ML20148H800
| ML20148H800 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 11/02/1978 |
| From: | Varga S Office of Nuclear Reactor Regulation |
| To: | Gary R TEXAS UTILITIES ELECTRIC CO. (TU ELECTRIC) |
| References | |
| NUDOCS 7811150010 | |
| Download: ML20148H800 (97) | |
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g NUCLEAR REGULATORY COMMISSION o,
UNITED STATES l
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NOV 2 1978 Docket Nes:
50-445 50-446 Mr. R. J.
Gary Executive Vice President and General Manager Texas Utilities Generating Company 2001 Bryan Towers Dallas, Texas 75201
Dear Mr. Gary:
SUBJECT:
REQUESTS FOR ADDITIONAL INFORMATION FOR COMANCHE PEAK STEAM ELECTRIC STATION, UNITS 1 AND 2 Enclosed are requests for additional information which we require to complete our evaluation of your application for an operating license for Comanche Peak.
These requests for additional information are the results of our review of the information in your FSAR through amendment 2 including your responses to the information requested in our letter of April 24, 1978.
Please amend your FSAR to include the information requested in the enclosure.
The information lequested in the Enclosure covers all areas of our review with the exception of those per-formed by the following:
(1) Instrumentation and Control Systems Branch; (2) Power Systems Branch; (3) Analysis Branch and (4) Structural Engineering Branch.
Also, the Accident Analysis Branch has submitted only a portion of their information requests.
We anticipate that the requests for additional information for the areas of review performed by these branches ull be transmitted to you by December 29, 1978.
As was discussed in your August 9, 1978 meeting with Mr. Denton, recent regulatory activities have necessitated our re-evaluation of the review schedules and review programs for several licensing applications, including Comanche Pea).
In order that we may better evaluate the Comanche Peak licensing review program and determine any necessary review schedule changes, we ask that you provide your schedule for responding to the enclosed 78111500/0
ya Mr. R. J. Gary
-2 NOV 2 1978 requests for additional information by November 20, 1978.
Based on your schedule for response and our workload, we will determine any licensing review schedule adjustments and inform you of any significant changes.
Please contact us if you desire any discussion or clarification of the enclosed requests, ncerel>[';
htreA cKt Steven A. Varga, Ch\\ie f Light Water Reactors Branch No. 4 Division of Project Mangement
Enclosures:
As stated cc:
See next page 4
.s 6i Texas Utilities Generating Company NOV 2 1978 ccs:
Nicholas S. Reynolds, Esq.
Debevoise & Liberman 700 Shoreham Building 80015th Street, N. W.
Washington, D.C.
20005 Spencer C. Relyea, Esq.
Worsham, Forsythe & Sanipels 2001 Bryan Tower Dallas, Texas 75201 Mr. Homer C. Schmidt Project Manager - Nuclear Plants Texas Utilities Generating Company 2001 Bryan Tower Dallas, Texas 75201 Mr. H. R. Rock Gibbs and Hill, Inc.
393 Seventh Avenue New York, New York 10001 Mr. G. L. Hohmann Westinghouse Electric Corporation P. O. Box 355 Pittsburgh, Pennsylvania 15230 Richard Lawene, Esq.
Office of the Attorney General P. O. Box 12548 Austin, Texas 78711
V G.
n ENCLOSURE REQUEST FOR ADDITIONAL INFORMATION COMANCHE PEAK - UNITS 1&2 These requests for additional information are numbered such that the three digits to the lef t of the decimal identify the technical review branch and the numbers to the right of the decimal are the sequential request numbers. The number in parenthesis indicates the relevant section in the Safety Analysis Report. The initials RSP indicate the request represents a regulatory staff position.
Branch Technical Positions referenced in these requests can be found in " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," NUREG-75/087 dated September 1975.
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AUXILIARY SYSTEMS BRANCH 005.1 In Table 3.2-2, provide the Quality Group (Safety Class) classiff-cation, the component code and code class, and the seismic classi-fication of the following components:
(1) Refueling Water Storage Tank, (2) Reactor Makeup Water Storage Tank, and (3) Condensate Storage Tank.
005.2 In Table 3.2-1, identify Quality Group B (Safety Class 2) atmos-pheric storage tanks as constructed to Subsection NC-3800 of Section III of the ASME Boiler and Pressure Vessel Code.
005.3 In order to establish your compliance in accordance with footnote 6 to the Codes and Standards Rule, Section 50.55a of 10 CFR Part 50, provide a list of ASME Code Cases that have been utilized in the construction of all Quality Group A components within the reactor coolant pressure boundary.
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- AUXI!.1ARY SYSTEMS BRANCHs
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010.4 According to Table 3.5.1, four component cooling water pumps for (3.5.1) the two units arE arranged such that 2 sets of adjacent stalls are separated by a corridor. Provide the results of an analysis that l
demonstrates that a missile from a pump on one side of the corridor j
cannot damage the two pumps across the corridor.
010.5 Describe the protection from turbine missiles that is provided for (3.5.1) the condensate storage tank.
010.6 Cemonstrate that yourplant can be brought to cold snutdown assuming (3.6.3) a crack in the fire protection system piping concurrent with a single active failure in safe shutdown compenents.
1 010.7 We require that the compartment between the containment and the (3.6.8) safety valve house which houses the main steam lines and feedwater lines and the isolation valves for those lines, be designed to con-sider the environmental effects (pressure, temperature, humidity) and potential flooding consequences from an assumed crack, equivalent to the flow area of a single ended pipe rupture in tFese lines. We require that essential equipment located within the compartment, including the main steam isolation and feedwater valves and their operators be
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capable of operating in the environment resulting from the above crack. We also will require that if this assumed crack could cause the structural failure of this compartment, then the failure should not jeopardize the safe shutdown of the plant.
In addition, we require that the remaining portion of the pipe in the tunnel between the safety valve house and the turbine building meet the guidelines of Branch Technical Position APCSB 3-1.
We require that you submit a subcompartment pressure analysis to confirm that the design of the pipe tunnel conforms to our posi-tion as outlined above.
We request that you evaluate the design against this staff position, and advise us as to the outcome of your review, including any design changer which may be required. The evaluation should include a verification that the methodt used to calculate the pressure build-up in the subc0mpartments outside of the containment for postulated breaks are the same as those used for subcompartments inside the containment. Also, the allowance for structural design margins (pressure) should be the same.
If different methods are used, justify that your method provides adequate design margins and iden-tify the margins that art. available. When you submit the results of your evaluation, identify the computer codes used, the assump-tions used for mass and energy and release rates, and sufficient design data so that we 'may perform independent calculations.
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3-The peak pressures and temperatures resulting from the postulated break of a high energy pipe located in compartments or buildings is dependent on the mass and energy flows during the time of the break.
You have not provided the informatior, necessary to determine what terminates the blowdown or to determine the length of time blowdown exists. For each pipe break or leakage crack analyzed, pro-vide the total blowdown time and the mechanism used to terminate or limit the blowdown time of flow so that the environmental effects will not affect safe shutdown of the facility.
010.8 Provide a tabulation of all vcives in the re'-Nr pressure boundary (9.0) and in other seismic Category I systems
- egulatory Guide 1.29) whose operation is relied upon either iure safe plant shutdown or to mitigate the consequences sient or accident. The tabulation should identify the sys.
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.n which it is installed, the type and size of valve, the actuation type (s), and the environ-mental conditions to which the valves are qualified.
010.9 Provide the location of all liquid storage tanks and demonstrate that (9.0) their failure cannot result in flooding or unacceptable degradation of safety related equipment that would impair the safe shutdown of the plant.
010.10 Verify that the fuel building overhead crane is prevented by mechanical (9.1.2) stops or interlocks from moving over the spent fuel during cask handling operations.
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- 010.11 Identify in Figure 9.1.13 the boundary between the non-seismic (9.1.3) and seismic Category I portions of the spent fuel pool cooling and cleanup system.
010.12 Demonstrate that tornado missiles will not damage the 2 impoundment dams (9.2.5) and cause the draining of the Ultimate Heat Sink.
010.13 Compartments containing safety related equipment are provided with (9.3.3) backwater valves to prevent water from backing up through the drain lines and impairing the function of safety related equipmert.
Since these backwater valves are non-seismic, demonstrate that the safe shutdown earthquake does not cause flooding that backs up through the drain lines Of the compartments containing safety related equipment.
If the safe shutdown earthquake can czuse ficod-ing that can back up into compartments containing safety related equipment, provide back up valves and drain lines between the back up valves and the safety related equipment
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010.14 Provide a failure modes and effects analysis for all the safety re-(9.4.1, 9.4.2, late
.mpers in the control room, fuel building, auxiliary building 9.4.3,
- 9.4.5) and engineered safety features building heat, ventilation and air conditioning systems.
Include in your analysis the effects of loss of offsite power.
C10.15 The Auxiliary Building and Engineered Safety features Heating and (9.4.2 9.4.5)
Ventilation and Air Cor.ditions System and their respective supply and exhaust units are shown on three different drawings.
Identify in figures 9.4.2, 9.4.4 and 9.4.9 the interfaces between the Auxiliary Building and Engineered Safety Features Heating and Ventilation and Air Conditioning Systems and their respective supply and exhaust units.
010.16 You state in Section 9.4.E.1 taat the non-seismic plant ventilation (9.4.E.1) chilled water system is required to operate during a loss of offsite Since seismic events may cause the loss of offsite pcwer, power.
provide a seismic Category I plant ventilation chilled water sys tem.
010.1 7 Describe the protection provided to prevent tornado and turbine (010.3) missiles frem resulting in multiple piping failures in the main steam and feedwater systems.
010.18 It is our position that air operated atmospheric relief valves (010.3) be tested at power as part of plant checkout tt confirm that a safe ccid plant shutdown can be achieved with no offsite power.
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. 010.19 According to your FSAR, af ter a feedline break, the coerator manually (10.4.9) isolates the auxiliary feedwater flow to the effected steam generator in order to ensure a sufficient quantity of auxiliary feedwater to the three intact steam generators. Failure of this operator action results in insufficient flow to cool the core.
It is our position that you automate the isolation of the feedwater flow to the steam generator affected by a feedwater line break, or demonstrate that failure of the operator to take action within 30 minutes will not result in unacceptable consequences.
.yd Containment Systems Branch 022.9 Expand Table 6.2.5A-2 to specify the amount of zinc and the associated surface area for both paint and galvanized steel.
Specify and justify corrosion rates used for both paint and galvanized steel.
022.10 The FSAR states that all reflective insulation, with the exception (6.2.2.3.3) of the reactor coolant pipe insulation, is designed to remain in place during a seismic event.
Provide additional information to support this statement.
Furthermore, as previously requested in 022.5, discuss the effect of loose insulation and other debris on sump performance following a pipe break accident.
022.11 Discuss the potential for water becoming trapped in the instrumentation 6.2.2 tunnel, and not being effective in contributing to the available NPSH to the containment spray pumps.
l 022.12 The minimum containment pressure analysis for ECCS performance evaluation should be performed with containment data which is conservative with respect to the corresponding containment data used in the analysis of the maximum containment pressure for postulated high energy line pipe breaks. Therefore, demonstrate that the containment data used for ECCS backpressure analysis is conservative or revise the analysis using
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- l conservative containment input data. Also verify if the containment atmosphere temperature and essential raw cooling water temperatures used in the ECCS backpressure analysis are minimum values as specified in BTP CSB 6-1, " Minimum Containment Pressure Model for PWR ECCS Performance Evaluation."
022.13 Discuss the parameters sensed for the initiation of containment iso.lation.
It is our position that there should be diversity in the parameters sensed for the initiation of containment isolation for all containment
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isolation valves. Discuss your conformance with this position.
022.14 From Figure 6.2.2-2 it appears that the reauired NPSH for the spray pumps is 11.5 ft Describe in detail now the minimum available NPSH of the spray pumps was determined.
Specify if the static head at the centerline of the pump suction takes credit for the height of water on the containment floor.
022.15 Propose a system design for monitoring the hydrogen concentration within the containment following a LOCA that does not rely on recombiner installation or operation.
022.16 Provide a detailed drawing of the refueling canal drain provisions.
Discuss the potential for reactor coolant system and spray water becoming trapped; e.g._, in the refueling canal, and prevented from draining to the containment sump following a loss-of-coolant accident.
Discuss the design provisions within the containment that will permit the water to be drained to the containment sump.
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. 022.17 Provide a detailed drawing of the fuel transfer tube penetrations and discuss the design provisions for leak testing.
022.18 Discuss the capability to detect leakage from lines provided with remote manual isolation valves to assure that adequate information is available to the operator to initiate isolation if necessary.
022.19 Tables identified in your 6.2-4 series present information we require on containment leak testing. Your discussion and tables should be expanded. Therefore provide the following information with regard to the containment leak testing program:
a.
Identify those fluid lines penetrating the containment which will be vented and drained to ensure exposure of the system containment isolation valves to the containment atmosphere and the full differential pressure during the containment integrated leakage rate (Type A) test. Those systems that will rcnin fluid filled for the Type A test should be identified and justification given.
b.
Provide plan and elevation drawings of the personnel air lock and identify all mechanical and electrical penetrations. Discuss and schematically show the design provisions that will pumit the personnel air-lock door seals and the entire air lock to be tested.
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, Discuss the design capability of the door seals to be leak tested at a pressura of Pa; i.e., the calculated peak containment internal pressure.
If it will be necessary to exert a force on the doors to prevent them from being unseated during leak testing, describe the provisions for doing this.
When multiple openings of the containment air locks occurs, the air locks shall be tested at least once every three days. For those air locks incorporating dual seals, specify and justify the pressure used to pressurize the volume between the air lock seals.
c.
Provide a table of all containment penetrations; i.e., fluid system piping, instrument, electrical, and equipment and personnel access penetrations. For each penetration identify the Type B and/or Type C local leak testing that will be done.
Identify all valves for which the applied test pressure is not in the same direction as the pressure existing when the valve is required to perform its safety function, and provide evidence to show acceptability of testing the valve with pressure applied in the reverse direction.
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. For each fluid line that penetrates the containment, schematically show the isolation valve arrangement and the design provisions that will permit the isolation valves to be leak tested.
Indicate the direction in which the valves will be leak tested.
d.
Appendix J requires that containment penetrations fitted with expansion bellows be tested at Pa. Verify that this requirement can be met.
Identify any penetration fitted with expansion bellows that does not have the design capability for Type B testing and-provide justification.
e.
III.C.1 of Appendix J states that if containment isolation valves are to be testad with the test pressure appliec in a direction opposite to that which would occur under accident conditions, it must be shown tha' tb ast results in equivalent or more conservative leak es. Therefore, for all containment isolation valves that are to be tested in the reverse direction, provide the justification required by III.C.1 of Appendix J.
f.
Provide a compilation of the fluid system piping drawings showing, for each penetration, the isolation valves provided to satisfy the requirements for GDC 54, 55, 56 and 57, the location of test, vent and drain (TVD) connections, the block valve to facilitate local leak testing, and the branch lines between isolation valves Indicate the direction in which the isolation valves will be tested.
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It is our position that all isolation valves provided to satisfy General Design Criteria 54 through 57 (containment isolation
'<alves) should be pneumatically (Type C) leak tested. Alternatively, a containment isolation valve may be exempted from the Type C test requirements if it can be shown that the valve does not constitute a potential containment atmosphere leak path following a loss of coolant accident.
Identify the containment isolation valves that will not be Type C tested and justify that they do not constitute potential contaimnent atmosphere leak paths following a LOCA.
In this regard, a water seal may be shown to exist that will preclude containment atmosphere leakage.
If this approach is taken, discuss how a water seal can be established and maintained using safety grade pipes and components, and considering single failure of active :omponents.
System drawings showing the routing and elevation of piping may be used to show the existence of a water seal.
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CSB Interim Evaluation Model i
Environmental Qualification for Main Steam Line Break Inside Containment (Operating License Applicants Only)
Analyses of main steam line break (MSL3) accidents inside PWR dry-type containments have predicted temperature transients which exceed I
the qualification temperature of some safety related equipment. As a result there is a concern regarding the capability of this equipment to survive such an event to assure safe plant shutdown. This concern i
is related to Issue 25 of NUREG-OlS3 dated September,1976.
l The NRC has identified this matter as a Category A Technical Safety Activity and is currently pursuing a program :: rescive this c:ncern.
In the meantime it is required that you perform an evaluation of the containment environmental conditions associated with a MSLS accident as well as a LOCA and justify that the essential equipmen needed to mitigate inese accidents have been adequately qualified.
Since the NRC generic effort on this concern is still in progress, we are providing the analytical assumptions which are acceptable far tne interim period. These models and assumptions are acceptable for the spectrum of MSL3 accidents.
1.
Containment Environmental Response a.
Heat transfer coefficient to heat sinks.
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The Uchida heat transfer correlation (data) should be used while in the condensing mode. A natural convecticn heat transfer
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2 coefficient should be used at all other times. The application of these correlations should be as follows:
(1) Coddensing heat transfer q/A a h
. (T -T) 3 wher1 g/A = the surface heat flux h
= the Uchida heat transfer coefficient u
T.
= the steam saturation (dew point) temperature
=
T
= surface temperature of the heat sink y
(2) Convective heat transfer q/A = bc * (I w)
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V where h = convective heat transfer coefficient c
T = the bulk vapor temperature.
y All other parameters are the same as for the condensing mode.
b.
Heat sink condensate treatment When the containment atmosphere is at or belcw the saturation tempera ure, all condensate formed on the heat sinks should be transferred directly to the sumo. When the atmosobere is superheated a maximum of 8% of the ccndensate may be transferred i
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to the vapor region.
The revaporization should be calculated as follows:
M = X q / (h -h )
r y t where M = revaporization rate p
X- = revaporization fraction (0.08) q = surface heat transfer rate
.h
= enthalpy of the superheated steam y
hg = enthalphy of the liquid condensate entering the sump regicn (i.e., average enthalpy of the heat sink condensate boundary layer) c.
Heat sin'k surface area The surface area of the heat sinks should correspond to that used for the containment design pressure evaluation.
d.
Single active failure evaluation Single active failures should be evaluated for those containment safety systems and compenects relied upon to limit the containment temperature / pressure response to a MSLB accident. This evaluation
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4 should include, but not necessarily be limited to, the loss or availability of offsite power.(whichever is worse), diesel generator failure when loss of offsite power is evaluated, and loss of containment heat removal systems (either partial or total).
- e. Containment heat removal system actuation The time detennined at which active containment heat removal systems become effective should include censideration of actuation sensors and tetpoints, activation delay time, and system delay time (i.e., time required to come into operation),
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Identification of most severe environment The worst case for anvironmental qualification shculd be selected considering time duration at elevated temperatures as well as the maximum temcerature.
In particular, censider the spectrum of break sizes analy:ed and single failures evaluated.
2.
Safety Related Ccmponent Thermal Analysis Component thermal analyses may be performed to justify environmental qualification test c:nditions less than thot 2 calculated during the containment envir nmental response calculation. The thermal analysis shculd be performed for the potential points of component failure such as thin cross sections and tameerature sensitive parts where thermal stressing temperature-related degradation, steam er chemical interaction at elevated temperatures, or other thermal effects could at
result in failure of the compartment electrically or mechanically.
The heat transfer rate to components should be calculated as follows:
a.
Condt nsing heat transfer rate q/A = b
- (I -T) cd s
w where q/A = component surface heat flux h
= condensing heat transfer coefficient cd
= the larger of 4x Tagami Correlation or 4x Uchida Correlation T
= saturation temperature (dew point) s T = component surface temperature y
b.
Convective heat transfer A conveccive heat transfer coefficient snould be used when the condensing heat flux is calculated to be less than the convective heat flux. During the bicwdewn period, a forced convection heat transfer correlation should be used.
For example:
NU = C,(Re)"
where Nu = Nusselt No.
Re = Reynolds No.
C,n = empirical constants dependent en gecmetry and Reynolds No.
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The velocity used 1n the evaluation of Reynolds number may be i
determined as follows:
M Ve 25 80 COMT where V
= velocity in ft/sec M
= the blowdown rate in Ibm /hr BO Y
3 CONT = containment volume in ft After the blowdown has ceased or reduced to a negligibly low value, a natural convection heat transfer correlation it acceptable.
However, use of a natural convection heat t; ansfer coefficient must be fully justified whenever used.
3.
Evaluation of Environmental Qualification The compcnent peak surface temoerature(s) (7 3) snould be comouted using items I and 2 above.
The compenent ;ualification temperature (T ;) should be determined from the actual environment test condi:f ons,
g Where components have been " bathed" in a saturated steam or steam / air environment for extended periods (e.g.,10 minutes), the qualification temperature is the test chamber temperature.
For components subjected to test conditions substantially removed from the steam saturation point or for short durations (e.g., less than 10 minutes), the qualification temoerature must be justified by experimental thermoccuole readings on the component surface or analyses eehich minimizes the heat flux to the component.
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- If 'the component surface temperature, T is less than or equal to g3, the component qualification temperature, T q, the ccmponent may be considered qualified for an MSLB environment during the interim period.
If the component surface temperature is greater than the qualification temperature, then (a) provide additional justification that the component can operate in environments equal to or greater than that which wculd result in the calculated peak surface temperature, or (b) provide a requalification package for the component, or (c) provide approorf ate crotection to assure that the component will not experience a surface tamcerature in excess of the qualification temperature, Teq.
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212-1 212.0 REACTOR SYSTEMS BRANCH 212. 7 Section 3.5.1.2.3 of the FSAR discusses the general missile (3.5.1.2) protection provided for systems inside containment. Provide a table similar to table 3.5-1 (Internally Generated Missiles Outside Containment) that lists specific missile protection for internally generated missiles inside containment.
212. 8 Section 3.5.1.2.2 of the FSAR states that the valve failures (3.5.1.2) considered as potential missile sources were only~those valves in Westinghouse scope.
Identify ' val outside of Westinghouse scope and ju_yes Lnsid_e...coota.inment stify why these valves (if any) have not been considered credible missile sources.
i 21 2. 9 0 4 cuss the potential for damage to safety systems and/or (3.5.1.2) the generation of missiles inside containment as a result of a falling object.
212. 10 Discuss the potential for the failing of safety systems (3.5.1.2) inside containment by secondary missiles generated by impingement of primary missiles.
212.11 Section 3.5.1.2.1 states that " provisions' are made to assure (3.5.1.2) integrity of the containment liner from the resultant bonnet missile." Discuss these provisions to protect the containment liner.
212 12 Discuss the potential for the reactor vessel seal ring to (3.5.1.2) become a missile during a LOCA.
212.13 Provide the high level alarm setpoint for the pressurizer (5.2.2) relief tank. For overpressure events, state what initial 1
level has been assumed for the pressuri:er relief tank.
For the most severe overpressure event discuss whether the safety analyses took into consideration _the decreas_ing_
available volume and the possible rise in backpressure during the discharge to the pressurizer relief tank.
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212. 14 Section 5.4.11.3 of the FSAR states that the discharge (5.2.2) piping from the safety and relief valves to the relief tank is sufficiently large to prevent backpressure at the safety valves from exceeding 20 percent of the set-point pressure at full flow. Discuss what backpressure was assumed in this piping for overpressure transients and justify any assumed backpressures less than 20 percent of the setpoint pressure. Discuss the testing conducted to verify that this maximum backpressure assumption is conservative for Comanche Peak.
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212-2 212.15 You have referenced WCAP 7769 for the 'ComandLEda~k'
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(5.2.2.3) overpressurization protection system. Provide all_parcmeters for Comanche Peak, comparing them to tfie ones given in the report for a typical Westinghouse 4 loop plant. Where differences exist, show that those differences will not affect the conservatism of the results given in WCAP 7769.
212 16 Branch Technical Position RSB 5-2 related to overpressure (5.2.2) protection of PWRs while operating at low temperatures has been recently approved by the Regulatory Requirements Review Committee. Since Comanche Peak will receive an operating license after March 14, 1979, compliance to the following criteria is required prior to initial startup.
(1) A system should be designed and installed which will prevent exceeding the applicable Technical Specifications and Appendix G limits for the reactor coolant system while operating at low temperatures. The system should be capable of relieving pressure during all anticipated overpressurization events at a rate sufficient to satisfy the Technical Specification limits, particularly while the reactor coolant system is in a water-solid condition.
(2) The system must be able to cerform its function assuming any single active component failure. Analyses using appropriate calculational techniques must be provided wt!ch demonstrate that the system will provide the r equired pressure relief capacity assuming the most imiting single active failure. The cause for initiation 1
s# the event, e.g., operator error, ccmponent malfunction, wiil not be considered as the single active failure. The dnalysis should assume the most limiting allowable operating j
ynd systems configuration at the time of tne costulated cause of 'he overoressure event. All cotential over-pressurilation events must be considered when estacTTshing the worst case event. Potential events may not be eliminated from consideration in overpressure protection system design analyses merely by the imposition of technical specifications or other administrative controls, (e.g., prohibitions on safety injection pump operation).
(3)
The system must meet the design requirements of IEEE 279.
j The system may be manually enabled, however, the electrical instrumentation and control system must provide alarms to alert the operator to:
(a) properly enable the system at the correct plant condition during cooldown, (b) indicate if a pressure transient is occurring.
212-3 (5.2.2)
(4) To assure operational readiness, the overpressure protection system must be tested in the following manner:
(a) A test must be performed to assure operability of the system electronics prior to each shutdown.
(b) A test for valve operability must, as a minimum be conducted as specified in the ASME Code Section XI.
(c) Subsequent to system, valve, or electronics maintenance, a test on that portion (s) of the system must be per-formed prior to declaring the system operational.
(5) The system must meet the requirements of Regulatory Guide 1.26, " Quality Group Classifications and Standards for Water, Steam, and Radioactive-Waste-Containing Components of Nuclear Power Plants" and Section III of the ASME Code.
(6) The overpressure protection system must be designed to function during an Operating Basis Earthquake.
It must not compromise the design crfTiria or any other safety-grade system with which itlo~uTd'Tnterface, such that the requirements of Regulatory Guide 1.29, " Seismic Design Classification" are met.
(7) The overpressure protection system must not depend on the availability of offsite power to perform its function.
(8) Overpressure protection systems which take credit for an active component (s) to mitigate the consequences of an overpressurization event must include additional analyses considering inadvertent system initiation / actuation or provide justification to show that existing analyses bound such an event.
Discuss how Comanche Peak complies with this position and identify deviations and modifications to be made for compliance with this position.
212. 17 Section 3.9.B.3.3 discusses that the mounting of pressure (5.2.2) relief devices includes consideration of slug flow from the water seal, if applicable. Discuss whether the sizing and the design loading for the following components considered two-phase flow (in addition to slug flow from the water seal) and water relief:
o.
212e4 (5.2.2)
(1) Pressurizer safety valves and their supports, (2) Pressurizer safety valve piping and its support, (3) Pressurizer relief tank and its support.
212.18 Discuss the containment sumo flow monitoring system more (5.2.5) fully. Discuss what consideration has been given to the fact that unidentified leakage may not flow directly to the sump, but may accumulate at other locations in containment.
Also discuss the ability of the containment sump level _ alarms _ __
to detect a 1 gpm leak in one hour.
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212.19 Discuss the procedures available to the operator to convert (5.2.5) the readout from the various leakage detection systems to gallons per minute leak rate.
212. 20 Regulatory Guide 1.45 states that all three methods used in (5.2.5) the detection of unidentified leakage should meet the sensitivity and response time requirements of RG 1.a5. The containment air particulate monitors and radioactive gas monitors are dependent on background radiation levels for 1
detection of a leak. The containment background level is in turn dependenc on coolant activity and normal (expected)
I unidentified leakage. Show how the radiation monitors satisfy the requirements of RG 1.45 considering a range of containment activity levels stemming from changes in coolant activity and normal unidentified leak rates.
212 21 Section 5.2.5.1.1 discusses that controlled leakage is piped (5.2.5) to the Reactor Coolant Drain Tank and is, therefore, effectively isolated from the containment atmosphere. State if this collection is also used for other identified leakage.
212 22 For each_ leakage detection system, discuss _th_e._ provisions for (5.2.5) testing operability and calib. ration dtiring power operations ~
in accordance wiTh Regulatory Guide 1.45. ' ~~
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212. 23 Describe what alanns alert the operator that identified (5.2.5) leakage is greater than 10 gpm or that controlled leakage is greater than 40 gpm. Discuss the sensitivity and quali-fication of these leakage detection systems.
212. 24 Section 5.2.5.7 of the FSAR states that steam generator (5.2.5) primary-to-secondary leakage is detected by either the steam generator liquid sample radiation monitor or the SGBS radiation monitor. Section 5.2.5.1.4 of the FSAR states that primary-to-secondary leakage through all steam generators is limited to 1 gpm and 500 gpd through any one steam generator. Discuss how the steam generator liquid sample radiation monitor and the SGBS radiation monitor meet these criteria.
21 2-5 212.25 Section 5.2.5.1 of the FSAR discusses that identified leakage (5.2.5) is comprind of known pump seal or valve packing leaks. Describe how these leaks are detected and discuss the criteria used to classify these leaks as controlled leaks.
212.26 Section 5.2.5.2.2 of the FSAR describing intersystem leakage (5.2.5) detection methods must be expanded. For the RHR, ECCS, and pressurizer relief and safety valve systems, and all secondary systems connected to the reactor coolant system, discuss the intersystem leakage detection methods including:
(1) method of detecting intersystem leakage from the reactor coolant system during all modes of system operation.
(2) Method of detecting leakage from any of these systems to atmosphere during all modes of system operation.
(3) Alarms and indications available to the operator for each of the above leakage detection systems.
212.27 Section 5.2.5.1 of the FSAR discusses that identified (5.2.5) leakage includes leakage that is located and known not to interfere with Operation of the leakage detection systems or known not to be reactor coolant pressure boundary leakage.
Discuss the criteria that are used to classify leakage in this category. Are all valves with known packing leaks automatically included in this category, for instance?
For valve packing leaks in this category, do provisions exist to periodically verify that the leakage rates from specific valves have not increased to unacceptable levels?
212.28 Discuss the ability to manually sample the containment (5.2.5) atmosphere. The time to take and analyze a sample, the sensitivity of the analysis, and the procedure for con-version from activity to leakage rates should also be discussed.
212.29 Describe the consequences of a failure associated with the (5.4.7) isolation valves in the suction line from the hot leg to the RHR purnps during normal shutdown cooling. Evaluate this event assumine; thct only one RHR train is operating at the time of the failure. Describe the consequences of this event assuming (a) the reactor coolant system is intact, and (b) the reactor vessel head has been unbolted. The failure could be caused by operator error or a passive
212-6' (5.4.7) failure such as the gate separating from the stem. These failures could cause pump damage due to cavitation and loss of core cooling. Discuss the operator actions required to mitigate the consequences, describe the alarms available to alert him to the situation and the time frame available to perform the required action.
212.30-Provide assurance that-adequate alarms are provided to detect (5.4.7) leakage from the RHR in the event of a small leak or a signi-ficant pipe break. Specifically, provide the following information:
)
(1) ' Demonstration should be provided -that the leak detection system will be. sensitive enough to initiate (by alarm) operator action, permit identification of the faulted line and isolation of the line prior to 30 minutes and prior to the leak creating undesirable consequences such as flooding of redundant equipment.
(2) It should be shown that the leak detection system can identify the faulted train and that the. leak is isolable.
(3) Directions given to the operator to isolate the faulted train and to return the intact train to service should
-be provided.
(4) The leak detection system should meet the following requirements:
(a) Control room alarm (5)
IEEE-279 except single failure requirements 4
212.31 Provide an FMEA for the RHR system.
In addition to single, (5.4.7) active mechanical' failures, include the following:
(1) Spurious movement of a powered component, (2) Operator errors, and (3), Failure caused by leakage frem passive failures.
4 1
Include or reference the information identified or
. provide the rationale for its exclusion.
s
212-7 The USNRC Regulatory Requirements Review Committee has 212 32)-
recently approved a new. staff position (BTP RSB 5-1) for (5.4.7 the residual heat removal system. The technical requirements of this position for your plant are described below.
Your response to these requirements should be in sufficient detail to enable the staff to review your conpliance.
System parameters assumed should be the most limited parameters allowed by Technical Specifications:
BRANCH POSITION (A) Functional Requirements The system (s) which can be used to take the reactor from normal operating conditions to cold shutdown
- shall satisfy the functional requirements listed below.
(1) The design shall be such that the reactor can be taken from normal operating conditions to cold shutdown
- using only safety-grade systems. These systems shall satisfy General Design Criteria 1 through 5.
(2) The system (s) shall have suitable redundancy in components and features, and suitable intercon-nections, leak detection, and isolation capabilities to assure that for onsite electrical power system operation (assuming offsite power is not available) and for offsite electrical power system operation (assuming onsite power is not available) the system function can be accomplished, assuming a single failure.
(3) The system (s) shall be capable of being operated from the control room with eitner only onsite or only offsite power available.
In demonstrating
- Processes involved in cooidown are heat removal, depressurization, flow circulation, and reactivity control. The cold shutdown condition, as described in the Standard Technical Specifications, refers to a subcritical reactor with a reactor coolant temper-ature no greater than 2000F for a PWR and 2120F for a BWR.
s 212-8 (5.4.7) that the system can perform its function assuming a single failure, limited operator action outside of the control room would be considered acceptable if suitab
,ju s ti fied.
(4) The system (s) shall be capable of bringing the reactor to a cold shutdown condition, with only offsite or onsite power available, within a reasonable period of time following shutdown, assuming the most limiting single failure.
(B) RHR System Isolation Requirements The RHR system shall satisfy the isolation requirements listed below.
(1) The following shall be provided in the suction side of the RHR system to isolate it from the RCS.
(a)
Isolation shall be provided by at least two power-operated valves in series. The valve positions shall be indic::ed in the control room.
(b) The valves shall have independent diverse interlocks to prevent the valves from being opened unless the RCS pressure is below the RHR system design pressure.
Failure of a power supply shall not cause any valve to change position.
(c) The valves shall have independent diverse interlocks to protect against one or both valves being open during an RCS increase above the design pressure of the RHR system.
(2) One of the following shall be provided on the discharge side of the RHR system to isolate it from the RCS:
(a)' The valves, position indicators, and interlocks described in item 1(a) - (c),
(b) One or more check valves in series with a normally closed power-operated valve. The power-operated valve position shall be indicated in the control roem.
If the RHR system dis-charge line is used for an ECCS function, the l
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a_
m-
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c.
212-9 (5.4.7) power-operated valve is to be opened upon receipt of a safety injection signal once s
4' the reactor coolant pressure has decreased below the ECCS design pressure.
(c) Three check valves in series, or
'(d) Two check valves in series, provided.that there are design provisions to permit periodic testing of the check valves for leak tightness and the testing is performed at least annually.
(C) Pressure Relief Reouirements The RHR system shall satisfy the pressure relief require-ments' listed below.
i (1) To protect the RHR system against accidental over-pressurization when it is in operation (not isolated from the RCS), pressure relief in the RHR system shall be provided with relieving capacity in accordance with the ASME Boiler and Pressure Vessel Code. The most limiting pressure transient during the plant operating condition when the RHR system is not isolated from the RCS shall be con-sidered when selecting the pressure relieving
. For example, during capacity of the RHR system.
shutdown cooling in a PWR with no steam bubble in the pressurizer, inadvertent operation of an additional charging pump or inadvertent opening of an ECCS accumulator valve should be considered in selection of the' design bases.
(2) Fluid discharged through the RHR system pressure relief valves must be collected and contained such that a stuck open relief valve will not:
(a) Result in flooding of any safety-related equipment.
(b) Reduce the capability of the ECCS below that needed to mitigate the consequences of a postulated 1.0CA.
(c) Result in a non-isolatable situation in which the water provided to the RCS to maintain the 1
core in a safe condition is discharged outsie of tne containment.
~
1 212-10 (5.4.7)
(3)
If interlocks are provided to automatically close the isolation valves when the RCS pressure exceeds the RHR system design pressure, adequate relief capacity shall be provided during the time period while the valves are closing.
(D) Pumo Protection Reouirements The design and operating procedures of any RHR system shall have provisions to prevent damage to the RHR system pumps due to overheating, cavitation or loss of adequate pump suction fluid.
(E) Test Reouirements The isolation valve operability and interlock circuits must be designed so as to permit on line testing when operating in the RHR mode. Testability shall meet the requirements of IEEE Standard 338 and Regulatory Guide 1.22.
The preoperational and initial startup test program shall be in conformance with Regulatory Guide 1.68.
The programs for PWRs shall include tests with sup-porting analysis to (a) confirm that adequate mixing of borated water added prior to or during cooldown can be achieved under natural circulation conditions and pemit estimation of the times required to achieve such mixing, and (b) confirm that the cooldown under natural circulation conditions can be achieved within the limits specified in the emergency operating pro-i cedures. Comparison with performance of previously tested plants of similar design may be substituted for these tests.
(F) Operational procedures The operational procedures for bringing the plant from j
normal operating power to cold shutdown shall be in conformance with Regulatory Guide 1.33.
For pressurized water reactors, the operational procedures shall include specific procedures and information required for cooldown under natural circulation conditions, (G) Auxiliary Feedwater Supply The seismic Category I water supply for the auxiliary feedwater system for a PWR shall have sufficient inventory to permit operation at hot shutdown for at l
l
,c 212-11 i
(5.4.7) least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, followed by cooldown to the conditions permitting operation of the RHR system. The inventory needed for cooldown shall be based on the longest cool-down time needed with either only onsite or only off-
. site power available with an assumed single failure.
,l 212.33 Describe the consequences of loss of component cooling (5.4.7) water flow to the RHR and RCS pumps. Justify the time period that the pumps could operate without CCW. What signals, indicators, and alarms are provided to alert the operator to a loss of component cooling to the pumps?
212.34 Pressure relief valves in RHR discharge lines are sized (5.4.7) to relieve " maximum possible back leakage through valves separating the RHRS from the RCS."
What flow rate is considered to be " maximum possible back leakage" and what is its basis?
Discuss whether the system overpressure protection is sized to include relief requirements due to thermal expansion as well as the relief requirements to account for charging pump operation.
Discuss the potential for exceeding the allowable cooldewn 2123f.2)
(5.4.
rate of the RHR and the reactor coolant system during the shutdown cooling mode of operation assuming loss of the nonsafety-grade instrument air system which controls the RHR heat exchanger outlet and bypass valves.
Failure of the RHR heat exchanger bypass valves in the closed position would cause loss of bypass flow with the possibility of exceeding the allowable cooldown rate. The resulting stresses on the piping systems must be assessed.
212.36 Section 5.4.7 of the FSAR discusses the RHR miniflow bypass (5.4.7) lines which allow bypass flow when the RHR pump discharge flow is less than 500 gpm. Discuss what testing will be performed to validate that the miniflow lines provide an adequate pump flow path such that damage to these pumps would be precluded during this mode of operation.
212.37 Discuss the overpressure protection provided for the piping (5.4.7) between RHR valves 1-8701B and 1-8702B. Provide a similar (5.2.2) discussion for valves 1-8701A and 1-8702A. Discuss the overpressure protection provided for the piping between isolation valves which may be shut.
212-12 212.32 Deleted (5.4.7) 212.38 Section 5.4.7.1 of the FSAR discusses two single failures (5.4.7) for which operator actions are necessary to ensure continued performance of the RHR system.
For the operator actions required, provide the following information:
(1) The specific operator actions required.
(2) The instructions provided to the operator.
(3) The alarms which would alert the operator to initiate a particular action.
(4) The delay time assumed _from the time the operator _
becomes alerteif to the condition until the action is assumed to Ee taEen.
(5) Justification that sufficient core cooling is provided until the corrective action is completed.
(6) Justification that no damage is incurred to the RHR system or its components until the corrective action i
is completed.
(7) A discussion of the consequences of the operator's failure to take the appropriate action.
(8) A discussion of the consequences of the operator taking a closely related, but incorrect action as opposed to the action for which credit is being assumed.
212.39 Certain operator actions (both short term and long term) are (6.3) required for the various modes of operation of the ECCS to mitigate the consequences of certain events (i.e., steam line break, small LOCA, large LOCA).
For each of these modes of operation, provide the following additional information:
(1) List any operator actions required.
(2) Discuss alarms / indications available to the operator that would lead him to take the appropriate action.
1
=-
..w 212-13 (6.3)
(3) Discuss the time-interval assumed in the FSAR analhses between the time the operator is alarted to a condition by these alams/ indications and the time that he is assumed to perform the action.
212.40 Provide a discussion on excessive boron concentration in the
)
(6.3) reactor vessel and hot leg recirculation flushing related to long-term cooling following a LOCA. During hot leg injection, what will be the minimum. expected flow rate in the hot leg, and what is the required flow rate to match boil-off?
The. staff position concerning boron dilution is as follows:
(1) The boron dilution function shall not be vulnerable to a
-single active or. limited passive failure (i.e., leakages ofseals). A single active failure postulated during the long-term cooling period can be assumed to occur in lieu of a single active" failure during the short-term cooling l
period.
(2) The inadvertent operation of any motor-operated valve (open or closed) shall not compromise the boron dilution function nor shall it jeopardize the ability to remove decay heat from the primary system.
(3) All components of the system which are within containment shall be designed to Seismic Category I requirements and classified Quality Group B.
-(4) The primary mode for maintaining acceptable levels of boron in the vessel should be established.
Should a single failure disable the primary mode, certain manual actions outside the control.rocm may be allowed, depending on the nature of the action and the time available to establish the backup mode.
(5) The average boric acid concentration in any region of the reactor vessel should not exceed the level of 4 weight percent below the solubility limits at the temperature of the solution..
(6)
During the post-LOCA long-term cooling, the ECC system normally operates in two modes:
the initial cold leg injection mode, followed by the dilution mode.
The actual operating time in the cold leg injection mode will depend on plant design and steam binding considerations, but, in general, the switchover to the dilution mode should be made between 12 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after LOCA.
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(7) The minimum ECCS flow rate delivered to the vessel during the dilution mode shall be sufficient to accommodate the boil-off due to fission product decay heat and possible liquid entrainment in the steam discharged to the contain-ment and still provide sufficient liquid flow through the core to prevent further increases in boric acid concentration.
(8) All dilution modes shall maintain testability comparable to other ECCS modes of. operation (HPI-short term, LPI-short tenn), etc. ). The current criteria for levels of ECCS testability shall be used as guidelines (1 e., Regulatory 1
Guides 1.68,.1.79, GDC 37).
Discuss your conformance to this position.
212.41 For some plant designs, an early manual reset of the safety (6.3) injection signal followed by a loss of offsite power during the injection phase requires operator action in order to reposition ECCS valves and to restart some pumps. Discuss whether the reset of all or a portion of the ECCS during the injection phase would necessitate operator action to restart equipment.
l 212.42 Table 6.3-5 presents a single failure analysis for ECCS, It (6.3) is not clear, however, which limiting single failures were assumed -for ECCS performance evaluations.
For each event that requires ECCS operation, state the most limiting single failure assumed in the' system performance evaluations.
212.43 Table 6.3-1. lists the required NPSH for the centrifugal-(6.3) charging pumps as 28 ft. The available NPSH is listed as
>28 ft.
Provide the minimum available NPSH for the centrifugal charging pumps. Justify the most limiting ECCS condition for determining the available NPSH of all ECCS pumps.
21'2.44 During the changeover from the. injection mode to the recircu-(6.3) lation mode of operation, the FSAR states that the RHR pumps would continue to operate. Confirm that the preoperational test program will test this automatic changeover from the injection mode to the recirculation mode of operation and that this feature will be tested with the RHR pumps running
.in an ECCS injection mode. Discuss the acceptance criteria for the above test.
212.45 So that we may evaluate the dependence of the ECCS equipment (6.3) on the plant auxiliaries, provide, or reference in the FSAR the following:
-. ~. -
212-15 (6.3)
(1) A list of all of the primary auxiliary systems required to directly support each ECCS component.
(2) A brief description of the supporting function performed by the primary auxiliary.
(3) The method of initiating the primary auxiliary to provide support to the ECCS.
(4) The additional secondary auxiliaries required to directly support the primary auxiliary specified in (1).
(5) A brief description of this supporting function performed by the secondary auxiliary.
(6) The method of initiating this secondary auxiliary.
Also, discuss the potential for damage to ECCS equipment as a result of an auxiliary system transient such as over-pressurization or overheating.
212.46 Provide details of the procedures and methods to keep the (6.3)
ECCS lines filled to prevent water hanmer and possible damage to pipes and components when ECCS is activated.
212.47 A recently reported event has raised a question related to (6.3) the conservatism of NPSH calculations and whether the absolute minimum available NPSH has been considered.
In the past the required NPSH has been taken by the staff as a fixed number supplied through the applicant by either the i
architect engineer or the pump manufacturer. Since a number of methods exist and the method used can affect the suitability or unsuitability of a particular pump, it is requested that Comanche Peak provide the basis on which the required NPSH was determined (i.e., testing,, Hydraulic _..
Institute' Standards) for all the ECCS pumps and on the estimated NPSH variability between similar pumps including test. inacepr.acies.
212.48 Section 6.3.2.2.2 of the FSAR discusses redundant baron (6.3) injection tank heaters and line tracing to prevent boron precipitation. State whether these heaters and line tracings are' susceptible to a single failure which would defeat i
operation of the system. Also, operating experience has i
shown instances where the high head safety injection pump performance was degraded due to solidification of boric acid crystals. The potential also exists for valve movement to be hindered by the crystallization of boric acid crystals on valve j;tems. Discus.s any_ addjtional_ provisions taken to
~
prevent boric acid crystallization from degrading safety infection system perfo6nanEe7 -]
212-16 212.49 The notes to Figure 6.3-2 in the FSAR indicate that the (6.3)_
pressure at the suctions of the safety injection pumps and charging pumps is 10 psia for the ECCS injection mode of operation. Table.6.3-1 indicates that the minimum required NPSH for the charging pumps is 28 ft. and for the safety' injection pumps is 25 ft. Discuss this apparent discrepancy between the available and required NPSH for these pumps.
212. 50 The single active failure analysis for ECCS components is (6.3) provided in Table 6.3-5.
Modify the table to include the following additional failures:
(1) Spurious movement of a powered component.
(2) Operator error.
t (3) Leakage resulting from passive failures and (4) Failure of components connected to the ECCS, but not necessarily a part of the ECCS, such as air-operated valve 1-HCV-128.
Include or reference the information identified or provide the rationale for its exclusion. The FMEA for the ECCS should identify the components by number and a single schematic diagram that shows the entire ECCS should oe provided.
1 212.51 Section 6.3.1 of the FSAR discusses that certain ECCS valves (6.3) will have power locked out to prevent spurious operation.
For these valves, provide the following information:
(1) List the valves and describe their functions.
)
(2) Describe the administrative procedures that ensure the power lockout or removal of power lockout for these valves.
(3) Assess the potential for, and consequences of, a LOCA during the time these valves are locked out.
212.52 Check valves in the discharge side of the high head safety (6.3) injection, low head safety injection, RHR, charging, and boron (5.4.7) injection systems perfonn an isolation function in that they protect low pressure systems from full reactor pressure. The staff will require that these check valves be classified ASME IWV-2000 category AC, with,the leak testing for this class of
~
valve being performed to code specifications.
It should be noted that a testing program which simply draws a suction on -
the low pressure side of the outermost check valves will not be acceptable.
This only verifies that one of the series check valves is fulfilling an isolation function. The necessary frequency will be that specified in the ASME. Code, except in, cases where only one or two check valves separate high to low pressure systems.
In these cases, leak testing will be performed at each refueling after the valves have been exercised.
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212-17
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(6.3)
Identify all check' valves which should be classified category AC (5.4.7) as per the position discussed above. Verify that you will meet the required leak testing schedule, and that you have the nec-essary test lines to leak test each valve, Provide the' leak detection criteria that will' be in the Technical Specifications.
212 53 A minimum flow byp, ass line is_.provided on each safety injection (6.3).
(SI) pump discharge to recirculate flow to the refueling water storage tank (RWST) in the event the pumps are started with the normal injection floif~ paths ~ unavailable.
Normal injection paths could be unavailable for the _s.ituation of inadvertent actuation of safety injection while the RCS is at normal-operating pressure or in the event of a small LOCA during the period when RCS pressu're remains above the shutoff head of the pumps.
The minimum flow bypass l'ine for each pump contains a single motor-operated valve.
Downstream of these motor-operated valves the minimum flow bypass lines join and are connected to a single line which terminates in the RWST.
In this single line is a single motor-operated valve If valve 8813; should close while SI pumps are running (88131, he normal with t injection flow paths unavailable, both SI pumps could be damaged as a. result.
Demonstrate that no pump damage will occur as a consequence of the closure of. this valve or modify the design of the minimum flow bypass lines. Any proposed design must ensure that (1) no single failure can result in the loss or degradation of both SI j
pumps and (2)' no" single failure results in not being able to isolate the RWST during the recirculation phase following the postulated LOCA.
212 54 Discuss the design provisions for prevention of vortex (6.3) formation in the containment sump post-LOCA.
212. 55 It is the staff position that position indication for any (6.3) valve (including local manually operated valves) that could degrade the performance of the ECCS should be available in the control room. Identify all the ECCS valves that have position indication in the control room at n confinn that Comanche Peak meets the above. position.
J 212. 56 Section 6.3.2.2.9.1 of the FSAR discusses motor-operated (6.3) valves with a " hammer blow" feature to provide more positive J
opening or closing force. Discuss what qualification testing has been conducted to test this valve feature.
Specifically, discuss the number of valve cycles for which i
this valve operating feature has.been qualified. Also discuss what increased surveillance procedures have been incorporated j
in the plant technical specifications to verify continued integrity'of.the valves and operators, v_-.
s.
212-18 212 57 Section 6.3.2.5.1 of the FSAR discusses that provisions are (6.3) made for maintenance of ECCS components outside containment during recovery from a LOCA. Describe these procedures more fully including:
(1) Components which are repairable and the allowable repairs.
(2) Consideration given to radiation backgrounds involved in working on the affected equipment.
In addition, describe any periodic maintenance that is required by the ECCS during long-term cooling following a LOCA.
212.58 Section 5.4.7.1 of the FSAR states that the only motor-(5.4.7) operated valves in the RHRS which are subject to flooding (6.3) are the suction isolation valves. Section 6.3.2.5.5 of the FSAR states that all ECCS valve motors are above the local maximum post-accident water level. Evaluate the potential for post-LOCA submergence of valve motors whose spurious operation could degrade ECCS performance. The spurious operation of any such valve subjected to flooding should be included in the ECCS performance evaluation unless specific provisions are incorporated to prevent the spurious operation of the subject valves.
212.59 Because of freezing weather conditions, blocking of the vent (6.3) line on the RWST has occurred on at least one operating plant.
Describe design basis and features that preclude this condition from occurring in the Comanche Peak plant.
212. 60 Recent plant experience has identified a potential problem L5.47) regarding the long-tenn reliability of some pumos used for Le.31 long-term core cooling following a LOCA.
For all pumps that are required to operate to provide long-term core l
cooling, provide justification that the pumps are capable of operating for the required period of time. This justifi-cation could be based on previous testing or on previous operational experience of identical pumps. Differences between expected post-LOCA conditions and the conditions during previous testing or operational experience cited should be justified (e.g., water temperature, debris, waterchemistry).
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r 212-19 212.61 Closing of valves 1-8806,15I-048, or 1SI-047 may interrupt (6.3) flow from the RWST to the ECCS system resulting in damage to the ECCS pumps and interruption of adequate core cooling.
Discuss what design provisions ensure that control and positioning of these valves complies with RSB Branch Technical Position 6-1.
Specifically, Branch Technical Position 6-1 requires power lockout to valves whose single active failure could result in damage to pumps such that minimum flow requirements for long-tenn core and containment cooling after a LOCA are not satisfied. Also, the valves and piping that connect the RWST and the containment sump to the safety injection pumps must be arranged so as not to preclude auto-matic switchover from the injection mode of ECCS operation to recirculation cooling from the sump. These piping systems must be arranged so that the differential pressure between the sump and the RWST, even if there is a single active failure, will not result in a loss of core cooling or a path that permits release of radioactive material from the containment to the environment.
Also, discuss the valve position indication for these valves.
212. 62 Testing of the ECCS should include a demonstration of the (6.3) capabilities to realign valves and injection pumps to (14.0 )
recirculate coolant from the containment floor or sump.
The specific concerns of the staff are the possibility of inadequate NPSH, air bindage, or vortex formation at the sump screens, any of which could adversely affect ECCS performance.
Accordingly, we require that a recirculation test be performed at the Comanche Peak plant. Provide a statement regarding your intent to conform to our position on this matter and how the test objective will be satisfied.
212 63 Deleted (6.3) 212. 64 Certain automatic safety injection signals are blocked to (G,3 ).
preclude unwanted actuation of these systems during normal shutdown and startup operations. Describe the alarms available to alert the operator to a failure in the primary or secondary system during this phase of operation and the time frame avatlable to mitigate the consequences of such an accident.
Justify the time frame available,
212-20 212. 6S Provide justification that the valve discharge rates and (15.0) response times (such as opening and closing times for main feedwater, auxiliary feedwater, turbine and main steam isolation valves and steaa gelerator and pres 3urizer relief and safety valves) have :een onservatively modeled in the Chapter 15.0 analyses. This justification may cite previously approved references or preoperational and startup tests to be conducted at Comanche Peak.
212. 66 For each Chapter 15 accident event, provide the most limiting (15.0) single failure assumed in the FSAR analyses.
212.67 For Chapter 15 accident events, provide the_ number of fuel (15.0) rods calculated to be in DNB.
212.68 To complement the Chapter 15 event evaluations, provide a (15.0) summary of the systems functional analysis for_ systems assumed to operate for each Chapter 15 event. The summary should be shown in the form of simple block diagrams beginndng with the event, branching out to the various protection sequences for each safety action required to mitigate the consequences of the event (e.g., core cooling, containment isolation, pressure relief, scram, etc.), and ending with the identification of the specific safety actions being provided. The lines connecting the events should be labeled with the time delays assumed between events.
It is our understanding that certain functional diagrams provided in the RESAR 35 Safety Analysis Report may be applicable to Comanche Peak. The RESAR 35 functional diagrams may be referenced providing that the information cited above is included and provided that any deviations in the diagrams between RESAR 35 and Comanche Peak are identified.
212 49 For each Chapter 15 event, provide a table showing any (15.0) operator action for which credit is taken in the short term or the long term. The table should include any operator actions assumed until the plant has reached a j
final stabilized cordition. For instance, operator actions j
to prevent overpressurization of the reactor vessel in the i
long term following a feedwater line break or steam line break accident should be considered. For each of the operator actions, provide the following information:
]
(1) List the alarms which would alert the operator to initiate a particular action. Discuss the safety-grade classification of the alarms.
-.. - - - - ~. -..
i 212-21 (15.0)
(2) State the delay time assumed from the time the operator is alerted to a condition un'il credit for the action is assumed. Provide justification for this assumed delay time.
(3) Describe the instructions given to the operator for performing the required action.
(4) Describe the safety-grade classification of the components and instrumentation necessary to complete the indicated actions.
(5) Discuss the impact of a single active component failure on these actions.
(6) Discuss the impact of the operator's failure to take the indicated action and the impact of the operator taking a closely related, but erroneous action.
212. 70 Provide a confirmation, with bases, that all transient events (15.0) would not exceed the acceptance criteria for abnormal operational occurrences when credit is not taken for non-safety-grade systems (turbine trip, turbine bypass, pilot-operated relief valves, etc.).
212. 71 A change in the Westinghouse fuel rod internal pressure design (15.0) criteria has' been approved. Th'ilchance
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will permit the internal fuel rod pressure to exceed system pressure.
For some accident events, this will result in an increase in the number of rods normally expected to fail as a result of these events. This is due to the probability of a rod simultaneously being in DNB and exceeding system pressure. Subsequent ballconing and touching the adjacent rods follows, thereby causing more rods to go into DNB and fail. Therefore, for the Chapter 15 analyses of accident events, confirm if this change in the fuel rod internal pressure design criteria has been factored into the number of rods predicted to fail.
212 72 )
The main steam ifne break analysis took credit for the steam (15.1.5 generator flow restrictors to limit steam flow.
It is the staff position that these restrictors either be seismic Category I, if credit is to be allowed for the restrictor, or an analysis be provided not taking credit for these restrictors or for MSIV's damaged due to a dislodged restrictor for a break in a nonseismic portion of the steam line.
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212-22 212. 73 A decreasing condenser vacuum may result in a higher main (15.2.5) steam line pressure and, therefore, higher steam generator 1
temperature and pressure. Discuss why a decrease in condenser vacuum causing a turbine trip is not a more j
limiting event than a turbine trip from nominal conditions.
212. 74 Provide justification for the frequency decay rates assumed 1
(15.3) in.the decreasing flow event and the loss of nonemergency AC power event in the Comanche Peak FSAR. This justification should address the expected frequency decay rate for the Comanche Peak power grid as opposed to a general analysis of frequency decay rate.
212.75 For the feedwater system pipe break event with offsite (15.2.8) power available, provide the time at which the operator is assumed to secure the reactor coolant pumps.
212.76 For the reactor coolant pump locked rotor and shaft break (15.2.8) events and for the feedwater line break event, does the analysis assume water relief from the pressurizer safety valves? If so, provide justification for the water relief rate assumed in the analysis and state if the basis for the hydraulic loads used to analyze the mechanical design of the valve, discharging piping, and their supports include water relief loads.
212.77 Section 15.3.2.1 of the FSAR states that the reactor trip (15.3.2) on reactor coolant pump undervoltage is blocked below 10%
power. Discuss what reactor trip provides protection on a decrease in reactor coolant flow below 10% power. Discuss what analyses have been conducted to verify the adequacy of this trip.
212,78 Recently, an operating PWR experienced a boron dilution incident (15.4.6) due to the inadvertent injection of the NaOH tank into the reactor coolant system while the reactor was in the ctld shut-down condition.
This event occurred due to a single failure--
misposition of the isolation valve of the NaOH tank while the decay heat removal syst em was lined up for reactor ccolant recirculation.
Discuss the potential for a baron dilution incident caused by dilu M on sources other than the CVCS.
212 79 For decrease in baron concentration events, the FSAR states (15.4.6) that the reactor could become critical in 7.5 minutes if at cold shutdown, and the reactor could become critical in 17.6 minutes if in hot standby.
It is our position that no operator action can be assumed for 15 minutes from the time that the operator becomes aware that a boron dilution 4,
s.
t 212-23 1
(15.4.6) event is in' progress.
It is also of concern that during startup or shutdown, the resetting of nuclear instrumentation alarm set points may result in a delay before the operator becomes aware that a boron dilution event is in progress.
For decrease in boron concentration events, provide evaluations of the most limiting decrease in boron con-centration events. These evaluations should include the i
following information:
(1) Evaluations at cold shutdown, hot standby, and full power operations and during startup and shutdown.
(2) Alarms that alert the operator that the event is in progress should be listed. The safety-grade classification of the alarms should be discussed.
(3) No operator action should be assumed for 15 minutes from the time that the alarm alerts the operator to the event until operator action is initiated.
(4) Describe the instructions given to the operator for performing the required action, i
(5) The analyses should take into account the effect of increasing boron worth with dilution.
212.80 For the inadvertent opening of a pressurizer safety or relief l
(15.6.1) valve event, the FSAR analysis indicates no functioning of any system to restore system pressure or pressurizer level.
The analysis should be. carried out to the..poin.t.that_it.can _
be demonstrated that core cooling is. maintained.
212.
Table 15.6-1 states that for a 3" LOCA, the top of the core (15.6.5) is uncovered in 647 seconds. The time until top of the core is covered is listed as "NA".
Please explain.
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t 212-24 212 < 81 The FSAR references a generic study in precluding consideration (3.5.1.2) of the reactor coolant pump flywheel as a potential missile source. Discuss the potential missile sources from a failure of the reactor coolant pump impeller or other rotating part during normal operation.
212 82 Describe the consequences of the loss of CVCS water flow
(.5. 4.1 )
to the reactnr coolant pumps. State the time period that the (9.3.4)
RCS pumps could operate without CVCS. What signals, indicators, and alarms are provided to alert the operator to a loss of CVCS to the reactor coolant pumps?
It is our understanding that when the reactor coolant pumps are started at lower primary system pressure, the operator bypasses a portion of the CVCS flow to the first reactor coolant pump seal in order to ensure sufficient cooling flow for the reactor coolant pump bearings. Discuss the length of time that the reactor coolant pump can be operated in this condition without damaging the seal. Also, describe the effects on the second and third seals of the reactor coolant pump as e result of operating with this seal flow bypassed.
212 83 Table 9.3-3 provides a failure modes and effects analysis (9.3.1) for air-operated safety-related valves. This analysis l
discusses the effect of failure of individual valves.
Section 9.3.1 of the FSAR states that due to tne availa-bility of air accumulators for certain valves, the plant could be placed in a safe condition following loss of instrument air. Discuss a loss of instrument air more fully including instructions given to the operator to place the plant in a safe condition. Also, discuss the alarms and indications the operator would use while placing the plant in a safe condition following a loss of instrument air.
212. 84 In your discussions on the available equipment systems,
(.7. 4.1. 3 )
controls, and instrumentation required to bring the reactor to a cold shutdown from locations outside the control room (GDC 19), you note the following in subsection 7.4.1.3:
" Procedures for attaining the cold shutdown condition can be prepared in accordance with the existing conditions while the unit is maintained in a safe hot shutdown condition via the hot shutdown panel." Provide the procedures to bring the reactor to a cold shutdown outside the control room.
Identify any didferences that may exist in shutdown procedures from normal operations, particularly in the areas of system alignment or operation that would be required to achieve and maintain safe shutdown. Specify the location of each of the operator actions and discuss the alanns/ indications that are available to the operator at that location to monitor the indicated action.
COMANCHE PEAK 1 and 2 - REACTOR FUELS SECTION 231.1 The fuel performance code (PAD 3.3) used for the Comanche Peak (4.2.1.2) safety analysis will soon be approved by the NRC with some modifications.
The applicant should review the modifications to the code and determine their effects upon the safety analysis as presented.
231.2 Predicted cladding collapse times for Comanche Peak 1 and 2 (6.2.1.3) have been calculated with the model as given in WCAP-8377.
NRC approved the use of this model (SER of January 14,1975) subject to provisions that no alterations were made to the specified curves used as input to the model.
Provide assurance that these provisions have been satisfied.
i 231.3 The fuel rod internal pressure criterion as given in the FSAR (4.2.1.3) incorporates the acceptable modifications as approved by us (SER for WCAP-8963 of May 8, 1978). We further stated in the SER that "an approved fuel performance code must be used to show that the fuel-to-cladding gap does not open." Due to the modifications to the code imposed at high burnups as discussed in 231.1 above, the applicant should determine the effects of these modifications on satisfying the rod pressure criterion.
231.4 In addition to the previously discussed seismic and hydraulic (4. 2.1. 4 )
loads on fuel assemblies, Westinghouse has determined that an asymmetric horizontal load will be imposed on the reactor core
. in the event of a rupture in the primary system piping.
Provide the results of an analysis which shows that the Comanche Peak assemblies can withstand this phenomenon.
Similar analyses have been submitted on the North Anna, Sequoyah, Farley and Diablo Canyon dockets, and these can be referenced for information.
231.5 The full length absorber rods for Comanche Peak may incorporate (4.2.1.6) a new Westinghouse design feature. The technical bases and evaluation of this new rod design are given in a topical report, WCAP-8846, " Hybrid B C Absorber Control Rod Evaluation Report."
4 NRC has reviewed the noted topical report and found the rod design acceptable but noted that irradiated 8 C is leachable or 4
soluble in water. We thus require a routine surveillance program to assure that the reactivity in the absorber rods is not being lost through an unanticipated breach in the cladding.
Comanche Peak should submit plans for such a surveillance program, if B C 4
is to be used.
231.6 A new requirement for routine fuel surveillance has been established (4.2.1.7) and is discussed in Revision 1 of Section 4.2 of the Standard Review Plan.
Please refer to that document and submit a descrip-tion of the on-line fuel rod failure detection methods and a description of the post-irradiation fuel surveillance program for Comanche Peak Units 1 and 2.
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Design methods in this report have been approved by us.
Final acceptance of the report for fretting wear considerations is awaiting post-irradiation results obtained on Trojan fuel.
Please provide a schedule for the reporting of these data.
231.8 For fuel rod bowing calculations, Comanche Peak uses the model (4.2.3.1) given in WCAP-8_691. NRC issued an interim safety evaluation on this subject in February 16, 1977 and require certain modifications be made for calculating bow in Westinghouse fuel.
Provide assurance that these modifications have been factored into the Comanche Peak 17xl7 calculations.
231.9 Successful load follow operation is discussed at Reactor A and B.
(4.2.3.3)
Provide some details of the load follow tests, specifically, maximum power, delta power and maximum assembly burnup.
231.10 In view of recent reactor operational experience (A10 -B C burn-23 4 (4.2.3.5) able poison in St. Lucie 1, CEN-38(F), Revision 1), the stability of irradiated B C in water appears to be less than that expected 4
from the previous referenced studies. Therefore, the corrosion rates given in the Comanche Peak FSAR would seem to be non-conservative.
Provide. justification for the stated corrosion rates by additional suitable references or recent experimental data.
231.11 Recent PWR experierce has shown that fretting wear has occurred (4.2.3.5) between control rods and thimble tubes at a location associated with the fully withdrawn " parked" rod position.
Provide assurance, either through fuel assembly inspection results (See 231.6 above) or prototypical hydraulic flow tests, that this is not a concern in Comanche Peak.
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.n FIRST ROUND QUESTIONS FOR COMANCHE PEAK - REACTOR PHYSICS SECTION N
232.1 Has the uncertainty in the calculation of F been reduced to AH (4.3.2.2) four percent in the final design of Comanche Peak?
232.2 Expand the discussion of the reasons for the smaller Doppler (4.3.2.3) coefficient as a function of power at EOL as compared to BOL.
232.3 Comment on the division of the MTC into density and tempera-(4.3.2.3) ture effects as a function of core lifetime.
Recent calcu-lations (to be published) by BNL suggest that the spectral (temperature) component is positive and a significant portion of the total MTC for cores with large (s 10 GWd/t) burnups.
Comment on the effect of the use of density only moderator coefficients in the affected transients in Chapter 15, particularly for reload cycles (Ref. letter, Eicheldinger to Ross, dated February 28,1978, NS-CE-1706).
232.4 Is the coolant temperature control action passive in that the coolant temperature automatically responds to power changes j
or is deliberate action undertaken? For example, in a rapid power rise performed as part of a load following procedure, is there an anticipatory increase in moderator temperature in preparation for the power rise?
l 232.5 Is the burnable poison rod pattern shown in this figure consistent (Fig.
4.3.5) with the power distributions and reactivity coefficients given for the Comanche Peak c' ore?
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. 232.6 Describe the manner in which the more limiting of the two (4.3.2.5) control rod designs has been used in safety analysis.
For example, describe the manner in which the scram curve is obtained and the reactivity insertion rates for rod with-drawal transients.
232.7 Provide an estimate of the uncertainty in the calculation (4.3.2.8) of the flux at the inner boundary of the pressure vessel.
l In what manner is the azimuthal peaking factor obtained?
232.8 What value of moderator reactivity coefficient is used in (15.4.1.2) the analysis of the startup accident? Is the value a com-bination of spectral and density coefficients or only a density coefficient?
-232.9 In what way is the overtemperature aT setpoint reduced for (15.4.2.2)
This transient?
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- s 312-1 312.0 SECTION 8, ACCIDENT ANALYSIS BRANCH 312. 14 Page 312-2, Amendment 2 indicates that the present status of a (2.1.2) portion of the mineral rights within the exclusion area is deemed to be of such little potential safety consequences that it may be considered de minimis.
In order for us to reach a conclusion, the following information is requested:
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1.~ 'An ~ analysis of a potential" gas well-head leak and ' delayed
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cloud ignition on plant critical structures and systems
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(assuming that the well is drilled at the closest point of uncontrolled mineral rights as is shown on the map which was enclosed.with your letter of July 24,1978).
Indicate the peak overpressure on the critical structures and. components.
Compare these overpressures with the design pressures of the structures.
Include the generation of potential missiles in your analysis. Please state all your assumptions 2.
An analysis of a gas well leak producing a cloud of gas at the air intakes for the emergency diesel driven generators on their operation.
3.
Authority to control the potential transport and use of any explosive materials within the exclusion area for use in well fracturing operations in gas bearing rock formations or for extinguishing a gas fire at a well-head.
4.
An analysis of the detonation (of the naximum quanity of explosives that could be used within the exclusion area) on the Commanche Peak Safety related structures and com-ponents.
5.
Indicate how you will be made aware of mineral extraction activities and the presence and location of non-plant related personnel within the exclusion area.
6.
Provide an analysis of the dose consequences to personnel engaging in mineral extraction operations within the exclusion area, in the event of a postulated design basis accident.
312.15 The formation of combustible gas mixtures from organic materiale (6.1.2) and protective coating systems inside the containment is an important consideration in the evaluation of a LOCA. Estimate the total amount of hydrogen and methane gases that can be generated under DBA conditions from radiolytic and chemical de-composition of the organic materials and protective coating systems that are directly exposed to the containment atmosphere.
Provide the basis for this estimate.
312-2 312.16 Evaluate the total amount of solid debris that can be generated (6.1.2) under DBA conditions from chemical and radiolytic decomposition of organic and coating materials.
312.17 State if heat tracing is provided for the chemical (MaOH) addi-(6.5.2) tive tank and associated piping.
If not, justify the lack of i
heat tracing.
312.18 Fof the steamline break accideht, what is 'the basi. for~the 5%
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e-(15.1.5) fuel failure used for offsite, doses? Justify any / ailed fuel fraction used for offsite dase calculations.
312.19 For the steam generator tu'Je rupture accident with resultant loss (15.6) of offsite power, provide f4gures to describe the post-accident profiles of pressure and temperature (both coolant systems). Also, estimate the duration of steam venting from the affected SG, justifying the times o' commencement and termination.
312.20 In Table 15.6-9, it 'is not obvious how the three volumes (sprayed, (15.6) unsprayed but affected by spray, and unsprayed and isolated) you assumed relate to the four regions (A, B, C and D) depicted in Section 6.5.2.
Identify the specific regions making up the two unsprayed volumes.
312.21 It is noted on page 15.6-39 of the Commanche Peak FSAR that a (15.6.5) containment. purge isolation valve closure time of 44.46. seconds is proposed.
It is our position that,.in.the event of a LOCA where the containment purge isolation valves cantbe.shown to-have a closure tim-3 of 10 seconds or less, the radiological source term during this pariod.is that for the primary coolant activity alone at its tech. spec, limit (with a pre-existing iodine spike).
However, for periods greater than 10 seconds the staff believes it appropriate to use the source term of Reg. Guide 1.4.
Accord-i ingly, either reduce the containment purge valve isolation time to 10 seconds or less, or provide an analysis which shows the radiological consequences of purging the containment with a primary coolant source term for 0-10 seconds and a core inventory source term for 10 seconds to 44.46 seconds.
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Effluent Treatment Systems Branch 320.8 Your response to Question 320.7 on the solidification process control program and the parameters to be considered for the solidification of waste is not adequate.
Provide more detail concerning the process control program including the following:
a.
Data concerning the expected waste types to be processed. The process control program should be based on tests performed with simulated waste' formulations based on the expected inputs. You should discuss how the process control program considers the chemical constituents of the waste stream, the pH of the waste stream, boric acid content, solids content of the waste, concen-tration and type of radwaste, curing time, etc.
b.
Data concerning the solidification agents (UF + catalyst) to waste ratios to be used. The process control program should consider the correct ratios for the various input types and contaminant levels.
Data concerning the effects of various contaminants on the c.
solidification process. Specifically, address oil and deter-gent content in wastes, lab chemicals, and non-depleted ion-exchange resins, d.
Discuss the experimental procedures to be used in your process control program.
Discuss sampling of the waste. input to the SRS as it relates to your process control program to assure a satisfactory solidified product. Where will the waste be sampled? Discuss how the results of the process control pro-gram will be analyzed and used as operational considerations.
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331-1 331.0 RADIOLOGICAL ASSESStiENT BRANCH 331.5 Your response to item 331.1 does not clearly identify the (12.1.2) individual responsible for the independent radiation pro-tection review of design changes, nor how that individual is placed in the Texas Utilities Services, Inc./ Texas Utilities Generating Company organization, relative to the Describe individual responsible for.the overall design..
how this radiation protection review is to be independent from the overall design process.
331.6 Your response to item 331.3 is not acceptable. While use (12.4.3) may be made of published average data on experience at operating plants in evaluating likely doses, the dose assessment addressed in 12.4 should be plant-specific.
Describe the calculational model or engineering judgments from which your estimate of 421 man-rems is derived, taking into account actual projected dose rates at Comanche Peak, design improvements specific to Comanche Peak, and actual expected staffing levels and man-hour requirements for the various operations at Comanche Peak. An acceptable dose assessment is described in Regulatory Guide 3.19.
j 331.7 Your response to item 331.4 is incomplete. Descrioe the traffic flow, for male and female workers, from access points through the plant and the change areas, for duty assignments in high-zoned areas, and return. Describe how these facilities will be used to control the spread.of radioactive materials to uncontaminated areas by such workers.
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l GEOLOGY-SEIShDLOGY i
361.16 Structural cross-sections (Figures 2.5.1-30 and 2.5.1-31) depict the (2.5.1.2)
Big Saline and older units as essentially flat-lying. The overlying Strawn formation, however, is shown dipping rather steeply (roughly 100 ft/mi) to the east (Figure 2.5.1-23a).
Discuss.
361.17 As requested in NRC question 361.4, provide copies of the telephone (2.5.1.2)
I conversations with A. Winslow and J. Montgomery, both of the U. S.
Geological Survey) regarding the non-subsidence potential of the Cretaceous sandstone in the site vicinity.
361.18 The Stravn formation is apparently 400 ft. thicker in the Mid-Continent (2.5.1.2) Petroleum Corp. No. 1 Squaw Creek Co. well than at the Gulf 011 Corp.
1 No. 1, D. McIntosh well (Figure 2.5.1-30).
Explain why a fault could not be more likely placed between these wells rather than between the two
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wells indicated on Figure 2.5.1-30.
361.19 On cross-section A-A' (Figure 2.5.1-30), a f ault with approximately
( 2. 5.1. 2) 100 feet of displacement is interpreted between wells Gulf 011 Corp.,
No.1, C. L. Campbell and Gulf 011 Corp., No.1 D. McIntosh. Discuss the rationale and basis for the necessity of placing a fault at this location.
361.20 Provide a discussion and figures as appropriate addressing why a fault (2.5.1.2) could not be interpreted between wells 4 and 4a (see Figure 2.5.1-24, Marble Falls-Structure Map.)
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4 Insuf ficient positive evidence has been provided to enable the NRC 361.21 (2.5.1.1) exist with-staff to conclude that subsurface faulting does or does not If faulting were to exist within this radius in 5 miles of the site.
its non-capability can be shown by providing evidence demonstrating the continuity of a well-defined marker horizon such as the Paluxy Sand-Provide appropriate discussion and illustra-Glen Rose Limestone contact.
tions demonstrating the continuity of this Cretaceous contact within the area depicted on Figure 2.5.1-10, Vicinity Geologic Map.
361.22 Although the probability may be low, the NRC staff, based on presently (2.5.1.2) preclude hydracarbon producti:n within the plant avail ble data, can not Posi ion As depicted on the mineral right ownership r,ap provided exclusion area.
to the NRC by Texas Utilities Services, Inc. correspondence of July 24,
~ 1978 hydrocarbon production may be possible within 500 feet of a seismic category I structure (containment).
361,.23 provide the basis for the statement (FSAR p. 2.5-32) that the hydrocarbon (2.5.1.2) production within 5 miles of the site is believed to be from stratigraphic traps, not structural traps.
The requested 361.24 The response to NRC question 361.14 is not acceptable.
(2.5.1.2) information is to be provided on a bi-monthly basis through the safety Please indicate hearing (currently not scheduled before January,1980),
your intention to comply with this request.
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GCrrEQflICAL ENGINEERING Q362.1O Provide Tables 2.5.4-6, through 2.5.4-9, summaries of geophysical (Sec. 2. 5.4.4)'
test data, referred to in Section 2.5.4.4.
Correlate these tables with text pages 2.5-115-through 2.5-119.
Also, provide the correct references to test locations for gamma ray and resistivity tests (last paragraph, page 2.5-114).
l Q362.11 Provide sunmaries of field test data which show that the CP com-(Sec. 2.5.4.5) paction and gradation criteria have been met for backfill against the Service Water Intake Structure, and around Category I pipe-lines and conduits.
Q362.12 The SER stated that the applicant had made a commitment to remove (Sec. 2.5.4.5) any claystone exposed in Category I pipeline excavations if the invertlevel is less than 15 feet below final grade. Provide a summary of locations where undercutting vns required during construction.
Include depths of undercutting and corresponding invert levela.
Q362.13 The statement in Section 2.5.4.8 that ".
. no liquef action susceptible j
(Sec. 2.5.4.8) soils (are) present." may be misleading. Provide in this section, or cross reference to other sections, discussions of liquefaction potential affecting the SSI embankment and Category I pipelines and conduits. We agree that no liquefaction potential exists under a
pipes and conduits supported on only one foot of bedding over bed-rock, so address your response to areas (if any) where this condition does not exist.
In particular consider:
fa)' backfilled areas near the Service Water Intake structure I
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. i b) backfill over trenches.if each backfill impacts on the safety of any Category I structures c) areas where claystone was undercut and replaced by class I backfill, as discussed in Q362.12 above.
Also consider the limitation that Glen Rose limestone can be-utilized as backfill material to a depth of up to about 33 feet (page 2.5'- 124d).
In your response, incorporate the results of field tests requested in Q362.11, above.
Q362.14 Provide the equations for stress-strain relationship (page 2.5-128)
(Sec. 2.5.4.10) and for lateral pressures (page 2.5-128a).
Q362.15 Indicate what documents are available to verify that grouting (Sec. 2.5.4.12) operations were, in fact, "perforced at the appropriate time," and in accordance with the specifications. Provide a brief summary of any such documentation.
Q362.16 On page 2.5-148a, paragraph 4, line 2, the reference to Figure (Sec. 2.5.6.4.3.6) 2.7.4.5.3-1 should be to rigure 2.5.6-12.
On this figure show the average D sizes.
50 Q362.17 Describe how Figure 2.5.6-20 was developed and explain the interpre-(Sec. 2.5.6.4.4) tation of this figure.
Q362.18 On page 2.5-169 show the correct ref erence for R'eference (65).
(Sec. 2.5.6.6.2) a l
Q362.19 Identify the date and title of the report referenced on page 2.5-188.
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(Sec. 2.5.6.9.2)
Q362.20 On Figure 2.5A-3, or.elsewhere, show a summary of actual gradations (Sec. Appendix 2.5A) obtained from construction records for Filter A, Filter B a'6d rock-fill materials.
Compare these results with.the design gradations required, to. confirm that design criteria (Figure 2.5.6-12) have
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been met.
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Q362.21 Provide a description of the drainage system referred to in (Sec. 3.8.5.1.5)
Section 3.8.5.1.5.
Include typical cross sections and filter details to illustrate your description.
Q362.22 In the FSAR we note the following errors. Please make appropriate Corrections.
.i FAGE p;?.AS?.APH ONE CCTAECTION 2.5-123 1
4 Section 2.5.2-13 beccmes Section 2.5.4.13 2.5-124 2
4 Figure 2.5.5-5 becomes Fig. 2,5.5-77 2.5-124 3
11 Figure 1.2.6-48 becomes Fig. 2.5.6-48 2.5-131 3
1 2 ft centours bec:ces~10 ft contours 2.5-175 3
4 Sheet No.
- 2. 5-168 beceres Det ail A, Figure 2.5.6-53 rig. 2.5.1-22 wet unit we:;ht : -c i r '{ c-u : :c:ns = 135 ;cf Also, correct errors in calculations k'e also not e the folicwing errors i
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' Figure 2.5.4-31..Rockfill becoces backfii 2.5-119 3
3
--shown as --becemes--shown on ----
2.5-122 3
2 claystene (Sp) 2.5-123 1
4 Sec. 2.5.2-13 becomes Sec. 2.5.4-13 3
2.5-124d 2
7 App. 2.5.4 becomes Appendix 2.5A-4 2.5-125 2
8 capacity (Sp) 2.5-132 3
2 3.7.2.12 becomes 3.7B.2.13 2.5-133 last Fig. 2.5. 4-27 becomes Fig. 2.5.4-28 2.5-137 2
3
~~ drilling (Sp) 2.5-144 1
2 2.3.6.4.1 beccmes 2.5.6.4.1 1
2.5-148a 1ast
- becemes D5 i
shear (Sp)0 = 0.2 mm.
2.5-164 3
2 2.5-165 3
5 becomes --shell i tself is subj ected ----
2.5-171 6
5
' Figure - 2. 5. 6-50 (2) becoces Fig. 2.5.6-SD(2) 2.5-172 7
2 elevation (Sp) 2.5-182 4
6 becomes ---trench in the closure ---
Fig. 2.5.4-14
. Note becomes ----Figures 2.5.4-15 through 2.5.4-21 Fig. 2.5A-17
' Legend becomes Dr = 80%. See Fig. 2.5A-16
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METEOROLOGY 372.21 Provide the attractive area of each building and building dimensions (2.3.1) used in the development of Table 2.3-2A, " Seasonal and Annual Estimates of Lightning Strikes.to Safety-Related. Structures."
372.22 The selection of gust factors to be applied to extreme wind velocities (2.3.1).should be based on "the type of exposure and dynamic response I
characteristics of the structure, or parts and portions thereof" (ANSI A58.1-1972, " Building Code Requirements For Minimum Design Loads.In Buildings And Other Structures"). In ASCE Paper No. 6038, "New Distributions of Extreme Winds In The United States" (July 1968),
Thom states that "an often used gust factor at 30 ft elevation is 1.3."
Justify the use of a gust factor of 1.1 as stated on page 2.3-12 of the t
FSAR.
372.23, The response to Question 372.06 referred to Table 9.4-1, " Design (2.3.1) j Conditions-Outdoors," and Table 9.4-2, " Design Conditions-Indoors."
l Provide the bases for selection of the temperatures and wind speed 1
identified in Table 9.4-1, and discuss the frequency ar.d duration of these parameters. considered in plant design. Also discuss the outdoor environmental conditions assumed in. establishing the indooF design conditions identified in Table 9.4-2.
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d l Real-time data from the onsite meteorological measurements program will 372.24 (2.3.1) be used to provide assessments of dose consequences at and beyond the site boundary following accidental and routine releases of radioactivity to the atmosphere. The meteorological tower is located on a penninsula into Squaw Creek Reservoir with a maximum fetch over-water of about 4.5 miles with winds from the northwest, and long fetches over-water with winds from the northeast and east-northwast. Wind speed and vertical temperature gradient measurements at the present tower location during airflow with long over-water fetches could reflect modified conditions that are not representative of conditions away from the reservoir. Use of these modified conditions may result in i
non-conservative estimates of effluent concentration. Discuss the representativeness of meteorological data (particularly wind speed and vertical temperature gradient) from the present tower location for use in evaluating atmospheric transport and dispersion conditions away from the reservoir, particularly towards the southeast, southwest, and west-southwest.
372. 25 The response to Question 372.09 states that " natural fog (baseline)
(2.3.2) cccurrences were determined from 3-hourly meteorological observations taken at the Dallas National Weather Service (NWS) station." Occurrences of fog, particularly radiation fog and steam fog,can be extremely localized and the location of the Dallas NWS station may not be representative of the Comanche Peak site in this respect. Discuss the representativeness
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372. 26 The response to Question 372.1n stat 2s that " instantaneous values of each (2.3.3) meteorological parameter are recorded once each minute," and that "if the total number of minute observations during the hour for any parameter is less than 15, then that parameter is considered to be invalid for that hour." The use of a 15 minute averaging time to represent hourly average conditions probably was based on an analysis of 15-minute continuous samples of data rather than 15 instantaneous readings.
Becausa parameters such as wind speed and direction can vary rapidly in time, it is not clear that the use of 15 instantaneous readings will provide the same average as that based on a 15-minute continuous record or 15 1-minute averages. Provide comparisons between the analog strip charts recording wind speed and direction continuously and the digital system recording instantaneous values once each minute to support the use of 15 instantaneous readings to represent hourly average conditions.
372 27 The response to Question 372.12 indicated that " minor adjustments were (2.3.3) made (if necessary) on an approximately weekly basis" to keep the meteorological measurements program within calibration. Discuss this
" fine-tuning" in more detail, identifying the nature of the " minor adjust-ments," the qualifications of the person (s) who performed the adjustments, and the frequency of the adjustments. In other data collection programs, unauthorized " fine-tuning" by unqualified personnel has resulted in the collection of erroneous data.
I 372. 28 The response to Q372.13 indicated that the overall system accuracies (2.3.3) for measurements of wind speed and temperature difference do not meet the recommended system accuracies specified in Regulatory Guide 1.23.
The recommended system accuracy for measurement of wind speed is
_0.5 mph, and the recommended system accuracy for temperature difference
+
is _+0.1*C (not _+0.5aC as indicated in the response). Explain in more detail how the system accuracies were determined, and justify deviations from the recommendations of Regulatory Guide 1.23, particularly for parameters such as wind speed and temperature difference which are very important in the assessment of atmospheric dispersion conditions.
372.29 Vertical temperature gradient measurements between the 10m and 30m levels (2.3.3) are substituted directly for missing measurements of vertical temperature gradient measurements between the 10m and 60m levels. However, temperature generally varies logarithmically with height, and the gradient through a small height interval such as 20 meters will be different than the gradient through a larger height interval such as 50 meters. Indicate the fraction of vertical temperature gradient measurements for the four year period in the FSAR based on measurements between the 10m and 30m levels, and discuss the rationale for direct substitution of temperature gradient measurements. Comparisons of measurements when both temperature gradient systems were in operation should be used to support the applicability of direct substitutions.
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. 372 30 Identify the levels of measurement for. meteorological parameters (2.3.3) j' (wind speed, wind direction, and delta temperature) to be displayed i.
in the control room, and discuss the use of a " wind direction meter" considering the rapid variability of wind direction with time. Also indicate if the parameters displayed on " Weather Measure card frame assembly" will be hourly averaged values.
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422.0 Conduct of Operations 422.3-Describe the number of professional persons in each (13.1.1.2) group-(Nuclear Engineers, Mechanical Engineers, Civil Engineers. Electrical Engineers, I&C Engineers, and Assistant Engineers) reporting to the Project Engineer shown.in Figure 13.1-3. '
422.4 Describe if the groups (or individuals) have functional (13.1.1.2 )
responsibilities for other than the. Comanche Peak r
projects.
If so, describe the proportion of time assigned to the other activities.
422.5 Descnibe the functions, responsibilities, and authority (13.1.2.2) of the Maintenance Engineer and his staff that report to the Maintenance Superintendent, as shown in Figure 13.1-4.
i 422.6 You state in part 2 of Subsection 13.3B that site (13.38) responsibility for assuring implementation of the fire protection program is assigned to the Fire Protection Program Coordinator by the General Superintendent. Revise Figure 13.1-4 to show this position.
422.7 (RSP)
In regard to your responsibilities for the fire (13.3B) protection program, it is the staff's position that an offsite management position.have the responsibility for assessing the effectiveness of the fire protection program.
422.8 Describe your qualification requirements for the (13.1.3.1 )
position of Quality Assurance Supervisor (Note:
Section 4.4.5 of ANSI /ANS 3.1-1978; and provide the resume of the person filling this position.)
422.9(RSP)
The minimum qualification requirements for the
- (13.1.3.1 )
positions of Results Engineer, Chemistry and Health Physics Engineer, Mechanical Maintenance j
Supervisor, and Electrical Maintenance Supervisor are not satisfactory. Our position in regard i
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to acceptable qualification requirements for these positions is as follows:
1.
Results Engineer - The minimum requirements for this position shall include 6 years of power plant experience of which 2 years should be nuclear power plant experience.
2..
Chemistry and Health Physics Engineer - The minimum requirements, for this position should meet that described in Revision 1 to Regulatory Guide 1.8 for the position of Radiation Protection Manager, i.e., should have a bachelor's degree or the equivalent in a science or engineering subject, including some formal training in radiation protection and at least five years of professional experience in applied radiation protection.
(A master's degree may be considered equivalent to one year of professional experience, and a doctor's degree may be considered equivalent to two years of professional experience where course work related to radiation protection is involved.) At least three years of this professional experience should be in applied radiation protection work in a nuclear facility dealing with radiological problems similar to those encountered in nuclear power stations, preferably in an actual nuclear power station.
3.
Mechanical Maintenance Supervisor and Electrical Maintenance Supervisor - Should have a minimum of 4 years of experience in the craft or discipline they supervise without allowance for technical or academic training.
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Mechanics and Electricians-Should have a minimum of 3 years experience in their specialty.
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REQUEST FOR ADDITIONAL INFORMATION COMANCHE PEAK STEAM ELECTRIC STATION 421.0 Quality Assurance 421.1 The response in Section C (pages 9.5.235 through 9.5.240) of your June 15, 1978 submittal does not indicate whether the QA program for fire protection is under the management control af the QA organization. This control consists of (1) formulating and/or veriffing that the fire protection QA program incorporates suitable requirements and is acceptable to the management responsible for fire protection and (2) verifying the effectiveness of the QA program for fire protection through review, surveillance, and audits. Performance of other QA program functions for meeting the fire protection program requirements may be performed by personnel outside of the QA organization. The QA program for fire protection should be part of the overall plant QA program. These QA criteria apply to those items within the scope of the fire protection program, such as fire protection systems, emergency lighting, communication and emergency breathing apparatus as well as the fire protection requirements of applicable safety-related equipment.
We find that your response does not describe sufficient detail to address the ten specific quality assurance criteria in Branch Technical Position APCSB 9.5-1.
In order for the QAB to fully evaluate your plan to meet these criteria, additional detailed description is necessary. Examples of the detail we would expect Texas Utilities Generating Company / Texas Utilities Service, Inc. (TUGC0/TUSI) to consider are provided in Attachment 6 to Mr. D. B. Vassallo's letter of August 29, 1977.
If, however, you choose not to provide this detail, you may apply the same controls to each criterion that are comensurate with the controls described in your QA program description, Section 17.2.
These controls would apply to the remaining construction activities and for the operations phase of Unit Nos.1 and 2.
If you select this method, a statement to this effect would be adequate for our review of the QA program for fire protection.
L 421.2 Describe TUSI's specific responsibilities in executing (17.2.1) the QA program, and describe the responsibility and i
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421.3 Identify on Organizational Charts (Figures 17.2-1 (17.2.1 )
and 17.2-2) the "onsite" and "offsite" organizational elements of TUGC0 and TUSI which function under the control of the QA program.
t 421.4 Identify the management level responsible for the final (17.2.1 )
review and approval of the TUGC0 and Comanche Peak Steam Electric Station (CPSES) QA program and manual (s) including changes thereto, and describe the involvement of the QA Division and QA Supervisor in the review and concurrence of these documents.
i 4 21.5 Describe the involvement of the QA Manager in the (17.2.1) review and concurrence of CPSES operations, admin-istrative control, and QA plan.
421.6 Describe the amount of nuclear quality assurance (17.2.1) experience required for the position of Quality Assurance Manager. This description should be at least equal to the one year experience as listed in paragraph 4.4.5 of ANSI /ANS-3.1-1978,
" Selection and Training of Nuclear Power Plant Personnel. "
421.7 Describe the quality assurance and quality control (17.2.1 )
related experience qualifications required of the QA Supervisor.
421.8 Describe measures which assure that persor.nel i
(17. 2.1 )
(including those outside the QA/QC organization) l performing QA/QC functions have sufficient authority and organizational freedom to:
a)
Identify quality problems, b)
Initiate, recommend, or provide solutions-through designated channels, and c) Verify implementation of solutions.
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QA individuals have the responsibility and authority,
- delineated in writing, to stop unsatisfactory work and control further processing, delivery, or installation of nonconforming material.
421.10 Clarify the responsibility of the QA Supervisor (17.2.1) to communicate and interface with the QA Manager, and describe those conditions for determining when these actions should take place.
421.11 Identify the organizational position responsible (17.2.1 )
for inspection functions, including responsibilities for selection and qualification of 1nspection personnel, review and concurrence of inspection procedures, and assurance of proper independence from work being inspec.ted. Describe the involvement of the QA divisibn and QA Supervisor in this area.
421.12 Describe provisions which assure that menagement (17.2.2)
(i.e., above or outside the OA-organizatie) annually assesses the scope, status, implementation, and a
effectiveness of the QA program to assure tha'.
the program is adequate and complies with 10 CF9 Part 50, Appendix B criteria.
421.13 Provide a brief summary of the Policy Statement of (17.2.2) the CPSES Operations Administrative Control and Quality Assurance ~ Plan.
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l 421.14 Describe those provisions-established to control (17.2.2) the distribution of the QA manuals and revisions
- thereto, l
421.15 Describe provisions which assure that the QA (17.2.2) program for operations will be implemented at least ninety days prior to fuel loading.
421.16 Clarify whether TUGC0/TUSI reviews and documents (17.2.2) agreement with the QA program provisions of CPSES 1
suppliers to assure the provisions of Appendix B to 10 CFR 50 will be implemented.
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u 421.17 Table 17A-1 of the FSAR addresses those structures, (17.2.2) systems, and components covered by the operational QA program. We note that there are certain items not identified which we believe should be under the control of the QA program. Therefore, consideration should be given to identify and include the following items under the control of the QA program:
.s 1.
Reactor Pressure Vessel Internals (e.g.,
Fuel assemblies, control element assemblies, flow skirt, etc.)*
1 2.
All Reactor Coolant System Valves and Supports; 3.
Re, actor Internals Lifting Device; and 4.
Turbine Overspeed Protection System.
Also, please correct the apparent typo on page 17.2-10 referencing Section 17.3 which should be Table 17A-1, 421.18 Identify the organizational position with the authority (17.2.2) and responsibility to approve changes to the plant Q-List and describe those provisions for controlling the distribution of the plant Q-List, including signature approval and revision numbers and/or dates. Describe the involvement of QA and/or QC personnel in this area.
421.19 Table 17.2-2 does not provide a complete list of quality-(17.2.2) related Regulatory Guides. Also, some Regulatory Guides 1
identified have the wrong effectivity date. Accordingly, update the table to assure it is consistent with the
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following, and to preclude any'~misinterpra.tation.recardino the comitment statement, th' following wording is recomended:
"CPSES will comit to comply with the regulatory positions in the following Regulatory Guides and ANSI standard (identify by no. and rev. no. and/
ordate)-
1.8-Rev. 1-R; 1.28 (6/7/72); 1.30 (8/11/735;1.33-Rev.1;1.37(3/16/73);1,38 (3/16/73); 1.39-Rev. 2; 1.58 (8/73); 1.64-Rev. 2; 1.74 (2/74); 1.88-Rev. 2; T 94-Rev.1; 1.116-
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Any alternatives or exceptions should be identified with sufficient supporting detail to allow review and NRC acceptance.
421.20 Describe how CPSES will use the Regulatory Guides (17.2.2) and ANSI N45.2.12 listed in Table 17.2-2 to assure that the requirements contained in these documents will-be properly implemented.
e 421.21' Describe provisions which assure that appropriate (17.2.2)
Appendix B requirements will be applied to the preoperational test program.
i 421.22 Describe in more detail the authority and responsibility (17.2.2) of the QA Manager in regard to development of the TUGC0 QA program and procedures.
4 21.23 Describe those provisions for notifying NRC of:
(a)
(17.2.2) programmatic changes (except for those that are editorial in nature) to the QA these changes and (b) program prior to implementation of organizational changes within 30 days after announcement.
421.24 Clarify whether the design controls described in 17.2.3 (17.2.3)-
will also apply to new design activities, if such should occur during the operation phase.
421.25 Clarify whether the documented re, view and approval of (17.2.4) procurement documents are accomplished prior to release.
421.3 Describe provisions which assure that changes and revisions (17.2.4) to procurement documents are subject to at least the same review and approval pro'c~e~s's a~s~the original document.
421.27 Describe provisions which assure that procurement documents (17.2.4) for spare or replacement parts of safety-related structures, systems, and components are subject to controls at least equivalent to those used for the original. equipment.
421.2.
Describe those provisions for assuring that the.QA organi-(17.2.5) zation is made aware of quality-related procedures, including changes, and that they properly become ~ familiar with these documents such that they can effectively carry out their responsibilities.
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421.'29-Describe provisions whereby the evaluation of suppliers
- (17.2.7) includes the supplier's capability to comply with the elements of 10 CFR Part 50, Appendix B that are applicable to the type of material, equipment, or service being procured.
421.30 Describe provisions which assure that when surveillance-(17.2.7) of suppliers is performed, procedures provide for:
a.
Instructions that specify the characteristics or processes to be wit'nessed, inspected or verified, and accepted; the method of surveillance and the extent of documentation required; and those responsible for implemen-ting these instructions.
b.
Surveillance on those items where verification or. procurement requirements cannot be determined upon receipt.
421.31 Describe provisions which assure that the results cf (17.2.7) supplier evaluations are documented and filed.
421.32 Describe provisions which assure that the supplier (17.2.7) furnishes the following records as a minimum to the purchaser:
a.
Do 'Jmentation that identifies the purchased material or equipment and the specific procurement requirements (e.g., codes, standards, and specifications) met by the items.
b.
Documentation that identifies any procurement require-ments which have not been met together with a description of those nonconformances dispositioned " accept as is '
or " repair."
l 421.33 Describe provisions which assure that' spare or replacement (17.2.7) parts of safety-related structures, systems, and components are subject to controls at least equivalent to those used for the original equipment.
421.34 )
Clarify whether there will be recorded evidence of verifica-(17.2.9 tion in the performance of special processes.
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421.35 Describe the criteria for determining when inspection (17.2.10) hold points are required, including their insertion in procurement documents and plant inspection proceduros.
421.36 Describe the criteria for determining the accuracy (17.2.10) requirements of measuring and test equipment used for inspections and tests.
421.37 Describe provisions which assure that inspection (17.2.10) procedures or instructions \\are used with necessary drawings and specifications when performing inspection operations.
421.38 Clarify whether provisions are established that identify (17.2.10) mandatory inspection hold points for witness by an inspector during all aspects of the operations phase (i.e., maintenance, in-service inspection, etc.).
2 421.39 Describe provisions which assure that bypassing of (17.2.14) required inspections, tests, and other critical operations is procedurally controlled under the cognizance of the QA organization.
421.40 Clarify whether significant conditions adverse to quality, (17.2.16) the cause of the conditions, and the corrective action taken are reported to cognizant levels of both "offsite" or "onsite" management, including QA for review and assessment.
421.41 Describe provisions which assure that audits include an (17.2.18) objective evaluation of work areas, activities, and processes; and a review of documents and records, quality-related practices, procedures, and instructions for effective implementation.
421.42 Describe provisions which assure that audits are perfonned (17.2.18) by CPSES's principal contractors to verify and evaluate their suppliers' QA programs, procedures, and activities.
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INITIAL TEST PROGRAM 423.7 The minimum qualification *equirements for System (14.2.2)
Test Engineers and members of the Joint Test Group
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(or personnel designated by them to review test procedures and results) do not appear to be commensurate with the importance of the tasks they perform.
It is the staff's position that the follow-ing categories of personnel hold the listed minimum qualification requirements.:
Minimum qualifications of System Test Engineers or other individuals that direct or supervise the conduct of individual Preoperational Tests (it the time of assignment to the task).
1.
A Bachelor's Degree in engineering or the physical sciences or the equivalent and one year of applicable power plant experience.
Included in the one year of experience should be at least three months of indoctrina-tion / training in nuclear power plant systems and component operation of a nuclear power plant that is substantially similar in design to the type at which the individual will perform the function or, 2.
A high school diploma or the equivalent and four years of power plant experience. Credit for up to two years of this four year experience may be given for 'related technical training on a one-J for-one time basis.
Included in the four years of experience should be at least three months j
of indoctrination / training in nuclear power plant systems and component operation of a nuclear power plant that is substantially similar in design to the type at which the individual will be employed.
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(At the time t'
of assignment to the task).
1.
A bachelor's degree in engineering or the physical sciences or the equivalent and two years of applicable power plant experience of which at least.one year shall be applicable nuclear power plant experience or, 2.
A high school dipicma or the equivalent and five years of applicable power plant experience of which at least two years shall be applicable nuclear power plant experience. Credit for up to two years of non~ nuclear experience may be given for related technical training on a one-for-one time basis.
Minimum qualifications of Joint Test Group members or other individuals responsible for review and approval of Preoperational and Startup Test Procedures and/or review and approval of test results.
(At the time the activity is being performed).
1.
Eight years of applicable power plant experience with a minimum of two years of applicable nuclear power plant experience. A maximum of four years of the non-nuclear experience may be fulfilled by satisfactory completion of academic training at the college level.
423.8 Our review of the initial test program description (14.2) in the FSAR disclosed that the operability of some of the systems and components listed in Regulatory Guide 1.68, (11-73) Appendix A will not be demonstrated by preoperational or startup tests.
Section 14.2.7 does not list anyexceptions. to this guide. Expand i
your FSAR to include appropriate test descriptions for the following items from Appendix A of the guide or provide justification for any exceptions:
Preoperational 'Tes ts A.4.a Steam and Feedwater Process Lines A.4.d Turbine Control and Bypass Valves 6a.. h e-w%l-
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- A.4.e Feedwater Control A.4.f Fondenser Circulating Water System A.S.o Shield Cooling System (specifically, contain-ment penetration coolers)
A.5.p Leak Detection System (or methods, for ECCS, CCWS, RHRS, CSS,SSWS)
A.6.e Emergency Power Systems A.11 Reactor Components Handling System (containment polarcrane)
Precritical Tests - After Fuel Loading B.l.d Reactor Coolant System Leak Test B.l.f Calibration and Neutron Response Check of Source Range Monitors B.l.g Mechanical and Electrical Tests of Incore 4
Flux Monitors and Incore Thermocouple Tests Power-Ascension Tests D.1.a Natural Circulation Tests D.l. i Trip of Generator Main Breaker D.1.m Demonstration of Ability to Control Xenon Transient D.l.a Evaluation of flux assymmetry with single rod assembly fully inserted and partially inserted below the control bank (It 50%
)
power) and evaluation of its effect on DNS 423.9 Identify any of the initial'startup tests described (14.2) in Table 14.2-3 which are not essential towards the demonstration of conformance with design requirements for structures, systems, components, and design features that:
(a) will be relied upon for safe shutdown and cooldown of the reactor under nonnal plant conditions and for maintainirg the reactor in a safe condition for an extended shutdown period; or (b) will be relied upon for safe shutdown and cooldown of the reactor under transient (infrequent or moderately frequent events) conditions and postulated accident conditions, and for maintaining the reactor in a safe condition for an extended shutdown period following such conditions; or
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.. (c) will be relied upon for establishing conformance with safety limits or limiting conditions for operation that will be included in the facility technical specifications; or (d) are classified as engineered safety features or will be relied upon to support or assure the operations of engineered safety features within design limits; or (e) are assumed to function or for which credit is taken in the accident analysis for the facility (as described in the Final Safety Analysis Report);
or A
(f) will be utilized to process, store, control, or limit the release of radioactive materials 423.10 Your response to item 423.2 states that portions of (14.2) two preoperational tests will be performed during the 1
startup test phase of the initial test program (after fuel loading). However, Figure 14.2-3 shows that i
five preoperational tests will be completed after fuel i
load. For the four tests that are not addressed in 423.2, (1) state what portions of each test will be delayed until after fuel loading, (2) provide technical justification for delaying these portions, and (3) state when each test will be completed (key to operating modes defined in technical specifications or to power ascension test power levels defined in Chapter 14). Also, modify Figure 14.2-3 to show that the preoperational test of the Reactor Control System will be completed after fuel load (as stated in response to item 423.2).
423.11 Many of the test acceptance criteria given in the test (14.2) summaries of Tables 14.2-2 and 14.2-3 are not sufficiently detailed for the staff to conclude that adequate tests will be conducted. Expand the test summaries to provide acceptance criteria that show that the objectives of each test are satisfied. The acceptance criteria should be summary in nature but related to the parameters or functions of interest for each test.
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Therefore, clarify or expand the description of the ~
preoperational test phase to address the following:
1.
Station Service Water System Test - State your plans to demonstrate proper operation of the strainers.
2.
Component Cooling Water System Test - State your plans to demonstrate the system's capability to supply adequate cooling water flows to the "non-safety-related" loop loads.
3.
Vents and Drains System Test - State your plans to include testing which demonstrates the oper-ability of all vents and drains which can affect l
the capability of any equipment important to safety, even though those vents or drains may not handle potentially radioactive substances.
4.
Fire Protection System Test - State your plans to verify that installation of features designed to contain fires (e.g., fire stops, fire doors, penetra-tion seals) has been completed as a prerequisite to this test.
5.
Spent Fuel Pool Cooling and Cleanup System Test -
State your plans to verify correct flows entering and leaving the system for all modes of operation-(e.g., flow to purification loop from the refueling water storage tanks).
6.
Residual Heat Removal System Test - Expand the test summary to describe how each mode of system operation will be demonstrated.
7.
CVCS Chemical Control, Purification, and Makeup Subsystem Test - State your plans to demonstrate boric acid batching and transfer capabilities and j
operation in the emergency borate mode.
8.
Safety Injection System Hydraulic Ferformance Test -
Describe the tests that will demonstrate each mode of ECCS operation.
If any mode of operation will not be demonstrated by preoperational testing, provide technical justification for its omission. Also 3
,e describe the testing that will demonstrate proper sequencing and operation of components on automatic switchover from injection to recirculation mode.
9.
Safety Injection Accumulators Test - Modify the test summary to clarify which valves are opened in test method #3.
- 10. Gaseous Waste Processing System Test - State your plans to demonstrate the capability of the hydrogen recombiner.
- 11. Control Room Ventilation System Test; Auxiliary, Fuel, and Safeguards Building Ventilation Test; Combustible Gas Control Systems Test - Revise Section 14.2.7 to state that testing of atmosphere cleanup system, air filtration and adsorption units to be consistent with FSAR Appendix 1A (which refers to Regulatory Guide 1.52, Rev. 1, 7-76). Modify each of the test summaries to show that preoperational testing of each ESF air filtration and adsorption unit will be performed in accordance with the regulatory guide.
- 12. Containment Ventilation System Test - Modify test method #2 of the test summary to clarify the meaning of " energized drive mechanism shrouds."
13.
Diesel Generator Compartment Ventiliation Systems Test - The test method described by the test summary does not describe tests that will satisfy the stated test objective.
Expand the test method to demonstrate the capability of the ventilation systems to provide adequata ventilation for the diesel generator compartments.
- 14. Diesel Generator Test - Expand the test summary to show that your test conforms to regulatory positions 2.a and 2.b of Regulatory Guide 1.108 (Rev.1, 7-77) or provide technical justification for all exceptions to these positions.
- 15. AC Power Distribution System Test - Expand the test '
summary to show that this test will include normal power supply buses as well as ESF buses and vital buses. Also state your plans to perform full load tests using all sources of power supplies to each bus.
16.
DC Power System Test - State your plans to verify that individual cell limits aren't exceeded during the design discharge test and to demonstrate that the DC loads will. function as necessary to assure plant safety at a battery terminal voltage equal
,. to the acceptance criterion that has been established for minimum battery terminal voltage for the discharge load test.
17.
Instrumentation and Control Power Supply System j
Test - State your plans to demonstrate the capability 1
of the inverters to transfer to the alternate power source upon loss of the normal power supply and to verify that the transfer is initiated at the correct setpoint.
18.
Instrument Air System - Modify test method #2 of l
the test summary to describe how you will verify that the receivers are sized to meet the require-ments of the system for the required period of time.
State in the acceptance criteria the basis for the
)
requirement. State your plans to perform loss-of-air tests and to verify that the subsequent action of air operated components is acceptable (particularly control valves). State your plans to verify the proper operation of valves for the design time period using only air from the accumulators, and verify the operability and leak tightness of the accumulator double check valves.
I
- 19. Reactor Protection System Test - State your plans to demonstrate redundancy, coincidence, independence, and safe failure on loss of power (per Regulatory Guide 1.68, App. A, item 3, Nov.1973). Verify that your response time measurements of the RPS include primary sensors and acceptance criteria account for process-to-sensor coupling delays (e.g., instrument lines) for all channels for which response time limits are stated in your technical specifications.
(The delay times of instrument lines may be accounted for analytically).
- 20. Rod Control System Test - State your plans to verify the proper performance of rod blocks.
- 21. Excore Nuclear Instrumentation Test - Clarify test method #1 of the test summary to explain how you simulate neutron flux.
- 22. Steam Generator Safety and Relief Valves Test -
Several of the test methods of the test summary are in fact test objectives-not test methods. Revise the test sumary to include test methods #1, 3, 4, 5 as objectives and provide test methods that will describe how these objectives are satisfied.
7
,, 23. Main Steam and Feedwater Isolation Valves Test -
State your plans to verify that valve closure times meet technical specification requirements for minimum valve closure times as well as maximum.
- 24. Auxiliary Feedwater System Test - State your plans to verify the capability of auxiliary feedwater
}
pumps to use the station service water system as the backup supply (possibly without actual injection f
of service water) and to verify the proper sizing i
of the installed flow limiters.
- 25. Reactor Coolant Pressure Boundary Leakage Detection System - Expand test method #1 of the test summary to describe how you will verify the " operability and performance" of the system.
- 26. Pressurizer Safety and Relief Valves Test -
Expand the test summary to describe how proper actuation and operation of the power-operated relief valves is demonstrated.
Expand your test to include in-plant preoperational testing of the pressurizer safety valves (and modify your test summary as appropriate) or justify not performing in-plant tests.
27.
Containment Isolation System Test - Verify that your test demonstrates that the containment isolation valves close within the technical specification limits.
(Sheet 60A appears to be a duplicate of sheet 59).
- 28. Process Computer - Provide a test summary which describes a test that will verify proper operation I
of the computer, correct input sources, and correct outputs. Particular attention should be directed to computer functions that will be used during normal operation to determine if the plant is operating within technical specification limiting conditions for operation (LC0's).
- 29. Engineered Safety Features - Provide assurance that the manufacturer's head-flow curves for each ESF pump will be verified through preoperational testing.
Provide minimum and maximum bounds for acceptance criteria and the basis for each.
- 30. Cover Gas Systems - State ycur plans to demonstrate proper operation of tank cover gas systems.
(e.g.,
nitrogen blanket on Na0H addition tank, pressurizer relief tank).
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9 423.13 Our review of recent licensee event reports disclosed (14.2) that a significant number of reported events concerned the operability of hydraulic and mechanical snubbers.
Provide a description of the inspections or tests that will be performed following system operation to ~
assure yourself that the snubbers are operable.
These inspections or tests should be performed preoperationally if system operation can be accomplished prior to generation of nuclear heat.
423.14 Provide test descriptions or modify existing test (14.2) descriptions to assure that tests will be performed to demonstrate (1) that the plant's ventilation systems are adequate to maintain all ESF equipment within its design temperature range during normal operations and (2) that the emergency ventilation systems are capable of maintaining all ESF equipment within its design temperature range with the equipment operating in a manner that will produce the maximum heat load in the compartment.
If it is not possible to operate equipment to produce maximum heat loads, describe how the tests cerformed satisfv the objectives listed above.
423.15 Recently, questions have arisen concerning the operability (14.2) and dependability of certain ESF pumps in PWR's.
Upon investigation, the staff found that some completed preoperational test procedures did not describe the test conditions in sufficient detail.
Provide assurance that the preoperational test procedures for ECCS and containment cooling pumps will require recording the status of the pumped fluid (e.g., pressure, temperature, chemistry, amount of debris) and the duration of testing for each pump.
l 423.16 We could not conclude from our review of the startup (14.2) test summaries in Table 14.2-3 that all of the tests will be comprehensive. Therefore, clarify or expand the summaries to address the following:
1.
Reactor Trip System Test - State your plans to demonstrate the' proper operation of interlocks that prevent closing of both reactor trip breaker bypass breakers simultaneously.
2.
Effluent Monitoring Test - State your plans to also demonstrate the proper performance of process and area radiation monitoring equipment under 4
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. operating conditions.
Describe the portions of the test performed at initial fuel loading as shown in Figure 14.2-4.
3.
Control Rod Reactivity Worths Test - State how you will determine which RCCA is most reactive. Clarify the test method to show that the worth of all RCCA banks will be measured.
4.
Loss of Offsite Power Test - State your plans to I
initiate the transient from an initial condition l
of generator output of at least 10 percent power.
The transient should be initiated by opening the generator output breakers in order to simulate a loss of offsite power. This test should demon-strate (for approximately 30 minutes) that the necessary equipment, controls, and indication are available following the station blackout to remove decay heat from the core using only emergency power supplies.
5.
Rod Drop Tests - It appears that you do not intend to conduct this test in accordance with Regulatory Guide 1.63 (llovember,1973) which includes drop time measure-ments of each rod at cold no-flow, hot no-flow, cold full-flow, and hot full-flow. flodify your test summary to show that the test will be conducted in accordance with the regulatory guide or provide technical justifi-cation for any exceptions. Also describe the additional drop tests that will be required for the fastest and slowest dropped rods and state whether these require-ments apply to the fastest and slowest rod at each test condition.
6.
Flux Distribution Measurements Test - Specify the control rod configurations for which flux maps will be obtained.
7.
Core Performance Evaluation Test - Expand the test to include verification of calibration of flux and temperature instrumentation (Regulatory Guide 1.68, tiov.1973, Appendix A, Section D.l.g).
8.
Remote Shutdown Test - Expand the test abstract to show that the test will be performed in accordance with Regulatory Guide 1.68.2, Revision 1, July 1978.
9.
Turbine Trip Test - The acceptance criteria for this test should be modified to 1) identify the parameters or variables to be monitored, 2) provide assurance that the transient results will be compared with
. ~ predicted results for the actual test case, and 3) provide quantitative acceptance criteria and their bases for the required degree of convergence of actual test results with predicted results for the monitored variables and parameters.
423.17 Figure 14.2-3 lists tests for the " Reactor Protection (14.2)
System" and the " Reactor Trip System." However, Table 14.2-2 has a test summary for the R^ actor Protection System only.
Either provide a test summary for the Reactor Trip System or modify Figure 14.2-3 7
to delete it.
423.18 The initial test program should verify the capability 1
(14.2) of the offsite power system to serve as a source of power to the emergency buses. Tests should demonstrate the capability of each starting transformer to supply power (as the alternate supply) to its unit's emergency buses upon loss of the other source of offsite power while carrying its maximum load of plant auxiliaries and the other unit's emergency buses (as preferred supply). Tests should also demonstrate the transfer capabilities of the units' emergency bus feeders upon loss of one source of offsite power. These tests should be performed as early in the test program as the availability of necessary components allows.
Provide descriptions of the tests that will demonstrate these capabilities.
423.19 Provide a description of the electrical lineup for Unit (14.2)
No. 2 during preoperational tests that will be conducted to satisfy regulatory positions in Regulatory Guide 1.41 for Uni t No.1.
Provide a description of the lineup for both plants during similar preoperational testing on Unit No. 2 subsequent to initial criticality of Unit No.
1.
The descriptions should address both normal and emergency power distribution systems. Provide assurance that crossties will not exist which could cause loss of emergency bus power to one unit due to testing of the other unit.
. 423.20 Provide a commitment to include in your test program (14.2) any design features to prevent or mitigate anticipated transients without scram (ATWS) that may be incorporated in your plant design.
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432.0 EMERGENCY PLANNING BRANCH 5
Listed below are requests for additional information in tne area of emergency planning.
Response should be incorporated in page changes to FSAR Appendix 13.3A, the Comanche Peak Emergecny Plan.
The references to Regulatory Guide 1.101, Emergency Plaaning for Nuclear Power Plants, are to Revision 1 dated March 1977.
P 432.1 Fc.r the Station, Site, and General Emergency conditions described (3.0) in your emergency plan, identify emergency action levels (radiological) for each emergency condition for (a) declaring the emergency, and (b) -if different,-fc notifying the appropriate offsite organizations.
432.2 Your classification of a General Emergency is not compatacle with (3.5) that of R.G.1.101, which identifies hypothetical accidents and requires early warning of the public and prompt initiation of protective actions within the low population zone.
Revise your Emergency Plan accordingly (See R.G.1.101, Annex A, Section 4.1.5).
432.3 Provide the information requested in R.G.1.101, Annex A, at (3.0) section 4.2 432.4 Fully describe the bases for the dose curves presented in Figures 2, (3.5) 3, and 4.
(See R.G.1.70, Revision 2, September 1975, Section 13.3 item 1).
(-
. s 432-2 432.5 -
It is not clear from the description of the Emergency Organization (4.2.1) how the assignments are made for both day and night shifts 2.n:
for plant staff members both onsite and away from the site.
Include these planning provisions for each of the functional areas listed 2
in R.G.1.101, Annex A, at Section 5.)f,2.
432.6 Provide a copy of Annex L (the State Radiological Emergency Plan)
(4.5) to the State of Texas Disaster Plan for our review, or provide a summary that addresses the specific interfaces between the Comanche Peak Emergency Plan and Annex L (See R.G.1.101, Annex A, Section 5.4).
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432.7 Provide a copy of the Somerveil/ Hood County Disaster Plan, or (4.5) provide a summary of how this plan interfaces witn :ne Conanche I
Peak Emergency Plan (See R.G.1.101, Annex A, Section 5.a).
^
432.8 The emergency measures identified in section 5 of your plan have l
(5.0) i not been presented as specific emergency measures for each emergency l
class and related to action levels or criteria that specify when the measures are to be implemented.
Please provide this information (See R.G.1.101, Annex A, Section 6).
432.9 Describe the communication steps taken to alert or activate offsite (5.1 )
. emergency organizations under each class of emergency (See R.G.1.101, Annex A, Section 6.1),.
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432.10 Provide a copy of or summarize the contents of the emergency (5.2) procedures for accident assessment for each class of energency.
432.11 Describe the steps taken (1) to provide to visitors to the plant (5.4) or site and (2) to make available on request to occupants in the low population zone, information concerning how the emergency plans provide for notification to them and how they can expect to be advised what to do.
l 432.12 Section 5.4.1 of your Plan states in part that specific descriptive (5.4) and numerical guidance for implementing the evacuation of non-essential personnel, visitors and construction personnel will be developed. Provide this information as rc ;uested in R.G.1.101, Annex A, Section 6.4.1.
432.13 The locations of the Emergency Assembly Area and the Alternate (5.4.1)
Emergency Assembly Area do not appear to be included in the Plan.
Provide this information.
432.14 Provide the basis for your assurance that personnel at Hood General (5.5.4)
Hospital. will be prepared and qualified to handle radiological emergencies and that the hospital facilities will be adequate to handle contamination problems.
432.15-Provide a figure:o* the basement level of the Administration Building (6.1) showing the Enerscray Control Center, i
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l' 432-4 s
432.16 Asirequested' in R.G.1.101, Annex A, at section 7.6, provide a J
(6.0) sunnary description of the onsite damage control equipc. ant cod supplies.
432.17 The description of the training presented in section 7.1 of the (7.1 )
emergency plan and in section 13.2 of the FSAR is insufficient (except for the fire brigade training described in the FSAR in Appendix 13.3B) to judge its adequacy.
In addition, periodic retraining is not addressed.
Provide a description of the training and retraining for each of the categories of emergency personnel listed in R.G.1.101, Annex A at section 8.1.1.
432.18 The emergency plan states that training is available to the local (7.1 )
agencies.
Expand this portion of your plan to include additional details regarding the specialized training and annual retraining provided the two offsite fire departments, to assure tneir familiarity with the station, access procedures, and radiation protection precautions (R.G.1.101, Anner A, section 3.1.1).
432.19 Include a provision for annual drills for the repair and damage (7.2) control teams as stated in R.G.1.101, Annex A, section 8.1.2.
.432.20 The emergency plan does not specifically provide for an annual (7.2) participation by the offsite fire departments in a drill or test exercise. Revise your plan to provide this training.
(R.G. 1.101,.
Annex A, section 8.1.2).
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.o 432-5 432.21 Include provisions to review and update all written agree:.ients (7.2) with offsite emergency organizations at least every twc years.
432.22 Provide assurance that offsite emergency organizations will be I
(7.2) notified of any revisions to the emergency plan or relevant procedures.
432.23 Provide the road network information requested in R.G.1.70, (Appendix F)
Revision 2, 9/75 at section 13 3, item 6a.
432.24 The letters of agreement with the City of Glen Rose and the (Appendix G)
Granbury Volunteer Fire Department of May 1977 state that these organizations will respond to a request for assistance from the l
Comanche Peak Station.
The letters do not provide suff.icient evidence of the arrangements and agreements reached with these offsite organizations, hheagree.lentsshouldberevisedtomore clearly describe the responsibil.ty and authority of each organization when fighting fires at the site (R.G.1.101, Annex A, section5.3.2).
432.25 The Emergency Plan does not address the situation when Unit 1 is operating and Unit 2 is still under construction.
Include in your plan any special precautions to be taken during this period when construction personnel will be working within the Exclusion Area.
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.l OPERATOR LICENSING BRANCH 440.0 441.1 The position of Operations Engineer is not shown on (13.2.1 )
Figure 13.2-1.
ANSI /ANS 3.1-1976, Salection and Training for Nuclear Power Plants,.(%v. of ANSI N18.1-1971) requires the Operations Managi.-c to hold a Senior l
t Reactor Operator's License at the time of initial core loading.
If the Operations Engineer is to fulfill these requirements, indicate his training on Figure 13.2-1.
441.2 The number of persons for whom training is planned in (13.3.1) preparation for senior operator and operator examinations a
4 prior to criticality should be specified. This number should be sufficient to assure that applicable technical specification conditions with respect to the number of-licensed operators on shift crews can be met from the time of initial core loading of the first unit with due 4
allowance given for examination contingencies and the j
need to avoid planned overtime for supervisory personnel I
during the startup phase.
1 I
t 441.3 The program description should delineate clearly the extent (13.2.1. ) to which thG training program has been accomplished.
Indi-cate any significant changes that have occurred or are planned through the end of calendar year 1978.
Also, con-i
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tingency plans for additional training for individuals to i
be licensed prior to criticality should be described in the event. fuel icading is substantially delayed from the projected date.
441.4 Figure 13.2-1 indicates that the Phase III training will (13.2.1.1.1.6) have been completed by the end of 1977.
Cold license examinations and fuel loading are projected for 32 to 34 months following completion of the simulator training portion of the program. We consider it highly desireable that those individuals scheduled to take the cold license i
'l examinations participate in a short simulator course innediately prior to the examinaticns.
Is it TUGCO's in-I tention to provide such a course?
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"t 440.0 OPERATOR LICENSING BRANCH 1
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4 41.5 The use of training aids, such as video tapes, films,
.(13.2.2.1.2) and slides are-acceptable for use in lieu of an in-i structor.
However, no more than 50% of the lecture I
series may be repl' aced by the use of training aids.
i The applicant should comit to this requirement in this
} j; section.
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441.6 If'the requirements of this section are not satisfied L
(13.2.2.1.3.2) through the use'of a simulator the methods used.to
'k demonstrate the licensee's knowledge of plant operating
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procedures and the ability to operate or direct the j
operation in each area for.which they are licensed 1
should be specified. Acceptable methods include:
j 1.
Manipulation of the apparatus and mechanisms.
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A simulated walk through of the procedural steps
.' required to start, stop or change conditions of il "the' apparatus or mechanisms.
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441.7 The requalification program should clearly indicate the (13.2. 2.1.3. 3 )
methods used to assure each licensed individual is cog-
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nizant of facility design changes, procedure changes, and facility license changes. Acceptable methods include:
1.
Brief lectures conducted by shift supervisor.
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- 2.. Staff meetings.
N 3.
Written communications to each licensed individual from facility management.
J 4.
Explanation of major changes should be factored
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into the preplanned lecture series.
441.8 The applicant comits to a review of abnormal and (13.2.2.1.6.5) and emergency operating procedures on a regularly i'
schpduled basis.
We interpret " regularly scheduled 4
i-basis" to be at least annually. This should be in-cluded in this paragraph.
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2 440.0' OPERATOR LICENSING BRANCH' l
The individual.s. credited with successfully completing the
't 441.9 (13.2.2.1.6.5) written examination by means of preparing and administering it will be limited' to no more than three.
This is usually limited to the Training Supervisor and not more than two
,j other members of the plant management staff.
The applicant should commit to this. requirement in this section.
3 441.10 Standard Review Plan 13.2, Rev. 1 contains the requirements l
)i-(13.3B) for Fire Protection training. The CPSES Fire Protection The Program is addressed in Section 13.3B of the FSAR.
f following~ discrepancies between the requirements of SRP 13.2 and the comittments of Section 13.3B should be corrected.
J (2.3) 1.
The Training for the Fire Protection Staff is not specified. The FSAR states that the Fire Protection J
Coordinator is assigned the responsibility of assuring the effective implementation of the Fire Protection
-]
The description of this training should in-Program.
t clude the courses of instruction and number of hours of each course and the organization conducting the Course.
j (3.0) 2.
The instruction for personnel other than those assigned to the Fire-Brigade and the operating personnel is not specified.
This instruction should be 'provided for all u
l-employees once a: year and repeated on an annual basis.
a Instructions for security personnel, temporary employees
[
and construction per.sonnel should also be provided.
3;
.(3'.1.2) 3.
Practice sessions should be provided at regular intervals, J
but not to exceed one year.
(3.1.3) 4.
The frequency of drills should be on a quarterly basis for each fire brigade.
The minimum number of fire l
brigade drills conducted within a period of 3 months f >'shall be equal to the number of operating shifts at the i
station.- Each individual member of the fire brigade i
All
-shall participate in at least two drills per year.
employees should participate in an annual evacuation drill.
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.a 440.0 OPERATOR LICENSING BRANCH j
v (3.1.3) 5.
The coordination with.and training of off-site fire organizations is not specified*. These organizations should be included in a fire brigade drill at least annually.
Also, training of the off-site fire organizations should include courses in basic radiation principles and practices, typical radiation hazards that may be encountered when fighting fires and re-lated procedures.
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(442.1)
The schedule for the preparation of procedures is unacceptable.
(13.5.1.2) A generally acceptable target date for completion of adminis-trative and operating procedures is about six months prior to fuel loading. We believe that familiarity with these procedures is an essential part of the staff training program, including preparation for operator license examinations prior i
to criticality.
3 (442.2)
Provide a diagram of the control area that indicates the area (13. 5.1.3 ) designatsd "at the controls".
" Guidance on Being Operator at the Controls of a Nuclear Power Plant" should be consulted in developing this diagram.
(442.3)
Fire protection procedures of an administrative nature should be included in this section.
If these procedures are described (13.5.1. 3 ) elsewhere in the F5AR, reference should be made to them.
Simarily, fire protection procedures for operations and mainten-ance should be included or reference made to in Section 13.5.2.2.
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