buses which are uninterruptible power sources.
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2.
2.1.2 RELIEF AND SAFETY VALVE TESTING By letter dated December 17, 1979, Mr. William J. Cahill, Jr., Chairman of the EPRI Safety and Analysis Task Force submitted " Program Plan, for the Performance Verification of PWR Safety / Relief Valves and Systems",
December 13, 1979.
Northern States Power considers the program to be responsive to the requirements presented in NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations" dated July, 1979, Item 2.1.2 which recommended in part, " commit to provide performance verification by full scale prototypical testing for all relief and safety valves. Test conditions shall include two-phase slug flow and subcooled liquid flow calculated to occur for design basis transients and accidents."
The EPRI Program Plan provides for a completion of the essential portions of the test program by July, 1981. Northern States Power will be participating in the EPRI program to provide program review and to supply plant-specific data as required.
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3.
2.1.3.a DIRECT POSITION INDICATION OF RELIEF AND SAFETY VALVES Prairie Island already has direct indication of the Pressurizer Power Operated Relief Valve (PORV's) and will install an acoustic montior on the common Pressurizer Safety Valve Relief Header.
The new system will combine direct valve position indication, acoustic monitor on piping, individual temperature alarms, and combined Pressurizer Relief Tank (PRT) temperature, pressure, and level (See Figure 1). This system will provide the operator with clear indication of valve position and provide redundancy to ensure reliable indication. With this proposed system, the operator will have two separate means of determining PORV indication. Each PORV has a limit switch mounted directly on the valve's positioner, and adds an acoustic monitor mounted on the valve inlet piping.
The limit switch provides valve position indicated in the Control Room adjacent to the valve's control switch. The acoustic sensor's outputs will feed to the Control Room panels and to the plant computer. Both the limit switches and acoustic monitoring system are either on or will be powered from the plant's vital instrument buses through safety grade cabling.
The accustic system and closed limit switches are scismically qualified and are qualified to withstand the environmental transient caused by the worst credible accident for the system (Failure of the pressurizer safety and its discharge piping).
The pressurizer safeties each have individual temperature sensors and will have a combined acoustic sensor. Both will have Control Room alarms and computer printouts. Only one acoustic monitor will be used since the operator actions for a lifted safety are the same regardless of which safety has lifted. In addition, the piping geometry is such that a separation of input signals may not be possible and therefore, a second sensor would not provide any useful information. This system would give the operator immediate indication of safety valve lifts. After stable conditions have been reached the individual RTD data can be analyzed and the failed safety valve identified.
The acoustic system is the same as the one for the PORV's with respect to power supply, seismic and environmental qualification. The RTD's are supplied by an instrument power supply bus, but they are not safety grade.
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2.1.3.a - continued The PORV's and Safeties have backup indications and alarms for valve position. The discharge of the PORV's and safeties flows into the Pressurizer Relief Tank (PRT). The PRT has level, pressure, and temperature Control Room indications with alarms for high temperature and pressure and high and low level. These are backup instruments and therefore not required to be safety grade. They are powered from an instrument power supply. The PRT instruments are attached to a Type 11I component, thus seismic qualification is not necessary.
The acoustic monitor system is presently being installed on Unit I with installation to be completed and operational before January 31, 1980. The system will be installed and operational on Unit 2 during the unit's refueling outage beginning January 2, 1980. The entire system will be installed on Unit 2 before its outage is completed.
Environmental testing of the acoustic monitor system will be done by an Owners' Group, which Babcock and Wilcox is assembling, for the Valve Monitoring System.
The present schedule for the environmental testing is:
Propose the Generic Qualification Program Feb. 8, 1980 Complete Owners' Group Review of the Proposed Generic Program Feb. 22, 1980 Finalize Qualification Program March 7, 1980 Implement Qualification Program March 21, 1980 Complete Documentation of Test Results Report Mid 1980 1696 121
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[ PRT Inkicators: Tempe rature Control Level Room Pressure Ali rms: High Temperature High Pressure Hi/Lo Level NOT;;
g Circled items are presently installe3 Temperature Indication &
alarm in contro' Acoustic sensor p room Alam in control v room PORV's Acoustic
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< 44 E b I Alam in C.R.
Alam in C.R.
Safety valve line RTD's Valve position on also provide C.R. indication PORV's & Motor valve indication Pressurizer
- FIGURE 1 Pressurizer Relief & Safety System 1696 122
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6.
2.1.3.b INSTRUMENTATION FOR INADEQUATE CORE COOLING
- a. Procedures and Description of Existing Instrumentation The Westinghouse Owners' Group, of which NSP Prairie Island is a member, has performed analyses as required by Item 2.1.9 to study the effects of inadequate core cooling. These analyses were provided to the NRC " Bulletins and Orders Task Force" for review on October 31, 1979. As part of the submittal made by the Owners' Group, an
" Instruction to Restore Core Cooling during a small LOCA" was included.
This instruction provides the basis for procedure changes and operator training required to recognize the existence of inadequate core cooling and restore core cooling based on existing instrumentation. Prairie Island has incorporated the key considerations of this instruction into our LOCA procedures, and has provided training to the operators in this area,
- b. Subcooling Meter The requirements of this item are being met by installing two of the Combustion Engineering Subcooled Margin Monitors Model 001.
These monitors provide a continuous indication of the margin to sat-urati7n in the reactor coolant system.
The subcooling monitor consists of a microprocessor which has temperature and pressure signals as input. The temperature input comes from the incore thermocouples (2 per monitor, 4 per core, 1 each quadrant) and takes the highest reading thermocouple and uses that for the margin calculation. The pressure signals come from the RCS wide range pressure transmitters which are redundant and go from 0-3000 psig. The monitor uses the lowest pressure reading for the margin calculation.
The meter has been qualified as a class lE instrument and meets the IEEE 323-1974 and IEEE 344-1975 standards and is a safety grade instrument.
We are currently reviewing a draft of the Reg Guide 1.97 for the long term requirements for the subcooling monitors.
In addition, the subcooling monitor installation and operation does not affect the Reactor Protection or Engineered Safety features systems.
Installation and operation on 1/31/800f the Unit 1 subcooling monitors is expected. Unit 2 installation is continuing and is expected before the January 31, 1980 startup date following the refueling outage.
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2.1.3.b - continued 7.
- c. Additional Instrumentation to Indicate Inadequate Core Cooling The submittal referenced in a) above described the capabilities of the core exit thermocouples in determining the existence of inade.quate core cooling conditions and their superiority in some instances to the loop RTDs for measuring true core conditions. Other means of determining the approach to or existence of inadequate core cooling could be:
- 2. Incore detectors
- 3. Excore detectors
- 4. Reactor coolant pump motor currents
- 5. Steam generator pressure A discussion of the possible use or these measurements are addressed below.
The use of incore movable detectors to determine the existence of inade-quate core cooling conditions appears doubtful. The detectors could be driven in to the tops of the incore thimbles, which are located at the top of the core, following an accident in which concern for inadequate core cooling exists. However, for the very low neutron levels available, a switchover to battery-powered detectors and Keithly preamplifiers would be required, which is not normally an operator function. Futhermore, incore detectors would not provide a passive, continuous level indication. As a result, it does not appear worthwhile to pursue incore movable detectors as a means of determining inadequate core cooling conditions.
The use of excore detectors has been mentioned as a possibility in respon-ding to core uncovery. The only detectors which would have the required sensitivity are the source range monitors. The use of the source range monitors will be investigated further as part of the more indepth study of inadquate core cooling being performed by the Westinghouse Owners' Group.
However, their use is probably limited to those instances when significant voiding exists in the downcomer region, since normally water in the downcomer would effectively shield the detectors from the core region whether voids existed or not.
Reactor coolant pump motor current, which could be indicative of core voiding, is inappropriate for a reliable means of determining inadequate core cooling, since a loss of off-site power or pump trip due to LOCA blowdown shut the pumps down.
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8.
2.1.3.b - continued Steam generator pressure, which already exists, is useful in 'the case where heat transfer from primary to secondary is interrupted due to loss of natural circulation. This, however, does not satisfy. requirements to indicate the approach to inadequate core cooling, nor does it indicate the true condition of the core.
Reactor vessel water level determination is the most promising of the items discussed to provide additional capability of determining the approach to and the existence of inadequate core cooling. Several sys-tems for determining water level are under review by the Westinghouse Owners' Group. A conceptual design of one system is given below:
Vessel Level System Description Many different methods and principles for determining the water level in the reactor vessel have been examined. A basic delta pressure measurement from the bottom of the vessel to the top of the vessel should provide meaningful and reliable information to the operator. The main advantage this system is that the sources of potential errors are well known, and within the time frame available developmental efforts with new or untested systems must be minimized.
Figure 2 shows a simplified sketch of the proposed vessel level instrumentation system. The bottom tap of the instrument would use a thimble of the incore movable detector system either at the seal table or in the thimble below the vessel. Use of the thimble as part of the incore flux monitoring would not be lost. The flux thimble guide tube would be tapped below the vessel and an instrument line connection made. The instrument line would have an isolation valve and slope down to a hydraulic coupler connected to a sealed reference leg.
For connection at the seal table, a special fitting would be utilized which would be connected to an isolation valve and sealed reference leg.
The scaled reference leg would go to the differential pressure trans-mitter located at an elevation above the expected level of con-tainment flooding. A similar sealed leg would go tc the top of the vessel and penetrate the head using the vent line or a special connec-tion on a spare RCC mechanism penetratien. Two trains of vessel level instrumentation would be provided.
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2.1.3.b - continued The behavior of the signal generated by this level instrument under normal and accident conditions is being evaluated. The usefulness of this instru-ment to provide an unambiguous indication of inadequate core cooling is being evaluated as part of Item 2.1.9. Tne potential errors and accuracy of a final system configuration are being evaluated to assess its usefulness to provide information to the operator for proper operation of.a vessel venting system and for normal water level control during periods when the primary system is open and a water level may exist in the vessel. The connection of the level system to the vessel head should be designed to be compatible with the head vent system. Operation of the vent system should not upset all indications of vessel level. This can easily be avoided by using a separate instrument tap or by using more than one location.
Alternatives Two alternatives appear promising, and for the time being will be pursued in parallel with the AP System. One involves a string of heamd thermocouples installed through a spare head penetration to the top of the core, and a string of self-powered detectors added to an existing 1 core thimble in the core. Accuracy should be very good (within a few inches). Installation method and qualification of detectors, are as yet undetermined. A second alternative involves installation of neutron detectors above and below the core. Tests performed to date show that ratio of counts (bottom detector /
top detector) is linear for water level reduction to within a few feet of a high energy neutron and gamma source. Further tests in a commerical reactor will be performed early in 1980. The outcome of these tests and detector qualification and availability will determine the feasibility of this approach.
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10.
INFORMATION REQUIRED ON THE SUBC00 LING METER Display Information Displayed (T-Tsat, Tsat, Press, etc.) Tsat-T, P-Psat Display Type (Analog, Digital, CRT) Digital Continuous or on Demand Continous Single or Redundant Display Redundant Location of Display Control Board Low Margin < 10*f sub-Alarms (include setpoints) cooled - saturation Overall uncertainty (*F, PSI) -+ 1/2 %
Range of Display 0-999*F subcooled Seismic, IEEE 323-1974 Qualifications (seismic, environmental, IEEE323) 344-1975 Class lE Calculator Type (process computer, dedicated digital or analog calc.) Dedicated Digital If process computer is used specify availability. (% of time) NA Single or redundant calculators Redundant Selection Logic (highest T., lowest press) Highest T, Lowest P Seismic, IEEE 323-1974 Qualifications (seismic, environmental, IEEE323) 344-1975 Class lE Calculational Technique (Steam Tables, Functional Fit, ranges) Steam Table Look-up Input Temperature (RTD's or T/C's) T/C's Temperature (number of sensors and locations) 4 per core Range of temperature sensors 0-2300*F type K 1696 127
11.
'1 3/8 530-700*F Uncertainty
- of temperature sensors (*F at 1) --+ 2% 0-530*F Qualifications (seismic, environmental, IEEE323) None as yet Pressure (specify instrument used) RCS wide range Pressure (number of sensors and locations) 2 sensors Range of Pressure sensors 0-3000 psig Uncertainty
- of pressure sensors (PSI at 1) 1% overall channel acc-uracy Qualifications (seismic, environmental, IEEE323) None as yet Backup Capability Availability of Temp & Press NR Availability of Steam Tables etc. NR Training of operators NR Procedures NR
- Uncertainties must address conditions of forced flow and natural circulation
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13.
2.1.4 DIVERSE CONTAINMENT ISOLATION Containment Isolation is initiated by a Safety Injection signal which is generated by high containment pressure, low pressurizer pressure, and low steam line pressure. In addition, a high radiation level in the containment or ventilation system ducting is used as a diverse parameter for automatic Containment Ventilation Isolation.
Refer to Table 2.1.4 below.
TABLE 2.1.4 (abbreviations on following page)
Penetration System Essential Non-Essential Basis (Reg'd if Essential)
PRT to GA RC X PRT N2 Supply RC X Prim Vnt Hdr WD X RCDT WD X Main Steam MS X Main Feedwater FW X SGBD SGBD X RHR RHR X Emergency Core Cooling Letdown CVCS X Charging CVCS X Maintain Primary System Mkup RCP S1 Water Sply CVCS X Maintain RCP Operation RCP S1 Water Rtn CVCS X Przr Stm Smpl SM X Przr Liq Smpl SM X Lp B Htig Smpl SM X Instrument Air SA X RCDT to GA WD X Cntmt Air Smp1 RD X Catmt Smp A Dschg WD X Cntm Purge ZP X Safety Inj SI X Emergency Core Cooling Cntmt Spray CS X Engineered Safeguard System Cntmt Sump B Suct SI X Essential for Long Term Clg N to Accumulator SI X CbforRCP CC X Maintain RCP operation SI Test Line SI X Clg Wtr for FCU CL X Required for Cntmt Fan Coil Clg CC for Ex Ltdn Hx CC X Cntmt Vacuum Bkr ZC X Essential for Long Term Cond POST LOCA H Cntrl HC X Essential for Long Term Cond 2
Cntmt In-Serv Prg ZV X RMU to PRT RM X AF AF X Provide necessary heat sink 1696 130
2.1.4 - continued 14.
Abbreviations PRT Pressurizer Relief Tank GA Gas Analyzer RC Reactor Coolant N Nitrogen WD Waste Disposal RbDT Reactor Coolant Drain Tank MS Main Steam FW Feedwater SGBD Steam Generator Blowdown RHR Residual Heat Removal CVCS Chemical & Volume & Control RCP Reactor Coolant Pump System Przr Pressurizer Cntmt Containment RD Radiation Monitoring ZP Containment Purge Ventilation System System SI Safety Injection CC Component Cooling System Clg Wtr Cooling Water FCU Fan Coil Units Ex Ltdn Hx Excess Letdown Heat RMU Reactor Makeup Exchanger RM Reactor Makeup System CL Cooling Water System ZC Containment Fan Coil Vent- AF Auxiliary Feedwater System ilation System ZV Containment In-Service Ventilation System
- Non-Essential Systems to be automatically isolated by Containment Isolation Signals.
RESPONSE: All Non-Essential Systems are automatically isolated by a Containment Isolation Signal.
- Resetting of Containment Isolation Signa?s shall not result in the Automatic Loss of Containment Isolation.
RESPONSE: Resetting of Containment Isolation Signals does not result in the Loss of Containment Isolation.
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2.1.5.a DEDICATED H2 CONTROL PENETRATIONS Two independent 2" lines for containment hydrogen control exist presently at Prairie Island for each unit. These lines are safety related QA I lines and the valves are supplied by independent QA I power supplies.
Because there are two separate trains for each unit, a single active failure (such as a valve stdek shut) will cause only one train to be inoperable for containment hydrogen control. Failure of a single power source (or bus) can only cause one train to be inoperable because of independent power sources.
Containment integrity is assured for supply lines by a check valve inside containment and a normally closed (control switch locked) motor valve in the shield building. Vent lines to the shield building and gas analyzer are isolated from containment by a normally closed motor valve inside contain-ment (CS locked) and fail closed air-operated valves in the shield build-ing (CS also locked). Requirements of 10CFR50 APPENDIX A criteria 54 &
56 are met.
Each line is tested before heat-up to ensure a flov of 25 SCFM. Motor valves and air-operated valves are stroked quarterly and are leak tested at refueling intervals.
POWER SUPPLIES UNIT 1 IA Unit 1 Train "A" Power supply is Bus 110 (fed from 4160/480 volt transformer 101 which is supplied from 4160V Bus 15) for:
MV32274 MV32271 CV31923 CV31925 SV33990 IB Unit 1 Train "B":
Power supply is Bus 120 (fed from 4160/480 volt transformer 102 which is supplied from 4160 volt Bus 16) for:
MV32276 MV32273 CV31927 CV31929 SV33991 1696 132
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2.1.5.a - continued 16.
POWER SUPPLIES UNIT 2 IIA Unit 2 Train "A":
Power supply is Bus 210 (fed from 4160/480 volt transformer 201 which is supplied from 4160V Bus 26) for:
MV32293 MV32290 CV31924 CV31926 SV33992 IIB Unit 2 Train "B":
Power supply is Bus 220 (fed from 4160/480 volt transformer 202 which is supplied from 4160 V Bus 25) for:
MV32295 MV32292 CV31928 CV31930 SV33993 1696 133
8 a 17.
2.1.5.c H RECOMBINER 2
The plant has a pressurization / purge system for long-term post accident combustible gas control which does not require hydrogen recombiners.
No action on the part of the licensee is required at this time in-accordance with the letter from D. G. Eisenhut, USNRC, dated September 13, 1979.
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18.
2.1.6.a System Integrity for High Radioactivity
- 1. Leakage rates for systems cutside containment that would or could contain highly radioactive fluid during a serious transient and the test method used to measure the leakage are given in TABLE 1.
TABLE 1 PS & ID FLOW LEAK TEST LEAK TEST SYSTEM DIAGRAM LEAK RATE PROCEDURE METHOD U-l Residual Heat Removal X-H-1-31 .5 drop /sec S P-108.' Note 1 U-2 Residual Heat Removal X-H-1001-8 1 drop / min SP-2082 Note 1 U-l Charging & Letdown X-H-1-38 0 SP-120ld Note 1 SP-1001aa Note 2 U-l Charging & Letdown X-H-1-39 0 SP-1201d Note 1 SP-1001aa Note 2 U-l&2 Hold Up Tanks X-H-1-40 0 SP-1201c Note 3 U-2 Charging & Letdown X-H-1001-4 0 SP-2001a Note 2 SP-1201d Note 1 U-2 Charging & Letdown X-H-1001-5 0 SP-2001aa Note 2 SP-120ld Note 1 U-l Safety Injection X-H-1-44 0 SP-120le Note 1 U-l Safety Injection X-H-1-45 3 drop / min SP-120le Note 1 U-2 Safety Injection X-H-1001-6 0 SP-1201e Note 1 U-2 Safety Injection X-H-1001-7 0 SP-1201e Note 1 Waste Gas System X-H-1-124 +.04 SCFM SP-1201f Note 3 X-H-550-1 +.002 SCFM SP-120lf Note 3 Sampling System NF-3923B 0 SP-1201a Note 1 U-l Post Loca System NF-39251 6.2,15.5 SP-1072 Note 4 scc / min (42A,50)
U-2 Post Loca System NF-39251 0,2 sec/ min SP-2072 Note 4 (42A,50)
Containment Spray NF-39237 SP-120lb Note 1 NOTE 1. Leak Test Method is a visual inspection of the piping and components for evidence of leakage. Packing gland leak offs, packing glands, pump seals and valve and piping flanges are inspected for boric acid residue. If liquid is wetting an exterior piping system surface and/or liquid is observed running or dripping from the system such liquid is measured and recorded. All evidence of leakage is recorded. An effort is made to quantify the amount of liquid leakage or rate of formation of the boric acid residue. Work orders are initiated to correct the leakage condition.
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19.
NOTE 2: During power operation and when the reactor is in hot shutdown, total coolant (charging and letdown become part of reactor coolant) leakage is recorded daily. The recorded value is calculated from a water inventory balance. The results of the daily water inventory balance are used to satisfy the requirements of the Prairie Island Technical Specifications for a daily determination of reactor coolant leakage. In addition to the water inventory balance, the following data is recorded to estimate how much of the measured leak rate can be attributed to sources inside containment.
Containment sump pump operating hours.
Containment radioactive particulate monitor reading.
Containment radioactive gas monitor reading.
Containment relative humidity.
NOTE 3: A mass balance of the total waste gas system is performed daily; the results of balance are reviewed by the system engineer on a weekly basis. Unexpected changes in mass initiate efforts to pinpoint the location of the leak. These efforts are:
A. Gas sampling of air in selected areas of the plant.
B. Portable Continuous Air Monitor (CAM) is moved to inspect areas.
NOTE 4: This system is leak tested as part of the plant Technical Specifications required local leak rate testing of containment penetrations and associated piping and components. The test is conducted in accordance with the requirements of 10 CFR 50 Appendix J.
- 2. The absence of shielding, of suitable isolation barriers, and of leak tight components (packless valves and canned pumps) precludes using the following systems for processing highly radioactive fluids. However, the leakage conditions of these components are controlled and leakage to and from the systems are summarized.in a log of liquid waste inventory. The inventory is a log of tank levels and sump pump operating times and is reviewed by the plant staff on a weekly basis.
Excluded Systems A. Spent Fuel Pit Cooling System.
B. Mixed Bed, Cation and Deborating Demineralizers Portion of Reactor Coolant System Letdown.
C. Boric Acid Evaporators and Associated Pumps, Tanks, Valves and Demineralizers.
D. Boric Acid Storage Tanks and Associated Pumps and Valves.
E. Refueling Water Storage Tank and Associated Isolation Valves.
F. Liquid Waste Disposal Tanks, Pumps, Evaporators and Valves.
G. Caustic Standpipe and Associated Isolation Valves.
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20.
- 3. Continuing Leak Reduction Maintaining system leakage as low as practical is achieved at Prairie Island through a program of preventative maintenance, system leakage tests, waste liquid and gas inventory logs, surveillance tests and a radioactivity control program.
The following procedures, tests and administrative controls are used to assure leakage is maintained as low as practical.
- Administrative Control Directive 5 ACD 10.1 Control of Radioactivity
- SP-1201a Annual Sampling System Leakage Test
- SP-120lb Annual Containment Spray and Caustic Addition Leakage Test
- SP-1201c,d Annual Chemical Volume and Control System Leakage Test
- SP-120le Annual Safety Injection System Leakage Test
- SP-120lf Annual Waste Gas System Leakage Test
- SP-1082 Annual Residual Heat Removal Leakage Test
- 1P3124-3 Quarterly RHR Stud Inspection
- 1P3101-81 Diaphragm Replacement - Volume Control Tank and Blender Boundary Valves
- 1P3101-82 Diaphragm Replacement - Boric Acid Storage Tank and Related Piping Isolation Valves
- PINGP-87 Daily Waste Gas Inventory Log
- PINGP-90 Daily Waste Liquid Inventory Log
- 4. As a result of a review of the plant to IE Circular 79-21, Preventive Maintenance Guidelines, the following curbs will be constructed prior to January 1, 1981:
Door #92: Unit #2 Aux Bldg to D-3 room. Curb will be installed on Aux Bldg side.
Door #100: Fuel receipt area to Rad Waste Bldg. Curb will be installed on Rad Waste Bldg side.
Door #74: Unit 1 Aux Bldg to Service Bldg curb will be installed on Service Bldg side.
2 GPM Waste Evaporator Room. Curb to be installed in passageway to evaporator.
Doors to filter room. Curbs will be installed in filter room side of both doors.
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21.
2.1.6.b PLANT SHIELDING REVIEW An extensive design review of plant radiation levels has been completed using NuReg 0578 source terms. The design review identified the location of vital areas and equipment, such as the Control Room, radwaste control stations, emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during post-accident operation of these systems. The design review indicates that most sources are well shielded. However, a list of approximately 20 design or shielding modifications for each unit have been identified. Some major changes include routing the RHR pit sump pumps to containment and installing a vent from the volume control tank gas space back to containment rather than placing the highly radioactive gases in the waste gas systems. Several pipes may be rerouted and many areas will require additional shielding.
The requirement for < 15 mr/hr in the Control Room vill be met within hours after an accident to allow for decay of some short-lived noble gas. Integrated doses for an individual will be less than 2 rem for the first 30 days.
Those areas in the plant Auxiliary Building requiring infrequent access (sample room, radwaste panel, MCC areas, etc.) have been evaluated and shielding will be provided to allow access as may be required to those areas.
Doses to equipment outside containment have been evaluated. Most equipment presently appears qualified. Additional documentation of equipment qualification is continuing to verify equipment to be adequate. We are presently evaluating recirculation mode equipment assuring it is essentially degassed (equipment that receives its supply of highly radioactive water from the containment sump in a post-accident recirculation phase) for equipment qualification purposes.
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22.
2.1.7.a AUTOMATIC INITIATION OF THE AUXILIARY FEEDWATER SYSTEMS FOR PWRs The following signals AUTOMATICALLY start the pump motors and open the steam admission control valve to the turbine driven pump of the affected unit:
- 1. Low-Low water level in either steam generator
- 2. Trip of both main feedwater pumps
- 3. Safety Injection
- 4. Undervoltage on both 4.16KV normal buses (turbine driven pump only)
In addition, both local control (from the Hot Shutdown Panel) and remote control (from the control room) can be used to MANUALLY initiate AFW.
The initiating signals and circuits for starting both the motor and turbine driven pumps are capable of being tested.
The instrumentation and control power supplies are from the 120 VAC vital bus system. There are four vital buses per unit, each supplied by an inverter connected to the 480 VAC emergency bus and the 125 VDC power system.
The motor driven pump breaker controls are powered from the 125 VDC control batteries which are charged by battery chargers connected to the 480 VAC emergency buses.
The AFW motor driven puups are included in the load restoration sequencing on the emergency buses. Motor operated valves (also Safety Injection Pumps) are not stripped from the emergency buses, i.e., remain energized.
A failure in the automatic circuitry will not affect the manual capability to initiate the AFWS from the control room.
The SI actuation circuits which initiate AFW are of safety grade, being separated and trained. The SI actuation contacts which trip off the normal feedwater pumps are also of safety grade.
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2.1.7.b AUXILIARY FEEDWATER FLOW INDICATION TO STEAM GENERATOR Control room indication of auxiliary feedwater flow to each steam generator is provided for both Prairie Island Units 1 and 2. Upgrading to safety grade will be made in the long term as indicated in the October 30 letter.
Power supply for the analog devices providing this indication is from the Number 4 instrument inverter and instrument bus for the respective unit.
For each unit this is one of four separate safety grade inverters and bus instrument AC power circuits. Each inverter is continuously supplied power from one of the safeguards 480 volt AC buses and from one of the 125 volt DC emergency batteries.
The primary function of this flow measurement is indication of adequate heat sink availability. The presently installed wide range steam generator level channels provide a diverse fulfillment of this function. There is one wide range level channel per steam generator continuously recorded in the control room. Each of these channels is powered from one of the three inverters not supplying power to auxiliary feed flow.
Additional local indication, in the auxiliary building, of auxiliary feed flow is provided by separate instruments at the location of the flow trans-mitters for control room indication. These local indicators are readily accessible to operators and are used for auxiliary feed system operability testing.
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24, 2.1.8.a POST ACCIDENT PRIMARY COOLANT SYSTEM AND CONTAINMENT ATMOSPHERE SAMPLING SYSTEM Sampling procedures have been written that will enable plant personnel to obtain a containment air sample for radioanalysis or for H analy~is.
9 s Prairie Island was equipped with a post accident sampling system for H 2 using a Westinghouse-installed gas analyzer. This gas analyzer utilizes two small air blowers to obtain the sample and force it through a thermo-conductivity type H analyzer. This analyzer will detect H fr m 0 to 2 2 100% in three ranges. By utilizing this sample system, a sample can be taken of containment atmosphere using a small bomb with a septum to take a syringe of gas for spectral analysia. A NSP mobile GeLi located at Prairie Island will be used to analyze the gas sample.
Reactor Coolant System samples can be taken in our present sample room.
Samples could be taken from either the RCS loop B sample line, the RHR system sample line, or.the mixed bed inlet sample line. The normal sample room has been modified by installing 4 inches of lead shielding fcc the large sources in the lab.
Mobile shield panels are also provided for the technicians. A small sample will be drawn and placed directly into a shiet.d carriet for transport to a hot cell located outside the Auxiliary Building for boron, pH, chloride, or spectral analysis as may be requested by the Control Room or Technical Support Center. Oxygen analysis would be done in the sample hood in the sample room. Hydrogen analysis would be done by taking a small pressurizer sample in a sample bomb.
Boron analysis will be performed in the hot cell area using a diluted RCS sample and running a carminic acid and spectrophotometric test using the method of ASTM D3082 1975 Edition.
A pH on the undiluted sample could be run in the hot cell using a standard combination probe on a pH meter.
A chloride test can be done using a diluted sample and using the nitric acid-silver nitrate test with a turbidimeter in the hot cell area.
Spectral analysis will be performed utilizing a diluted RCS sample and counting it in the Prairie Island mobile GeLi. The mobile GeLi is presently on site, operational and calibrated.
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continued 25.
RCS oxygen analysis will be done in the sample room using an indigo carmine oxygen test on an undiluted sample.
RCS hydrogen analysis will be done in the sample room and hot laboratory by taking a small pressurized sample and expanding it into a H 8 ample 2
apparatus. The vented gas space will be sampled and 11 analy818 2
Performed on a gas partitioner.
In order to reduce radiation exposures, additional changes may be desireable.
An automatic boron titrator has been purchased which may be used to obtain a boron on an RCS sample. Investigations will be continuing into the availability and feasibility of inline 11 and 0 analyzers for the RCS.
2 2 Investigation is continuing on the permanent fix associated with obtaining samples. The existing sample room will be utilized with modifications to sample piping and/or shielding.
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2.1.8.b INCREASED RANCE OF RADIATION MONITORS Post accident ventilation of the Auxiliary Building is made via the Auxiliary Building special ventilation system to the Shield Building vent. Each Shield Building vent is equipped with one low range radiation monitor. An additional sample line has been routed to the Turbine Building and equipped with a particulate and charcoal filter and also a sample chamber. The sample blower is powered from a safeguards power supply.
Interim procedures define how the release activity can be determined using portable instruments and communication with the Control Room.
A \dctorcen area monitor which will be calibrated to read out the release rate in the Control Room has been purchased. It will be installed as soon as practical after arrival (prior to 1-1-81) which will allow the Control Room full scale release rate measurements to 104 p ci/cc. No direct containment releases are made post accident.
The charcoal and particulate filters from the Shield Building vent monitor will be taken to the Prairie Island Mobile GeLi for gamma spectrum analysis.
An interim procedure utilizing direct radiation measurements from the air ejector discharge pipe has been prepared which will permit the release rate to be known and communicated to the Control Room. The air ejector discharge will be rerouted to the Shield Building vent stack prior to 1-1-81 which will allow the sampling analysis to be done with the Shiald Building vent monitor.
All other ventilation discharges are stopped following an accident.
7 The in-containment high radiation monitor (10 R/hr photon radiation only) will be procureC and ir. stalled in the Unit 1 Fall 1980 refueling outage and in the Unit 2 refueling outage starting about 1-1-81. We are presently considering the Ceneral Atomics monitor over the Victorcen as it appears to meet ANSI N320-1978 more completely.
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2.1.8.c IMPROVED IN-PLANT RADI0 IODINE MONITORING A Mobile GeLi System is at Prairie Island, onerable and calibrated.
This system enables the plant technicians to take particulate and charcoal samples that can be accurately analyzed. Operating procedures and training have been completed on the Mobile GeLi System.
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2.1.9 TRANSIENT AND ACCIDENT ANALYSIS Analyses of small break loss-of-coolant ac ddents, symptoms of inadequate core cooling and required actions to restore core cooling, and analysis of transient and accident scenarios including operator actions not' pre-viously analyzed are being performed on a generic basis by the Westinghouse Owners' Group, of which Northern States Power Company is a member. The small break analyses have been completed and were reported in WCAP-9600, which was submitted to the Bulletins and Orders Task Force by the Owners' Group on June
~29, 1979. Incorporated in that report were guidelines that were developed as a result of small break analyses. These guidelines have been reviewed and approved by the B60 Task Force and have been presented to the Owners' Group utility representatives in a seminar held on October 16-19, 1979. Following this seminar, each utility has developed plant-specific procedures and trained their personnel on the new procedures. Revised procedures and training are in place in accordance with the requirament in Enclosure 6 to Mr. Eisenhut's letter of September 13, 1979, and Enclosure 2 to Mr. Denton's letter of October 30, 1979.
The work required to addrese the other two areas--inadequate core cooling and other transient and accident scenarios--has been performed in conjunc-tion with schedules and requirements established by the Bulletins and Orders Task Force. Analysis related to the definition of inadequate core cooling and guidelines for recognizing the symptoms of inadequate core cooling based on existing plant instrumentation and for restoring core cooling following a small break LOCA were submitted on October 31, 1979. This analysis is a less detailed analysis than was originally proposed, and will be followed up with a more extensive and detailed analysis which will be available during the first quarter of 1980. The guidelines and training will be in place by December 31, 1979, as required by the B&O Task Force.
With respect to other transient accidents containcd in Chapter 14 of the Prairic Island FSAR, the Westinghouse Owners' Group has performed an evaluation of the actions which occur during an event by constructing sequence of event trees for each of the non-LOCA and LOCA transients. From these event trees a list of decision points for operator action has been prepared, along with a list of information available to the operator at each decision point. Following this, criteria have been set for credible misoperation, and time available for operator decisions have been qualitatively assessed. The information developed was then used to test Abnormal and Emergency Operating Procedures against the event sequences to determine if inadequacies exist in the AOPs and E0Ps. The results of this study will be submitted by March 31, 1980.
The Owners' Group has also provided test predictions analysis of the LOFT L3-1 nuclear small break experiment. This analysis was provided on December 15, 1979, in accordance with the schedule established mutually with the Bulletins and Orders Task Force.
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2.1.9 CONTAINMENT PRESSURE INDICATION, CONTAINMENT WATER LEVEL INDICATION AND CONTAINMENT HYDROGEN INDICATION We will investigate and proceed with design and installation of extended range containment pressure, containment level and hydrogen measurement instrumentation putsuant to the ACRS requirements, the requirements of Reg Guide 1.89 and the forthcoming revision of Reg Guide 1.97. Installation of the sensors will be during the 1980 outage for Prairie Island Unit 1. Unit 2 will be shutdown for refueling outage and sensor installation on January 1, 1981.
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2.1.9 REACTOR VESSEL HEAD AND PRESSURIZER VENTING The reactor vessel head and pressurizer vent systems are designed to remove gases from the reactor coolant system via remote manual operations from the control room. Figure 3 shows the system flow diagram. Specific design features include:
- 1. Capability to vent either the reactor vessel head or the pressurizer steam space to either the pressurizer relief tank or to containment.
- 2. The 1/4" orifices restrict the flow rate from the pipe breaks downstream of the orifices to within the capacity of one charging pump.
- 3. All valves will be powered off emergency buses, and will be trained such that any single active failure will not prevent venting or venting isolation from either the head or the pressurizer.
- 4. All valves will fail closed.
- 5. Each vent is capable of venting a gas volume of 1/2 the RCS in one hour.
- 6. All valves will be remotely operable from the control room.
- 7. All valves will have position indication in the control room.
- 8. The vent system will be seismically qualified.
- 9. The containment vent will be located in a well ventilated area of containment in order to ensure optimum dilution of combustible gases.
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2.2.1.a SHIFT SUPERVISOR RESPONSIBILITY We commit to the requirement and implementation schedule. Provisions exist and are defined in our Administrative Controls which define the Shift Supervisor's responsibility. In light of Lessons Learned, we have modified the corporate and plant level Directives to ensure proper management direction.
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2.2.1.b SHIFT TECHNICAL SUPPORT By January 1, 1980, Prairie Island will have a Shift Technical Advisor on duty that meets the requirements of NUREG-0578 and Mr. Denton's letter of October 30, 1979.
The training of the Shift Technical Advisor will be completed by January 1, 1981.
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2.2.1.c SHIFT AND RELIEF TURNOVER PROCEDURE A checklist is presently in use for shift turnover, which defines shift change status information between Shift Supervisor, Lead Plant Equipment and Reactor Operator and Plant Equipment and Reactor Operator. Information includes significant equipment / system not available for service, signifi-cant equipment repaired and made available for use during the shift, out-standing surveillance procedures, significant work requests, operational plans for the coming shift, and new operational and administrative pro-cedures. Important Technical Specification limits and plant parameters are indicated on control room annunicators.
Other plant sections such as maintenance and instrument technicians normally do not work shifts. All work is controlled by the control room so that critical system line up and status is the control room responsibility.
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2.2.2.a CONTROL ROOM ACCESS We commit to the requirement and implementation schedule. Presently, provisions exist for limiting access to the Control Room which are defined in our administrative controls.
The requirements for succession of authority during an emergency are defined in our administrative controls.
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2.2.2.b ONSITE TECHNICAL SUPPORT CENTER 1/1/80 Requirements The Technical Support Center (TSC) is established in the "Engineerin" Conference Area" of the plant administrative office. As-built plant records that include general arrangement drawings, piping and instrument diagrams, piping system isometrics, electrical schematics, wire and cable lists and single line electrical designs are available to this area. The Technical Support Center is located across the Turbine Building from the Units 1 and 2 main control rooms.
The procedure for providing the engineering / management support and staffing of the TSC is provided as a Temporary Memo to the existing approved Emergency Plan Operation Manual Section F3.
The TSC will be a'ctivated when a " Site Emergency" as defined in our Emergency Plan is declared or whenever it is deemed necessary by plant management. If activation of the TSC occurs during the normal working day, the onsite members of the Operations Committee will report directly to the center. If activation occurs during off-duty hours, the Duty Engineer will be contacted and will contact the appropriate members of the management staff depending on the type of expertise needed.
Communications between the Technical Support Center, the near site Emergency Operations Center, the Control Room and the Nuclear Regulatory Commission have been established.
A dedicated communication link between the TSC and the NRC has been installed by the telephone company. Communications between the TSC and the Control Room will utilize the plant telephone system. Backup communication will be provided by the plant Sound Powered communications system. Alternate backup communi-cations can be supplied by plant portable radios. The NRC " hot line" phone extension will be installed as soon as the telephone company receives the order from the NRC.
A portable continuous air sample airborne monitor and a portable whole body nonitor have been installed in the TSC. Upon reaching high radiation levels in the TSC, selected management and engineering support personnel will evacuate to the control room. Other non-essential personnel will be evacuated.
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A Unit 1 and Unit 2 Computer " Engineers Console" is located in the TSC. This console has access to all data points accessed by the plant processor via a keyboard and output typer. In addition, a " slave" CRT is provided to display a dedicated group and alarm group of parameters as selected by the control room operator. A notebook containing flow diagrams, computer addresses, instrument numbers, control room control board identification numbers and ranges for the parameters needed for accident assessment in the TSC will be provided in the TSC in early 1980.
Upon evacuation from the TSC, selected individuals would be dispatched to the control room. By using the informati;n in the notebook described above, accident assessment could be performed from the parameters displayed on the control board.
1/1/81 Requirements Plans are being made to upgrade the TSC by 1/1/81 as follows:
- a. Physical Size and Staffing The TSC will be sized to accommodate approximately 25 people. A minimum of 600 square feet will be available in the TSC for equipment and personnel. The main functional areas in the TSC.will be: recording and display panels, plant process computer engineers consoles, conference area and communication cubicles.
The TSC is located in close proximity to the normal plant administrative area such that records of as-built conditions and drawings of structures, systems and components will be readily available. Also, normal administrative functions will be available as needed. Because the use of these functions will be limited and protective measures could be applied to their use, the administrative functions will not be included in the habitability envelope of the TSC.
The maximun staffing level for the TSC is anticipated to be as follows:
- a. 5 NRC personnel including a site inspector
- b. 3 Westinghouse members of the " site response team"
- c. 1 Corporate Management Representative
- d. 1 communications person 1696 154
& 4 38.
- e. 1 administrative specialist
- f. 11 members of plant management (Operations Committee) 9 The remainlag personnel would consist of technical specialists from the plant staff or outside consultants as appropriate for the occurrence,
- b. Building The area being considered for the TSC is presently designated as the Administration Building Annex. The structure is located on the same elevation as the Control Room, approximately 100 feet away across the Turbine Room floor. Easy access from the TSC to the Control Room is, therefore, assured.
The area under consideration is large enough to house 25 persons, informational displays, radiation monitoring equipment and the necessary technical data.
The structure is constructed of concrete blocks and precast concrete panels. This structure can be modified to afford protection from direct radiation as well as airborne. A pressurizing-type ventilation system will be added which will include particulate and charcoal filtering.
It is anticipated that the backup electrical power supply to the HVAC, instrumentation, lighting and radiation monitoring equipment will utilize the diesel generator which provides the backup for the plant security system.
Since sufficient reserve capacity is not available on the present security system diesel generator, replacement with a larger capacity diesel generator is foreseen,
- c. Communications A minimum of three direct telephone lines to the Corporate Office Telephone Exchange will be installed. These lines are part of Northern States Power's microwave communications system and do not depend upon the plant telephone system or the local telephone system. In addition, a multi-channel radio phone will be installed in the TSC. The radio will have the ability to communicate with the following:
- 1. Sheriffs Department
- 2. NSP Dispatcher and State Emergency Operations Center
- 3. Portable Radios (Plant)
- 4. Mobile Radios (Trucks, etc.)
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- d. Information Display and Storage The engineers computer console will be utilized to provide access to the parameters needed by the TSC staff to assess the consegences of and supply engineering support to the control room operating staff following an accident or severe transient on the Nuclear Steam Supply System.
A series of Graphic Displays in the form of simplified flow diagrams will be developed for the systems or components necessary to follow the course of an accident or mitigate the consequences of an accident. Major instrumentation and valves will be shown on these diagrams along with their computer addresses. A matrix will also be developed to cross reference the computer addresses with the 1) instrument identification number, 2) control board identification number, and 3) instrument range.
Most of this information is available to the engineer's console at this time. By 1981, all vital information will be avail'able to the Technical Support Center via the engineer's console, closed circuit T.V. or teletype.
In addition, the following key parameters needed to analyze the severity and course of an accident will be recorded in the Technical Support Center:
Parameters RCS Pressure SG Level Steam Pressure Containment Pressure Incore T/C Containment Rad. Monitor Pressurizer Level Vessel Level (if DP)
- e. Data Transmission To satisfy the need for offsite transmission of critical plant parameters to the NRC and vendor response centers, the following method is being investigated:
- 1. A critical parameters data sheet could be prepared and a supply located in the TSC. The parameters on this sheet would be pre-selected to give maximum information for critical plant systems.
- 2. When the TSC is activated and staffed, the critical parameters list would be completed periodically and briefly reviewed for validity of data.
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- 3. The sheet would then be transmitted to the response centers by compatible facsimile machines.
- 4. The cycle would be repeated as long as the TSC was activated and the offsite centers requir'd the data.
The advantages of such a system are as follows:
- 1. The system is simple, reliable, inexpensive and easy to implement.
- 2. Agreement in advance could be reached on what data would be collected and transmitted.
- 3. The option is available to send the most representative data for the parameter of interest.
- 4. The problem of unreliable raw data being transmitted offsite is eliminated.
It is felt that unreliable data being transmitted to response centers by direct data transmission is a problem that will impact the operation of the TSC. There is a high probability that a significant work load for TSC personnel would result from having to explain to offsite personnel why the data they are receiving is not significant, incorrect or is being influenced by some event. We believe this would have a significant negative impact on the function of the TSC.
The feature of the facsimile transmission method is that the data transmitted is reviewed to ensure that it is the most correct available. Also, comments could be added and data points changed at will as conditions change.
None of these features would be available with a direct data transmission system.
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2.2.2.c ONSITE OPERATIONAL SUPPORT CENTER The Prairie Island Nuclear Plant Operational Support Center is located in what is presently called the Plant Operating Records Room. It is located immediately adjacent to the Main Control Room.
The Operational Support Center will be activated when a " Site Emergency" as defined in our Emergency Plan is declared or whenever it is deemed necessary by plant management. The procedure for activating the center is provided as a temporary memo to the existing approved Emergency Plan Operation Manual Section F3.
Communications between the Operational Support Center, the Technical Support Center and the Control Room will be handled by two extensions of the present plant telephone system.
The Operational Support Center will be upgraded by January 1,1981 by installation of a multi-channel intercom system to enhance communications between the Operational Support Center, the Technical Support Center and the Control Room.
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