ML19241C237
| ML19241C237 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 07/06/1979 |
| From: | Harold Denton Office of Nuclear Reactor Regulation |
| To: | Roe L TOLEDO EDISON CO. |
| Shared Package | |
| ML19241C238 | List: |
| References | |
| FOIA-79-98 TAC-55581, NUDOCS 7907300431 | |
| Download: ML19241C237 (4) | |
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July 6,1979 Docket No..
50-346 Mr. Lowell E. Roe Vice President, Facilities Development Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, Ohio 43552
Dear Mr. Roe:
.I By Crder of May 16,1979(ne comm ss u ad yoi undertaking a series o f actions, both imma nd long-term, to increas a' capability and reliability o f the, avis-Besse Nuclear pcwer Station, hi-t No. I to respond to various transient events.
in addition, the Order confirmed that you would maintain the plant in a shutdown condition until the following actions had been satisfactorily completed:
(a) Review all aspects of the safety grade auxiliary feedwater system to furtner upgrade components for added reliability and performance.
Present modifications will include the addition of dynamic braking on the auxiliary feedpump turbine speed changer and provision of means for control room verification of the auxiliary feedwater flow to the steam generators.
This Teans of verification will be provided for one steam generator prior to startup from the present maintenance cutage and for the other steam generator as soon as vendor-supplied equipment is available (estima:ed date is June 1,1979).
In addition, the licensees will review and verify the adequacy of the auxiliary feedwater system capacity.
(b) Revise operating procedures as necessary to e minate the option of using the Integrated Control System as a backup means for contrciling auxiliary feedwater flow.
(c)
Implement a hard-wired control-grade reactor trip that would be actuated on loss of main feedwater and/or turbine trip.
(d) Complete analyses for potential small breaks and develop and inplement coerating instructions to define operator action.
(e) All licensed reactor operators and senior reactor operators will have completed the Three Mile Island Unit No. 2 simulator training at B&W.
577029 790730043l
Mr. Lov. ell E. Roe (f) Submit a reevaluation of the TECO analysis of the need for automatic or administrative control of steam generator level setpoints during auxiliary feedwater system operation, previously submitted by TECO letter of December 22, 1978, in light of the Three Mile Island Unit No. 2 incident.
(g) Submit a review of the previous TECO evaluation of the September 24, 1977 event involving equipment problems and depressurization of the primary system at Davis-Besse 1 in light of the Three Mile Island Unit No. 2 incident.
By your letters dated April 27 and May 4,1979 and supplemented by sixteen letters dated May 11,18,19, ^2(2), 23(2), 26(2), 29 and June 15(2), 18, 21, 23 and 25,1979, you have documented the actions taken in response to the May 16 Order. We have reviewed this submittal, and are satisfied that, with respect to Davis-Besse, Unit 1, you have satisfactorily complett ) the actions prescribed in items (a) through (g) of paragraph (1) of Sect. ;n IV of the Order, the specified analyses are acceptable, and the specified imolementing procedures are appropriate. The bases for these conclusions are set forth in the enclosed Safety Evaluation.
Appropriate Technical Specifications for Limiting Conditions for Operation and for surveillance requirements should be developed as soon as practicable and provided to the staff within seven days with regard to the design and procedural changes which have been completed in compliance with the provisions of the May 16, 1979 Commission Order. The revised Technical Specifications should cover:
(1) Addition of flow rate indication for the auxiliary feedwater system; (2) Adcition of the anticipatory reactor trips; and (3)
Changes in set points for high pressure reactor trip and PORV a ctua tion.
Within 30 days of receipt of this letter, you should provide us with your schedule for completion of the long-term modifications described in Section II of the May 16 Order.
My finding of satisfactory compliance with the requirements of items (a) through (g) of paragraph (1) of Section IV of the Order will permit resumption of operation in accordance with the terms of the Commission's Order; it in 577G30
4 Mr. Lowell E. Roe no way affects your duty to continue in effect all of the above provisions of the Order pending your submission and approval by the Com.ission of the Technical Specification changes necessary for each of the required modi fica tions.
Sincerel,-
d Harold R. Denton, Director Office of Nuclear Reactor Regulation
Enclosures:
1.
Safety Evaluation 2.
Notice cc w/encis:
See next page 577031
~
Toledo Edison Company cc w/ enclosure (s):
Mr. Donald H. Hauser, Esq.
Director, Technical Assessrent The Cleveland Electric Division Illuminating Company Office of Radiation Programs P. O. Box 5000 (AW-459)
Cleveland, Ohio 44101 U. S. Environmental Protection Agency Crystal Mall #2 Gerald Charnoff, Esq.
Arlington, Virginia 20460 Shaw, Pittman, Potts and Trowbridce U. S. Environmental Protection Agency 1800 M Street, N.W.
Federal Activities Branch Washington, D.C.
20036 Region V Office ATTN:
EIS COORDINATOR Leslie Henry, Esq.
230 South Dearborn Street Fuller, Seney, Henry and Hodge Chicago, Illinois 606C4 300 Madison Avenue Toledo, Ohio 43604 cc w/ enclosure (s) and incoming dtd..
Mr. Robert B. Borsum Babcock & Wilcox Ohio Department of health Nuclear Power Generation Division ATTN: Director of Health Suite 420, 7735 Old Georgetown Road 450 East Town Street Bethesda, Maryland 20014 Columbus, Ohio 43216 Ida Rupp Public Library 310 Madison Street Port Clinton,Chio 43452 President, Board of County Connissioners of Ottawa County Port Clinton, Ohio 43452 Attorney General Department of Attorney General 30 East Broad Street Columeus, Ohio 43215 Harold Kahn, Staff Scientist Power Siting Commission 361 East Broad Street Columbus, Ohio 43216 G??C32
.c )
July 6, 1979 EVALUATION OF LICENSEE'S (CMPLIANCE WITH THE NRC ORDER DATED MAY 16, 1979 TOLECO EDISON CCMPANY AND THE CLEVELAND ELECTRIC ILLUMINATING COMPANY DAVIS-BESSE NUCLEAR POWER STATION, UNIT No. 1 DOCKET NO. 50-346 INTROC'JCTION By Order dated May 16, 1979, (the Order) the Toledo Edison Company and the Cleveland Electric Illuminating Company (TECO or the licensee) were directed by the NRC to take certain actions with respect to Davis-Besse Nuclear Power Station, Unit 1 (0B-1).
Prior to this Order and as a result of a preliminary review of the Three Mile I. land, Unit No. 2 (TMI-2) accident, the NRC staff initially identified several human errors that contributed significantly to the severity of the event.
All holders of operating licenses were subsequently instructed to take a number of immediate actions to avoid repetition of these errors, in accordance with bulletins issued by the Commission's Office of Inspection and Enforcement (IE).
Subsequenuly, an additional bulletin was issued by IE which instructed holders of operating licenses for Babcock &
Wilcox (B&W) designed reactors to take further actions, including immediate changes to decrease the reactor hign pressure trip point and increase the pressurizer power-operated relief valve (PORV) setting."
- [IE Bullt, ins Nos. 79-05 (April 1, 1979),79-05A (A;ril 5, 1979), and 79-05B (April 21, 1979) accly to all B&W f acilities.]
577033
% The NRC staff identified certain other safety concerns that warranted addi-tional short-term design and procedural changes at operating facilities having 3&W designed reactors. Those were identified as items (a) through (e) on page 1-7 of the " Office of Nuclear Reactor Regulation Status Report to the Commission" dated April 25, 1979. After a series of discussions betwee. the NRC staff and the licensee Joncerning possible design modifications and changes in operating procedures, the licensee agreed, in letters dated April 27, 1979 and May 4, 1979, to perform promptly certain actions.
The Commission fo'ind that operation of the plant should not be resumed until the actions described in Items (a) through (g) of paragraph (1) of Section IV of the Order are satisfactorily completed.
Our evaluation of the licensee's compliance with items (a) through (g) of paragraph (1) of Section IV of the Order is given below.
In performing this evaluation we have utilized additional information provided by the licensee in letters dated May 11, 18, 19, 22 (2), 23 (2), 26 (2), 29 and June 15 (2), 18, 21, 23 and 25, 1979 and numerous discussions with the licensee's staff.
Confirmation of design and procedural changes was made by memDers of the NRC staff at the DB-1 site.
An audit of the training and performance of the CB-1 reactor operators was also performed by the NRC staff to assure that.the design and procedural changes were understood and were being correctly implemented by the operators, b77.T 'M.
-4 9
s EVALUATION Item (a)
It was ordered tnat the licensee take the following action:
" Review all aspects of the safety grade auxiliary feedwatet
. stem to further upgrade components for added reliability and performance.
Present modifications sill include the addition of dynamic braking on the auxiliary feedpump turbine speed changer and provision of means for control room verification of the auxilicry feedwater ficw to the steam generators.
This means of verificatiun will be provided for one steam gent ator prior to startup from the present maintenance outage and for the other steam gerieratcr as soon as vendor-supplied equipment is available (estimated date is June 1, 1979).
In addition, the licensees will review and verify the adequacy of the auxiliary feecwater system uapacity."
The auxiliary feedwater (AFW) system at DB-1 consists of two safety grade AFW pumps capable of being actuated and contrclied by safety grade signals that s
ensure the availability of feedwater to at least one : team generator, under the assumed conditions of a single failure.
In addition, the capability to manually actuate and c0ntrol AFW ir available in the control room.
The sources of water include two condensate storage tanks (CST), the service water system and the fire protection system.
The CSTs provide the normal supply (non-safety-grade) and the service water system is used as a backup safety grade supply.
t~m n.~
- /( r * /1 el
s A low level in either CST is alarmed to the operator and a continuous level is displayed inside the control room.
Low pressure switches on the AFV pump suction provide safety grade signals to automatically shift suction for the pump from the CSTs to the backup service water supply. Additionally, the operator could also manually transfer the AFW suction to the fire water storage tank '(FWST) in the fire protection system.
Both steam-driven auxiliary feedwater pump turbines at DS-1 are provided with a governor imod for variable cumo speed control.
The governor is equipped with a small DC motor which c'.anges the spead setpoint on the turbine control valve, thereby controlling steam flow which regulates the turoine and pump speed.
This DC motor receives " raise-and-lower" pulses from the safety grade steam generator level control system or the manual control switches (located in the control room), which change the turbine speed as required.
Pulse
' length is automatically increased the further steam generator level deviates from its setpoint.
These changes in pump speed alter 'ae AFW ficw and thus control the water level in the steam generators.
A "cynamic brake" feature has been added, which consists of a resistor and electrical contacts in parallel with the windings of the DC motor. When the control pulse is terminated, the braking resistor is placed in parallel with the motor windings, causing rapid dissipation of the energy associated with the motor acmentum (thus reducing the amount of motor coast).
This, in turn, reduces the amaunt of pump speed overshoot, thereby allowing fewer speed changes to match the AFW flow rate to the steamarg rate of the steam generators.
57?O N'
' The licensee has also added flow rate indication for both steam generator AFW inlet lines.
Each inlet line has a pipe-mounted ultrasonic flow transducer and signal conditioner. These are located in the auxiliary building and are accessible during normal plant cperations.
The signal conditioners provide outputs both locally and in the contre 1 room on the AFW pump section of the main control console.
Each device is designed to provide flow rate indication to each steam generator from 0 to 1000 gpm.
The systems tre powered fron, 120 VAC, 60 H:: buses which are fed by redundant non-Class IE station inverters.
Functional testing of the installed auxiliary feedwater flow rate indication is to be conducted in conjunction with the functional testing of the dynamic braking modification of AFW pump. 'bine controls.
The staff concludes that the dynamic brake and AFW flew rate indication modifications are acceptable contingent upon successful testing prior to restart.
We have reviewed the piping and instrumentation diagrams and have cetermined that no active failure.of a mechanical component, such as a pump or valve, would preclude obtaining the required AFW flow rate.
The licensee has pre-viously performed tests of the man?al and automatic level control system.
The test results showed that the control system functioned as designed to control steam (;enerator level. Verification of acceptable flow capacity fo. each of the two AFW pumps wt.s based upon recorded steam generator level changes following a previous reactor trip.
These data showed that each pump exceeded the design flow rate of 800 gpa at a steam generator pressure of 1050 psig.
(The 800 gpm is the flow rate delivered to the steam generators and does not include the approximately 250 gpm recirculation flow rate.)
577G37
. Additional information submitted by the licensee (letter from Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC' dcted May 23,1979) shows that a total minimum flow, to one or both stea., generators, of 550 gpm is required to support the accident analyses.
Based on these data and analyses, and the agreement by the licensee to perform checkout testing of the dynamic braking and flow rate indication modifications prior to restart, we conclude that adequate assurance uists that the AFW system will deliver the required flow rate upon demand.
By letter (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated May 23, 1979), the licensee proviced results of a review of the operating history of the AFW system at 08-1.
The largest number of failures
- occurred during the initial operating and debugging phase of the facility.
Fourteen (14) of the seventeen (17) reported failures occurred prior to January, 1978.
Subsequent to implementing system design changes as a result of several of these failures, the systems failure rate has been reduced and its reliability enhanced.
There were 3 failures of AFW system components from January 1978 to May 1979.
(There were a total of 65 actuations of the AFW system in this time period.)
Three different components in the AFW syste. were involved in these three failures:
(1) the speed control circuit for #1 AFW pump turbine, (2) a faulty limit switch on an AFW discnarge valve, and (3) two sticky AFW pump turoine steam sucaly valves.
In each case, the licensee performed corrective actions.
% For tne purpose of demonstrating improvement in the performance of the AFW system, the licensee has defined a failure of the AFW system to ce any event for wnich at least one train of the AFW system i< not delivering design flow to a steam generator.]
57703R
& A later letter (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC)~ dated June 29, 1979) addressed a series of pressure switch failures which were discovered on May 21, 1979, and which affected both AFW trains.
An evaluation of these failures by the licensee concluded that both trains would have automatically actuated if required, but that one train would not have shifted automatically to the service water supply.
The NRC staff has discussed these failures with TECO and has requested that an improved surve',llance program for these pressure switches be initiated to determine the cause of the failures and the optimum calibration interval.
The licensee has agreed to an increased frequency of switen calibration.
In addition, the licensee has made procedural changes, requested by the staff, to instruct the operator to manually shift to the alternate supply of water for the AFW pumps, when the CST level drops to three feet (if autohatic switchover has not occurred).
This procedure provides greater assurance that, even with failures of this nature, the AFW system is availaole during the longer term.
More recently (July 5, 1979), the NRC staff was verbally informed by TECO (Mr. G. Novak) of a valve malfurction which took place in an AFW system pump discharge line on July 4, 1979.
The cause of the valve failure (failed closed) was apparently due to an electrical malfunction.
TECO stated that they would request the motor vendor to examine tha failed motor to determine the cause of the mal-function.
The IE site inspector has been requested to follow this evaluation and to determine the need for further study and corrective action if necessary.
The licensee has noted that manual capaDility (local hancwheel) to open the valve existed at the time of the failure and that the redundant AFW train was availaole.
577039
.g.
With regard to the operating history of the AFW system, the staff concludes that the licensee has increased the reliability of the AFW system by imple-menting appropriate corrective actions and design modifications. With regard to the more recent pressure switch and valve failures, the staff concludes that adequate assurance exists that the causes of the failures are being pursued by the licensee in a timely manner, and that the IE site inspector will follow the need for further corrective action.
In addition, the licensee has revised the administrative procedure pertaining to valve alignment and control.
These revisions to A9 1839.02 (" Operation and Control of Locked Valves") provide further assurance that mispositioning of AFW system valves would be detected.
Based on the above evaluation, the NRC staff concludes that the licensee has complied with the requirement of Item (a) of the Order.
Item (b)
It was also ordered that the licensee:
" Revise operating procedures as necessary to eliminate the option of using the Integrated Control System as a backup means for controlling auxiliary feedwater flow."
57704.0
.g_
As indicated in Item (a), the DB-1 AFW system has been designed as a safety grade system and, as such, is separate from the integrated control system (ICS); however, the licensee has indicated that the AFW system is capable of being switched to the ICS mode for a backup means of control.
As currently designed, the AFW system has three operational modes of controlling flow:
"ICS control", " auto-essential" and " manual." We requested that the licensee consider a more positive means to assure the continued separability of the ICS control position of the mode selector switches.
The licensee agreed (letter from Lowell E. Roe (TECO) to Mr. Robe.t W. Reid (NRC) dated June 15, 1979) to install a mechanical stop on these switches to further deter use of the ICS control position.
The IE site inspector has verified the installation of tnis mechanical stop.
The licensee has revised SP 1106.06 (" Auxiliary Feedwater System"), which
. describes procedures for AFW system operation.
This procedure specifically pronibits the use of the ICS control position on the mode selector switches.
Procedural steps for placing the AFW syste, in service for plant startup require the operator to place the AFW mode selector switches in the auto-essential position. We have reviewed the revised pra
~
'e for AFW switen operation and conclude there is sufficient guidance to prevent use of the AFW system in the ICS mode of control.
Other plant procedures that made reference to the ICS control mode of AFW nave been revised by the licensee to no longer autnorize that mode of control. The 577CA1
- staff has reviewed those procedures and concludes that those revisions are
- adequate, In addition, the NRC staff audit confirmed that the control room operators are aware that ICS control of AFW is prohibited.
Based o4 the above evaluacion, we conclude that the licensee has complied with the requirements of Item (b) of the Order.
Item (c)
The Order requires that the licensee:
" Implement a hard wired control grade reactor trip that would be actuated on loss of main feedwater and/or turbine trip."
The DB-1 original design did not have a direct reactor trip from a malfunction in the secondary system (loss of main feedwater and/or turbine trip).
To obtain an earlier reactor trip (rather than delaying the trip until an operator took action or until a primary system parameter exceeded its trip setpoint),
the licensee committed to install a hard wired, control grade reactor trip on the loss of all main feedwater and/or on turbine trip (letter from _Lowell E. Roe (TECO) to H. Denton (NRC) dated April 27, 1979).
The purpose of this antici-patory trip is to minimize the potential for opening of the power-operated relief valve (PORV) and/or the safety valves on the pressurizer.
This new 577042
. circuitry meets this objective by providii,g a reactor trip during the incipient stage of the related transients (turbine trip and/or loss of main feedwater).
TECO has added control grade circuitry to 02-1 which is designed to provide an automatic reactur trip when either the main turbine trips or there is a reverse differential pressure of 177 psid across both of the two main feedwater check valves (one check valve is located in the main feedwater discharge piping associatec with each steam generator).
The main turoine trip is sensed by a normally deenergized auxiliary relay associated with the main turbine generator master trip bus.
The power for this bus is provided from a 24 volt DC source, which in turn is provided power (through rectifier circuitry) from a non-Class lE inverter supplied 120 volt AC distribution panel.
A contact from the above auxiliary relay is arranged into a 120 volt AC circuit containing four normally deenergized relays.
Power for this 120 volt circuit is provided from a Class lE inverter supplied distribution panel.
The design for these four relays and acpropriate associated circuitry conform to Class lE requirements, including physical independence and provisions for testing.
Each of these four relays provide one consact wnich is arranged in series wicn one of the four Class lE undervoltage coils associated with one of the four AC reactor trip circuit breakers (one undervoltage coil associated with each AC reactor trip circuit breaker). When these relays are energized, power to the assc iated Class lE uncervoltage coils is interrupted so as to produce the desired aactor trip.
577043
a As indicated aoove, differential pressure switches across check valves, located in the main feedwater pump discharge piping, actuate upon sensing a reverse differential pressure across these check valves.
Two contacts from these differential pressure switches are arranged into a 125 volt DC circuit, whicn is provided power from a Class lE 125 volt distribution panel.
This circuit contains two associated DC relays.
Two contacts (one contact per relay) associated with these relays are arranged in series.
This series contact arrangement is provided in parallel with the contact associated with the main turbine generator master trip bu:.
The remaining circuitry associated with this trip is identical and common (shared) to that described above for the turbine trip (including power supply identification).
Provisions have been included in the design to manually bypass and to reinstate the reactor trip feature associated with the main turbine generator trip.
To supplement this feature, the design includes an annunciator which actuates whenever this reactor trip is bypassed and the reactor power level is above 15 percent.
Access to this bypass switch will require a key which is under suitable acministrative control.
Operator verification of the bypass removal is required by procedure during power escalation.
The NRC staff has reviewed these procedures and concludes that sufficient acministrative control exists.
No bypass features are included in the design for the reactor trio feature associated with the loss of main feedwater circuitry.
During normal startup or shutdown, an electric auxiliary pump is used wnen the steam driven main feecwater pumps are not availaDie.
577044
.e The licensee has analyzed this additional circuitry with respect to its independence from the existing reactor trip system and to assure that the design and operation of this additional circuitry will neither degrade the reliability of the existing reactor protection system nor create any new adverse safety system interactions.
Based on our review of the implementation of the added trip circuitry, with respect to its independence from the existing trip circuitry, we conclude that this additian will not degrade the existing reactor protection system design.
In addition, the licensee has satisfactorily completed tes<ing of this trip circuitry.
The licensee has committed to perform a monthly periodic test of the added circuitry to demonstrate its ability to open the AC reactor trip circuit breakers (tripping of the AC reactor trip circuit breakers via the unde--
voltage trip circuit). We conclude that there is reasonable assurance that the additional circuitry will perform its intended function.
Based on the above evaluation, we conclude that the licensee has complied with the requirements of Item (c) of the Order.
Item (d)
This Item in the Order requires the licensee to:
577045
,- " Complete analyses for potential small breaks and develop and implement operating instructions to define operator action."
By letter, (Lowell E. Roe (TECO) to H. Denton (NRC) dated April 27, 1979), the licensee agreed to provide the analyses and operating procedures of this requirement.
B&W, the reactor ve, dor for the 08-1 plant, submitted generic analyses for B&W plants entitled, ' Evaluation of Transient Behavior and Small Reactor Coolant Systems Breaks in the 177 Fuel Assemoly Plant," and supplements to these analyses (References 1 through 5).
Additional information specific to 05-1 was transmitted in References 6 to 8.
The transmittal under Reference 6 contains Volume III for the B&W generic study covering raised-loop plants.
Reference 7 provides additional analytical results specific to DB-1 with appropriate auxiliary feedwater flow rates.
Reference 8 provides additional analytical results for the loss of all main feedwater flow accident with loss of all AFW.
This latter analysis demonstrates that capability exists at 08-1 which the operator could use in the unlikely event of a loss o' main feedwater and a loss of both safety grade AFW trains.
This capability consists of using the combined functions the makeuo pumps,* the electric startup auxiliary feedwater pump and the PORV to achieve depressurization (only if necessary). We requested that the availability of this option be incorporated in procedures at 08-1.
The NRC staff will review these proceoural changes prior to startup.
"At DE-1, tne makeup pumps are separate from the HPI pumos.
577046
e-By letter, (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated May 22, 1979), TECO referenced the analyses as appropriate for 0B-l.
The staff evaluation of the B&W generic study has been cc,mpleted and the results of the evaluation will be issued as a NUREG report in July 1979.
A principal finding of our review of the 08-1 submittals and the generic study is a reconfirmation that loss-of-coolant accident (LOCA) analyses of breaks at the lower end of the small breaks spectrum (smaller than 0.04 ft.2) demonstrate that a combination of heat removal by the steam generators, high pressure injection (HPI) system and through the break ensure adequate core cooling.
The AFW system used to remosa heat through the steam generators has been modified to enhance its reliability as discussed in Item (a).
Uncovering of the reactor core is not predicted for breaks at this end of the small break spcctrum with these features available, therefore, cladding temperatures do not rise significantly above pre-reactor trip temperatures (less than 800 F), and remain well within the 10 CFR 50.46 limit of 2200 F.
The ability to remove heat via the steam generators has always been recogni:ed to be an important consideration when analyzing very small breaks.
The licensee cemonstrated that permanent loss of main feedwater and loss of AFW for the first 20 minutes of a small LOCA will not r esult in uncovering the reactor core.
However, when AFW is delayed beyond this time, a positive reliance on AFW actuation exists as a result of the relatively low (1600 psig)
HPI system shutoff head for 08-1.
Thus permanent loss of both main and auxiliary o@
577%
. feedwater could result in uncovering the core and fuel damage for the facility because of the unavailability of the high pressure injection pumps. Makeup pump and startup feedwater pump actuation, as discussed in the analysis of Reference 8 for the loss of feedwater accident with permanent loss of AFW, are considered pote'tially capable of maintaining the vessel mixture above the core for a small break, but this scenario was not confirmed in the small break analyses. The licensee's position is that such analyses are unwarranted in light of the safety grade design of the AFW system.
Since~the additional heat removal and coolant makeup capability does exist at DB-1, we requested that the procedures identify the availability of this option.
Implementation of this procedural change will be verified by the staff prior to rest:rt.
While the staff recognizes that the AFW system is safety grade, we also note that the licensee has agreed to continue to review performance of the AFW system for assurance of reliability and performance.
Consistent with this long-term agreement, we will require that the licensee modify the plant to provide the greater degree of diversity offered by a 100% capacity motor-operated AFW pump, or an alternative acceptable to the staff.
Another aspect of the analytical studies conducted was an assessment of tne effect of recent design changes on the lift frequency of pressurizer safety and relief valves.
The design changes included:
(1) a change in the setpoint of the PORV from 2255 psig to 2400 psig, (2) a cnange in the high pressure reactor trip setpoint from 2355 psig to 2300 psig, and (3) the installation of anticipatory reactor trips on turbine trip anc/or loss of main feedwater.
In the past, during turoine trip and loss of feedwater transients, the PORV was 5770c8
. lifted. With the new design, these transients do not result in lifting of this valve.
Huwever, lifting of both PORV and safety valves might occur in the cases of rod withdrawal or inadvertant boron dilution transients, using the normally conservative assumptions presented in Chapter 15 of the Final Safety Analysis Report (FSAR).
The above design changes did not affect the lift frequency of the valves for these Chapter 15 safety analyses.
Based on our review of the analyses presented by B&W, the staff has determined that a loss of all main feecwater with (1) an isolated PORV (closed block valve), but safety valves opening and closing as designed, or (2) a stuck open PORV consequentially does not result in uncovering the reactor core, provided AFW pumos are initiated within 20 minutes.
It is also concluded, that in the event of a loss of all APd for either case, covering of the core would be sustained to long-term cooling by. operator actions described in the analysis of Reference 8.
These actions consist of starting at least one of the two makeup pumps, starting the startup feedwater pump, and opening the PORV (only if needed).
Based on the consequences calculated for small break LOCAs and loss of all main feedwater events, and taking into account the expected reliability of the AFW and HPI systems for 08-1, we concluc'e that the licensee has complied with the analyses portion of Item (d) of the Order.
To support long-term operation of the facility, requirements will be developed for aaditional and more cetailed analyses of loss of feecwater and other 577049
.. anticipated transients.
More detailed analyses of small break LOCA events are also needed for this purpose.
Accordingly, the licensee will be required to provide the analyses discussed in Sections 8.4.1 and 8.4.2 of the recent NRC
" Staff Report of the Generic Assessment of Feedwater Transients in Pressurized Water Reactors Designed by the Babcock and Wilcox Company" (NUREG 0560).
Further details on these analyses and their applicability to other PWRs and BWRs will be specified by the staff in the near future.
In addition, to assist the staff in developing more detailed guidance on design requirements of relief and safety valve reliability during anticipated transients, as discussed in Section 8.4.6 of NUREG 0560, the licensee will be required to provide analyses of the lif t frequency and the mechanical reliability of the pressurizer relief and safety valves of the 08-1 facility.
The B&W analyses show that some operator actions, both immediate and followuo, are required under certain circumstances for a small break accident.
Immediate operator actions are defined as those actions, committed to memory by the operators, which must be carried out as soon as the problem is diagnosed.
Followuo actions require operators to consult and follow steps in written and approved procedures. These procedures must always be readily available in the control room for the coerators' use.
Guidelines were developed by B&W to assist the operating B&W facilities to deselop emergency procedures for the small break accident.
577050
, The " Operating Guidelines for Small Breaks" were issued by B&W on May 5, 1979 and reviewed by the NRC staff.
Revisions recommended by the staff were in-corporated in the gui. lines.* In addition, by. letter, the licensee submitted supplemental guidelines (Lowell E. Roe (TECO) to Mr. Racert W. Reid (NRC) dated May 22, 1979).
In response to these guidelines, the licensee made substantial revisions to EP 1202.06 (" Loss of Reactor Coolant and Reactor Coolant Pressure"), EP 1202.14 (" Loss of Reactor Coolant Flcw/RCP Trip"), and EP 1202.26 (" Loss of Steam Generator Feed").
These emergency procedures define the required operator action in response to a spectrum of accidents including a LOCA in conjunction with various equipment availability and failures.
The procedure dealing with loss of reactor coolant (EP 1202.06) is divided into three sections.
The first section deals with small reaccor coolant system leaks within the capacity of the makeup pumps and assumes the reactor does not automatically trip.
The second section assumes a small break within the capacity of the HPI system and a situation where the SFAS" and reactor trips may or may not automatically occur.
This section incorporates the B&'a small break guidance and provides for operator actions in the event other
- [ Letter f rom J. Taylor (B&W) to Z. Ros: toc:y (NRC) dated May 16,1979]
"[The safety features actuation system (SFAS) monitors variaoles to detect loss of reactor coolant system boundary integrity.
Upon detection of "out-of-limit" conditions of these variaoles, the system initiates various actions, dacending uoan tne location and severity of the "out-of-limit" conditions mesh red.
These actions can include:
initiation of emergency core cooling (ECC), anich consists of hign cressure injection (HPI) ar.* low pressure injection (LPI);
containment vessel cooling and isolation; con.'inment vessel spray systems; and starting of the emergency diesel generatom ]
577C51
, systems (such as reactor coolant pumps) do not operate as expected.
The third section of this procedure deals with a pipe rupture well in excess of the capability of the makeup and/or HPI pumps (a large break in which the system depressurizes to the point of low pressure injection).
Automatic reactor trip and SFAS actuation are assumed.
In all cases dealing with a small break, the operator actions are aimed at achieving a safe cold shutdown in accordance with the normal cooldown procedure.
As indicated above, procedures provide guidance to the operators for dealing with small breaks in the event of a degraded condition (such as loss of reactor coolant pumps).
If the reactor coolant pumps are inoperable, the operatcr is directed to establish and verify natural circulation.
Procedural steps to restore reactor coolant pump operation, once e pump becomes available, are provided.
In the event natural circulation cannot established and a reactor
'a coolant pump cannot be restarted and plant pressure reaches 2300 psig, the operator is provided procedural steps to relieve the heat energy via the PCRV.
(Additional relief capacity is provided via the code safety valves if the PORV is inocerable).
In the event that normal feedwater is lost to the steam generators, auxiliary feedwater is automatically initiated via the safety grade AFW system.
EP 1202.25 provides operator guidance in this event.
With SFAS actuation, steam generator level is automatically maintained at 96 incnes on the startuo range to assure adecuate neat removal during the small break event.
5??C52
9 For all cases in which HPI is manually or automatically initiated, the operators are specifically instructed to maintain maximum HPI flow unless one of the two following criteria is met:
(1) Lcw pressure injection has been operating for greater than 20 minutes with flow rates in excess of 1000 gallons per minute per train, or (2) All hot and cold leg temperatures are at least 50 degrees below the saturation temperature for the existing reactor coolant system pressure.
If the 50 degrees subcooling cannot be maintained after high pressure injection cutoff, the high pressure injection shall be reactuated.
This requirement to cetermine and maintain 50 F subcooling has been incorporated into EP 1202.06 (" Loss of Reactor Coolant and Reactor Coolant Pressure") and EP 1202.24 (" Steam Supply System Rupture").
The procedures also provide instructions to the operators to check alternate instrumentation channels to confirm key parameter readings, such as the degree of subcooling.
Accordingly, the use of core exit thermocouples as alternate temperature indicators is addressed in the procedures.
Under degraded cooling conditions (such as a LOCA), tLe pressure-temperature limits considered in the Technical Specifica-tions are not applicable to the ensuing depressurization and cooldown because these limits were develcped for normal and upset operating conditions only.
Density differences between the downcomer and reactor core will cause recirculation flow between the core exit and cowncomer via the vent valves.
577053
. Mixing of the hot core exit water with the cold HPI water (or makeup water) will provide sufficiently warm vessel temperatures to preclude any significant thermal shock effects to the vessel.
Subsequent restoration of AFW would depressurize the reactor coolant system to below 600 psig where pressure vessel integrity is assured for any reasonable thermal transients that might subsequently occur.
B&W has agreed to provide a detailed thermal.-mechanical generic report on the behavior of vessel materials for those extreme conditions.
The " Loss of Reactor Coolant and Reactor Coolant Pressure" procedure was reviewed by the NRC staff to determine its conformance with the B&W guidelines.
Comments generated as a result of this review were incorporated in a further revision to the procedure.
A member of the NRC staff walked through this emergency prccedure in the Davis-Stsse control room.
The procedure was judged to provide adequate guidance to the operators to cooe with a small break LOCA.
The instrumentation necessary to diagnose the break, the indications and controls required by the action statements, and the administr3ti c controls which prevent unacceptable limits from being exceeced are readily available to the operators.
We conclude that the operators should be able to use this procedure to bring the plant to a safe shutdown condition in the event of a small break accident.
An audit of 9 of the 25 licensed reactor operators and senicr reactor operators was conducted by the NRC staff to determine the operators' understanding of the small break accident, including how they are required to diagnose anc respond to it.
The CB-1 staf# has conducted special training sessions for tne 577054
. operators on the concept af and use of Emergency Procedure 1202.06.
The operators were found to have sufficient knowledge of the small break pheno-menon and the general requirements of the emergency procedure, although some deficiences were identified which were primarily due to the operators' lack of familiarity with the recently revised procedure.
All operators will receive additional training on EP 1202.06 and a facility acministered audit prior to assum ng licensed duties during power operation.
i The audit of the operators also included questioning about the TMI-2 accident and the resulting design changes made at CB-l.
The discussions covered the initiating events of the incident, the response of the plant to the simul-taneous loss of feedwater and small break LOCA (PORV stuck ooen), and operator actions that were taken during the course of the incident.
In addition, similarities and differences between the TMI-2 accident and the 08-1 incicent of Septemcer 24, 1977 were discussed. We found their level of understanding sufficient to be able to respond to a similar situation if it happened at Cl-1.
We also conclude that they have adequate knowledge of succooling and saturated c'nditions and are able to recognize each condition in the primary coolant system by several methods.
The AFW system was also discussed during the audit to determine the operators' ability to assure proper starting and operation of the system during normal conditions, as well as during adverse conditions such as loss of offsite power or loss of main feed ater.
The long-term operation of the system was examined to evaluate the operators' ability to use available manual controls and water sucolies.
The level of understanding was found to be sufficient to assure procer short-anu long-term AFW flow to the steam generators.
577055
, +
The licensed reactor operators and senior reactor operators have received training concerning the TMI-2 accident, small break LOCA recognition, design
,_cdifications, and procedure changes.
The training included formalized class-room sessions and on-shift review of training material and emergency procedure changes.
To determine the effectiveness of this training program, a written exam was administrated to all licensed personnel by the licensee. The exam was reviewed and foind acceptable by a member of the NRC staff.
Individuals scoring less th:, 90 percent on the exam will receive additional training and will not assume licensed duties until a score of at least 90 percent is attained on an equivalent, but different exam.
The NRC staff conducted audits to evaluate the effectiveness of the training program.
The results were judged satisfactore.ith some deficiencT:s noted to the DB-1 staff.
The DB-1 staff will use the results of these audits as well as any generic weaknesses discovered on the written exams in '. heir development of future training and requalification programs.
The NRC staff will review all results and records as part of the normal inspection function of the DB-1 requalification program.
We conclude that there is adequate assurance that the operators at DB-1 have, anM will continue to receive, a sufficient level of tra:ning concerning the TMI-2 a cident.
Based on the above evaluation, we conclude that the licensee has compliec with the recuirements of Item (d) of the Order.
577056
. Item (e)
The Order requires that:
"All licensed reactor operators and senior reactor operators will have completed the Three Mile Island Unit No. 2 simulator t aining at B&W."
The licensee has confirmed that all reactor operators and senior reactor operators have completed the TMI-2 simulator training at B&W as required by the Order.
This training consisted of a class discussion of the TMI-2 event and a demonstration of the event on the simulator and how it should have been controlled.
The class discussion was about one hour long and the remainder of the four hour session was conducted on the simulator.
The TMI-2 event, including operational errors, was demonstrated to each operator.
The event was again initiated and the operators were given " hands-on" experience in successfully regaining control of the plant by several methods.
Other transients, which resulted in depressurication and saturation conditions, were presented to the operators, in which they maneuvered the plant to a stable, subcooled condition.
The licensee has submitted copies of procedures that were revised as a result of this Order and actions the licenr 5as taken to preclude tne occurrence of an incicent similar to that which occur e at TMI-2.*
The procedures reviewed by the staff include:
"[As noted on page 16 of tnis Safety Evaluaticn, additional and more detailed analyses of loss-of-feedwater transients and otner anticioated transients will be cone, wnich could affect these procetures in the long-term.]
577057
.s
, EP 1202.01 Load Rejection EP 1202.02 Station Blackout EP 1202.03 RCS Overpressure Anticipatory Manual Trip EP 1202.04 Reactor-Turbine Trip EP 1202.06 Loss of Reactor Coolant and Reactor Coolant Pressure EP 1202.14 Loss of RC Flow /RCP Trip EP 1202.22 High Condenser Pressure EP 1202.24 Steam Supply System Rupture EP 1202.26 Loss of Steam Generator Feed AB 1203.04 Depressurization of the RCS with Safety Grace Equipment A8 1203.02 Loss of All AC Power AP 3003.41.44 High Pressure Injection Hign Flow Alarm AP 3003.49.50 Low Pressure Injection High Flow Alarm AP 3003.51.54 High Pressure Injection Law Flow Alarm AP 3C03.5?.60 Low Pressure Injection Low Flow Alarm SP 1105.16 Steam and Feedwater Rupture Control System Operating Procedure SP 1106.06 Auxiliary Feedwater System ST 5071.01 Auxiliary Feedwater System Monthly Test Special Order No. 20 Additional Guidance for Checking Critical Parameters for Emergency Procedures The licensee's revised procedures provide additional guidance for the acerators nen cooing with emergency plant concitions.
Where accropriate, operators are 577.)-J 377y38
.. directed to recheck certain critical plant parameters.
Operators are also directed to check alternate instrument channels to confirm readings and reduce the possibility of reliance on faulty or misleading indications.
NRC staff comments on the licensee's procedures have been incorporated into the revised documents.
These revisions have been reviewed by the staff and determined to be acceptable.
The staff walked through the following proce'dures with the control room operators:
EP 1202.06 (" Loss of Reactor Coolant and Reactor Coolant Pressure"), EP 1202.14 (" Loss of RC Flow / RCP Trip"), EP 1202.26
(" Loss of Steam Generator Feed"), and SP 1106.06 (" Auxiliary Feedwater System").
Based on this walk through and interviews with the cperators, (see the discussion of the NRC staff audit of operators under Item (d)), we conclude that the procedures are functionally adequate and the operator training on their use is satisfactory.
Based on the above evaluation, we conclude that the licensee is in compliance with Item (e) of the Order.
Item (f)
The Order requires that the licensee:
" Submit a reevaluation of the TECO analysis of the need for automatic or administrative control of steam generator level setpoints during auxiliary feecwater system operation, previouc,1y submitted by TECO letter of December 22, 1978, in light of the Three Mile Island No. 2 incident."
r7769
. By letter, (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated May 19, 1979), the licensee provided additional discussion of the steam generator dual level setpoint.
The need for this feature is to reduce the potential for loss of pressurizer level indication as a result of overcooling of the primary system for non-LOCA events.
The results of a natural circulation test conducted at 08-1 and B&W analyses demonstrate that 08-1 can be operated at a low steam generator level (35 inches on the startup range instrumentation).
The high level setpoint (96 inches indicated on the startup range instrumentation) is required since previous small break analyses assumed that auxiliary feedwater was controlled to a steam generator level of 96 inches.
Pending incorporation of permanent design modifications to provide the automatic dual setpoint steam generator level control, emergency procedures instruct the operator to manually control the steam generator level at 35 inches for all events requiring AFW unless an SFAS level 2* signal occurs.
When the SFAS level 2 signal occurs, the operator is instructed to control the steam generator level at 96 inches by placing the AFW made selector switch in the auto essential position.
This manual provision required no previous change to the design of the AFW control system.
The future circuitry modification, to automatically control to 35 inches, will be reviewed by the staff during the long ter-.
TECO has cited Reference 9 to demonstrate that no unreviewed safety issues or detrimental accident consequences would result if tne operator failed to manually control the steam generator level at 35 inches.
The staff reviewed the information contained in this reference and concluded that additional information was required to verify that the effects of manually controlling the steam generator level at 35 inches is acequate for the Es-1 FSAR Chapter 15 transient and
- [5FAS ievei 2 - An SFAS level 2 signal is develoced wnen reactor coolant system pressure crocs to 1600 psig or containment vessel pressure increases to 4 psig.]
577060
. i accident analyses, and the more recent B&W small break analyses (Reference 1).
By letter, (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated June 15, 1979), the licensee stated that the control of the steam generator level at 35 inches has no adverse effect on the DB-1 FSAR analyses, since the peak reactor temperature and pressure following the most severe transients (loss of feedwater, feedwater line breaks, loss of offsite power) occur prior to initiation of the AFW.
The results of natural circulation testing conducted at DB-1 support the effectiveness of the 35 inch steam generator control level to maintain natural circulation and remove decay heat for:
(1) transients that result in loss of forced circulation (loss of offsite power) and (2) for small breaks (less than 0.01 ft.2) that depressurize slow enough that it is possible to manually control the steam generator level prior to actuation of the SFAS level 2 signal.
For small breaks larger than 0.01 ft.2, reduction of the reactor coolant system pressure to SFAS level 2 occurs prior to the steam generator level decreasing to 96 inches. With the steam generator level controlled at 35 inches, the effectiveness of natural circulation is such that there is no small break size that will result in repressurizstion of the primary system without an SFAS level 2 actuation.
The staff has reviewed the information provided by TECO in the referenced documents and concludes that dual level setpoints, with manual control of the steam generator level at 35 inches, are acceptable. Also, the NRC staff has verified that this manual control cacability has been previously demonstrated.
The licensee has submitted revised procedures, which the staff has reviewed, that provice requirements for steam generator level control.
These procedures 577061
. include:
EP 1202.06 (" Loss of Reactor Coolant and Reactor Coolant Pressure"),
EP 1202.14 (" Loss of RC Flow /RCP Trip") and EP 1202.26 (" Loss of Steam Generator Feed"). The NRC staff has verified that these procedures instruct the operator to confirm that the AFW mode selector switches are in the auto essential position and maintaining steam generator level at 96 inches on the startup range indication in the event SFAS level 2 condition is present.
If a SFAS level 2 condition is not present and an AFW system demand event occurs, steam generator levels will automatically control at 96 inches (since the AFW mode selector switches are in the auto-essential position).
The operator is directed to take manual control of steam generator level and maintain level at 35 inches on the startup range indication.
If an SFAS Level 2 condition subsequently develops, the operator must' return the AFW mode selector switches to the auto-essential position to allcw automatic level control at 96 inches.
Therefore, the emergency procedures are written to permit manual control of steam generator level after an automatic initiation of AFW only if an SFAS level 2 condition is not present.
If a SFAS level 2 condition is present (or develops), the operator is directed to leave (or return) the AFW mode selector switches in the auto-essential position.
In addition, a warning plate has been installed adjacent to the mode selector switch for each AFW train, reminding the operator of the requirement to maintain the switch in the auto essential position mode if an SFAS level 2 condition is present.
The NRC staff has verified the installation of this warning plate.
Also, during the audit the NRC staff confirmed that 577062
. the control room operators are aware of the requirements outlined in the revised procedures and understand the purpose of the warning plate.
Based on the above evaluation, we conclude that the licensee has complied with the requirements of Item (f) of the Order.
Item (c)
The Order requires that the licensee:
" Submit a review of the previous TECO evaluation of the September 24, 1977 event involving equipment problems and depressurization of the primary system at Davis-Besse 1 in light of the Three Mile Island Unit No. 2 incident."
By letter (Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated May 18, 1979), the licensee sucmitted additional discussion of the September 24, 1977 event.
This event was similar in several important areas to the TMI-2 accident.
The initiating malfunction was a loss of main feedwater (the same as TMI-2);
however, the ensuing trainsient was much less severe than TMI-2 for several significant reasons.
The following discussion compares The 03-1 event to the accident at TMI-2.
The bases for this comparison are the six human, cesign and mecnanical f ailures cescribec in IE Bulletin 79-05A ( April 5,1979) which resulted in core camage anc -adiation releases at the TMI-2 nuclear plant.
577063
, 1.
At the time of the initiatina event, loss of feedwater, (at THI-2) both of the auxiliary feedwater trains were valved out of service.
The 08-1 loss of feedwater (LOFW) event initiated both trains of AFW.
However, only one train fed its associated steam generator (SG) due to a malfunction of a turbine governor which kept one of the two AFW pump turbines at a speed insufficient to pump water into its associated SG.
As a result of the 08-1 event, the modifications that have been made include:
(1) the APW pump turbine governors were modified to prevent binding malfunctions; (2) springs were installed in the APW governor to prevent closure of the governor valve due to vibration; (3) the APW governor control circuitry relays were replaced (see additional AFW discussions in Item (a)).
2.
The cressurizer oower-coerated relief valve (PORV), which coened dur _nc the initial oressure surce (at TMI-2), failed to close when Dressure cecreased below the actuation level.
During the 08-1 LOFW, the PORV also failed to close, causing loss of coolant and some voiding in the reactor coolant system (RCS).
- However, the operators recognized the open PCRV about 20 minutes into the event (compared with 2 1/2 hours at THI-2) and responded by closing the PCRV block valve and reinitiating nigh pressure injection (HPI) flow.
577064 The 08-1 unit has been modified to provide the operator with a better status of the position of the PORV.
The emergency procedures were also revised and now require the operator to verify that no leak exists at the top of the pressurizer by monitoring the saturation curve and quench tank pressure and level.
3.
Following racid decressurization of the cressurizer (at TMT-2) the cressurizer level indication may have led to erroneous inferences of hich level in the RCS.
This erroneous high level indication accarently led the coerators to crematurely terminate HPI. even throuch voids existed in the RCS.
For the 08-1 LOFW event, the operator also initially terminated HPI due to a high pressurizer level indication; however, the operator recognized the open PORV at 20 minutes and reinitiated HPI at 49 minutes (after failing to control pressurizer level with a second makeup pump).
DB-1 procedures have been revised and ncw require that for all cases in which HPI is initiated, maximum HPI flow is to be maintained unless one of two criteria is met. These criteria are addressed in i em (d).
t 4
Because the contairment does not isolate on HPI initiation (at TMI-2). the hichlv radioactive water from the relief valve discharce was cumoed out of, containment by the automatic initiation of a transfer cumo.
This water entered tne radioactive waste treatment system in the auxiliary buildinc 577065
. where some of it overflowed to the floor.
Outgassina from this water and discharge throuch the auxiliary building ventilation system and filters was the princical source of the offsite release of radioactive noble cases.
Containment isolation at DB-1 occurs at either 1600 psig RCS pressure (HPI initiation) or 4 psig containment vessel pressure.
During the DB-1 event, containment isolation signals occurred and the sump was not pumped outside containment as at TMI-2.
5.
Subsecuentiv. the HPI system was intermittently coerated (at IMI-2) attemoting to control RCS inventory losses through the PORV. accarently based on Dressurizer level indication.
Due to the cresence of steam and/or noncondensEble voids elsewhere in the RCS, this led to a further reduction in crimary coolant inventory.
During the DB-1 event, the operator initially tried to control the pressur-izer level decrease with a second make-up pump aftar closing the PORV block valve.
However, after the pressurizer level decreased further he restarted a HPI pump. When the pressurizer level was recovered, he terminated the HPI flow.
At this time plant parameters were under control and the plant was brotght to a stabilized condition.
As indicated in Part 3 above, DB-1 procedures have been revised to require that for all cases in which HPI is initiated, maximum HPI flow is to be maintained unless one of two criteria is met.
These criteria are addressed in Item (c).
577066 6.
Tricoing of reactor coolant cumos durina the cour se of the transient (at TMI-2), to orotect acainst cumo damace due to cumo vibration, led to fuel damage since voids in the RCS orevented natural circulation.
During the DB-1 incident, two RCP's were tripped to reduce system heat input into the RCS.
One RCP per loop was maintained in operation throughout the incident.
The DB-1 emergency operating procedures now require keeping at laas+. one RCP per loop running in the event of a small LOCA.
To summarize Item (g) of the Order, the staff views the September 24, 1977 event at 08-1 to have been similar to the TMI-2 event in several important aspects.
However, significant differences in plant status and operator response contributed to produce a much less severe transient.
The staff concludes that satisfactory improvements in both design and emergency pro-cedures have been made since the DB-1 event and, that, the licensee has complied with the requirement of Item (g) of the Order.
CONCLUSION We conclude that the actions described above fulfill the requirements of our Or er of May 16, 1979 in regard to Paragraph (1) of Section IV.
The licensee having met the requirements of Paragraph (1) may restart DB-1 as provided by Paragracn (2).
Paragrapn (3) of Section IV of the Order remains in force 577067
. until the long term modifications set forth in Section II of the Order are completed and approved by the NRC.
577068
. REFERENCES 1.
Letter from J. H. Taylor (B&W) to R. J. Ma,ttson (NRC) transmitting report entitled, " Evaluation of Transient Behavior and Small Reactor Cocaint System Breaks in the 177 Fuel Assembly Plant," dated May 7, 1979.
2.
Letter from J. H. Taylor (B&W) to R. J. Mattson (NRC) transmitting revised Appendix 1, " Natural Circulation in B&W Operating Plants (Revision 1),"
dated May 8, 1979.
3.
Lettar from J. H. Taylor (B&W) to R. J. Mattson (NRC) transmitting addi-tioral information regarding Appendix 2, " Steam Generator Tube Thermal Stress Evaluation," to report identified in Item 1 above, dated May 10, 1979.
4.
Letter from J. H. Taylor (B&W) to R. J. Mattson (NRC), providing an analysis for "Small Break in the Pressurizer (PORV) with no Auxiliary Feedwater and Single Failure of the ECC5," identified as supplements 1 and 2 to Section 6.0 of report in Item 1, dated May 12, 1979.
5.
Letter from J. H. Taylor (B&W) to R. J. Mattson (NRC), providing Supplement 3 to Section 6 of report in Item 1, dated May 24, 1979.
6.
Letter from Lowell E. Roe (TECO) to Mr. Robert W.
Reid (NRC) dated May 22, 1979, providing Volume III to Reference 1 for tne raised loop plant.
577069
. 7.
Letter from Lowell E. Roe (TECO) to Mr. ~ cert W. Reid (NRC) dated May 23, 1979.
8.
Letter from Lowell E. Roe (TECO-Serial No. 517) to Harold R. Denton (ONRR) dated June 15, 1979.
9.
Letter from Lowell E. Roe (TECO) to Mr. Robert W. Reid (NRC) dated December 22, 1978.
577G70
UNITED STATES NUCLEAR REGULATORY CCMMISSICN TOLECO EDISON AND THE CLEVELAND ELECTRIC ILLUMINATING COMPANY DOCKET NO. 50-346 NOTICE OF AUTHORIIATICN TO RESUME OPERATION The United States Nuclear Regulatory Commission issued an Order on May 16,1979 (44 F.R. 29767, May 22,1979), to The Toledo Edison and The Cleveland Electric Illuminating Company (TECO or The Licensee), holders of Facility Operating License No. NFF-3, for the Davis-Besse Nuclear Power Station, Unit No.1 (Davis-Besse), confirming that the licensee accomplish a series of actions, both immediate and long-term, to increase the capability and reliability of Davis-Besse to respond to various transient events.
In addition, the Order confirmed that the licensee would maintain the plant in a shutdown condition until the following actions had been satisfactorily compl eted :
(a) Review all aspects of the safety grade auxiliary feedwater system to further uograde components for added reliacility and performance.
Present modifications will include the addition of dynamic braking on the auxiliary feedpump turbine speed changer and provision of means for control room verification of the auxiliary feedwater flow to the steam generators. This means of verification will be provided for one steam generator prior to startup from the present maintenance outage and for the other steam generator as soon as vendor-supplied equipment is available (estimated date is June 1, 1979).
In addition, the licensees will review and verify the adequacy of the auxiliary feedwater system capacity.
(b) Revise operating procedures as necessary to eliminate the option of using the Integrated Control System as a backup means for controlling auxiliary feedwater flow.
(c)
Implement a hard-wired control-grade reactor trip that aould be actuated on loss of main feedwater and/or turoine trip.
(d) Comolete analyses for potential small breaks and develop and implement operating instructions to define operator action.
577071
~
. (e) All licensed reactor operators and senior reactor operators will have completed the Three Mile Island Unit No. 2 simulator training at B&W.
(f)
Submit a reevaluation of the TECO analysis of the need for autcmatic or administrative control of staam generator level setpoints during auxiliary feedwater system operation, previously submitted by TECO letter of December 22, 1978, in light of the Three Mile Island Unit No. 2 incident.
(g)
Submit a review of the previous TECO evaluation of the September 24, 1977 event involving equipment pr^blems and depressurization of the primary system at Davis-Be.s',e 1 in light of the Three Mile Island Unit No. 2 incident.
By letters dated April 27 and May 4,1979 and supplemented by sixteen letters dated May 11, 18, 19, 22 (2), 23 (2), 25 (2), 29, and June 15 (2),
18, 21, 23, and 25, 1979, the licensee has documented the actions taken in response to the May 16 Order. Notice is hereby given that the Director of Nuclear Reactor Regulation (the Director) has reviewed this submittal and has concluded that the licensee has satisfactorily completed the actions prescribed in items (a) through (g) of paragraph (1) of Section IV of the Order, that the specified analyses are acceptable and the specified implementing procedures are appropriate. Accordingly, by letter dated July 5, 1979, the Director has autnorized the licensee to resume operation of Davis-Besse. The bases f0r the Director's conclusicns are more fully set forth in a Safety Evaluation dated July 6, 1979.
Copies of (1) the licensee's letters dated April 27 and May 4,1979 and sixteen letters dated May 11, 13, 19, 22 (2), 23 (2), 26 (2), 29, and June 15 (2),
13, 21, 23, and 25, 1979, (2) the Director's letter dated July 5, 1979 and (3) the Sa fety Evaluation dated July 6,1979, are available for inspecticn at the Commission's Public Document Roem at 171T H Street, N. W., Washington, D. C. 20555, 577G72
_ ~
'A and are being placed in the Comission's local public document room in The IDA Rupp Public Library, 310 Madison Street, Port Clinton, Ohio 43452. A copy of items (2) and (3) may be obtained upon request addressed to the U. S.
Nuclear Regulatory Commission, Washington, D. C. 20555, Attention: Director, Division of Operating Reactors.
FOR THE NUCLEAR REGULATORY COMMISSICN O
~
~
j
_. [, AN
- '$ $ $ u J Robert W. Reid, Chief Operating Reactors Branch #4 Division of Operating Reactors Dated at Bethesda, Maryland this 6tn day of July 1979.
577073