ML20077K400

Forwards Responses or Revised Responses to Open Items of Listed Technical Review Branches.Responses Will Be Included in FSAR Rev 7

ML20077K400
Person / Time
Site:	Catawba
Issue date:	01/11/1983
From:	Tucker H DUKE POWER CO.
To:	Adensam E, Harold Denton Office of Nuclear Reactor Regulation
References
NUDOCS 8301130004
Download: ML20077K400 (55)

Text

VR DUKE Poweit GOMPANY l'.O. ISOX 33189 CIIAHLOTTE, N.G. 28242 II AL 15. TUCKER TELE PIf0NE wwm... men (704) 373-4:W31 January 11, 1983 mm. ====

Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Attention:

Ms. E. G. Adensam, Chief Licensing Branch No. 4 Re: Catawba Nuclear Station Docket Nos. 50-413 and 50-414

Dear Mr. Denton:

In order to facilitate the completion of the review of the Catawba FSAR, Duke Power Company is transmitting herewith responses or revised responses to open items of the following technical review branches. - Mechanical Engineering - HGEB - Materials Engineering - Corrosion Engineering - Reactor Systems - Containment Systems - Core Performance These responses will be included in FSAR Revision 7.

Very truly yours, M

Hal B. Tucker ROS/php Attachments cc:

Mr. James P. O'Reilly, Regional Administrator U. S. Nuclear Regulatory Commission Region II 101 Marietta Street, Suite 3100 Atlanta, Georgia 30303 Mr. P. K. Van Doorn NRC Resident Inspector Catawba Nuclear Station 8

8301130004 830111 PDR ADOCK 05000413 A

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Mr. Harold R. Denton, Director January 11, 1983 Page 2

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cc: Mr. Robert Guild, Esq.

Attorney-at-Law P. O. Box 12097 Charleston, South Carolina 29412 Palmetto Alliance 2135% Devine Street Columbia, South Carolina 29205 Mr. Jesse L. Riley Carolina Environmental Study Group 854 Henley Place Charlotte, North Carolina 28207 Mr. Henry A. Presler, Chairman Charlotte-Mecklenburg Environmental Coalition 943 Henley Place Charlotte, North Carolina 28207 i

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1 CNS Loading combinations and allowable stresses for ASME III Class 1 components and supports are given in Tables 3.9.1-2 and 3.9.1-3.

For Faulted condition evalua-tions, the effects of the safe shutdown earthquake (SSE) and loss-of-coolant ac-cident (LOCA) are combined using the square root of the sum of the squares (SRSS) method.

Justification for this method of load combination is contained in Ref-erences 4 and 5.

The responses to other loading combinations defined in Table 3.9.1-2 are combined using the absolute sum method.

3.9.1.4.7 Balance-of-Plant Components, Piping and Supports Seismic category I piping other than NSSS is analyzed for the faulted condition' utilizing elastically-determined stresses compared against allowables provided in Table F-1322.2-1 of Appendix F of the ASME Code Section III.

This is in accordance with applicable sections of the ASME Code or ANSI B31.1 as appro-priate.

Load combinations and allowable stresses for faulted and other plant conditions are discussed in Section 3.9.3.

Dynamic seismic analysis for the SSE is performed on this piping utilizing the model combination method in accordance with USNRC Regulatory Guide 1.92.

All seismic Category 1 supports are designed and analyzed for the Normal, Upset, Faulted and Test Conditions.

The stress limits for normal and upset conditions l

are as presented in ASME III Subsection NF and Subsection NA Appendix XVII for the portion of the support within the NF boundary.

The stress limit for the i

faulted load combination is as specified in Subsection NF with the exception that to avoid column buckling in compression, for members subject to local in-stability associated with compression flange buckling in flexural members and web buckling in plate guides, the allowable stress has been limited to 2/3 of the critical buckling stress.

For support design there is no inelastic analysis.

Temperature effects for material properties are considered.

For the portion of the support not within the NF boundary and for supports for 831.1 piping, stress limits are as provided in MSC-SP58 or the AISC Manual.

For integral attachments to the pressure boundary the rules of ASME Section III, Subsection NB, NC, ND are used as applicable.

3.9.2 DYNAMIC TESTING AND ANALYSIS 3.9.2.1 System Operational Test Program 3.9.2.1.1 System Vibration Testing ASME III requires that piping design minimize vibration and that piping sys-tems be observed under startup or initial operating conditions to insure that i

steady state vibration in piping systems is not excessive.

As part of the preoperational test program described in Chapter 14, steady state piping vi-bration and transient response of piping due to valve closures, pump starts, and other changing configurations are observed.

Details of the tests are given in Table 14.2.12-1.

MEB Duke Class A, B, C, and F systems satisfy the criteria of Regulatory Guide 1.68, l

Item 78 Revision 2, Appendix A, 5.o.0, for systems to be included in the vibration test 3.9-24 Rev. 7 1

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CNS program.

Systems which will be subject to steady state vibration testing are identified in Table 3.9.2-1.

Duke Class A, B, C, and F systems not in this table have been omitted for one or more of the following reasons:

a)

Vibration testing is not performed on piping with nominal size 1 in. or less, with the exception of the Reactor Coolant System instrumentation lines (including pressurizer level and reactor vessel level) which are specifically included in the test program.

The consequences of the failure of small line does not justify the expense of designing them to i

meet the vibration requirements.

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Vibration testing is not performed on piping containing gases, rather than liquids, because the relatively small forces exerted by flowing gases pre-clude the development of excessive vibration.

High flow velocity steam lines are an exception and will be tested.

c)

Vibration testing is not performed on piping systems which have no flow, or have less than 1% of the normal operating life span of the station, because of the lack of or relatively short duration of flow induced vib-ration in these pipes.

The acceptance criteria for piping vibration is that the maximum measured amplitude shall not induce a stress in the piping greater than one-half the endurance limit corresponding to 108 cycles as defined in Section III of the ASME Boiler and Pressure Vessel Code, 1974, Summer 1974 Addenda.

In the steady state, vibration testing of piping, the systems will be placed in the normal operating mode.

Qualified personnel shall perform a visual MEB inspection of the systems, noting locations of maximum vibration.

These Item 77 locations will be used for the measurement of the pipe vibration.

Data col-lected, with suitable instrumentation, will be compared with acceptance criteria based on the piping material (carbon or stainless steel).

If an unfiltered vibration reading exceeds the acceptance criteria, a spectrum analyzer will be used to obtain a spectrum plot of the vibration at that point.

The location, along with the pertinent thermal and hydraulic condi-tions of the system at that time, is noted and the results are sent to Design Engineering for evaluation and recommendations.

The piping systems listed in Table 3.9.2-1 will be subjected to routine tran-sients, valve closures, pump starts, etc., during system functional testing.

Inspections will be carried out by qualified personnel after the transient l

event to verify the occurance of any excessive piping motion.

Excessive motion will be evidenced by induced damage to piping supports, loosened hangers, out-of-range snubbers, damaged spring cans, etc.

If excessive move-ment or vibration is indicated, an evaluation will be done by Design Engineer-ing and corrective action taken as necessary.

lTransientvibrationtestingwillbedoneonsystemsaslistedinTable3.9.2-la.

A graded approach is used in testing.

3.9-25 Rev. 7

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f CNS 2.4.2

' FLOODS 2.4.2.1 Flood History

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The maximum flow recorded for the Catawba River at USGS gage number 1460 near Rock Hill, South Carolina is 151,000 cfs (4273 m3/s) on May 23, 1901.

The period of record for this gage is 1895 to 1903 and 1942 to the present.

Two major floods not recorded by the gage are the flood of 1916 with an estimated i

j flow at Wylie Dam of 299,400 cfs (8473 m3/s) and the flood of 1940 with an estimated flow of 169,160 cfs (4748 m3/s).

Six reservoirs exist on the Catawba River upstream from the station and Lake Wylie.

They have a combined usable storage of approximately 1.5 million Ac-ft (1.85 x 108 m3).

Because of such a large volume of storage, the floods of record are well modified and the annual flood peaks on the main stem of the Catawba do not represent the uncontrolled flood potential of the basin.

Table 2.4.2-1 shows the return period of annual peak floods for the Catawba River at the USGS gage near Rock Hill.

The flood of August 1940 caused Lake Wylie to reach a maximum surface water elevation of 575.0 ft (175 m) ms1, 5.6 ft (1.7 m) above full pond.

l 2.4.2.2 Flood Design Considerations

' Flood levels for the site are analysed for the following flood producing phenomena:

a.

Probable Maximum Flood (PMF) resulting from the probable maximum precipita-tion in the drainage area.

b.

A 25 year frequency flood passing through Lake Wylie combined with a seismic failure of Cowans Ford Dam, the largest upstream reservoir.

c.

A Standard Project Flood (SPF) passing through Lake Wylie combined with the failure of one of the upstream dams due to an Operating Basis Earth-quake (OBE).

The SPF is considered equal to one-half of the PMF.

The effect of wind on wave height and runup at this site is also analyzed.

The maximum static water elevation of 592.4 ft (180.6 m) ms1 occurs during a SPF combined with the failure of Cowans Ford Dam.

The station yard elevation l

is at elevation 593.5 ft (180.9 m) msl.

Conservative engineering analysis, such as those presented in Regulatory Guide 1.59 " Design Basis Floods for Nuclear Power Plants", are used in the PMF analysis.

Appendix A of Regulatory Guide 1.59 was used in making the flood study evaluation at Catawba.

In summary, descriptions for determining probable maximum flood, hydrologic characteristics, flood hydrograph analysis, precipitation losses and base flow, runoff model, probable maximum precipitation estimates, channel and' reservoir routing, seismically induced floods, water level determinations, and l

coincident wind-wave activity are provided in Section 2.4.3.

2.4.2.3 Effects of Local Intense Precipitation The plant site is provided with a surface water drainage system that is de-Q240.13 signed and constructed to protect all safety related facilities from flooding l

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l during a local PMP.

Modifications to the drainage system will be evaluated and accomplished under the pertinent requirements of the operational quality l

assurance program.to ensure against increasing the flood vulnerability of safety related systems dr components.

As discussed in Section 2.4.1.1, ex-terior access to safety related buildings are at elevation 594.0 ft. (181.1m) i msl.

l The yard drainage system subdivides the plant site into sub-basins, each of i

which has a catch basin for a runoff water inlet.

Each catch basin is sized based on the area of its sub-basin, consequently both 18 inches and 24 inches nominal diameter inlets are used on the site.

The individual inlets are con-nected by corrugated metal pipe, fully coated with a paved invert, which join to provide several different networks that carry the runoff to Lake Wylie.

Subdivision of the Powerhouse Yard into sub-basins is established so that runoff water does not flow overland more than 250 feet (76.2 m) to reach a catch basin.

The average sub-basin is characterized by an inverted pyramid with a top area of 0.31 acres and a corresponding apex depth of 1.27 feet below the yard high point (Elev. 593.5 feet).

Major features of the yard l

drainage system are shown on Figure 2.4.2-1.

l Based upon Hydrometeorological Report No. 33 (Reference 1), the probable max-l imum precipitation is 29.7 in. (75.4 cm) within a six-hour period.

The max-

' Q240.13 imum distribution sequence for this six-hour period, according to U. S. Army Corps of Engineers procedure (Reference 2) is as follows:

Time Incremental PMP Accumulative PMP (Ending Hour)

Inches (cm)

Inches (cm) 1 3.0

( 7.6) 3.0

( 7.6) i l

2 3.6

( 9.1) 6.6 (16.8) 3 4.4 (11.2) 11.0 (27.9) l 4

11.3 (28.7) 22.3 (56.6) 5 4.1 (10.4) 26.4 (67.1) 6 3.3

( 8.4) 29.7 (75.4)

Inflow from the PMP is due to precipitation which falls directly on the yard, buildings, and the lower Construction Yard.

With the exception of the Reactor Building, the roofs of safety-related struc-tures are designed with no obstructions, so that water flows directly off roofs and there is no accumulation.

A gutter drain system catches the water and routes it to collection points.

These collection points then discharge directly into the yard drainage system.

The Reactor Building roof drainage system is designed for a rainfall intensity of 5.0 in/hr (12.7 cm/hr).

In-tensities in excess of 5.0 in/hr (12.7 cm/hr) result in pending.

However, once the water level reaches E1. 711.34 ft (216.3 m) msl, the water flows directly off the roof.

The Reactor Building roof is designed to safely carry live loading due to ponding as discussed in Section 3.8.

In determining the 1

j effect of a local intense PMP on the Powerhouse Yard, it is assumed that water flows directly off the Reactor Building without ponding or discharging d

through the roof drainage system.

2.4-3 Rev. 7

CNS Total inflow is computed using the rational method which assumes 95 percent runoff and an instantaneous time of concentration.

The formula corresponding to this rational method is:

Q = cia 145.2 where Q. = PMP inflow, Ac.-ft, per 5 minutes Cl = Runoff coefficient = 0.95 i = Incremental PMP, inches per hour A = Total drainage area = 139.56 acres Discharge into the yard drainage system is controlled by slotted catch basin covers.

It is conservatively assumed that each catch basin inlet is 18 inches in diameter with a gross area of 1.77 square feet and an effective opening of 0.69 square feet.

The effective opening is obtained by reducing the gross area by 61 percent to account for the slotted catch basin covers.

The resulting outflow for all basins in the powerhouse yard is calculated using the orifice equation:

Q240.13 Q = ca f 2gR o

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Q = Orifice outflow, cfs i

l C = Orifice coefficient = 0.60 a = Total effective opening of catch basins

= (141 C.B.) x (0.69 ft2 per C.B.) = 97.29 ft2 g = Acceleration due to gravity = 32.2 ft/sec2 H = Depth of ponding above average catch basin inlet elevation (592.23 feet).

Once ponding reaches the yard high point (Elev. 593.5), sheet outflow over the northeast and south ends of the yard begins.

This sheet outflow is calculated using the weir equation:

Q,= CLh3/2 where Qw = Weir outflow, cfs C = Weir coefficient = 2.70 l

L = Length of weir = 913 feet h = Depth of ponding above yard high point.

The Puls graphical flocd routing method is used to predict the elevation of ponding in the yard due to the previously discussed PMP inflow, catch basin 2.4-4 Rev. 7 L

CNS outflow, and sheet outflow.

Results of the flood routing are presented on l

Figure 2.4.2-2.

At no time will ponding exceed Elevation 594.0, and there-fore local PMP will not result in flooding of any Category I structures.

All yard drainage pipes individually and within a network are designed using Manning's equation for pipe flowing full.

Accumulative totals are used throughout the networks to determine pipe sizes.

All pipe gradients are 0.5 percent or greater.

The invert elevations of pipe discharge points are shown on Figure 2.4.2-1.

Inspection of the catch-basin inlets to the yard drainage system will be made prior to Unit 1 fuel loading and will be conducted annually until at least two years after Unit 2 fuel loading.

The inspections will be per-formed and documented in accordance with pertinent requirements of the site quality assurance program.

Any condition which may increase the flood vul-Q240.13 nerability of safety related systems and components will be corrected.

The inspection program will be re-evaluated two years after Unit 2 fuel loading and the need for any subsequent inspections will be determined at that time.

Ice accumulation occurs only at infrequent intervals because of the tem-perate climate.

Maximum winter precipitation concurrent with ice accumula-tion do not result in flooding of Category I structures.

2.4.3 PROBABLE MAXIMUM FLOOD (PMF) ON STREAMS AND RIVERS 2.4.3.1 Probable Maximum Precipitation A search, made of historically great storms which occurred near the Catawba River basin is used to obtain the hypothetical flood characteristics of peak discharge, volume, and hydrograph shape considered to be the most severe

" reasonably possible" at the Catawba site.

The storms, listed on Table 2.4.3-1, are believed to be the greatest to occur in the southeastern part of the country.

Table 2.4.3-1 lists the locations of storm centers and maximum

' rainfall depths and durations for a drainage area equal to that above the Wylie Dam.

The greatest storm over the Wylie drainage area is recorded for the period July 13-17, 1916.

However, greater amounts of precipitation occurred in Elba, Alabama, and Bonitoy and Yankeetown, Florida as shown in Table 2.4.3-1.

It is of note that the later storms all occurred immediately along the coastal area and are expected to produce diminishing amounts of precipitation by trans-posing these storms inland some 200 mi (322 km) to the Wylie watershed.

Maximum-depth-duration of rainfall, from a study made by the Hydrometeoro-logical Section of the Weather Bureau for the Savannah River above Hartwell dam site, is included in Table 2.4.3-1 for comparison purposes since the location is very close to the Catawba River watershed.

The Savannah River study uses the storm of July 13-17, 1916 as a guide for the determination of maximum rainfall.

However, to arrive at a maximum possible precipitation and transposing the storm over the Savannah River basin, an adjustment is made to increase the precipitation values by 42 percent.

To arrive at the Probable 2.4-4a Rev. 7 Carry Over s.

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6.0 ENGINEERED SAFETY FEATURES 6.1 ENGINEERED SAFETY FEATURE MATERIALS 6.1.1 METALLIC MATERIALS 6.1.1.1 Materials Selection and Fabrication Typical materials specifications used for components in the Engineered Safety Features (ESF) are listed in Table 6.1.1-1, Engineered Safety Feature Mat-erials.

In some cases, this list of materials may not be totally inclusive.

However, the listed specifications are representative of those materials used.

Materials utilized are procured in accordance with the materials specification requirements of the ASME Boiler and Pressure Vessel Code,Section III, plus applicable and appropriate Addenda and Code Cases.

Even though fracture toughness was not required by the ASME Code, fracture toughness requirements were imposed on the accumulators which were identified as the only ferritic material actually used in Catawba's engineered safety features systems.

The material met the ASME Code for the Catawba components.

l The welding materials used for joining the ferritic base materials of the ESF conform to or are equivalent to ASME Material Specifications SFA 5.1, 5.2, 5.5, 5.17, 5.18, and 5.20.

The welding materials used for joining nickel-chromium-iron alloy in similar base material combination and in dissimilar ferritic or austenitic base material combination conform to ASME Material Specifications l

SFA 5.11 and 5.14.

The welding materials used for joining the austenitic l

stainless steel base materials conform to ASME Material Specifications SFA 5.4 l

and 5.9.

These materials are tested and qualified to the requirements of the ASME Code,Section III and Section IX rules and are used in procedures which have been qualified to these same rules.

The methods utilized to control delta ferrite content in austenitic stainless steel weldments are discussed in Sec-tion 5.2.3.

All parts of components in contact with borated water are fabricated of or clad with austenitic stainless steel or equivalent corrosion resistant mat-erial.

The integrity of the safety-related components of the ESF is main-l tained during all stages of component manufacture.

Austenitic stainless steel l

is utilized in the final heat treated condition as required by the respective ASME Code,Section II, material specification for the particular type or graae of alloy.

Furthermore, it is required that austenitic stainless steel materials used in the ESF components be handled, protected, stored, and cleaned according to recognized and accepted methods which are designed to minimize contamination which could lead to stress corrosion cracking.

The rules covering these con-trols are stipulated in Westinghouse process specifications, which are discus-sed in Section 5.2.3.

Additional information concerning austenitic stainless steel, including the avoidance of sensitization and the prevention of inter-granular attack, can be found in Section 5.2.3.

No cold worked austenitic stainless steels having yield strengths greater than 90,000 psi are used for l

components of the ESF within the Westinghouse standard scope.

6.1-1 Rev. 7 i

CNS 10.3.6 MAIN STEAM AND FEEDWATER SYSTEM MATERIALS 10.3.6.1 Fracture Toughness The basic material specifications and thickness for the Main Steam and Feed-water Systems are:

Feedwater Pipe - SA-106 Gr. B Thickness =.937" Nom.

Fittings - SA-234 WPB Thickness =.937" Nom.

Main Steam Pipe - SA-106 Gr. C Thickness = 1.375" Min.

Thickness = 1.750" Min.

Thickness = 2.375" Nom.

Fittings - SA-234 WPB Thickness = 1.375" Min.

- SA-105 Thickness = 2.375" Nom.

Even though fracture toughness testing is not required under the effective Edition and Addenda of ASME Section III, NC 2300, materials of similar com-position and thickness have been used successfully in the past for service in the range of our lowest service metal temperature (50*F).

Current manufacturing controls SA-105 and SA-106 keep the carbon content well below the maximum allowable by material specification.

The strength is maintained by adjusting the other alloying elements, such as Manganese, within the material specification limits.

The reduction Carbon and adjust-ment of Manganese help lower the Nil Ductility Transition Temperature and enhances the fracture toughness properties.

l 10.3.6.2 Materials Selection and Fabrication l

Material selection and fabrication for these systems are based on the follow-ing:

l 1.

Materials used are included in Appendix I of Section III of the ASME Code.

2.

No austenitic stainless steel piping material is used in these systems.

l 3.

Cleaning and acceptance criteria are based on the requirements of ANSI N45.2.1-73 and the recommendations of Regulatory Guide 1.37.

4.

Low-Alloy steels are not used in these systems for piping materials.

5.

Duke Power Company complies with Regulatory Guide 1.71, " Welding Qualifica-tion for Areas of Limited Accessibility," except that the guide's restric-tion on access is deemed too stringent and would require unnecessary test-ing.

In that it is impossible to define each variable that is site related 10.3-6 Rev. 7

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CNS 282.0 CORROSION ENGINEERING 282.1 The secondary water chemistry monitoring and control program as you (10.3.5) provided in the FSAR is incomplete.

Provide a complete secondary water chemistry monitoring and control program following the guidance of Branch Technical Position MTEB 5-3 attached to SRP 5.4.2.1, Revision 2, July 1981.

Response

See revised Section 10.3.5.2.

Station chemistry procedures will be available for on-site review at least six months prior to fuel load.

The Catawba Chemistry Program will designate the specific respon-sibilities and authority to take actions to maintain the chemistry program described in Section 10.3.5.2.

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CNS the reactor coolant system has been partially drained for steam generator inspection or maintenance.

Response

Lowering of the reactor coolant level in the system for maintenance is such that the level is maintained in accordance with specific main-tenance procedures.

If it is required that the water level be lowered to drain the steam generator tubes, the residual heat removal flow rate is throttled to about 1500 gpm through each of the residual heat removal loops.

Draining is to the point where the indicated level is stable and at the elevation of the center of the reactor vessel nozzles.

At this point, reactor coolant level is monitored continuously to assure that the RHR system inlet lines do not become uncovered.

Inventory make-up, if required, can be accomplished via the chemical and volume con-trol system (CVCS)/ centrifugal charging pump (s).

Should a RHR system inlet line become uncovered, air may be drawn into the suction piping and entrained in the fluid.

Factors which minimize the effects of air entrainment on pump performance are as follows:

1.

the location of the residual' heat removal pumps provides positive head on the pump inlet, and 2.

the circulation flow rate is kept low and unnecessary circulation l

of fluid is avoided (i.e., the minimum flow required for core decay heat removal is maintained).

l Provisions have been made to minimize the effects of air entrainment; however, should such an event preclude the continued us'e of the op-erating train, actions will be taken to permit the utilization of the alternate train by providing sufficient refill / makeup from the CVCS/

charging pumps.

440.13 RHR suction lines can have water trapped between the two isolation (5.4.7) valves.

Address the possibility of pressure increasing in this pipe due to a temperature rise with respect to protection needed to assure

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valve and piping integrity.

Response

l Duke will provide a reverse check valve (spring loaded lift check) in parallel with the inner RHR suction isolation valve to provide protection against pressure increases due to heating water trapped between the two isolation valves.

440-18 Rev. 7

i CNS Valve Function Number i RHR pump. discharge to cold legs 1NI173A, 1NI1788 RHR pump discharge to hot legs 1NI183B SI pump suction from RWST INIl008 SI pump common miniflow 1NI1478 j

SI pump discharge to cold legs 1NI162A I

SI pump discharge to hot legs 1NI121A, 1NI152B l

t 440-93a Rev. 7

CNS 440.126 Your response to Question 440.24 states that non-seismic piping (6.3) which connects to the RWST is not required for safety related func-(440.24) tions.

The piping from safety injection pump miniflow line valve 147B to the RWST is non-seismic as well as connecting piping.

This piping could fail due to the initiating accident event and degrade ECCS performance.

Address this concern.

Response

The SI pump common miniflow line, while non-nuclear safety, is pro-tected from high and medium energy line breaks, tornadoes, and is located in a seismic category 1 building.

Should the line rupture, redundant safety related, Class 1E powered isolation valves are lo-cated upstream and can be closed by the operator to isolate the failure.

The line itself is only used during inservice testing of the SI pumps and during the initial injection phase following receipt of an SI signal.

The line is isolated during the switchover from in-jection to cold leg recirculation.

J 440.127 Your response to the steam generator tube rupture portion of Question (15.0) 440.56 states:

" Consideration of the indications provided at the l

(440.56) control board, together with the magnitude of the break flow, leads to the conclusion that the isolation procedure can be completed with-in 30 minutes of accident initiation.

Included in this 30 minute time period would be an allowance of 5 minutes to trip the reactor and actuate the safety injection system (automatic actions), 10 minutes to identify the accident as a steam generator tube rupture and 15 minutes to isolate the faulted steam generator." This scenario is not consistent with Table 15.6.3-1, Steam Generator Tube Rupture l

Sequence of Events, which states the safety injection signal occurs at 773.0 seconds.

Evaluate this discrepancy and show that adequate time is available for completion of operator action at 1800 seconds as indicated in Table 15.6.3-1.

Response

The response to Question No. 440.56 and FSAR Section 15.6.3 have been revised.

Please refer to these revisions in response to this l

question.

440.128 It is not apparent from your response to Questions 440.85 and 440.87 (15.3.3 &

that you intend to analyze the locked rotor and shaft break transients 15.3.4) consistent with the acceptance criteria in SRP 15.3.3 - 15.3.4 in 440.85 &

NUREG-0800.

We require that this event be analyzed assuming turbine 440.87 trip and loss of offsite power to the undamaged pumps.

The event should also be analyzed assuming the worst single failure of a safety grade system active component.

Maximum primary system activity (in addition to activity from fuel failure resulting from the transient) and maximum steam generator tube leakage as allowed by the technical 440-107 Rev. 7

440.132 Identify administrative procedures associated with reducing the potential for overpressure events.

Identify technical specifica-tions which will be proposed to assure that assumptions used in low-temperature overpressure design analyses are not violated.

Response

The unit startup and shutdown procedures will utilize a sequence of operations which ensures that a pressure relieving path is always available.

The philosophy of operation is essentially the same as utilized at McGuire.

A steam bubble is formed in the pressurizer early in the startup sequence.

This provides a cushion against pressure surges and over pressurization when the Reactor Coolant System is isolated from the Residual Heat Removal System.

The Technical Specifications for Catawba will be submitted as dis-cussed in Chapter 16 and should be essentially identical to the McGuire Technical Specifications.

The following limiting condi-tions for cperation will assure the validity of assumptions used in the low temperature overpressure design analysis.

1.

The Reacto. Coolant Syster. lowest operating loop terperature (T,yg) shall be > 551*F with K,ff g 1.0.

2.

One charging pump shall be operable in Modes 3, 4, and 5.

The other charging pumps shall be demonstrated inoperable.

3.

At least two reactor coolant and/or resinual heat removal loops shall be operable in Mode 4.

4.

The pressurizer shall be operable with a water volume of less than or equal to 1600 cubic feet in Modes 1, 2, 3, and 4.

If a steam bubble is not available in Mode 4, two residual heat removal loops shall be operable.

5.

At least two PORV's with a lift setting of 5 400 psig or a Reactor Coolant System vent of > 4.5 square inches is required in Mode 4 when the temperature of any RCS cold leg is 1 300 F,

Mode 5, and Mode 6 with the reactor vessel head on.

6.

The Reactor Coolant System temperature and pressure is limited by the envelope shown on Figures Q440.8-1 and -2.

440.134 RSB 5-1 requires that Catawba be designed such that cold shutdown

_can be achieved without leaving the control room.

Identify all actions (such as power restorations to valves) which the operator at Catawba must take outside the control room to achieve and maintain cold shutdown and provide justifications for these exceptions to RSB 5-1.

Response

The only valves that have power removed from their operator at a location outside the control room during normal operation and are repositioned to achieve a cold shutdown are the cold leg accumulator isolation valves.

These valves are active, ASME Section III Class 2, electric motor operated gate valves located inside containment.

In order to pre-clude mispositioning these valves during unit operation, power is removed from these valves at the motor breakers in a readily acces-sible area of the Auxiliary Building.

These valves are closed be-fore the RCS pressure is reduced below the accumulator pressure as the plant is cooled from hot standby to cold shutdown.

It is felt that the operator will have sufficient time before the need to achieve cold shutdown to reach the breaker locations, restore power, close the valves, and remove power.

However, cold shutdown (i.e.,

RCS < 200 F) can be achieved without closing the accumulator isola-tion valves.

This would result in additional fluid that would re-quire processing in the Boron Recycle System but no nitrogen would be injected into the RCS as long as pressure remained above approxi-mately 155 psia, i

l

\\

440.135 RSB 5-1 requires that Class 2 Plants " provide safety grade dump valves, (5.4.7) operators, and power supply, etc., so that manual action should riot be required after SSE except to meet single failure." Discuss Catawba compliance with this position.

Response

As discussed in the response to Questions 410.20 and 440.22, it is felt that a non-safety related air supply and control system is suf-ficient and acceptable for the steam generator power operated relief valves (PORVs) since they are not required to mitigate the conse-quences of an accident.

The main points of those responses are as follows:

1.

Since hot standby is a safe and stable condition which can be maintained for an extended period of time, there is no safety requirement for reaching cold shutdown within a short period of time.

2.

The steam generator PORVs are equipped with redundant safety related solenoid valves (Train A & B) which are deenergized to vent air off the spring loaded PORVs to close them upon receipt of a main steam isolation signal.

Continued heat rejection fol-lowing PORV closure will be provided by the main steam safety valves.

3.

The steam generator PORVs are normally closed, active, ASME Section III Class B, containment isolation valves and satisfy the single failure criteria for this function.

As discussed above, these valves are not required to perform a safety func-tion to achieve or maintain hot standby.

In addition, since hot standby is a safe and stable condition, which can be main-tained for an extended period, there is no safety requirement for reaching cold shutdown within a short period of time.

The possible function of these valves in achieving cold shutdown is not required to be designed to satisfy single failure criteria since time is available to correct any failures which might occur.

4.

Once hot standby is reached there will be ample time to call in additional personnel or expertise to assess the situation and take the necessary corrective action.

The plant can then be taken to a cold shutdown condition by manually operating the steam generator PORVs using local handwheels in the event instrument air is not available and cannot be restored.

5.

Instrument air can be provided by any of the three instrument air compressors or either of the two station air compressors l

which automatically back up instrument air.

The instrument air compressors and dryers can be manually loaded on the black-out bus during sequence #13 after 12 minutes in the event of a station blackout.

Based on the above, complete unrestorable loss of instrument ai is very unlikely and manual operation of the PORVs is acce table.

6.

The controls for the steam generator PORVs are standard com-merical quality instruments.

The pressure transmitter for each main steam line is located in its respective doghouse and sup-plies a signal to two controllers.

One controller is located in the control room and the other controller is located on the auxiliary shutdown panel.

The controllers supply control air to the PORVs through two safety grade solenoids described in item 2 above. A harsh environment in one doghouse would not affect the other two transmitters in the other doghouse which could still be used to cool down.

7.

Pressure boundary parts of the steam generator PORVs are qualified to ASME Section III Class 2, Duke Class B.

Valves are qualified for pressure, seismic and pipe loads by analysis documented in the seismic report.

In addition to operability qualification in the seismic report, static deflection test is performed to qualify the valve for operability under pressure and seismic loads.

Valve is qualified to fail closed by actuator spring force.

Actuator is qualified by analysis to withstand a main steam line break environment in the dog house.

440.137 The response to Q440.32 and FSAR Section 6.3.2.2 do not provide (6.3) adequate quantification to verify the NPSH calculations (limiting l

(440.33) ease), or consistency with RWST sizing basis.

Provide the following:

a) values for each term in the NPSH calculation (limiting case) b)

pump flow rate assumed (limiting case) c)

discussion to show that kinetic heat loss (V2/2g) term has been considered consistent wiht the pump manufacturer's method of specifying NPSH required d) containment water level, pump suction centerline level, and volume of water assumed to determine containment water level.

Response

a)

For ND Pump Limiting Case (see Section 6.3.2.2 and Q440.33):

NPSHA = (PCont. P )(144) + H y

elevation loss = 25.34 @ 4600 gpm

-H NPSHR @ 4600 gpm is 19 ft.

P

= 14.696 psia = minimum containment pressure post accident Cont.

P = 9.34 psia - vapor pressure of water at 190*F y

p = 60.34 lbm/ft3 - water density at 190*F Helevation = 24.5 ft - assume containment floor elevation for reservoir level minus centerline of pump discharge Hloss = 11.94 ft.

piping losses from sump to pump inlet We can demonstrate that there is sufficient NPSH in the recir-A culation mode for the ND pump should it runout to values seen during preoperational testing and refueling conditions (when the discharge head is significantly reduced due to lowered back-pressure resulting from removal of the reactor vessel head).

Under these conditions the flow rate will be below 5300 gpm.

The value of the piping loss component will rise to 15.28 ft.

and NPSH increases to 23 ft.

For this case we will take credit R

for two feet of water on the containment floor (which translates into approximately 100,000 gallons which is roughly half the minimum volume injected from the FWST and ignores ice melt and RCS spillage).

For this case:

NPSHA = (14.696-9.34)(2.386) + 26.5 -15.28 = 24.0 ft @ 5300 gpm NPSHR @ 5300 gpm = 23.0 ft.

b)

Pump flow rates are given above.

~c) - The manufacturer did not add velocity head to the pressure measured during NPSH tests so velocity head does not need to R

be subtracted from NPSH calculations.

A d)

The containment water level in the above analysis was a maximum of 2 feet which corresponds to less than 100,000 gallons or about half the minimum RWST injection volume.

Pump discharge centerline was selected since it is higher than pump suction centerline and is thus conservative.

l h

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440.141 The responses to Q440.106 and 440.108 describe power removal and (6.3)

. interlocks to prevent spurious mispositioning of valves.

Identi fy (440.106) and justify any actions outside the control room which the operator (440.108) must take in a post-accident or normal cold shutdown scenario.

Our position is that such actions should be performed from the control room.

Response

The response for actions taken in the normal cold shutdown scenario is presented in response to Q440.134.

In order for the operator to switch from cold leg recirculation to hot leg recirculation there are six valves which require power be reestablished before they can be repositioned.

These valves are 1NI178B, 1NI173A, 1NI152B, 1NI162A, 1NI121A, and 1NI1838.

Power is removed from the operators of the last four valves at the motor breakers in a readily accessible area of the Auxiliary Building.

Since these valves will not require repositioning until approxi-mately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the start of the accident, it is felt that the operator will have sufficient time to perform this task before the need to align for hot leg recirculation.

Valves 1NI173A and 1NI1738 could require repositioning as early as one hour after the start of the accident if residual containment spray is required.

For this reason, power removal / restoration cap-ability for these valves will be added to the main control room after first refueling.

A summary of operator actions outside the control room is provided in Table Q440.141-1.

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.. ! l Table Q440.141-1 (Page 1)

['

i Operator Actions Outside Control Room 4

Control Room Indication Operator Action Required Outside the Control Room Available to Operator To Achieve To Achieve Location of Yalve Normal Cold Shutdown Operator Action Type of 141 Status Monitor Computer Protective t

No.

Function Cold Shutdown Following DBA 81da Elev Operator Action Panel Lights / ANN tights Point Interlock Remarks NI54A Cold leg acctanu.

Yes NR A8 577 Reestablish power Yes Yes Yes Yes Yes Can reach cold shutdown j

NI658 lator Isolation AB 560 to motor operator Yes Yes Yes Yes Yes without closing valves i

NI76A valves A8 577 at motor control Yes Yes Yes Yes Yes N!888 A8 560 center.

Yes Yes Yes Yes les j

nil 848 Sump Isolation NR No Yes No Yes Yes Yes NI185A valves Yes No Yes Yes Yes N!173A RHR/ Cold leg NR No Yes No Yes Yes No Control Room lockout Mil?88 isolation valves Yes No Yes Yes No Control Room lockout N!121A SI/ Hot leg NR Yes A8 577 Reestablish power Yes No Yes Yes No N!!528 1 solation valves A8 560 to motor operator Yes No Yes Yes No at motor control i

.}

center l

N11838 RHR/ Hot leg NR Yes A8 560 Reestablish power No No Yes Yes No to motor operator l

at motor control l

center l

N1162A SI/ Cold leg NR Yes A8 577 Reestablish power Yes No Yes Yes No to motor operator l

at motor control i

center NI1478 SI mintflow to RWST NR

• No Yes No Yes Yes Yes Control Room lockout.

Yes Yes Yes Yes no Control Room lockout -

i NII008 RWST/51 suction NR No isolation l

Nb28A RHR/Chg.

NR No Yes NO I'S I'S I8S suction isolation 7t,.

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Operator Actions Outside Control Room I t l

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To Achieve To Achieve Location of

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Valve Normal Cold Shutdown Operator Action Type of 141 Status Monitor Computer Protective I

No.

Function Cold Shutdown Following DBA Bido Elev Operator Action Panel Lights / ANN Lights Point Interlock Remarks I

I N!1368 RHR/$1 Suction NR No Yes No Yes Yes Yes

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1 solation l

I NS388 RHR Contalrunent NR No Yes No Yes Yes Yes I

NS43A spray Yes No Yes Yes Yes NDIS RHR suction No No No No No Yes Yes i

ND2A isolation No No No Yes Yes N3366 No No No Yes Yes l

l ND37A No No No Yes Yes l

SV1 Steam generator NR Yes DH 634 Local Handwheel No No No Yes No Local handwhnis are provided I

SV7 PORVs DH 634 Local Handwheel No No No Yes No to cpen valves in the event l

SVI3 DH 634 Local Handwheel No No No Yes No of loss of normal non-safety j

SV19 DH 634 Local Handwheel No No No Yes No grade controls.

NC328 Pressurizer PORVs NR Yes AB.58 543.568 Realign Valves No Yes No

'Yes No Valves require manual l

NC34A

$8

$94 Close Breakers No Yes No Yes No loading of air compressers l

NC368 No No No Yes No to black out bus if offsite l

power is lost.

l l

t Notes:

1) NR - No required function for this scenario No - No outside control room action needed to reposition valve Yes - Action outside control room needed to reposition valve t

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440.145 The response to Q440.38 cited Westinghouse Owners Group " Emergency Response Guidelines" to address concern about loss of offsite power (6.3)

~

(440.38) subsequent to manual reset of the ECCS after a LOCA.

A preliminary review-of these ERGS indicate that they do not provide adequate guidance.

We therefore require that this issue be addressed in greater detail.

Response

The issue regarding loss of offsite power subsequent to manual reset of the ECCS is a long standing issue which was raised before the TMI event.

This issue was addressed by Westinghouse and the NRC initially in 1977 where the NRC evaluation is documented in NUREG-0138 (Issue 4).

Immediately after the TMI event Westinghouse reiterated its position on this issue in response to IE Bulletin 79-06A and has incorporated the appropriate provisions into the appropriate emergency procedure guidelines which have been approved by the NRC both generically and on specific plant procedures for issuance of an operating license.

Rather than instructing the operator not to reset Safety Injection (SI) for 10 minutes following an ECCS actuation as suggested by NUREG-0138, the Emergency Response Guidelines (ERG's) referenced in response to Q440.38 provide the operator with a symptom based diagnostic procedure.

For example, ECCS actuation could be the re-sult of a spurious actuation, a loss of reactor coolant, or a loss of secondary coolant.

Following SI actuation the operator would review indications such as Reactor Coolant System pressure; contain-ment temperature, pressure, sump level and radiation level; and secondary side radiation levels in assessing the occurrance.

If, as would be most likely, the operator identifies the occurrance as a spurious actuation, he would be required to verify Reactor Coolant System pressure, pressurizer level and subcooling; and a secondary system heat sink all within specified limits prior to resetting SI.

The operator would be directed to other appropriate actions if a loss of reactor coolant or secondary coolant had occurred.

The operator is specifically cautioned that manual action may be re-quired to restart safeguards equipment if offsite power is lost after SI reset.

i

440.146 The response to Q440.34 identified indicators and alarms to alert (6.3) the operator to a LOCA at shutdown for Catawba, but presented no

~

(440.30) analytical results to show that this event is not limiting.

Analyze this event or reference an analysis for a similar plant to show that a LOCA at shutdown is not limiting for Catawba.

Response

A LOCA may be postulated to occur during the shutdown procedure at Catawba when all accumulation isolation valves have been closed and locked out.

Such a LOCA during shutdown will behave the same for Catawba as for any other four-loop plant (without or with UHI) which has comparable pumped safety injection flow capability and operates at a similar core power level.

An analysis of the limiting large break LOCA event during shutdown was previously provided on the Donald C. Cook Unit No. 2 plant docket in response to NRC Question 212.33.

The conclusion drawn therein that a postulated LOCA event occurring at shutdown is not limiting is applicable to Catawba as well.

I

440.147 From the response to Q440.129 and discussions with the NSSS vendor (6.3)

_it was concluded that in the computer representation of the Catawba (440.129) vessel the downcomer would be relatively smaller than for most UHI -

plants:

Justify that Catawba is not " imperfect mixing" limited as is the other "small downcomer" UHI plant.

Response

Three additional breaks will be performed with the imperfect mixing assumption to complete the imperfect mixing FSAR spectrum:

CD = 0.8, 0.6, and 0.4 DECLG break cases. The same version of the UHI Evalua-tion model as was used in the FSAR will again be used.

1

440.149 Table 440.3-3 and the response to Q440.56 indicate that credit has (15.6.3) been taken for non-safety grade equipment, without applying single (440.127)

~ failure, and without loss of offsite power in the analysis of steam generator tube rupture.

Provide an analysis fo this event with loss of offsite power, applying single failure, and taking credit only for safety grade systems and instrumentation in the mitigation of the event.

Response

The analysis of the steam generator tube rupture event assumed the loss of offsite power coincident with reactor trip.

Maximization of steam released through the faulted steam generator safety valves and power operated relief valve was obtained by assuming the limiting single failure within the auxiliary feedwater system that then results in minimum delivered auxiliary feedwater flow.

As discussed in Sec-tion 15.6.3.2, no operator actions are assumed until 30 minutes after the accident.

During this time period no credit is taken for non-qualified (i.e., non-safety grade) equipment.

The Chapter 15 analysis assumes that the operator takes action at 30 minutes to depressurize the primary system and, thereby, termi-nate the steam release to the atmosphere through the faulted steam generator safety valves.

Depressurization will be accomplished via any of several methods depending upon the availability of the com-ponents and power supplies.

Depressurization following a SGTR will be accomplished in three stages.

The first stage involves depres-surizing the reactor coolant system to a pressure slightly less than that of the faulted steam generator secondary side.

The second and third stages bring RCS pressure down to RHRS initiation conditions (approximately 415 psia) and, finally, to atmospheric pressure.

Adequate time exists for both the second and third depressurization stages to permit manual actions to recover previously unavailable components.

I An adverse environment is not expected within the containment during the initial recovery period of the SGTR and prior to opening of a pressurizer PORV for depressurization.

The single opening of a pres-surizer PORV is adequate to depressurize the RCS.

Should the pres-surizer PORV fail in the open position, the pressurizer PORY block valve provides a fully qualified safety related means of isolating the stuck open pressurizer PORV.

l Pressure boundary parts of the pressurizer PORVs are qualified to ASME Section III, Class 1, Duke Class A.

Valves are qualified for i

l pressure loads, seismic loads and piping loads by analysis documented l

in the stress / seismic report.

In addition to operability qualifica-l tion in the seismic report, static deflection test is performed to l

qualify the valve for operability under pressure and seismic loads.

Valve is qualified to fail closed by actuator spring force.

Actuator l

is qualified by analysis for temperature and radiation for inside containment LOCA and steam line break environments.

Pressurizer l

PORV's successfully passed full flow, full pressure and temperature testing by Duke at Marshall Steam Station and by EPRI under EPRI's PWS Safety and Relief Valve Test Program.

l

Containment Systems Branch I

1 l

l l

CNS The sequencing system for loading the onsite emergency electrical generators is designed to actuate all valves receiving an engineered safety features actuation signal within adequate time to supply ECCS and auxiliary pumps after the switch to emergency onsite electrical power signal is accomplished.

lTheContainmentPurgeSystem(asdescribedin'Section9.4.5)reducesradio-activity levels in the containment as well as in the Incore Instrumentation Room by taking in fresh air from the outside and exhausting containment air through cleanup filters prior to discharge to atmosphere through the unit vent stack.

Expected Containment Purge System usage is described in Section 9.4.5.2 and is further limited by the Station Technical Specifications.

The Contain-I ment Purge System (VP) is designed to meet the requirements outlined in Branch Technical Position CSB 6-4, Revision 1, dated December 1978.

A comparison of the system to CSB 6-4, Revision 2, dated July 1981 is given in Table 6.2.4-2.

Other systems similar in function as well as in design requirements are the I

Containment Air Release and Addition System (VQ), Containment Hydrogen Sample and Purge System (VY), and the Hydrogen Skimmer System (VX).

All containment penetrations of the above systems are provided with isolation valves capable of 5 second closure.

Airborne fission products in the ECCS Pump Room should be effectively contained by filters located in the Auxiliary Building Ventilation System (VA).

In ad-dition, the VA System contains radiation monitors in the unit vent stacks which check the radiation level in the ECCS Pump Room.

This system is discussed fur-ther in Section 9.4.3.

The VA System in conjunction with the area radiation monitor (see Section 12.3), located at El. 522' and 543' in the ECCS Pump Rooms should satisfactorily serve to detect leakage in the engineered-safety-feature systems.

As described below adequate protection is provided for piping, valves, and vessels against dynamic effects and missiles which might result from plant equipment failures, including a LOCA.

Isolation valves inside the Containment are located between the secondary shield l

and the inside Containment wall.

The secondary shield serves as the missile bar-rier.

Any missile barriers for isolation valves and piping, or vessels which provide one of the isolation barriers outside the Containment, consist of str-uctural steel and concrete which forms walls and floors of adjacent buildings, either the Auxiliary Building or Doghouses.

Piping, isolation valves, and actuators in the Containment Isolation System out-side Containment are located inside a Seismic Category 1 enclosure complex, and are located as close as practical to the Containment wall; i.e., in almost all cases, isolation valves will be located immediately after the penetration as-sembly.

There will, however, be exceptions, such as the case of the main steam lines which require a series of safety valves before the isolation valve.

Also, there will be some exceptions due to normal structural design arrangements.

Act-ual lengths of pipe from penetrations to the isolation valves outside Containment have been kept to a minimum.

The isolation arrangement of the fuel transfer tube, shown in Figure 6.2.4-3 consists of a transfer tube closure and a blind flange, enclosing the transfer tube.

The blind flange contains two 'O' -ring grooves and a pressure tap which runs through the blind flange to the annulus between the two 'O' -rings.

When 6.2-57 Rev. 7

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TABLE 6.2.4-1 (Pag 2 9) Containment Isolation Valve and Actuation Data NOTES: ~ 1. Valve arrangements are shown in Figure 6.2.4-1. ~ 2. Definition of Actuation Signals S - Safety Injection Signal (T signal also activated by S signal) T - Containment Isolation Signal (Phase A containment isolation) P - Containment High-High Pressure Signal (Phase B containment isolation) 3. Deleted 4. Symbols: Valve Position Abbreviations 0 Open C Closed A Automatic R Remote Operation M Manual Local Operation LC Locked Closed C/0 Closed prior to Sump or Hot Leg Recirculation; Open after Sump or Hot Leg Recirculation LO Locked Open AI Fails As is Actuator Type E Motor (Power Source - Electricity) D Pneumatic Diaphragm (Power Source - Compressed Air) l P Pneumatic Piston (Power Source - Compressed Air) HW Handwheel (Power Source - Manual) i 5. Each Personnel Lock will have double doors with an interlocking system l to prevent both doors being opened simultaneously. 6. System Identification from valve number. BB - Steam Generator Blowdown System BW - Steam Generator Wet Layup Recirculation System CA - Auxiliary Feedwater System CF - Feedwater System i FW - Refueling Water System KC - Component Cooling System KF - Spent Fuel Cooling System NB - Boron Recycle System Rev. 7 i

TABLE 6.2.4-1 (Page 10) Containment Isolation Valve and Actuator Data NC - Reactor Coolant System ND - Residual Heat Removal System NF - Ice Condenser System NI - Safety Injection System NM - Nuclear Sampling System NS - Containment Spray System NV - Chemical and Volume Control System RF - Fire Protection System RN - Nuclear Service Water System SA - Main Steam to Auxiliary Equipment SM - Main Steam System SV - Main Steam Vent to Atmosphere VB - Breathing Air System VE - Annulus Ventilation System VI - Instrument Air System VP - Containment Purge System VQ - Containment Air Release and Addition System VS - Station Air System VV - Containment Hydrogen Sample and Purge System VX - Containment Air Return Exchange and Hydrogen Skimmer System WE - Equipment Decontamination System WG - Waste Gas System WL - Liquid Radwaste System YM - Demineralized Water System 7. The given response indicates whether or not the penetration is con-nected to Seismic Category 1 equipment inside and/or outside contain-ment. 8. The Containment pressure control isolation valves are also automat-ically closed by nigh containment radiation. 9. Connected Piping is temporary and is removed before startup. Pene-trations are closed with blind flanges during all modes containment integrity is required. 10. See FSAR Section 6.3 for automatic actuation signals for these valves. 11. See Section 6.3 for Accumulator Water level signal used to close these valves after initial injection. 12. Open for startup, closed when plant reaches ' 30% power. 13. As documented in Engineering Justification Report SES-JR-10, the one inch containment isolation valves for this system were purchased i as Duke Class F instead of Duke Class B. This was necessary due to the high system design pressure (8000 psig) which exceeded the pressure / temperature ratings of the ASME section III Code. l Rev. 7 l

1 TABLE 6.2.4-1 (Page 11) Containment Isolation Valve and Actuator Data 14. Valve c1cses upon receipt of a high radiation signal. 15. The following systems are considered Engineered Safety Feature systems: FW - Refueling Water System NB - Boron Recycle System NC - Reactor Coolant System ND - Residual Heat Removal System NF - Ice Condenser System NI - Safety Injection System NS - Containment Spray System NV - Chemical and Volume Control System VE - Annulus Ventilation System 16. Power Source - Refer to Note 4. 17. General Design Criteria met - Any valve arrangement designated with an "A" or "B" prefix meets the spec-ifications of GDC 55 and 56 of 10CFR50, Appendix A. Valve arrangements with a "D" prefix meet GDC 57. Valve arrangements with a "C" prefix fall into a miscellaneous category in which the piping is considered a part of the containment and meeting GDC 50. In addition, the 'C2' arrangement (the fuel transfer tube) also meets GDC 51, 52, and 53 (see Section 6.2.4.2.1). 'C1' and 'C3' arrange-ments are considered closed to outside atmosphere. See Note 9 concerning specifics on arrangement 'C3'. 18. All potential bypass leakage paths in dual containment plants are required a Type C test per Position No. 7, Section B, of Branch Technical Position CSB 6-3, " Determination of Bypass Leakage Paths In Dual Containment Plants." 19. Piping, isolation valves, and actuators in the Containment Isolation System outside Containment are located inside a Seismic Category 1 enclosure com-plex, and are located as close as practical to the Containment wall; i.e., in almost all cases, isolation valves will be located immediately after the penetration assembly. There will, however, be exceptions, such as the case of the main steam lines which require a series of safety valves before the j isolation valve. Also, there will be some exceptions due to normal struc-l tural design arrangements. Actual lengths of pipe from penetrations to the isolation valves outside Containment have been kept to a minimum. 20. Deleted l 21. Deleted l l 1 Rev. 7 l 1L----. m -

TABLE 6.2.4-1 (Page 12) Containment Isolation Valve and Actuator Data 22. During the injection phase of safety injection, these valves are closed. Water from the refueling water storage tank (FWST) provides approximately 48 feet of head on these valves (* 20.8 psig). This head will preclude any leakage through this penetration. During the recirculation phase of safey injection, these valves are open to provide flow to ND pump suction. 23. The main steam, feedwater, auxiliary feedwater, sample and blowdown lines are all connected to the secondary side of the steam generator which is kept at a higher pressure than the primary side soon after a LOCA occurs. Any leakage between the primary and secondary sides of the steam gene-rator is directed inward to the containment. 24. Deleted 25. Type C leak test not required by 10 CFR 50, Appendix J because these containment isolation valves: a. Do not provide a direct connection between the inside and outside atmospheres of the primary reactor containment under normal opera-tion. b. Are not required to close automatically upon receipt of a contain-ment isolation signal in response to controls intended to effect containment isolation, and c. Are not required to operate intermittenly under post accident conditions. 26. These valves are sealed against leakage by the Containment Valve Injec-tion Water System as discussed in Section 6.2.4.4. 27. Type 8 test performed per 10 CFR 50, Appendix J. 28. Deleted 29. This system is required to be in operation during the Type A test in order to maintain the unit in a safe condition. Therefore, this penetra-tion will not be vented and drained. l 30. This penetration is a part of a closed system inside containment. All l piping inside containment is seismic Category 1 and therefore not subject to rupture as a result of a LOCA. This penetration will not be drained i and vented for the Type A test. I t l Rev. 7

Table 6.2.4-2 (Page 1) Comparison of Containment Purge System With Branch Technical Position CSB 6-4, Revision 2 Paragraph Compliance Status B-1-a The Containment Isolation System is des-cribed in Section 6.2.4. Operability of the containment purge isolation valves is currently under review by the Equipment Qualifications Branch. (Reference E. G. Adensan's April 1, 1982 letter to W. O. Parker.) B-1-b The system has a total of nine supply and exhaust penetrations (as shown on Figure 9.4.5-1) in order to serve the upper and lower compartments of the ice condenser containment and to limit the penetration sizes. B-1-c Containment penetration and isolation valve sizes are listed in Table 6.2.4-1. Note that SRP 6.2.4 states that the 8 inch maximum duct diameter recommendation is not applicable since purge system opera-tion is Technical Specification limited to < 90 hours per year during power, startup, hot standby and shutdown modes of operation. B-1-d In Compliance. See Section 6.2.4. l B-1-e In Compliance. See Section 6.2.4. l B-1-f In Compliance. See Section 6.2.4. B-1 g The potential for entrainment of debris in the containment purge isolation valves is minimized by the ice condenser contain-ment design. Since the lower containment purge isolation valves will be closed during power, startup, hot standby and shutdown ( modes of operation (Technical Specifi'ation c requirement), any debris generated from the postulated LOCA would be confined to the lower compartment by the ice condenser's filtering the debris. The upper contain-ment isolation valves are not in the ice condenser blowdown stream, further reducing Rev. 7 New Page l l

Table 6.2.4-2 (Page 2) Comparison of Containment Purge System With Branch Technical Position CSB 6-4, Revision 2 Paragraph Compliance Status the probability of debris entrainment in the valves. B-2 In Compliance. See description of Contain-j ment Purge System in Section 9.4.5. B-3 In Compliance. See description of Contain-ment Auxiliary Charcoal Filter System in Section 9.4.6. B-4 In Compliance. See Sections 6.2.4 and 6.2.6. B-5-a The loss-of-coolant accident analysis does B-5-b not assume the purge valves are open at the onset of the postulated LOCA. Purge system operation is limited to < 90 hours per year in accordance with SRP 6.2.4 guide-lines. Lower compartment purge valves are closed during power, startup, hot standby and shutdown modes of operation. B-5-c If the system is in operation at the start I of an accident the amount of air lost while the valves are closing is insignificant. The minimum containment pressure analysis is presented in Section 6.2.1.5. B-5-d An allowable leak rate for these valves will be developed in the Type "C" test program. E i Rev. 7 New Page ,,r-,, ,, - ~ ~ - - - ,,. = - ~ - - - -

i Core Performance Branch I e

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6 CNS The absorber rods are fastened securely to the spider. The rois are first threaded into the spider fingers and then pinned to maintain joint tightness, after which the pins are welded in place. The end plug below the pin position is designed with a reduced section to permit flexing of the rods to correct for,small misalignments. The overall length is such that when the assembly is withdrawn through its full travel the tips of the absorber rods remain engaged in the guide thimbles so that alignment between rods and thimbles is always maintained. Since the rods are long and slender, they are relatively free to conform to any small misalignments with the guide thimble. After each refueling, prior to startup, control rod worth measurements are performed on the control banks for-at least 1/3 of the total predicted worth of all groups. Normal reload design practice dictates shuffling of RCCA's from control to shutdown banks for subsequent cycles. Greater than expected worth loss would be detected by this surveillance. 4.2.2.3.2 Burnable Poison Assembly Each burnable poison assembly consists of burnable poison rods attached to a holddown assembly. A burnable poison assembly is shown in the composite core component Figure 4.2.2-12. When needed due to nuclear considerations, burnable poison assemblies are inserted into selected thimbles within fuel assemblies. The poison rods consist of borosilicate glass tubes contained within Type 304 stainless steel tubular cladding which is plugged and seal welded at the ends to encapsulate the glass. The glass is also supported along the length of its inside diameter by a thin wall tubular inner liner. The top end of the liner is open to permit the diffused helium to pass into the void volume and the liner extends beyond the glass. The liner is flanged at the bottom end to maintain l the position of the liner with the glass. l The poison rods in each fuel' assembly are grouped and attached together at the I top end of the rods to a hold down assembly by a flat perforated retaining plate which fits within the fuel assembly top nozzle and rests on the adaptor plate. The retaining plate and the poison rods are he'ld down and restrained i I against vertical motion through a spring pack which is attached to the plate and is compressed by the upper core plate when the reactor upper internals assembly is lowered into the reactor. This arrangement ensures that the poison rods cannot be ejected from the core by flow forces'. Each rod is permanently attached to the base plate by a nut which is lock welded into place. l The cladding of the burnable poison rods is slightly cold-worked Type 304 stainless steel. All other sturctural materials in the assembly are Types 304 l or 308 stainless steel except for the springs which are Inconel-718. The bor-osilicate glass tube provides sufficient baron content to meet the criteria i discussed in Section 4.3.1. 4.2.2.3.3 Neutron Source Assembly 1 4.2-13 Rev. 7}}