ML19210D079
| ML19210D079 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 11/17/1979 |
| From: | Baynard P FLORIDA POWER CORP. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML19210D080 | List: |
| References | |
| RTR-NUREG-0578, RTR-NUREG-578 3--3-A-3, 3-0-3-A-3, NUDOCS 7911200498 | |
| Download: ML19210D079 (18) | |
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%lQ Florida Power 00HPOHATsON November 17, 1979 File:
3-0 a-3 Mr. Harold R. Denton Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555
Subject:
Crystal River Unit 3 Docket No. 50-302 Operating License No. DPR-72 Lessons Learned Short-term Requirements
Dear Mr. Denton:
On November 2,1979, Florida Power Corporation received your let-ter of October 30, 1979, requesting a detailed description of our proposed methods and justification for those Lessons Learned Recommendations in which we are not in complete agreement.
Your letter further requested that we revise, as appropriate, our im-plementation schedule and provide detail ed justification for delays beyond the NRC's compliance schedule.
We have perfonned a thorough review of your letter and rereviewed NUREG-0578 and Darrell G. Eisenhut's letter of September 13, 1979, to further clarify the work scope of each Lessons Learned Recom-mendation and reeval uate our abil ity to comply with the NRC's implementation schedule.
Attachment 1
provides additional information concernir.,
NUREG-0578, and Darrell G.
Ei senhut's letter of September 13, 1979, which was not provided in our October 17, 1979, submittal.
In areas where our review has detennined that our implementation plan is not in complete agreement with the NRC's requirements, and/or it is not possible for us to meet the total intent of your request within the NRC's compliance schedule, we have provided our best schedule, justification for inability to comply with the schedule, and interim actions, as appropriate.
jj[]
j [)J As discussed in our response of October 17, 1979, and this re-sponse, we have identified to date two NUREG requirements that are required to be implemented by January 1,1980, which will require Gp a unit shutdown for installation.
These two requiremegg gg fg General Office 320i inirty fourin street soutn. P O Bo= 14042. St P rsbu g FicMa 33733 e 813 866 5151 r
in Mr. Harold R. Denton Page Two November 17, 1979 Recommendation 2.1.1 Emergency Power Supply -- Pressurizer Heat-ers, and Recommendation 2.1.3.a Direct Indication of Valve Posi-tion. As described in our response, we will be unable to complete the pressurizer heater modifications by January 1,1980, due to the availability of equipment.
The equipment necessary for the PORV and safety valve indication modifications will be available to allow installation of this modification.
However, the instal-lation of this equipment would require an outage of a minimum of 5 days in duration, during a period of high system load demand.
The unavailability of CR3 during this time frame could result in a generation capacity shortfall of between approximately 377 MW to 577 HW, reducing the system reliability for Florida Power Corpora-tion and the entire State of Florida.
It should also be pointed out that this shortfall estimate does not include any considera-tion for other units being out of service due to forced outages.
Additional detail ed discussion of this concern is provided in to this letter.
It is, therefore, requested that an exemption for installation of this modification from January 1, 1980, until March,1980 be granted.
Additional justification for this request is as follows:
1.
The purpose of the modification is to provide posi-tive indicaticn of the Power Operated Relief Valve (PORV) and safety valves positions.
2.
Since the occurrence of the TMI-2 event, there has been extensive operator training at CR-3 to insure op-erator awareness of the indications of a Stuck Open PORY or safety valve.
3.
In addition to the proposed modification per NUREG-0578, the drain tank level and pressure instru-mentation which is conspicuously located on the front of the main control board, does provide indication that the PORV or safety valve has opened.
Positive indication on the solenoid position of the PORV is also provided to the operator.
4.
In response to an NRC request, the PORV setpoint has been raised above the high pressure reactor trip set-point which has been lowered.
These new setpoints are 2300 psi for the high pressure trip and 2450 psi for the POR V.
With this setpoint change, the reactor trips on high pressure precl uding the RC pressure reaching the PORV setpoint value.
This is evidenced by five reactor trips on high pressure experienced at CR-3 since the setpoint change during which the PORV or safety valves (2500 psi setpoint) did not open.
Additional discussion of PORV lift frequency is pro-vided in our November 14,
- 1979, response to Mr. Robert W. Reid.
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e as Mr. Harold R. Denton Page Three November 17, 1979 Based on the potential generation capaci ty shortf all described above and additional justification provided in this letter, it is our position that our requested delay for the implementation of this modification does not present undue risk to the health and safety of the public during this short period of delay.
Florida Power Corporation's senior management further requests a meeting with you and/or members of your staff, on November 28, 1979, to discuss our requested exemption and other items of con-cern with regard to the implementation of NUREG-0578.
Very truly yours, FLORIDA POWER CORPORATION Dr. P. Y. Baynard Manager Nuclear Support Services NUREG-0578(ECSRes pns)DN-88 Attachments 1371 169
STATE OF FLORIDA COUNTY OF PINELLAS Dr. P. Y. Baynard states that she is the Manager, Nuclear Support Services, of Florida Power Corporation; that she is authorized on the part of said company to sign and file with the Nuclear Regulatory Canmission the information attached hereto; and that all such statements made and matters set forth therein are true a nd correct to the best of her knowl edge, i nfo nnation, and bel ief, ahw. Y. YwvwL
$GP.YJeaynard Subscribed and sworn to before me, a Notary Public in and for the State and County above named, this 17th day of November,1979.
Notary Public kp1 170 Notary Public, State of Florida at Large, My Commission Expires: August 8, 1983 CameronNotary 3(D12)
ATTACHMENT 1 Additional Information Concerning NUREG-0578 Recommendation 2.1.1 Emergency Power Supply Pressurizer Heater Emergency Power Supply In order to satisfy the Emergency Power Supply requirements for the Pressurizer Heaters, as detailed in NUREG-0578, Section 2.1.1, addi-tional time is needed for designing, procuring, an<i installing the new equi pment.
For example, the new cable requi red will take 12 to 16 weeks for delivery and part of the installation requires access into the Reactor Building.
A detailed installation schedule for this modification will be submitted as soon as possible.
In the interim, a procedure is available to the operators which will allow the connection of the preselected heaters to the Engineered Safeguards (Safety-related) Bus during a loss of offsite power.
This will be accomplished by utilizing the existing cross-tie breakers and assuring that all nonessential loads are disconnected from the respec-tive buses.
This method meets the intent of the NUREG requirenents with the exception that the manual transfer is not entirely accom-plished in the control room. Some of the disconnections of the nones-sential loads may have to be accomplished at the local power centers.
The proposed final design, to fully satisfy the requirements for the Pressurizer Heaters Emergency Power Supply, will include manual trans-fer switches to switch power from the nornial source to the emergency source, new distribution panels, as sociated control devices, and necessary power, control, and instrumentation cabl es.
The fi nal design will have the following features:
1.
Each redundant group of heaters will have access to only one Class 1E division power supply, and each group is consistent with the number of heaters (126 kW) required to maintain natural cir-culation in the HOT STANDBY condition.
2.
The transfer of the heaters fran the normal source to the emer-gency source will be accomplished in the control roan.
3.
The Class 1E interfaces for main power and control power will be protected with safety-grade circuit breakers consistent with Reg.
Guide 1.75.
4.
The Pressurizer Heaters will be autonatically shed fran the ener-gency source upon the occurrence of a safety injection actuation signal.
1371 171
Recommendation 2.1.1 Emergency Power Supply Pressurizer Level and Pressurizer Relief and Block Valves Emergency Power Supplies The existing design satisfies the requirements of NUREG-0578 for the power supplies for the Pressurizer Level Indicators and Pressurizer R6 lief and Block Valves, as follows:
1.
The motive and control components for the Relief Valve are pow-ered fran the on-site DC power system.
2.
The motive and control components for the Block Valve are powered fran the AC emergency power supply (Engineered Safeguards Bus).
3.
The pressurizer level indication instrument channels are powered fran the vital instrument buses (Inverters).
4.
As noted in 1. and 2. above, the power for the Block Valve is sup-plied fran a different bus fran that which supplies the Relief Val ve.
5.
The motive and control power connections to the energency buses are through safety-grade devices.
6.
The manual transfer of power fran the normal power to the emer-gency power is not applicable to the design.
As noted in 1.
above, the Relief Valve is normally powered fran the on-site DC power system, therefore, no transfer is required.
As noted in 2.
above, the Block Valve is normally powered fran the Engineered Safeguards Bus, which is normally powered from an offsite source.
On a Loss of Offsite Power Event, the Emergency Diesel Generators will automatically pick up the Engineered Safeguards Bus and the safety-related loads connected to it.
Thi s incl udes the ES 3AB MCC, which feeds the Block Valve, therefore, a manual transfer is not applicable.
Recommendation 2.1.3.a Response to Direct Indication of Power-0perated Relief Valve and Safety Valve Position for PWRs and BWRs In direct response to NUPEG-0578, Item 2.1.3.a, FPC has purchased from Babcock and Wilcox a Valve Monitoring System.
This systen incorpor-ates acoustical monitoring techniques to provide the reactor operator with indication of valve open/ closed position.
The equipment is very similar to the existing Loose Parts Monitoring System supplied by Babcock and Wilcox.
The engineering design for installation of this equipment is proceeding on an expedited basis to meet the specified inservice date.
This design provides for two transducers mounted on each safety valve and the PORV.
Each of these transducers will be wired out of the con-tainment to the PORV/Tsat monitoring cabinet, to be located in the 4160 V SWGR Roan. Within this cabinet will be three channels (one for each valve) of signal conditioning with local indication, alarm (high 1371 172
and low), and selectable audio monitor.
Only one transducer will be normally monitored on each valve.
The other is manually selectable for conparison of performance or in the event of transducer failure.
Each channel will also provide remote analog indic; tion and annunci-ator events recorder high alarm functions.
This analog indicator for each channel will be mounted on the PSA section of the main control board.
A common annunciator window will al so be located on this sec-tion.
The events recorder will provide CRT and hard copy indication of valves that actuate.
The valve monitoring Tsat cabinet will be powered fran a vital source with all cable routing meeting seismic requirements.
Seismic testing of equipment identical to that used in the Babcock and Wilcox Valve Monitoring System has been performed.
Environmental qualification of in-containnent equipment has been satisfied by similar equipment test and survival of TMI-2 equi pment.
The present design and equipment schedule will permit installation of this modification by January 1,1980, with the exception of the mount-ing cabinet and remote visual indicators for the main control board.
These will not be avail abl e from Babcock and Wilcox until mid-February, due to their supply problems.
It is presently planned to install cabinet-mounted equipment on temporary stands in the SWGR Room and have only alarm indication in the control room.
This modification will require a unit shutdown for installation.
Recanmendation 2.1.3.b Instrumentation for Inadequate Core Cooling In response to NUREG-0578, the Babcock and Wilcox Owners' Group has developed an extensive program for inadequate core cooling which has been discussed with the Bulletins and Orders Task Force.
In addition, at the request of the Bulletins and Orders Task Force, the program has been expanded beyond the requirements of NUREG-0578.
The objectives of this program are as follows:
1.
Develop operating guidelines that will allow the reactor operator to recognize and respord to conditions of inadequate core coolirs under the following conditions:
a.
Power Operation with portions of the core in DNB.
b.
Loss of RCS Inventory without the reactor coolant pumps operati ng.
c.
Loss of RCS Inventory wi th the reactor ccolant pumps opera ti ng.
d.
Loss of the Decay Ikat Removal System and Loss of RCS Inven-tory During Refueling Operations.
e.
Loss of natural circulation due to loss of heat sink.
1371 173
2.
Provide recommendations for any additional instruentation re-quired to indicate inadequate core cooling under the conditions listed above.
Included with the recommendations will be:
a.
A description of the functional design requirements for the additional instrumentation.
b.
A description of the Operating Guidelines to be used with the proposed equipment.
c.
A description of the analyses used in developi ng these guidelines.
d.
Installation schedules for additional instrtsnentation.
To date, Operating Guidelines and supportive analyses are complete for the following conditions within the scope of the Inadequate Core Cool-ing Program:
1.
Loss of RCS Inventory without the reactor coolant ptrnps operating.
2.
Loss of RCS Inventory with.the reactor coolant pumps operating.
3.
Loss of natural circulation due to a loss of heat sink.
These guidelines and supportive analyses have been submitted to the NRC by Florida Power Corporation in response to IE Bulletin 79-05C, dated November 14, 1979.
Florida Power Corporation is presently re-vising Plant Procedures to incorporate these.new guidelines and will implement operator training related to the inadequate core cooling.
This activity is scheduled for completion by January 1,1980.
The additional guidelines / support analyses for refueli ng operations and power operation-DNB condition are presently being performed by Babcock and Wilcox arxl are scheduled for completion on December 14, 1979 and February 22, 1980, respectively.
This schedule was discussed with the Bulletins and Orders Task Force and fourri acceptable.
Upon receipt of these additional guidelines, Florida Power Corporation will develop the necessary procedures and impl ement operator training as soon as possible.
Babcock and Wilcox is scheduled to submit to Florida Power Corporation recommendations for additional instrumentation in late January,1980.
FPC will submit this infonnation as soon as possible to you, following our review.
Every effort will be made to install this new instrumen-tation by January 1, 1981, subject to equipment availablity and NRC review.
1371 174
Subcooling Meter In direct response to NUREG-0578, Item 2.1.3.b, Florida Power Corpora-tion has purchased from Babcock and Wilcox two saturation meters and a field change package to provide wide-range T ot input to these devi-h ces; Tcold wide-range is currently available.
This meter was designed by Babcock and Wilcox to monitor plant temperature and pressure and implement, with hard wire logic, the determination of margin to satur-ation for present plant conditions and indicate this to the plant operato r.
The engineering design for installation of this equipnent is proceeding on an expedited basis to meet the specified inservice date.
Thi s design provides for two Tsat meters to be mounted in the PORV/Tsgt monitoring cabinet that will be located in the 4160 V SWGR Ro om " B.
Each meter will receive the following inputs:
4 hot leg temperature (2 per loop) 120 F to 920 F 2 RC pressure (1 per loop) 0 to 2500 psig These signals will be taken from the Non-Nuclear instrumentation (NNI)
System, with individual buffers to preclude interaction between Tsat meters or NNI/ICS.
The temperature inputs are not qualified safety-grade, however, they are reliable in that this NNI provides two vital sources and signal cables are routed in seismic instrument trays.
Each meter will < ive a remote digital indicator / selector mounted on the PSA section of the main control board and a low margin to satura-tion alann to the annunciator events recorder.
The low margin to saturation alarms will lite a common window on the PSA section of the control board with CRT and hard copy events recorder identification of loop indicating the condition.
The digital indicator on the control board will have a spring return selector switch such that one meter is normally looking at Loop A and the other is looking at Loop B with the capabili ty to swi tch for checki ng per fo nnance and, in the event of meter failure, the power to each meter will be from different vital so urces.
The schedul es fo r the Construction Work Package is presently December 7, 1979, with equipment on-si te by mid-December, wi th the exception of the PORV/Tsat monitoring cabinet (see Item 2.1.3.a).
We presently plan to install the two Tsat meters on tenporary mountings until the cabinet is installed.
Recannendation 2.1.4 Diverse Containment Isolation 4
Florida Power Corporation, in its April 12, 1979 response to Item 6 of IE Bulletin 79-05A, identified essential and nonessential systems with regard to containment isolation and core cooling.
Essential systems were defined as those systems which are required for cor e coolire ca-pability and, therefore, should not be isolated on automatic HPI actu-ation.
For the valves listed in our April 12 response, which receive no ES signal and are normally closed and remain closed following the accident conditions, no further action is required.
1371 175
The nonessential valves, listed in our response, which receive a con-tairinent isolation signal (4 psig RB pressure) will be provided with a diverse containment isolation parameter with the addition of an auto-close i solation signal, based on autanatic HPI actuation.
These di-verse containment isolation signals will satisfy safety-grade require-ments and resetting of these signals shall not result in the autanatic loss of containment isolation.
Recommendation 2.1.5.a Dedicated Penetrations for External Recombiners or Post-Accident Purge Systems The present CR-3 design has installed a reduadant, dedicated, hydrogen purge system.
The CR-3 system uses two penetrations, dedicated to hydrogen purge only, which are sized consistent with the flow require-
.ments of the purge system.
The CR-3 purge system is single failure proof.
Therefore, we conclude that the existing hydrogen purge system satisfies the requirements of Section 2.1.5.a of NUREG-0578.
Recommendation 2.1.5.c Recombiner Procedure CR-3 does not have a requirement for hydrogen recombiners as a design basis for licensing.
Therefore, this requirement does not apply to CR-3.
Recommendation 2.1.6.a Integrity of Systems Outside Containment Likely to Contain Radioactive Material for PWRs and BWRs Prior to issuance of the NUREG-0578 requirements, FPC had a leak re-duction program implemented to satisfy the leakage rate requirement identi fied in the CR-3 Technical Speci fications.
This program is desc ribed and implemented by SP-317--RC System Water Inventory Bal ance.
Since receipt of NUREG-0578, the CR-3 program has been expa nded to meet these new requirements beyond the CR-3 Technical Speci fications.
The present program includes the following systems:
1.
RC Bleed Line 2.
Waste Gas Disposal System 3.
Decay Heat 4.
Building Spray 5.
Make Up 6.
High Pressure Injection Thi s leak reduction program is described in SP-317 (see above),
SP-412--ECCS and Containment Spray System Leak Rate Test, S P-429--
Waste Gas System Leak Rate Test, PT-108--Decay Heat Removal and Reac-tor Building Spray System Leak Rate Test, and PT-109--RC Bleed Line Leak Rate Test.
Copies of these procedures are attached for your review, except for SP-317, which is being revised to include some ad-ditional sample lines in the program.
A copy of SP-317 will be sub-mitted as soon as it is revised.
1371 176
To date, the RC Bleed Line and the low pressure portion of the Waste Gas Disposal System have been Ic.ak tested.
The measured leakage rates for both systems were within acceptable limits.
THe RC Bleed Line leakage was measured at 1140 ml/hr, and, after the system was tighten-ed up and retested, zero leakroe was measured.
Zero leakage from the low pressure portion of Waste Gas Disposal System was also achieved after the system was tightened and retested.
Additional leakage rate measurements for the remaining systems will be subnitted upon their compl etion.
Reconinendation 2.1.7.a Auto-Initiation of Auxiliary Feedwater System AFWS 1.
Short-te nn:
a.
Emergency feedwater is automatically initiated to the turbine-driven emergency feedwater pump at all times and to the motor-driven emergency feedwater pump if offsite power is available.
b.
The automatic initiation signal s and circuits are not presently single failure proof because a convnon relay initi-ates the start signal to the emergency feedwater pumps. The design is in the process of being changed to provide redun-dant initiation relays which will then meet the single fail-ure criteria.
The schedule for completion of this control grade modification is January 1,1980.
c.
The testability of the initiating signals and circuits is accomplished by Plant Procedure SP-416, perfonned at each refueli ng outage.
The test consist of a two-part test to insure that the automatic circuitry is operational.
The first test consists of disconnecting the pneumatic tubi ng from the feedwater pump oil supply pressure switch and veri-fying that the auxiliary relay deenergizes to actuate the auto-start circui t.
This test verifies that the failure of both main feedwater pumps will cause an actuation of the auxiliary feedwater system.
The second test consists of putti ng a signal into the steam genera tor l ow-low level modules to simulate a low level condition.
The module out-put causes the auxiliary relay to deenergize to actuate the auto-start circuit.
d.
The initiating signals and circuits are powered fran a vital bus wi th a battery-backed inverter.
e.
Both the turbine-driven "xl motor-driven energency feedwater pumps can be started manually from the main control board.
Failure of a manual circuit in one pump will not affect the manual start circuit of the other pump.
f.
The AC motor-driven energency feedwater pump is powered from a diesel generator backed bus. This punp will start automa-tically upon receipt of an energency feedwater initiation
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system, provided offsite power is available.
Upon loss of offsite power and the alarm that the turbine-driven energen-cy feedwater pump has failed to start, the operator has a procedure to manually start the AC motor-driven energency feedwater pump and shed unnecessary loads as determined by the evaluation of the emergency at that time.
The required moto r-ope rated val ves are DC-operated and the AC motor-operated valves are prealigned open and fail as is.
We are presently investigating methods of automatically loading the AC notor-driven emergency feedwater pump under all condi-tions.
There is a turbine-driven emergency feedwater failed-to-start signal that alerts the operator to start the motor-driven emergency feedwater punp.
g.
The automatic initiation signals and circuits do not prevent manual action capability in the event that these automatic initiation signals are lost.
Recommendation 2.1.7.b Auxiliary Feedwater Flow Indication to Steam Generators 1.
Short-term Control Grade:
a.
Emergency feedwater flow indication to each steam generator satisfies the si ngle failure criteria because there are ultrasonic flow indications on each steam generator with a backup steam generator level indication on each steam genera tor.
b.
The present ultrasonic flow indication channels are testable by electronically verifying the zero and circuit fault con-ditions for each unit.
c.
The present energency feedwater flow indicating devices are powered from vital buses with a battery-backed inverter.
2.
Long-term Safety-Grade:
a.
We are in tt ^ process of evaluating the present equipment for upgradi r., to safety-grade, as well as eval uati ng other alternate methods of emergency feedwater flow measurenent.
3.
Other:
a.
The short-term control grade flow indication channels satis-fy the single failure criteria because each steam generator has an ultrasonic flow indicator and steam generatcr level i ndication.
b.
Ultrasonic fl ow indicators were facto ry-cal ib rated as a matched systen (transducers and flow display conputers) at 740 gpm and has an accuracy of about 2%.
137i i78
R_econmendation 2.1.8.c Improved In-Plant Iodine Instrumentation CR-3 presently has six portable air samplers and procedures in place for obtaining and determining airborne iodine concentrations using spectral analyses.
Therefore, we currently satisfy the requirenents of this section.
Reconmendation 2.1.9 RCS Venting A generic design effort is underway at Babcock and Wilcox, to which Florida Power Corpordtton is commi tted, to provide a functional description of the construction, location, size, and appropriate power supply for RCS vents.
Appropriate safety analyses, considering the effects of such vents, are also being pursured.
The current schedule indicates that a prel hainary design and safety analysis will be re-ceived by FPC from Babcock and Wilcox during the last week of Decem-ber, 1979.
In order to allow for internal review and resolution of problems, we will not be able to meet the January 1,1980, submittal requir enent.
We will attenpt to submit this preliminary design and analysis information as soon as possible in January, 1980.
Every atteipt will be made by FPC to improve on this schedule.
Additional detailed design and safety analyses will be submitted for NRC review as soon as possible in 1980.
The installation of these vents will be complated by January 1,
1981, subject to NRC approval, equi pment availablity, and plant outages, if required.
Recommendation 2.2.1.b Shift Technical Advisor The on-shift Technical Advisor to the Shift Supervisor will be provid-ed as follows:
1.
Short-term Plan:
By January 1,1980, Shift Technical Advisors (STAS) will be on-shi f t to provide accident assessment.
The conpliment will be provided by current plant personnel who meet the requirenents, as identi fied in paragraphs A.1, 2,
and 3 of Encl os ure 2 of Darrel G. Eisenhut's letter of September 13, 1979.
The Shift Technical Advi sors will be assigned for 24-hour pe r-iods, will be on the pl ant si te, and will renain wi thi n 10 minutes of the Control Center.
The STAS will be in the Con-trol Center for planned major plant evaluations.
They will be i ndependent fron supervision of the manipulation of plant con-trol s.
In addition to performing the function of the STA, they will be perfonning the functions of their normal positions.
To provide the operating experience assessment function, contract personnel will be located on-site, dedicated to evaluation of plant operations for potential safety implications. The STAS and contract personnel will provide feedback to one another, on a current basis, on the nature and results of their assessments.
This plan will be in effect until the necessary personnel can be hired and trained.
1371 179
2.
Long-term Plan:
Establish Nuclear Operations Engineer positions to provide both the accident assessment and operating experience functions.
These engineers would meet the intent of the requirements as identified in Enclosure 2 of Darrel G.
Eisenhut's letter of September 13, 1979.
As of Or tober 29, 1979, the Nuclear Operations Engineer positions were approved.
The position descriptions are currently being de-veloped and will be followed by recruitment of personnel.
The Nuclear Operations Engineers will undergo training to bring them up to the level of experti se requi red prior to being pl aced on-shift to perfonn the STA function.
Reco'ninendation 2.2.2.b On-Site Technical Support Center A Technical Support Center (TSC) will be temporarily established prior to January 1, 1980, in the office building located on the northwest corner of the turbine building.
This is the nonnal storage and re-trieval area for those d rawi ng s and records desc ribed in ANSI N45.2.9-1974.
The TSC will provide assistance to the operating personnel in evaluating the course of an incident or accident and will also be the designated point of contact with offsite agencies (after activation) in providing advice on the expected course of the acci-dent.
This area cannot be designated as the pennanent TSC, due to the requirement for the TSC to be habitable to the same degree as the con-trol roon for postulated accident conditions.
The designated tempo-rary location is habitable, provided with two conference rooms, capa-ble of supporting 15 - 20 assigned per sonnel.
Portable monitoring equipment for measuring radiation levels in the TSC will be provided.
Action level criteria are being developed to define when protective measures (breathing apparatus, evacuation to the control room, etc.),
should be taken.
Dedicated telephone communications will be provided by January 1, 1980, to allow reliable communications between the TSC and the Control Room, Operational Support Center, and the NRC.
Dedicated telephone conmunications will be provided between the TSC ard the Emerg'acy Operation Center (E0C), once the E0C is established, prior to mid-1980.
In addition, nondedicated telephone lines ard interplant communication systems are available for additional communications.
Plant parameters necessary for assessment will be provided by a com-puter printout, located in the TSC and paralleled with the control roon printer.
Plans for staffing the TSC during emergency situations, and for per-forming this accident assessment function fran the control room should the TSC become uninhabitable, are being developed and will be couplet-ed by January 1,
1980, consistent with our revi sion of the CR-3 Emergency Plan.
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There is a plan presently under consideration for the establishment of a permanent TSC.
This plan is to construct a new building, canplete with the requi red instrumentation and communications idertified in N UREG-0578.
This new structure will meet or exceed the recairenents for structural integrity and radiological habitability.
The proposed site is within the security boundary, below the berm surrounding the plant.
Additional details and our 1ong-range plan for upgrading the TSC to meet all the requirenents will be submitted as soon as possible.
Recommendation 2.2.2.c On-site Operational Support Center In order to provide an on-site assembly area where assigned support personnel will report in the event of an accident or energency situa-tion the following actions have been taken by CR-3:
a.
The north end of the shop facilities building, located northeast of the control complex, has been designated as the Operational Support Center (OSC).
This choice of locations allows ready access to the control canpiex and utilizes the existing control conplex personnel radiation shielding to reduce potential radia-tion exposures during accident conditions which require manning of the OSC.
b.
The designated location is habitable and provided with washroom and facilities to support 25 assigned personnel.
c.
A dedicated telephone line will be provided to allow reliable conmunication between the OSC, Control Roan, and Technical Sup-port Center.
In addition the interplant conmunication system is available for additional cormunications.
1371 181 NUR EG-0578(Response)DN-88 SYSTEM RELIABILITY Florida Power Corporation is presently projecting a peak load of 4750 MW's in January of 1980. Historically, the winter peak occurs in January.
The probability of this occurrence is spread over our winter season (January and February). The probability of peak occurrence in January is approximately-70% while only 30% for February.
Florida Power's present installed net winter generating capability is 4819 MW's and including the firm purchase from Tallahassee of 130 MW is 4949 MW's.
If Crystal River Unit #3 is taken off line during the winter season, the state system capability is reduced by 807 MW's while the Florida Power system capability is reduced by 726 MW's to 4223 MW's.
When also con-sidering a spinning reserve requirement of 50 MW's, a generating capa-bility shortfall of 577 MW's is projected to occur with Crystal River Unit #3 off line on the Florida Power system.
It should be pointed out that this above calculation is a static one and does not include any probability associated with other units being off line due to forced outages.
It should also be pointed out that Florida Power is negotiating with Southern Company for a purchase of 200 MW's to begin in January of 1980.
If this contract is not completed by January, it is hopeful that emergency power of approximately 200 MW's could be purchased from Southern Company. Therefore, due to the facts that all generating capa-city is assumed to be a/ailable and that an emergency purchase of 200 MW's could be purchased from Southern Company, a sho'tfall of 377 MW's is very optomistic.
In any event, without Crystal River Unit #3 in operation, firm load customers will have to be curtailed.
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With a 70% probability that the winter peak of 4750 MW's will occur in the month of January, there is a 15.2% probability that the winter peak will occur during a five-day outage of Crystal River #3 and a 45.7%
probability that the winter peak will occur during a 20-day outage of Crystal River #3 in January.
Since the probability of winter peak occur-rence in February is 30%, there is a 7.1% probability that the winter peak will occur during a five-dey outage and a 21.4% probability that the winter peak will occur during a 20-day outage of Crystal River #3 in~ February.
The state of Florida is presently a winter peaking state.
This means that when Florida Power Corporation peaks, it is of a very hiah proba-bility that the other utilities throughout the state will also experience system peaks.
Because of this, no firm or emergency purchases from other utilities except that which is already under contract (Tallahassee -
130 MW's) can be considered in the above calculation.
It is also imoortant to understand that the state reliability will also deteriorate with a unit the size of Crystal River (807 fiW) off line.
This, coupled with the probability of other units within the state being forced off line, could brina about an unstable condition for the state of Florida.
In order to take into account the orobability of various units being unavailable due to forced outages, a probabilistic reliability connuter model " PROM 0D" was used to show the effect of a Crystal River Unit #3 outage in January. The base case with Crystal River available in Januarv shows a loss of load orobability (LOLP) of 4.22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> in which load will exceed the available generation. The effect of a 20-day outage in January increases the LOLP by a factor of 2.7 to 11.28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />.
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From the above calculations and probabilistic projections, it is evident that for Florida Power Corporation to be able to prevent the curtailment of firm load customers during the winter peaking season, Crystal River Unit #3 must be available for operation.
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