ML20245A571

Forwards Resolution of Outstanding Advanced BWR Std SAR Issues Resulting from Ge/Nrc 890531 & 0601 Meetings.Proposed New Chapter 15 Analysis for Events Impacted by Implementation of Two motor-generator Sets Summarized

ML20245A571
Person / Time
Site:	05000605
Issue date:	06/19/1989
From:	Marriott P GENERAL ELECTRIC CO.
To:	Chris Miller Office of Nuclear Reactor Regulation
References
MFN-38-89, NUDOCS 8906220068
Download: ML20245A571 (65)

Text

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'W GE Nuclear Energy .

..J Ceneral Electre Compary 175 Curtner Amue. San Jose. CA 95125 '

1 MFN No. 38-89 June 19,1989 j

l Docket No. STN 50-605 -

y 1

Document Control Desk U.S. Nuclear Regulatory Commission  :

Washingt.on, D.C. 20555 j Attention: Charles L. Miller, Director:

Standardization and Non-Power Reactor Project Directorate I-l

Subject:

Resolution of Outstanding ABWR SSAR Issues. 3 i

Enclosed are thirty four (34) copies of the resolution of outstanding ABWR Standard Safety Analysis Report (SSAR) issues resulting from the May 31,1989 -

and June 1,1989 GE/NRC meeting in San Jose. The resolution of the issues is provided in Attachment 1 in the form of changes to the SSAR which GE intends to amend in the near future.

Also included in this transmittal is Attachment 2 which summarizes our q proposed new Chapter 15 analysis for events impacted by the implementation of i two motor-generator sets and our plans to provide additional of the. i classification of selected events. Attachment 2 includes a summary description '

of these motor-generator sets.  ;

Finally, Attachment 3 provides a draft amendment to the SSAR which' updates .j Subsec'. ion 5.4.5," Main Steamline Isolation System". The major change is in the main steam isolation valve (MSIV). Following an extended and thorough review of MSIV operating experience by the Japanese ABWR Project, the decision was made to use the MSIV design installed in current operating BWRs and apply the improvements to this basic design which have been demonstrated ,

in Japan. l l

Sincerely, P. W. Idlarriott, Manager Licensing and Consulting Services lfY 8906220068 890619 * &1 j St -

PDR ADOCK 0500060'5 A PDC

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w Document Control Desk j U.S. Nuclear Regulatory Commission Washington, D.C. 20555 June 19,1989 j Page 2 MFN No. 38-89 1

cc: D. R. Wilkins (GE)

F. A. Ross (DOE)

J. F. Quirk (GE)

D. C. Scaletti (NRC)

G. Thomas (NRC) l t:

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! Document Control Desk l U.S. Nuclear Regulatory Commission Washington, D.C. 20555 June 19,1989 Page 3 MFN No. 38-89 trc:

L. S. Gifford (GE Rockville)

R. C. Mitchell (GE)

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ATTACHMENT 1 f 1

RESOLUTION OF OUTSTANDING ASWR SSAR ISSUES  ;

l l

.Section Subleet 3.1.2 & Standby liquid control system 9.3.5 l

l 4.6 Fine motion control rod drive i

5.2.2 Overpressure protection

-i 5.2.5 Leak detection 5.4.6 & Reactor core isolation cooling system l 9.2.9 5.4.7 Residual heat removal system 1

1 6.2.6 Containment leckage testing l 6.3.3 Emergency core cooling system 9.3.5 Standby liquid control system App. 1A TMI action plan items l

'., ABWR

' Standard Plant 3 12 /9.3.5 2 w aooxn REV A

.5 (5) 7.2 Reactor Trip System The circuitry for manual insertion or with-drawal of control rods is completely independent (6) 7.7.1.2 Rod Control and Information of the circuitry for reactor scram. This and System -Instrumentation and separation of the scram and normal rod control 7.7.2.2 Controls functions prevents failures in the reactor manual control circuitry from affecting the (7) 15 Accident Analyses scram circuitry. Two sources of energy (accumulator pressure and electrical power to 3.1.23.7 Criterion 26 - Reactivity Control the motors of the fine motion control rod System Redundancy and Capability drives, FMCRDs) provide needed control rod insertion performance over the entire range of 3.1.23.7.1 Criterion 26 Statement reactor pressure (i.e., from operating conditions to cold shutdown). The design of the Two independent reactivity control systems control rod system includes appropriate margin ofdifferent design principles shall be provided, for malfunctions such as stuck rods in the One of the systems shall use control rods, pre- unlikely event that they do occur. Control rod ferably including a positive means for inserting withdrawal sequences and patterns are selected the rods, and shall be capable of reliably con- prior to operation to achieve optimum core trolling reactivity changes to assure that under performance and, simultaneously, low individual conditions of normal operation, including rod worths. The operating procedures to anticipated operational occurrences, and with ' accomplish such patterns are supplemented by the appropriate margin for malfunctions such as stuck rod pattern control system, which prevents rod sods, specified acceptable fuel design limits are withdrawals yielding a rod worth greater than not exceeded. The second reactivity control permitted by the preselected rod withdrawal system shall be capable of reliably controlling pattern. Because of the carefully planned and the rate of reactivity changes resulting from regulated rod withdrawal sequence, prompt planned, normal power changes (including renon shutdown of the reactor can be achieved with the burnout) to assure that acceptable fuel design insertion of a small number of the many limits are not exceeded. One of the systems independent control rods. In the event that a shall be capable of holding the reactor core reactor scram is necessary, the unlikely suberitical under cold conditions. occurrence of a limited number of stuck rods will not hinder the capability of the control 3.1.23.7.2 Evaluation Against Criterion 26 rod system to render the core subcritical.

N SsfLT Two independent reactivity control systems - TLv - J :odcr mdc.; icaci. . g i ;. J A

utilizing difference design principles are pro- myacu , p=Wd:d by :h: :=:: x'=hj=

vided. The normal method of reactivity control  ;,a

% .xy*:; :=::= :::b:: c!:u , '-

en. ploys control rod essemblics which contain pen!b!: :Mx *he :yp: . ' : = ::' 1 boron carbide (B4C) powder. Positive insertion d arg n m m ry ' p' - a d =^ 1 p^ -

of these control rods is provided by means of the ch.usc , (b;NdE; n;;; 5 :::::). Fh control rod drive electrical and hydraulic sys- - u :Leiy ac~; :h;; ;n;;; ik b xddr!y tem. Th: control rods are capable of reliably h;.an d :: ' ==' := c!= (p a rp :: n:),

contro!!ing reactivity changes during normal :h; a M" ::: ==:d f::: d=!;: " '

operation (e.g., power changes, power shaping, 5:xxx :h: pen : w=:p &F x h: :.!Enbk xenon burnout, normal startup and shutdown) via inith! cp;;=b; ::ca :: :hn :h: pump : x t operator centrolled insertions and withdrawals. "" ;;: " b:: :h x 9;h:.

The contro! rods are also capable of maintaining the core within acceptable fuel design limits du- The control rod system is capable of holding ring anticipated operational occurrences via the the reactor core suberitical under cold automatic scram function. The unlikely occur- conditions, even when the pair of control rods rence of a limited number of stuck rods during a of highest worth controlled by an hydraulic scram will not adversely affect the capability to control unit is assumed to be stuck in the fully maintain the core within fuel design limits. withdrawn position. This shutdown capability of Amendment 1 3.119

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l l A standby liquid control system containing a neutron-absorbing sodium pentaborate solution is the independent backup system.

This system has the capability to shut the recctor down from full power and maintain it in a suberitical condition at any time during the core life. The reactivity-control provided.to reduce reactor power from rated power to a shutdown condition with the control rods withdrawn in the power pattern accounts for the reactivity effects of xenon decay, elimination of steam voids, change in water density due to the reduction in water temperature, Doppler'effect in uranium, change in neutron leakage.

from boiling to cold, and change in rod worth as boron affects the neutron , migration length.

l j

l

,g MM Standard Piant 23A6100AE RFV.A the control rod system is made possible by There is no credible event applicable to the '

designing the fuel with burnable poison /Ol2 ABWR which requires combined capability of the

03) to control the high reactivity of fre.h control rod system and poison additions. The fuel. L . L w o, Ju u a o e, ..t,_::v.:d u. _ __.. ' ABWR design is capable of maintaining the

.. . _ _ , . . n s. , _ . 2 2 ,_

reactor core subcritical, including allowance

.xdn;S

' =b;

M=! = dE=

::I  ?;; for a pair of stuck rods controlled by an

i; :=!=&; ;;i.;: C;..;c.;; 27 hydraulic control unit (HCU), without addition of any poison to the reactor coolant. The The redundancy and capabilities of the primary reactivity control system for the ABWR reactivity control systems for the BWR satisfy during postulated accident conditions is the the requirements of Criterion 26. control rod system. Abnormalities are sensed, and, if protection system limits are reached, For further discussion, see the following corrective action is initiated through automatic sections: insertion of control roda. High integrity of the protection system is achieved through the Chapter / combination of logic arrangement, actuster Section Iilk redundancy, power supply redundancy, and physical separation. High reliability of (1) 1.2.1 Principal Design Criteria reactor scram is further achieved by separation of scram and manual control circuitry, (2) 4.6 Functional Design of Reactivity individual HCU controlling a pair of control Control Systems rods, and fail-safe design features built into the rod drive system. Response by the reactor (3) 73 Engineered Safety Feature protection system is prompt and the total scram Systems time is short.

(4) 7.4.1.2 Standby Liquid Control System - In the very unlikely event that more than one and Instrumentation and Controls control rod fails to insert and the core cannot 7.4.2.2 be maintained in a subcritical condition by con-trol rods alone as the reactor is cooled down (5) 7.7.1.2 Rod Control and Information subsequent to initial shutdown, the standby li-and System - Instrumentation and quid control system (SLCS) can be actuated to 7.7.2.2 Controls insert soluble boron into the reactor core. The SLCS has sufficient capacity to ensure that the 3.1.23.8 Criterion 27 - Combined Reacthity reactor can always be maintained subtritical; Control Systems Capability and, hence, only decay heat will be generated by l the core which can be removed by the RHR System, 3.1.23.8.1 Criterion 27 Statement thereby ensuring that the core will always be coolable.

The reactivity control systems shall be de-signed to have a combined capability in conjunc- The design of the reactivity control systems tion with poison addition by the emergency core assures reliable control of reactivity under cooling systems of reliably controlling reacti- postulated accident conditions with appropriate vity changes to assure that, under postulated margin for stuck rods. The capability to cool accident conditions and with appropriate margin the core is maintained under all postulated for stuck rods, the capability to cool the core accident conditions; thus, Criterion 27 is is maintained. satisfied.

3.1.23.8.2 Evaluation Against Criterion 27 For further discussion, see the following sections:

Amendment 1 3.1 20 I

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33A6100All Standard Plant REV A i

nuclear system safety / relief valves begin to Criterion 26: The SLCS is the second reactivity _

relieve pressure above approximately 1100 psig. control system required by this criterion.4h-Therefore, the SLCS positive displacement pumps 7 '----" " !E L ::':::':: d: ce :pp?;

cannot overpressurize the nuclear system. '!EH :E: "' Cf E d.

Only one of the two standby liquid control Criterion 27: This criterion applies no I pumps is needed for system operation. If a specific requirements onto the SLCS and redundant component (e.g., one pump) is found to therefore is not applicable. See the General [

be. inoperable, there is no immediate threat to Design Criteria Section for discussion of shutdown capability, and reactor operation can combined capability. l continue during repairs. The time during which one redundant component upstream of the injection Criterion 29: The SLCS pumps and valves out. j valves may be out of operation should be board of the outboard drywell check valve are consistent with the following: the probability redunaant. Two suction valves, two pumps, and of failure of both the control rod shutdown two injection valves are arranged and crosstied capabili ty and the alternate component in the such that operation of any one of each results SLCS; and the fact that nuclear system cooldown in successful operation of the system. The SLCS takes several hours while liquid control solution also has test capability. A special test tank injection takes approximately two-and-one half is supplied for providing test fluid for the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Since this probability is small, consi- yearly injection test. Pumping capability, j derable time is available for repairing and injection valve operability and suction valve- I restoring the SLCS to an operable condition while operability may be tested at any time.

reactor operation continues. Assurance that the system will still fulfill its function during The SLCS is evaluated against the applicable repairs is obtained by demonstrating operation of regulatory guides as follows:

the operable pump.

Reculatorv Guide 1.26: Because the SLCS is a The SLCS is evaluated against the applicable reactivity control system, all mechanical (-

General Design Criteria as follows: components are at least Quality Group B. Those  ;

portions which are part of the reactor coolant Criterion 2: The SLCS is located in the area pressure boundary are Quality Group A. This is inside the secondary containment, outside drywell shown in Table 3.2-1.  !

and below the refueling floor. in this location, it is protected by the containment and Reculatory Guide 1.29: All components of the I compartment barriers from external natural SLCS which are necessary for injection of phenomena such as earthquakes, tornadoes, neutron absorber into the reactor are Seismic hurricanes and floods and internally from effects Category I. This is shown in Table 3.21.

of postulated events (e.g., DB A-LOCA).

ASB 3-1 and MEB 3-1 Criterion 4: The SLCS is designed for the expected emironment in the secondary containment Since the SLCS is located within its own and specifically for the area in which it is compartment inside the secondary containment, it located. In this area, it is not subject to the is adequately protected from flooding, torna-more violent conditions postulated in this does, and internally / externally generated criterion such as missiles, whipping pipes, and missiles. SLCS equipment is protected from pipe discharging fluids. break by providing adequate distance between the seismic and nonseismic SLCS equipment, where Criterion 21: Criterion 21 is applicable to such protection is necessary. In addition, protection systems only. The SLCS is a reactiv- appropriate distance is provided between the ity control system and should be evaluated SLCS and other high energy piping systems.

, against Criterion 29.

Amendment 2 9.3-5

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. 9 ABM 2arnooxs Standard Plant Rn n QUESTION 440.105 We understand that boron mixing tests were performed for optimizing the location of boron injection. Describe the test criteria and the test results. (9.3.5)

RESPONSE 440.105 Boron mixing tests were performed in a 1/6 scale three dimensional model of ABWR with reactor internal pumps. In these tests, the overhead type high pressure core spray sparger was used as the primary injection location. Injection st the reactor internal pump suction was examined as a backup location. The objective of the tests was to understand the mixing phenomenon when a boron solution is injected into the reactor coolant, and to determine the mixing coefficient, n, which is a measure of the mixing efficiecey or effectiveness as defined as:

Concentration ofinjection solution at a measured location (region of the model) n=

Concentration if well mixed with entire modelinventory A coefficient of unity thus represented the equivalent of a completely mixed solution. Incomplete mixing was characterized by coefficients less than unity in some regions of the model and greater than unity in others. Transit time is defined as the time required for the injected solution to travel from ~the point of injection to the region of interest.

Based on the data analyses, the following conclusions were drawn:

(1) Boron injected through HPCF will reach the core in all conditions including time after hot shutdown. No stratification was found anywhere in the vessel for all the tests.

(2) HPCF is the recommended injection location. If HPCF were not the design basis, injection through four recirculation pump suction locations will also provide good mixing.

QUESTION 440.106 In SSAR Section 9.3.5.3, under criterion 26,it is stated that *The requirements of this criterion do not apply within the SLCS itself.* Elaborate on this assumption. (9.3.5)

RESPONSE 440.106

-t h e, t elswh8t e d s4 M Sw4 1bAF b e. 4.w t-4.vmoV4 E'

-CJ.ai:c; 20 ;;;.::: :h:: ::.: 'ad:p::d::: :=: ' .:y ::::::1 ;y::::: := aqu!=d. SLCS n:Y!n

he ;;;;;;;;; e,f 5:':; = ~!:d:p::d=* :=:: : y ==::0! :y:::=*; her:=:, 5 den ::: n: :fy :h:

n;;!n== : the *::: ef th: ty:!:r: :E:!! ::: ::::: ! ::d;" :: th:: *:h: :=::d :=::' ::y 22:;;!

y:::= :E:!' b: up:b!: cf =li;bly ;;;;ro!!!:g :h; re:c ei scac;'..:y ;h;.;gn ;;;t!;bg f:;;.

p!==d, :::  ! p:ver chstge: (!::!ud!:; n :: 5 :::::)* Th: ft::: = ;:!= = ::

• cf= :=-

=:an;d by :h: = :: ! cd :y:::=. Th: :==d nq :n==: !: =:!:E:d by th: :=Ine!::!= :y::::

bj ujig :h =:!n !::!:- Der n::. Th:= fen, ;;;; :h;7gh :h; SLCS e ;; .;Lr Lui . _ ;.;;y

= :=1 :y;::= *:h: nq:;r==!: ef :E!: ri:::!:: dc ;;: :qply nhi :h; SLCS hacif

• QUESTION 440.107 In SSAR Section 9.3.5.3, under criterion 27,it is stated that 'this criterion epplies no specific requirements onto the SLCS and therefore is not applicable.* Describe in detail the justification for the above statement. (9.3.5)

Amendment 4 20.M54

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. 1 4.g l

., MM 2sA61ooAT l Remndard PInnt arv s (

i f QUESTION 440.4 i In Figure 4.6-8a, CRD system P&ID, sheet 1, piping quality classes AA D, FC D, FD D, FD B, etc. ,

are shown. Submit the document which explains these classes and relates them to ASME code classes. ]

RESPONSE 440.4 This information is scheduled to be included in Section 1.7. Essentially, the first two letters .,

of the codes specify the pipe primary pressure rating (150 lb.,900 lb., etc.) the type of service j (conde3 sate or reactor water, steam, etc.), and material (carbon or stainless steel). The symbols 'j

'A*, 'B' and "C" represent ASME Section III, code Classes 1,2, and 3, respectively. The symbol *D* j represents ASME Section 8, or ANSI B31.1 or other equivalent codes.

QUES"I1ON 4403 j i

In Figure 4.6-8b, the leak receiver tank is shown. What is the function of this tank? How big is j this tank? Will a high level in the tank impact the operation of the control rod drive? . ]

RESPONSE 440J I

This leakage collection tank is no longer part of the design. The intent of the leakage collec-  !

tion system was to assist the operator in identifying which drives were potential candidates for seal I replacement during plant outages, which would facilitate plant maintenance planning. However, the de-  ?

sign could not provide the level of differentiation of leakage between individual drives needed for this purpose and was therefore deleted. An updated P&ID (Figure 4.6-8b) will be provided by December 31,1968 to document this change.

t I QUESTION 440.6 Identify the essential portions of the CRD system which are safety related. Confirm that the safety related portions are isolable from non essential portions. (4.6)

RESPONSE 440.6 He essentiti portions of the CRD system which are safety-related are:

(a) The hydraulic control units (HCUs),

(b) The scram insert piping from the HCUs to the fine motion control rod drives (FMCRDs), and (c) The FMCRDs (except the motors)  !

The non-essential portions of the CRD system interface with the essential portions at the follow-ing connections to the HCUs:

(a) The accumulator charging water line (b) The FMCRD purge water line,and (c) The scram valve air supply from the scram air header.  ;

i Amandaunt 3 20.M4

. o ABWR 23xax4r Standard Plant nrv n .

The safety-related portions of the HCU and the scram function are protected against failure in the non essential portions of the charging water and purge water lines by check valves. Also,instrumeo-tation in the charging water line provides signals to the reactor protection system to cause reactor IN SW scram in thethe causes event scramofvalves loss of charging to actuate, water inpressure.

resulting LossThis reactor scram. of pressure in theisscram fail-safe feature the sameair header as provided on current BWR designs using locking piston type control rod drive.

6 QUESTION 440.7 In the old CRD system, the major function of the cooling water was to cool the drive mechanism and its seals to preclude damage resulting from long term exposure to reactor temperatures. What is the function of purge water flow to the drives? (4.6)

RESPONSE 440.7 K The function of the purge water flow to the fine motion control rod drives is to prevent reactor water from entering the drive housing during operation. This will minimize crud buildup in the drive housing and reduce operator exposure during drive maintenance.

QUESTION 440.8 We understand that the LaSalle Unit 2 fine motion control rod drive demonstration test is stillin progress. Submit the test results as soon as it is available.

RESPONSE 440.8 i_

At the current time, the LaSalle Unit 2 fine motion control rod drive demonstration test is ex- '

pected to be terminated in October 1988. The final report for the FMCRD in-Plant Test Program, which will include the LaSalle Test results, will be formally issued in September 1989.

QUESTION 440.9 In the present CRD system design, the ball check valve ensures rod insertion in the event the accu-mulator is not charged or the inlet scram value fails to open if the reactor pressure is above 600 psig. Confirm that this capability still exists in the ABWR design. (4.6)

RESPONSE 440.9 The ABWR control rod design does not have the capability of the locking piston control rod design to insert hydraulically using reactor pressure in the event of a failure in the hydraulic control units (i.e., scram valve fails or accumulator is not charged). However, the fine motion control rod drive (FMCRD) has a diverse means of inserting the control rod using electric motor run-in if hydrau-lie scram fails. This feature provides the FMCRD with the capability to insert the control rod over the entire range of reactor operating pressures.

QUESTION 440.10 In section 4.6.2.3.1, it is stated the scram time is adequate as shown by the transient analyses of Chapter 15. Specify the scram time. (4.6.2.3.2.1)

Amendment 3 20 M 5

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The FMCRD provides the following functions:

1. Normal rod positioning in response to commands from the Rod Control and Information System

2. Rapid control rod insertion (scram)

3. Scram follow function (post-scram electric motor run-in)

4. ATWS FMCRD run-in, and

5. Selected control rod run-in (for stability control).

Of these, only the hydraulic scram function (Item 2) is classified as a #

safety-related function. The other functions, all of which involve positioning the rods by means of the EdCRD electric motors, are designed for high reliability but are not classified as safety-related. Therefore, because the FMCRD motor does not perform a safety-related function, it is classified j as non Class IE.

j 1

With respect to ATWS in particular, the FMCRD run-in function is considered )

an ATWS mitigating system. As such, the NRC design guidance regarding system j and equipment specifications for 10CFR50.62, as defined in the Federal i Register, Volume 49, No. 124, pg 26042 (dated 6/26/84), was applied. This l guidance states that the ATVS mitigatin5 systems are not required to be '

safety-related; therefore, the FMCRD motors are not required to be Class 1E.

However, the automatic FMCRD run-in function for ATUS is designed to provide high reliability. Some features to be noted are:

1. FMCRD run-in provides means of control rod insertion that is diverse from the hydraulic insertion of both the normal scram (RPS generated) and ATWS ARI (venting of scram air header). Both of these independent functions must fail before FMCRD run-in is needed to shut down the reactor.

2. The automatic FMCRD run-in utilizes initiation signals (high reactor pressure or low reactor water level 2) which are diverse from the RPS.

3. The FMCRD run-in controls and instrumentation are powered from non-divisional, non-interruptible DC power independent from RPS power.

4. The FMCRD motors are connected to the divisional power buses which are connected to the emergency diesel generators. This allows FMCRD run-in during any loss-of-offsite power event. The i divisional power assignments throughout the core for the FMCRD motor power supplies are in a " checkerboard" pattern. This arrangement provides the capability to achieve hot shutdown even with failure of offsite power and one of the diesel generators (a degraded ATWS condition beyond the design basis). Under these t . _ . __

o .

., 8 ( co u r iwso) circumstances the operator would have time to reestablish offsite power or startup of the failed diesel generator to achieve cold shutdown. As a last resort, manual initiation of the SLCS would always be available to achieve cold shutdown.

5. Continuous self-test features provide assurance that the FMCRD run-in logic is capable of functioning as designed. No single logic failure can result in the failure of more than one rod to insert.

The above features contribute to the high reliability of the ATUS FMCRD l run-in feature of the ABkT design. Classification of the motors as i safety-related (Class 1E) is not warranted, either by current regulatory

requirements or from a reliability standpoint.

l

I 5,2 7

. ABM 2s461oo41 Standard Plant REV B- ,

and reclosure in the safety mode occur at a higher pressure than the respective " normal" opening and reclosure in the relief mode (i.e., as normally initiated by pressure sensors in the steam lines).

The upper reclosure limit (reclosure point at 96% of opening setpoint) is a reasonable upper limit which will serve to limit the number of times the SRV will open and reelose in case of a pressure transient causing valve operation in the safety mode. It permits the valve to sen.ain open longer and cycle less often (as compared with prior allowed upper reclosure limits, which were set at 97% and 98% of opening setpoint in the past).

The %% upper limit also provides an extra measure of insurance that deviations in manufacturing l tolerances, actual back pressure in service, and other such variables do not result in an SRV with I negative blowdown, in which buildup of backpressure would reclose the valve before it could perform its pressure relief function.

QUESTION 440.22 In Figure 5.1.3a the SRV solenoid valves are not shown as DC powered as they should be. Note 8 states that Nalve motor operators and pilot solenoids are ac operated unless otherwise specified."

RESPONSE 440.22 At the next revision, Figure 5.1.3a will be revised to show that the SRV solenoids are DC powered.

QUESTION / RESPONSE 440.23 This question number not used. _

QUESTION 440.24 Confirm that SRVs are designed to meet seismic and quality standards consistent with the recommendations of Regulatory Guides 1.26 and 1.29.

RESPONSE 440.i4, he SR 8 C#d (,# ' d3 byb A f, c me4 Na M4 9 Gede: n.16 e c l. a. 9 (1) Tests required by ASM_3E Code Section III for Class I valves are imposed in the ABWA SRV equipment specification. Analyses equivalent to those required by ASME III are performed in accordance with the requirements of MITI 501 (the Japanese equivalent of ASMEIII).

(2) SRV's are Class IE (active, safety related, electrically driven). It is currently planned to impose a complete environmental qualification program on the entire SRV, including both electrically and pneumatically driven compocents of the actuator system. This program will be in compliance with NUREG-0588 requirement < 3 6s v- e v-% mc.,W e.rd pc w (

QUESTIONS / RESPONSES 440.25 through 440.27 g g4 .p , g, q

" " S S E, .

These questions numbers not used. 4 ) a f a wh8 8p " ' V" \

• A' l

QUESTION 440.28 .

In SSAR Table 1.8-19,it is stated that branch technical position RSB 5 2 is applicable for ABWR.

How does the ABWR design comply with BTP RSB 5 2? [

Amendment 3 20.3-101

, Mkb 23A6100AD Standard Plant arv c so that they are sensitive to air temperature (1) Within reactor building:

only and not radiated heat from hot piping or i equipment. Increases in ambient temperature will (a) Main steamline and RCIC steamline high indicate leakage of reactor coolant into the flow '

area. These monitors have sensitivities suitable for detection of reactor coolant leakage into the (b) Reactor vessellow water level monitored areas of 25 gpm or less (8.35 pounds of steam is equivalent to 1 gallon of condensate). (c) High flow rate from reactor building The temperature trip setpoint will be a function - sumps outside drywell  ;

of the room size and the type of ventilation I provided. These monitors provide alarm and (d) High temperature in equipment areas of indication and recording in the control room and RCIC, RHR, and the hot portions of the will trip one isolation logic to close selected RWCS isolation valves, e.g., the main steam tunnel 1 monitors will close the main steamline and MSL (c) RCIC turbine exhaust line high diaphragm 1 drain isolation valves and others, (Table 5.2-6). pressure Leakage detection will be provided in the (f) High differential flow rate in RWCS turbine building. The turbine building monitors piping will also alarm and indicate in the control room and trip the isolation logic to close the main (g) High radiation in the RHR RWCS, and RIP steamline isolation valves and MSL drain (and FPC) reactor building cooling water

{

l isolation valves when leakage reaches 25 gpm. heat exchanger discharge lines i Large leaks external to the drywell (e.g.,

process line breaks outside of the drywell) are (h) RCIC steamlinelow pressure detected by low reactor water level, high process line flow, high ambient temperatures in the (2) Within steam tunnel (between primary piping or equipment areas, floor or equipment containment and turbine building)-

drain sump activity, high differential flow (RWCS I only), low steamline pressures or low main (a) High radiation in main steamlines (steam condenser vacuum. These monitors provide alarm tunnel) and indication in the control room and will trip the isolation logic to cause closure of (b) Main steam tunnel high arrbient air appropriate system isolation valves on the temperature indication of excess leakage (Table 5.2-6).

Intersystem leakage detection is accomplished W G. L. '...- w!. ,, -f by monitoring radiation of the :cactor building (3) Within turbine building (outside secondary cooling water (RBCW) coolant return lines from containment):

the reactor internal pumps (RIP), residual heat removal (RHR), and reactor water cleanup system (a) Main steamlinelow pressure (RWCS) and fuel pool cooling heat exchangers.

This monitoring is provided by the process (b) Low main condenser vacuum radiation monitoring system.

(c) Turbine building ambient temperature in Listed below are the variables monitored for areas traversed by main steam lines detection of leakage from piping and equipment located external to the primary containment 5.2.5J Laak Detection Instrumentation and (drywell): Monitoring Amendment 7 5.2 20

ABM .

mandard Plant 224stoors nry c 1

RWCS can be isolated first and thereby preserve are established at 25 spm andp/gpm, respec-the operation of tbc RCIC system for core cooling tively, if tbc high ambient temperature is due to leaks in nonessential systems. The delay is long- The total leakage rate limit is established low enough to permit the tunnel ventilation system to enough to prevent overflow of the sumps. The lower temperatures to below the RCIC isolation equipment drain sumps and the floor drain sumps, trip setpoint after the nonessential system leak which collect allleakage, are each pumped >ut by has been isolated. A time delay is provided for two 50 spa pumps.

RWCS differential flow isolation signals to prevent system isolation during RWCS surges. If either the total or unidentified leak rate limits are exceeded, an orderly shutdown can be The LD&lS is a four divisional system which is initiated and the reactor can be placed in a cold redundantly designed so that failure of any shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.-

single element will not interfere with a required detection of leakage or a required isolation. In' 5.2JA.2 IdentlBad Isabey Inalde Drywell .

the four division portions of the LD&lS, applied where inadvertent isolation could impair plant The valve stem packing of large power operated performance (e.g., closure of the MSIVs), any valves, the reactor vessel head flange seal and single channel or divisional component other seals in systems that are part of the malfunction will not cause a false indication of reactor coolant pressure boundary, and from which leakage and it will not cause a false isolation normal design identified source leakage is trip becanse it will only trip one of the four - expected, are provided with leakoff drains. The channels and two or more channels are required to nuclear system valves inside the drywell and the trip in order to cause closure of the main reactor vessel head flange are equipped with~

steamline isolation valves. The LD&lS thus double seals. The leakage rates from the inner combines a very high probability of operating valve stem packings and the reactor vessel head ,

when needed with a very low probability of fiange inner seal, which discharge to the drywell I i

operating falsely. The system is testable during equipment drain sump, are measurable during plant plant operation. operation. Leakage from the main steam SRVs, discharging to the suppression pool, is monitored 5.2J.3 ladicstlos in the Control Room by temperature sensors mounted in thermowells in  ;

the individual SRV exhaust lines. The thermowells j Leak detection methods are discussed in are located several feet from the vslve bodies so l Subsection 5.2.5.1. Details of some of the LD&lS as to prevent false indication. These temperature  !

alarms, recordings and other indications in the sensors transmit signals to the control room and control room are discussed in Subsections any temperature increase detected by these 5.2.5.1.1, 5.2.5.1.2, 5.2.5.2.1 a n d 5.2.5.2.2. sensors, that is above the ambient temperatures, .  !

Further details of the LD&lS control room indicates SRV leakage.

Indications are included in Subsections 7.3.1.1.2, 7.6.1.3 an d 7.7.1.7. 5.2JJ Unidentitled Imakage laside the Drywell  ;

5.2JA usalts for Itasctor Coolant IAskage $.2JJ.1 UBldestifled IAskap Rate j 5.2.5A.1 Totallmakage Rate . The unidentified leakage rate is the portion

, of the totalleakage rate received in the drywell i The total reactor coolant leakage rate con- sumps that is not identified as previously sists of all leakage, identified and unidenti- described. A threat'of significant compromise to fied, that flows to the drywell floor drain and the nuclear system process barrier exists if the equipt.aent drain sumps. The total leakage rate barrier contains a crack that is large enough to limit is well within the makeup capability of the propagate rapidly (critical crack length). The RCIC system (800 gpm). The total reactor coolant unidentified leakage rate limit must be low be-leakage rate limit is established at 9p gpm. The cause of the possibility that most of the identified and unidentified leakag rate limits Amondment 3 M 5.2 26

s

• \

8

.. )

. ABWR- -ooxr Standard Plant arv. s from

• Testing Procedures". As was indicated in Subsystem 5.2.5.7, the Position C8 requirements of RG 1.45 are satisfied, as, per the requirements, the leak detection systems of the ABWR are ' equipped with provisions to readily permit testing for operability and calibration during plant operations.*

The SSAR text provides example testing methods to show how provisions had been made to permit testing

- for operability and calibration during plant operations.

In the context of this question,

• Testing Procedures" are those viable methods which can be used during reactor operations to confirm the operability of specific leak detection systems, or are the )

methods which, because of design features or provisions, can be used to confirm that adequate calibration has been maintained, e.g., by the cross comparing or correlation of the signal outputs from two or more leak detection systems.

As an ' example of provisions in the design, the sump design for the ABWR requires that the sumps be configured such that the sump volume increases as a function of water level in the ratio of 16 gallons per vertical inch. The sump level monitoring is compatible with this sump configuration. By using sump pump timers, the rate at which a sump fills with reference to sump pump operations can l' ,

determine the degree of abnormalleakage collected in the sump. Also, the rate of actual sump level l change, whici. is also being monitored can determine the degree of abnormalleakage. Because of the required sump configuration, these two measures of the degree of abnormal leakage have a known correlation. As another example, the measurement of drywell air coolers condensate flow can be -

checked against sump level rate of change.

Similar examples of such

• Testing Procedures

• are methods as provided in Subsection 5.2.5.7 to show satisfaction or compliance with Position C8 requirements. l RESPONSE 430.3e Part e of Question 430 apparently requests discussion related to compliance with RG 1.45 Position C8 with respect to the possible inclusion of new limiting conditions in the ABWR Technical Specifications for the leakage collected outside the drywell, i.e., unidentified and identified leakage collected in the reactor building and ./... .... '..s., . .: .:n ___d . 4 floor drain (HCW) sumps and equipment drain (LCWj sumps.

Such inclusion for the ABWR Technical Specifications is not being proposed. As indicated at the outset of this response, the statement in Subsection 5.2.5.4.1 has been revised.

j

~

1 Ameadment 5 20.3-29

s.A A /s.2.s AMVR m-nrv c

- Standard Plant

~

the following suggested procedure: enough period to obtain meaningful data. An alternate means ofleak testing the outer f

(1) With the reactor at approximately 1250F and isolation valve is to utilize the previously normal water level and decay heat being re- noted steamline plug and to determine leak-moved by the RHR system in the shutdown age by pressure decay or by inflow of the cooling mode, all main steam isolation valves test medium to maintain the specific test are closed utilizing both spring force and pressure.

air pressure on the operating cylinder.

During pre startup tests following an exten-(2) Nitrogen is introduced into the reactor sive shutdown, the valves will receive the same  !

vessel above normal water level and into the hydro tests that are imposed on the primary connecting main steamlines and pressure is system.

raised to 20-30 psig. An alternate means of pressurizing the upstream side of the inside Such a test and leakage measurement program  !

isolation valve is to utilize a steamline ensures that the valves are operating correctly.  !

plug capable of accepting the 20 to 30 psig pressure acting in a direction opposite the 5.4.6 Reactor Core Isolation Cooling System hydrostatic pressure of the fully flooded reactor vessel. Rhnk . ef :h; ;n;;;; :er; heh.kr.

j r

<::E:;; :A: f" :h; g,1 th Cs.. ' S (3) A pressure gage and flow meter are connected j M:i . : p: Mfd r

• SM" ?H to the test tap between each set of main steam isolation valves. Pressure is held 5.4.6.1 Design Basis below 1 psig, and flow out of the space C between each set of valves is measured to The reactor core isolation cooling (RCIC) g gg,y establish the leak rate of the inside isola- system is a safety system which consists of a tion valve. turbine, pump, piping, valves, accessories, and {

instrumentation designed to assure that suffi- -

(4) To leak check the outer isolation valve, the cient reactor water inventory is maintained in reactor and connecting steamlines are flooded the reactor vessel to permit adequate core cool-to a water level that gives a hydrostatic ing to take place. This prevents reactor fuel head at the inlet to the inner isolation overheating during the following conditions:

valves slightly higher than the pneumatic test pressure to be applied between the (1) aloss-of-coolant (LOCA) event; valves. This assures essentially zero leakage through the inner valves. If neces- (2) vessel isolated and maintained at hot sary to achieve the desired water pressure at standby; the inlet to the inner isolation valves, gas from a suitable pneumatic supply is intro- (3) vessel isolated and accompanied by loss of duced into the reactor vessel top head. Ni- coolant flow from the reactor feedwater trogen pressure (20 to 30 psig) is then system; applied to the space between the isolation valves. The pistons are checked for leak (4) complete plant shutdown with loss of normal tightness. Once any detectable piston ring feedwater before the reactor is depressur-leakage to the drain system has been ac- ized to a level where the shutdown cooling l counted for, the seat leakage test is con- system can be placed in operation; or ducted by shuttirg off the pressurizing gas and observing any pressure decay. The volume (5) loss of AC power for 30 minutes, between the closed valves is accurately known. Correction for temperature variation Acceptence criteria II.3 of SRP Section 5.4.6 during the test period are made,if necessary, states that the RCIC system must perform its to obtain the required accuracy. Pressure function without the availability of any a c and temperature are recorded over a long power. Review Procedure !!!.7 further requires Amendment 7 5A-10

~ .

+.

C Evaluations of the reactor core isolation cooling system against the General Design Criteria (CDC) 5, 29, 33,.34 and 54 are provided in Subsection 3.1.2. Evaluations against the ECCS CDC 2,- 17, 27, 35, 36 and 37 are provided below.

Como11ance with CDC 2. The RCIC system is housed within the reactor building which provides protection against wind, floods, missiles and other natural phenomena. Also, RCIC system and its components are designed;to withstand earthquake and remain functional following a seismic event-.

Comoliance with CDC 17. _The RCIC is a part of the ECCS network. It is powered from a Class IE source independent of the HPCF power sources. Although RCIC is a single loop system, it is redundant to the two HPCF loops which comprise the high pressure ECCS (1-RCIC and 2-HPCF).

Since. independent-Class 1E power supplies'are provided, redundancy and single failure criteria are met, GDC 17 is satisfied.

Comoliance with GDC 27. As discussed in Subsection 3.1.2.3.8.2, the design of the reactivity control systems assures reliable control of reactivity under postulated accident conditions with appropriate margin for stuck rods.

The capability to cool the core is maintained under'all postulated accident conditions by the RHR system. Thus, GDC 27 is satisfied without RCIC system.

Como11ance with eqp__31. The RCIC in conjunction with HPCF, RHR and auto depressurization systems perform adequate' core cooling to prevent excessive fuel clad temperature during LOCA event. Detailed discussion of RCIC meeting this GDC is described in Subsection 3.1.2.

Como11ance with CDE_31. The RCIC system is designed such that in-service inspection of the system and its components is carried out in accordance with the intent of ASME-Section XI. The RCIC design specification requires layout and arrangement of containment penetrations, process piping, valves, and other critical equipment outside the ,

reactor vessel, to the maximum practical extent, permit access by perronnel and/or appropriate equipment foro testing and inspection of system integrity.

. C (cowwuso3 ComD11ance with GDC 37. The RCIC system is designed such that system and its components can be periodically. tested to verify operability. Systems operability is demonstrated

.by preoperational and. periodic testings in accordance with RG 1.68. Preoperational test will ensure proper functioning of controls, instrumentation, pumps and valves. Periodic testings confirm systems availability and operability through out the life of the plant. During normal plant operation, . a full flow pump test is being performed periodically to assure systems design flow and head requirements are attained. All RCIC system components are capable of individual functional testings'during plant operation. This includes sensors, instrumentation, control logics, pump, valves, and more. Should the need for RCIC operation occur while the system is being tested, the RCIC system and its components will automatically re. aligned to provide cooling water into the reactor. The above test requirements satisfy GDC 37.

l 3

se l

-i ABM isasioors  !

mandard Plant arv. c j i

b (6) General opens to accelerate the turbine to an initial- ]

peak speed of approximately 1500 rpm; now under Periodic inspections and maintenance of the governor control, turbine speed is returned'to : l turbine-pump unit are conducted in accor- the low limit turbine speed demand of 700 to' ]

dance with manufacturers instructions. 1000 rpm. After a predetermined delay (5 to 10 Valve p ition indication and instruments . sec), the steam supply ralve leaves the full tion alarms are displayed in the control closed position and the ramp generator is re-room. leased. The low signal select feature selects  !

I and sends this increasing ramp signal to the-gA4.2.8 System Operation governor. The turbine increases in speed until' the pump flow satisfies the controller set-Manual actions required for the various modes ' point. Then the controller leaves saturation,' ,

of RCIC are defined in the following subsections. responds to the input error, and integrates the  !

output signal to satisfy the isput demand. j gA4.24.1 StandbyMode . _

The operator has the capability to select l During normal plant operation, the RCIC . manual control of the governor, and adjust speed l '  !

system is in a standby condition with the motor- and flow (within hardware limitations) to match i operated valves in their normally open or mor- decay heat steam generation during the period of mally closed positions as shown in the piping and RCIC operation.

Instranentation diagram (P&ID) included in Figure 5.4-8. In this mode, the RCIC pump discharge The RCIC pump delivers the makeup water to line is kept filled. The relief valve in the the reactor vessel through the feedwater line, pump suction line protects against overpressure which distributes it to obtain mixing with the from backleakage through the pump discharge isola- bot water or steam within the reactor vessel.

tion valve and check valve.

C' gA4.2J.2 Emergency Mode (Transient Events The RCIC turbine will trip automatically upon l receipt of any signal indicating turbine-and thCA Events) overspeed, low pump suction pressure, high l turbine exhaust pressure, or an auto isolation Startup of the RCIC system occurs auto- signal. Automatic isolation occurs upon receipt l matically either upon receipt of a reactor vessel of any signalindicating:

low water level signal (Lev:12) or a high

• drywell pressure signal. During startup, the (1) A high pressure drop across a flow device in turbine control system limits the turbine pump the steam supply line equivalent to 300% of speed to its maximum normal operating value, the steady-state steam flow at 1192 psia. 1 controls transient acceleration, and positions j the turbine governor valve as required to -(2) A high arcatemperature.  ;

maintain constant pump discharge flow over the l

pressure range of the system. Input to the (3) A low reactor pressure of 50 psig m'mimum. i turbine governor is from the flow controller i monitoring the pump discharge flow. During (4) A high pressure between the turbine exhaust l standby conditions, the flow controller output is rupture diaphragms.  ;

saturated at its maximum value.

The steam supply, steam supply bypass and I When the RCIC system is shut down, the low cooling water supply valves will close upon  ;

signal select feature of the turbine control receipt of signal indicating high water level j system selects the idle setting of a speed ramp (Level 8) in the reactor vessel. These valves generator. The ramp generator output signal will reopen should an indication of low water i during shutdown corresponds to the low limit step level (Level 2) in the reactor vessel occur, and a turbine speed demand of 700 to 1000 rpm. The RCIC system can also be started, operated, -

and shut down remote manually provided On RCIC system start, the bypass valve F092g initiation or shutdown signals do not exist.

C ( pr.ovs d e.J +o n h ca.+ke wn eq of br6e Aamedmen 7 oygtN S ptAM M {g) 5+25

.i

~

. ABM 23A6100AH

.> Standard Plant REV B 9.2 WATER SYSTEMS 9.2.9 Makeup water system (conderisate) 9.2.1 Station Service Water System 9.2.9.1 Design Bases The functions normally performed by tbe .

(1) The makeup water condensate system (MUWC) station service water system are performed by the shall provide condensate quality water for systems discussed in Subsection 9.2.11. both normal and emergency operations when required. 1 9.2.2 Closed Cooling Water System (2) The MUWC system shall provide a required 'j The functions normally performed by the closed water quality as follows:  !

cooling water system are performed by the systems discussed in Subsections 9.2.11, 9.2.12, 9.2.13, Conductivity (p S/cm) 10.5 at 25 C and 9.2.14 Chlorides, as CI(ppm) 5 0.02 pH 5.9 to 83 at 25"C 9.2.3 DemineralizedWaterMakeup Conductivity and pH limits shall be applied System after correction for dissolved CO2 . (The .l) above limits shall be met at least 90% of ,

The functions normally performed by the demin- the time.)

eralized water makeup system are performed by the systems discussed in Subsections 9.2.8, 9.2.9 and (3) The MUWC system shall supply water for the .

9.2.10. uses shown in Table 9.2-1.

9.2.4 Potable and SanitaryWater (4) The MUWC system is not safety related.

Systems (5) The condensate storage tank shall have a Out of ABWR Standard Plant Scope. capacity of 2,110 m3 . This capacity was determined by the capacity required by the  ;

9.2.5 Ultimate Heat Sink uses shown in Table 9.2-2. -

Out of ABWR Standard Plant scope. See (6) All tanks, piping and other equipment"shall gpp[

Subsection 9.2.15.1 for interface requirements. be made of corrosion-resistant materials. ,

9.2.6 Condensate Storage Facilities 9.2.9.2 System Description '

and Distribution System The MUWC P&ID is shown in Figure 9.2-4 This j The functions of the storing and distribution system includes the following-  :;

of condensate are described in Subsection 9.2.9.

(1) A condensate storage tank (CST) is provid.

9.2.7 Plant Chilled Water Systems ed. It is of concrete construction with a stainless steel lining. The volume is shown The functions of the plant chilled water. in Table 9.2 3.

system are performed by the systems described in Subsections 9.2.12 and 9.2.13. (2) The following pumps take suction from the CST:

9.2.8 Makeup Water System (Preparation)

(a) RCICpumps Out of ABWR Standard Plant scope. See Subsection 9.2.15.2 for interface requirements. (b) CRD pumps (c) HPCFpumps (d) SPCU pumps Amendment 7 9.21

a .

.- o D

(7) The'HPCF and RCIC instrumentation, which initiates the automatic switchover of HPCF and RCIC. suction from-the CST header to the suppression pool, shAll be designed to safety-grade requirements (including installation with necessary seismic support).

~

4 l

l i

j l,

)

ABM 2miooxr

. Standard Plant REV B rerouted to the vessel should system initiation be required during CST to CST testing. There would

[ also be additional interlocks needed to prevent pumping suppressing pool water to the CST.

Complexity and cost would also increase from the required maintenance of the additional hardware, instrumentation and logic.

Suppression pool water quality will be maintained by the suppression pool cleanup system which is designed to be operated continuously. Although this quality may be somewhat less than that of the CST, it will be consistent with infrequent filling of RCIC piping during testing and possible injection to the RFV and therefore the reference draining, flushing and filling of the system is not necessarily required. Additionally, an decrease in personnel crposure realized by performing CST to CST testing (assuming draining, flushing and filling were required) might be fully or partially offset by an increase from the additional maintenance considerations.

QUESTION 440.42 Why are the power. supply for valves F063, F064, F076, FD77, and FD78 standby AC instead of DC?

RESPONSE 440.42 For the ABWR all RCIC, oth only the steam supply inboard r e L 4isolation

- 9 w iii valves, le<. u PF063 da f e.anda F076 are power AC **v t s 5 * *F054 ango wew sgurce. e + MO{'s t c.=t w,gr areg powered. FgP ower Sweth e t.o redt Valves F077 and FD78 have recently been removed from the ABWR RCIC design. The line where these valves were located performed a vacuum breaking function of the turbine exhaust line and had a separate containment penetration. The current ABWR RCIC configuration climinated F077 and F078 since the vacuum breaking function is now inside containment and has no sepasste penetration that mandates provision for F077 and F078. Figure 5.4 8 will be updated at its next revision to reflect the deletion this line of these valves.

The use of AC power source for F063 and F076 is considered technically acceptable for the following reasons:

(1) DC motors require considerably more maintenance than AC motors. Since they cannot be maintained during plant operating if they are located inside the drywell, DC MOV's would be far less reliable than AC.

(2) During loss of AC power RCIC system will remain operable since these valves are normally open.

QUESTION 440.43 Address the following TMI 2 action items related to RCIC.

(a) D.K.1.22 (b) D.K.3.13 (c) D.K.3.15 (d) D.K.3.22

(:) I'.K.3.24 Amendment 3 20.3 108

1 a

j

.. MM 23A6100AT Standard Plant REV.B 4 RESPONSE 440.43 j l Response to thi!. question is provided io Appendix 1A.

QUESTION 440.44 Confirm that the RCIC system meets the guidelines of Regulatory Guide'1.1 regarding pump Net Positive Suction Head (NPSH).

RESPONSE 440.44 The key requirement of Regulatory Guide 1.1 is that no credit be taken for containment pressurization when establishing the NPSH conditions for ECCS pumps. The RCIC meets this requirement. New Table 5.4-la provides the numerical evaluation of RCIC NPSH conditions assuming no containment pressurization and 770C (1700F) suppression pool water temperature In summary, the I RCIC pump will have over 2.5 feet NPSH margin at the most limiting condition.

J Note that NPSH calculation is based on suppression pool tempeneture of 770C, This is the maximum temperature RCIC is expected to operate. )

The following summarizes the transient / accident events which can result in increasing suppression pool water temperature. It summarizes the basis for concluding that RCIC NPSH conditions (14.7 psia i containment pressure,770C suppression pool water) are acceptable.

EVENT RCIC NPSH ASSESSMENT

• Reactor Isolation Event Maximum pool temperature well below 770C (approx. 490C), ,

Large Break LOCA Rapid vessel depressurization. RCIC not required.

Intermediate Size LOCA Rapid vessel depressurization. Reactor pressure less than 150 psig before pool temperature reaches 770C.

l Small Break LOCA RCIC operation not required when pool temperat.tre reaches I 770C.

Station Black Out Event RCIC suction is taken from the condensate storage tank (CST)

(8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> capability) with a capacity of 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> operation. Suppression pool (S/P) water is not expected to be used during this event.

However, if the automatie transfer of suction from the CST to S/P were to occur due to high S/P water level, a manually controlled override switch is operated to continue taking suction from the condensate storage tank.

'RCIC design basis requires 100 percent system flow only for rea-tor pressure > 150 psig.

l QUESTION 440.45 SRP 5.4.6 identifies GDCs 5,29,33,34 and 54 in the acceptance criteria. Confirm that the RCIC system, described in Chapter 5.4.6 of the SSAR, meets the requirements of the above GDCs.

Amendment 7 20.>109 l

8 1

. ABM 2mioars Standard Plsnt arv. e TABLE 5.4-la NET POSITIVE SUCTION HEAD (NPSH) AVAIIABLE TO RCIC PUMPS A. Suppression pool is at its minimum depth, El. -3740mm (-12.27 Ft).

B. Centerline of pump suction is at El. -7200mm .62 Ft).

C. Suppression pool water is at its maximcm temperatue for the given operating mode, 77'C (170'F).

D. Pressure is atmospheric above the suppression pool.

E. Maximum suction strainer losses are 2.0 psi. I ( 507' P )" M

• NPSH = HATM + Hs HVAP Hy where:

= atmospheric head HATM

= static head Hs

= vapor pressure head HVAP 3 g <

Hp =

Frictional head including strainer ',

Minimum Ernected NPSH Maximum suppression pool temperature is 77 C (170'F)

=

HATM 10.73m (35.20 Ft)

=

Hs 3.46m (1135 Ft)

HVAP " 2 %;'II % E) 4. 22. m (t s .e s F 4)

Hp =

1.82m (5.97 FL)

Strainer head loss = 2.0 psi = 1.46m = 4.80 F1 NPSH available = 10.72 + 3.46 - 1.82 = m- (? f? F:) 8.15 m (7.6.T 7 F+)

NPSH required = 73m (_'? af F:) ( 2 4 F 4)

• NPSH Reference Point Amendment 7 5.4-31a

. 23A6100AT Standard Plant REV B testing done by Terry Co. with water applicable to the ABWR? Describe in detail the components, .

especially the turbine and the pump.

RESPONSE 440.48 l

The ABWR RCIC equipment specification does not specify the type of turbine, rather, its performance requirements.' Performance testing will be performed with water applicab!c to the ABWR )

Standard Plant design. The equipment and component description given in Subsection 5.4.6.2.2 is commensurate with a standard design. The depth of information provided in this subsection is the -j i

same as that provided for BE's standard BWR/6 Nuclear Island design. This information is reflected in the RCIC equipment specification. The amount of information provided is sufficient to delineate the performance requirements of the RCIC without restricting its supply by qualified equipment vendors. ,

QUESTION 440.49 To the best of our knowledge, the steam isolation valves F063 and F064 in currently operating BWRs -

are not tested with a steam pipe break downstream and with actual operating conditions (pressure 1000 psig and temperature 546 degrees F). There is no guarantee that the steam isolation valves will close during a break. We require that a proper testing of the valves be performed before the final {

design approval. (Reference Generic Issue GI-87 " Failure of HPCI Steam Line Without Isolation.")

RESPONSE 440.49 The ABWR RCIC equipment specification requires that the valves in question close within a specified tirne under prescribed environmental conditions. 'the method of confirmation will be either testing or demonstration of similarity with previously qualified valves. Since this is a 1 standardized design it is not possible to identify a specific equipment vendor and the method of confirmation. However, the commitment to either test or demonstrate via similarity has been considered sufficient in past NRC reviews of standardized designs.

QUESTION 440.50 Steam isolation valves F063 and F064 are to be opened in sequence to reduce water hammer and for slow warm up of the piping. F064 and F076 are opened first. The valves logic should prevent the operator from opening the valves out of sequence. Confirm that the valves controllogic includes an interlock.

RESPONSE 440.50 C C d .. ... =. 2d.. ;L .; ;a .;;'c;h  ;;;. y Jan :p;c':; c' 'h::: n!r: .: ;:n- :d '"

_::!:: edr%::::2: and p:2,d :2! -- :21.

b AD"O d . 3,u ar L i.vu .%om ;L .. .o!... ;e b; ep;..;d 3;p;;;.r.!!y  ;.:..;d b;!:r

" ::dx :: p::u.-: d:r g: 'e- =::: h:rm::. ::I'h:: ".::r !: !::!:: =!": !: :;:::?

"*^r:t:!!; '; :: '-L::t ;i;;;! S::!d :Ph:: : 50:' of :h:,; .in b; ind, :h;7

... ;; b; ;op;..;d t, Or;;; &ig ic:' =!=: n. .p':::!y. """ 5::' c!=; :!:x d, :h:

c :bcxd i;c! :i ; =!x F064 == 5: :=p:::d :: !!c: =; mi:::: '- 'h: " : :: d::!:. Th::.

c..,;;;; ;had of h ' bce:d ;r!::" u!n F06? z dr - d s' "r M "-- "~""~ ~^"

' bord r!:92- c!w :: ::;;;!S:d ::d h: d : n::== " : ; rn .;d by tw!, opa.ag ;L.

=-d ;;a:!: u ! : b;p::' u !t: "6 r  !'" '% -bo r d :r'#- "' : 3 my "

{

E -

Amendment 7 20.3-110 I NSEB.T

+ .

The inboard (F063) and outboard (F064) isolation valves are l I

provided with keylock switches as protective features in addition to several administrative constraints.

Administratively, the valve control switch key must be obtained, then (1) the key must be inserted into the lock to enable the maintained contact switch and (2) the switch must be turned from OPEN to CLOSE to enable reset of the sealed-in isolation signal from the leak detection system.

(An interlock for the isolation valve to be in CLOSE position before the leak detection system isolation signal can be reset is in compliance with NUREG 0737. NUREG 0737 Item II.E.4.2 Position 4 requires that isolation valves must not open automatically upon reset of the isolation signal and must only be opened by a deliberate operator t action). f i

Upon reset of the leak detection system, the outboard  !

isolation valve (F064) is allowed to open by placing the l control switch key in the OPEN or STOP (intermediate  !

position for throttling) position to drain trapped condei. sate between the inboard and the outboard isolation valves. Then the inboard bypass valve (F076) is opened to {

drain trapped condensate upstream of the inboard isolation valve (F063) at the same time slowly equalizing the ,

pressure across inboard valve (F063) and warming-up the  !

downstream piping. Finally, the inboard isolation valve #

I (F063) is opened by placing the control switch key in the OPEN position to allow full pressurization of the steam line. This opening sequence procedure is delineated in the I RCIC system design specification and RCIC system operating l' procedure.

CE considers that an interlock between the inboard and outboard valves is not necessary. The addition of an interlock will only complicate the logic without an offsetting benefit. Even if an interlock is provided, the potential for water hammer is still likely to exist if the operator failed to drain, equalize and warm-up the line before opening the inboard valve.

Ancther complication to an interlock is that the outboard valve (F064) is a throttling type. Once the inboard valve is opened, the interlock prevents inching of the outboard valve (F064).

It is GE's position that strict administrative and procedural control is adequate. The same administrative and procedural control is being practiced on all GE BVR's and to date no such problem has been reported.

1

,M M 23A6100AT q

. Standard Plant REV B testing done by Terry Co. with water applicable to the ABWR? Describe in detail the components, ]

especially the turbine and the pump.

{  ;

RESPONSE 440.48 The ABWR RCIC equipment specification does not specify the type of turbine, rather, its performance requirements. Performance testing will be performed with water applicable to the ABWR j Standard Plant design. The equipment and component description given in Subsection 5.4.6.2.2 is -

commensurate with a standard design. The depth of information provided in this subsection is the ,

same as that provided for BE's standard BWR/6 Nuclear Island design. This information is reflected i in the RCIC equipment specification. The amount of information provided is sufficient to delineate  !

I the performance requirements of the RCIC without restricting its supply by qualified equipment vendors.

l QUESTION 440.49 l l

To the best of our knowledge, the steam isolation valves F063 and F064 in currently operating BWRs 'l are not tested wi:h a steam pipe break downstream and with actual operating conditions (pressure 1000 psig and temperature 546 degrees F). There is no guarantee that the steam isolation valves will close during a break. We require that a proper testing of the valves be performed before the final design approval. (Reference Generic Issue GI-87 " Failure of HPCI Steam Line Without Isolation.")

F m ntSeoNSE 440.49 t

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QUESTION 440.50 .

Steam isolation valves F063 and F064 are to be opened in sequence to reduce water hammer and for slow warm up of the piping. F064 and F076 are opened first. The valves logic should prt; vent the operator from opening the valves out of sequence. Confirm that the valves controllogic includes an  ;

interlock.

RESPGNSE 440.50 GE does not consider that an interlock is necessary since opening of these valves is governed by strict administrative and procedural control.

The ABWR design specification requires these valves to be opened sequentially as stated below:

"In order to prevent damage from water hammer, neither steam isolation valve it opened automatically by an initiation signal. Should either or both of these valves be closed, they must be reopened by firsts closing both valves completely.. With both valves closed, the outboard isolation valve F064 can be reopened to allow any moisture in the line to drain. Then, moisture ahead of the inboard isolation valve F063 is drained slowly as line pressure across inboard isolation valve is equalized and the downstream line is warmed by slowly opening the inboard isolation valse bypass valve F076. Finally, the inboard isolation valve F063 may be reopened."

Amendment 7 20.3 110

4 F j l

The ABWR.RCIC equipment specification requires that the-valves inquestion close within a specified time under actual operating conditions. Since this is a standardized design it is not possible to identify a' specific. equipment vendor and test the valve.before_the final design approval. However, GE will closely follow the current valve testing in support of GI-87 and will make appropriate modifications to the equipment' specification prior of issuance of the final SER.

h

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S&n '

ABWR maims

.- Standard PInnt _.

REv c system may be performed during normal plant op. .

vessel outside the core shroud (via the feedwa-eration by drawing suction from the suppression ter line on Division A and via the core cooling pool and discharging through a full flow test subsystem discharge return line on Divisions B '

' return line back to the suppression pool. The andC).

discharge valve to the vessel remains closed during test mode operation. The system will The RHR provides two independent containment automatically return from test to operating mode spray cooling systems (on loops B and C) each if system initiation is required and the flow having a common header in the wetwell an.d.a com-will be automatically directed to the vessel. mon sprty header in the drywell and sufficient capacity for containment depressurization.

5A4.2.5.4 Limiting Single Failure Shutdown cooling suction is taken directly The most limiting single failure with the from the reactor via three shutdown cooling RCIC system and its HPCF system backup is the . suction nozzles on the vessel. Shutdown cooling failure of HPCF. With an HPCF failure, if the' return flow is via the feedwater lines on loop A capacity of RCIC system is' adequate to maintain and via core cooling subsystem discharge return-reactor water level, the operator shall follow lines on loops B and C.

Subsection 5.4.6.2.5.2: However, if the RCIC capacity is inadequate, Subsection 5.4.6.2.5.2 Connections are provided to the upper pools still applies, but additionally the operator may - on two loops to return shutdown cooling flow to also initiate the ADS system described in Subsec- the upper poo!s during normal refueling activi-tion 6.3.2.2.2. ties if necessary. These connections also allow the RHR to provide additional fuel pool cooling 5A.6.3 Performance Evaluation capacity as required by the fuel pool cooling system during the initial stages of the refuela The analytical methods and assumptions in ing outage.

evaluating the RCIC System are presented in Chap-ter 15 and Appendix 15A. The RCIC system pro- 5.4.7.1.1 Functional Design Basis d Q vides the flows required from the analysis (Fig. ggfggT ute 5.4-9) within a 30 second interval based upon The RHR provides the following four princi-considerations noted in Subsection 5.4.6.2.4. pal functions:

5.4.6.4 Preoperational Testing (1)' Core cooling water supply to the reactor to compensate for water loss beyond the normal The preoperational and initial startup test control range from any cause up to and program for the RCIC system is presented in including the design basis (LOCA).

Chapter 14.

(2) Suppression pool cooling to remove heat re-5.4.7 Residual Heat Removal System leased to the suppression pool (wetwell), as necessary, following he, inputs to the

~

3 Evaluations of residual heat removal (RHR) sys- pool.

I tem against the applicable General Design Crite-ria (GDC) are provided in Subsection 3.1.2 and ' (3) Wetwell and drywell sprays to remove heat 5.4.7.1.4. and condense steam in both the drywell and wetwell air volumes following a LOCA. In 5.4.7.1 Design Basis addition, the drywell sprays are intended to -

provide removal of fission products released The RHR is composed of three electrically and during a LOCA.

mechanical independent divisions designated A, B, and C. Each division contains the necessary (4) Shutdown cooling to remove decay and piping, pumps, valves and beat exchangers. In sensible heat from the reactor. This the low pressure flooder mode, suction is taken includes the safety related requirements from the suppression pool and injected into the that the reactor must be brought to a cold j

I Amendment 7 5 4-16  !

a .

As shown in Table 5.4-4, the RHR heat exchanger primary (tube) side design pressure is 500 psig and the secondary (shell) side design pressure is 200.psig. This pressure distribution is acceptable for the.following. reasons:

(1) Heat exchanger primary side leakage is accommodated by the surge tank of the pump loop of the reactor building cooling water system. The inlet to the secondary side of the heat exchanger is always open to this continuously running pump loop.

(2) The ABWR design bases against interfacing LOCAs essentially eliminates interfacing LOCA concerns by requiring that : (a) two or more malfunctions are necessary to expose piping systems to reactor operating pressure with design pressures greater than or equal to one-third reactor operating pressure (e.g., RHR heat' exchanger primary side):and (b) three or more malfunctions are necessary to expose piping systems to reactor operating pressure with design pressures less than one-third reactor operating pressure-(e;g.,

RHR heat exchanger secondary side).

Further, the interfacing LOCAs design bases requires the motor operated ECCS injection valves to be tested with the reactor vessel at low pressure and ECCS injection lines to have inboard testable check valves with position indication in the control room.

l l

1 4

~

ABM urnooxn  ;

Standard Plant REV.A i

Table 5.4-4 RHR HEAT EXCHANGER DESIGN AND PERFORMANCE DATA '

Number of units 3 Seismic CategoryI design and analysis I

-l 1

Types of exchangers Horizontal U Tube /Shell  !

/secowdarg i Maximum primaryfde pressure 500psig /2 oo P 3 t 3 Design Point Function Post-LOCA Containnient Cwling .  ;

i Primary side (tube side) performance data (1) Flow 4200 gpm 1 (2) Inlet temperature 3580 maximum (3) Allowable pressure drop (max) 10 psi (4) Type water Suppression Pool or l Reactor Water (5) Fouling factor 0.0005 Secondary side (shell side) performance data j

l (1) Flow 5,280 gpm (2) Inlet temperature 1050F maximum (3) Allowable pressure drop - maximum 10 psi (4) Type water Reactor Building Cooling Water (5) Foulingfactor 0.0005 i

5.4-40

s , l S'

~

ABWR z w ioors meandard Plant arv c .

I The relief valves for the RHR system (Ell) are (7) In the absence of a valid LOCA signal with-listed in Table 5.4 5 and the operating character. out high drywell pressure and without the istics of each valve (i.e., their relieving injection valve being fully closed, it is ,  ;

pressure) are tabulated. All of the E11 relief not possible to open the drywell spray j valves in Table 5.4 5 are quality group B, safety valves in a loop.when the corresponding class 2, and Seismic Category I. All valves are containment isolation valve in the same loop classified as an essential component whose prime is open; i.e., the two valves, in series,' .iI safety function is active. All of the relief are both not to be open during shutdown or valves in Table 5.4 5 are standard configurations surveillance testing. d  :

meeting all applicable codes and standards. None P '

of these valves are air operated nor can their SA7.24 Appikable Codes and delana actpoint be changed by the operators. IN MI (1) Piping. Pumps, and Valves 5A7.23.1 Interlocks

.(a) Process aide ASMEIII dass1/2 (1) The valves requiring a keylock switch are (b) Servicewaterside I P001, P032 and FD33 as indicated on the RHR ~ ASMEIII Class 3 .

PAID, Pigure 5.4-10. l (2) Heat Exchangers (2) It is not possible to open the shut down connection to the vessel in any given loop (a) Process aide ASMEIII Class 2 ,

whenever the pool suction, pool discharge TEMA Class C valve or containment spray valves are open i in the same loop to prevent draining the (b) Servicewater vessel to the pool. side ASMEIII Class 3 TEMA Class C (3) Redundant interlocks prevent opening the 't shutdown connections to and from the vessel (3) ElectricalPortions whenever the pressure is above the shutdown range. Increasing pressure trip shall cause (a) IEEE 279 closure of these valves.

(b) IEEE308 (4) A timer is provided in each pump minimum j flow valye controf eirevitry so that the 5A.7.2.5 Reliability Considerations pump has an opportunity to attain rated speed and flow before automatic control of The MIR system has included the redundancy the valve is activated. This time delay is requirements of Subsection 5.4.7.1.5. Three necessary to prevent a reactor water dump to completely redundant loops have been provided to the suppression pool during the shutdown remove residual heat, each powered from a operation, separate emergency bus. All mechanical and i electrical compor.ents are separate. Two out of (5) It is not possible to operate the RHR main three are capable of shutting down the reactor pumps without an open suction source because within a reasonable length of time.

l these pumps are used for core, vessel and containment cooling and their integrity must ' 5A.7.2.6 Manual Action be preserved.

(1) Emergency Mode [ Low pressure flooder (6) Redundant interlocks prevent opening and (LPFL) mode) automatically closes the shutdown suction connections to the vesselin any given loop  :

whenever a low reactor level signal is present.

Amendment 7 SM1

9 b.

5.4.7.2.3.2 Heat Exchanger Leak Leak Detection A radiation detector is provided in'the main loop o f. the reactor building' cooling water (RCW) system,-which. cools.

the secondary side of the RHR heat' exchanger. If radioactive watier- from the primary side of the heat exchanger leaks.to the secondary side, the radiation detector will signal a radiation increase soon after the' RHR is started. Conformation is achieved through a sample port in the specific RHR pipe line of the RCW system.

l F

i l

~

'.ABWR 6.2.6 msms

. Standard Plant REV C (5) Systems that are normally filled with water or other convenient intervals, but in no case at and operating under post LOCA conditions intervals greater than two years.* Air locks opened when containment integrity is required F need not be zented. will be tested in manual mode within 3 days of M .hi.W.yNenetration 6.2.6.2 Containmen Leakage Rate,h

• EEN being opened. If the air lock is to be opened l Test (Type B) more frequently than once every 3 days, the air (

lock will be tested at least once every 3 days $

6.24.2.1 General during the period of frequent openings. Air locks will be tested at initial fuel loading, Containment penetrations whose designs incor- and at least once every 6 months thereafter.

porate resilient seals, bellows, gaskets, or Testing may be initiated automatically at the sealant compounds, airlocks and lock door seals, end of each interval by the seal test instrumen-equipment and access hatch seals, and electrical tation system, with manual override of the auto-canisters, and other such penetrations are leak mated sequence provided for in the associated tested during preoperational testing and at peri- logic. Testing involves the injection of air odic intervals thereafter in conformance to Type under pressure (15 psig) into the space between B leakage rate tests defined in Appendix J of the two redundant seals in each door of the air 10CFR50. The leak tests ensure the continuing lock. The leakdown rate is measured by sensing structural and leak integrity of the penetra- the pressure drop and/or flow rate necessary to tions. maintain the pressure. Main control room readout of time to next test, test completion To facilitate local leak testing, a perma- and test results is provided. An alarm sounds nently installed system may be provided, consist- if the specified interval passes without a test ing of a preswized gas source (nitrogen or air) being effected. No direct, safety-related and the manifolding and valving necessary to function is served by the seal test instruments-subdivide the testable penetrations into groups tion system. j of two to five. Each group is then pressurized, {

and if any leakage is detected (by pressure decay 6.2.6.2.4 Design Provisions for Periodic _.

j or flow meter), individual penetrations can be Pressurization ( ~

4 isolated and tested until the source end nature of the leak is determined. All Type B tests are In order to assure the capability of the performed at containment peak accident pressure, containment to withstand the application of peak Pa. The localleak detection tests of Type B and accident pressure at any time during plant life Type C (Subsection 6.2.6.3) must be completed for the purpose of performing ILRTs, close atten-prior to the preoperational or periodic Type A tion is given to certain design and maintenance l tests. provisions. Specifically, the effects of corro-sion on the structural integrity of the contain-6.24.2.2 Acceptance Criteria ment are compensated for by the inclusion of a 60-yr service life corrosion allowance, where The combined leakage rate of all components applicable. Other design features that have the subject to Type B and Type C tests shall not ex- potential to deteriorate with age, such as ceed 60% of L (cfm). If repairs are required flexible seals, are carefully inspected and to meet this lim *t, the results shall be reported tested as outlined in Subsection 6.2.6.2.2. In in a separate summary to the NRC. The summary this manner, the structural and leakage integ-shall include the structural conditions of the rity of the containment remains essentially the components which contributed to failure. same as originally accepted.

6.2.6.2.3 Retest Frequency la compliance with the requirement of Section *In compliance with the requirement of Section III.D.2(a) of Appendix 3 to 10CFR Part 50, type B III.D.2(b)(iii) of Appendix 1 to 10CFR Part 50 tests (except for air locks) are performed during each reactor shutdown for major fuel reloading, Amendment 3 6.0 42

~

JABWR 6. 3. 2 23A6100AB Standard Plant .REV C (6) vesselpressure as a function of time; elevation it is the lowest break on the vessel '

except for the drainline break. Furthermore, the (7) flows out of the vessel as a function of worst break / failure combination leaves the time; fewest number of ECC systems remaining and no high pressure core flooder systems. LOCA (8) flows into the vessel as a function of time; analyses using break areas less than the maximum values were also considered. The cases analyzed (9) peak cladding temperature as a function of are indicated on the break spectrum plot (refer time. to Figure 6.310). From these results it is clear that the overall most limiting break in A conservative licensing assumption is that terms of minimum transient water level in the all offsite AC power is lost simultaneously with downcomer, is the maximum core flooder line the initiation of the LOCA. As a further conser- break case.

vatism, all reactor internal pumps are tripped at the start of LOCA event even though this in 633.7.7 Line Breaks Outside Containment itself is considered to be an accident (See '

Subsection 15.3.1). The resulting rapid core This group of breaks is characterized by a flow coastdown produces a calculated departure rapid isolation of the break. Since a maximum from nucleate boiling in the hot bundles within steam line break outside the containment pro-the first few seconds of the transient. duces more vessel inventory loss before isola-tion than other breaks in this category, the LOCA analyses using break areas less than the results of this case are bounding for all breaks maximum values were also considered for the in this group. Important variables from these steamline, feedwater line, and RHR shutdown analyses are shown in Figure 6.3-60 through suction line locations. The cases analyzed are 6.3 66.

indicated on the break spectrum plot (refer to --

Figure 63-10). In general, the largest break at As discussed in Subsection 6.3.3.7.4, the (s,"

each location is the worst in terms of minimum trip of all reactor internal pumps at the start transient water level in the downcomer. of the LOCA produces a calculated departure from nucleate boiling for all LOCA events. Further-6.33.7.5 Intermediate Line Breaks Inside more, the high void content in the bundles Containment following a large steamline break produces the earliest times of loss of nucleate boiling for For these cases the maximum RHR/LPFL injection any LOCA event. Thus, the summary of results in 2

line break (0.221 ft ) was analyzed. Important Table 63-4 show that, though the PCTs for all variables from this analyses are shown in Figures break locations are similar, the steamline 63 37 through 63-43. breaks result in higher calculated PCTs and the outside steamline break is the overall most J 633.7.6 Small Line Dreaks Inside Containment limiting case in terms of the highest calculated l PCT.

For these cases the maximum high pressure core flooder line break (0.099 ft 2) and the maximum 633.7.8 Bounding Peak Cladding Temperature  ;

l bottom head drain line break (0.0218 ft2 ) were Calculation i analyzed. Important variables from these analyses are shown in Figure 6.3-44 through Consistent with the SAFER application 6.3 59.a gThe drainline break analysis is also methodology in Reference 2, the Appendix K peak boundir g for any credible break within the cladding temperatures calculated in the previous reactor ,nternal pump recirculation system and sections must be compared to a statistically its aspiated motorW '-E .; and cover, calculated 95% probability value. Table 6.3 6

[, 9 presents the significant plant variables which As expected, the core flooder line break is were considered in the determination of the 95%

T.NStiM.T 'the worst break location in terms of minimum probability PCT. Again, since the ABWR LOCA (

transient water level in the downcomer. In results have a large margin to the acceptance Amendment 6 6.3-12

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ __ . _ _ _ _ _ _ _ _ _ _ _ _ _ _______o

• s l k A break in a reactor internal pump would involve either the welds or the casing. If the weld from the pump casing.to the PRV stub tube breaks, the stretch tube will prevent the pump casing from moving._ The stretch tube clamps the diffuser to the stub-tube.and runs from the diffuser to a land in the pump casing, where its nut seats. The land is located below the casing attachment weld and therefore the stretch tube forms a redundant parallel strength path to the pump casing restraint which is designed to provide support in the event of weld failure. In case the pump casing and the stretch tube break, the pump and motor will move downward until stopped by the casing restraints. The pump will drop until the. impeller seats on the backseat that is part of the stretch tube., In either case the break flow would be much less than.the drainline break case.

Therefore, 1

i 1

,' ABWR zNseRT 23xsaxa

'. Standard Plant nrv s J

l plant variables in the conse rvative direction 63.4.2 Reliability Tests and inspections simultaneously. The results c f this calculation for the limiting case are give 2 in Figure 6.3-67 The average reliability of a standby through 6.3-75 and Table 6.3-4.g Si nce the ABWR (nonoperating) safety system is a function of results have large margins to the 10CFR50.46 the duration of the interval between periodic licensing acceptance criteria, the ABWR licensing functional tests. The factors considered in PCT can be based on the bounding PCT which is determining the periodic test interval of the well below the 22000F PCT limit. ECCS are: (1) the desired system availability (average reliability); (2) the number of 633.8 LOCA Analysis Conclusions redundant functional system success paths; (3) the failure rates of the individual components Having shown compliance with the applicable in the system, and (4) the schedule of periodic' acceptance criteria of Section 6.3.3.2, it is tests (simultaneous versus uniformly staggered concluded that the ECCS will perform its function versus randomly staggered).

in an acceptable manner and meet all of the 10CFR50.46 acceptance criteria, given operation. All of the active components of the HPCF l at or below the MAPLHGRs in Table 6.3-7. System, ADS, RHR and RCIC Systems are designed so that they may be tested during normal plant 6.3.4 Tests and Inspections operation. Full flow test capability is provided by a test line back to the suction f 63.4.1 ECCS Performance Tests source. The full flow test is used to verify I the capacity of each ECCS pump loop while the All systems of the ECCS are tested for their plant remains undisturbed in the power operational ECCS function during the generation mode. In addition, each individual preoperational and/or stattup test program. Each valve may be tested during normal plant component is tested for power source, range, operation.

direction of rotation, setpoint, limit switch setting, torque switch setting, etc. Each pump All of the active components of the ADS is tested for flow capacity for comparison with System, except the safety / relief valves and vendor data. (This test is also used to verify their associated solenoid valves, are designed flow measuring capability). The flow tests so that they may be tested during normal plant involve the same suction and discharge source operation. The SRVs and azsociated solenoid I (i.e., suppression pool), valves are all tested during plant initial power j ascension per Appendix A, Paragraph D.2.c of All logic elements are tested individually and Regulatory Guide 1.68. SRVs are bench tested to then as a system to verify complete system establish lift settings. j response to emergency signals including the ability of valves to revert to the ECCS alignment Testing of the initiating instrumentation and from other positions. controls portion of the ECCS is discussed in Subsection 7.3.1. The emergency power system, Finally, the entire system is tested for which supplies electrical power to the ECCS in ,

response time and flow capacity taking suction the event that offsite power is unavailable, is '

from its normal source and delivering flow into tested as described in Subsection 8.3.1. The l the reactor vessel. This last sesies of tests is frequency of testing is specified in the Chapter performed with power supplied from both offsite 16 Technical Specifications. Visual inspections i power and onsite emergency power. of all the ECCS components located outside the I drywell can be made at any time during power See Chapter 14 for a thorough discussion of operation. Components inside the drywell can be preoperational testing for these systems. visually inspected only during periods of access Amendment 2 6 3-13

. J The bounding PCT is greater than'the Appendix K value.

This i s-typical of the first peak-PCT ~ values, which are dominated by the amount of. stored energy assumed, as documented in Reference 2. The' core remains covered throughout the LOCA event. so there is no second peak PCT.

1

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1 Cswa s. s, s .

ae.=Amed Plant _

nrv s RESPONSE 440.103 The ATWS rule contained in 10 CFR 50.62 speci5es that: -

a. Each BWR must have an AR* system that is diverse (from the reactor trip system) from sensor output se, the Enal actuation device,

b. Each BWR must have a SLCS with a minimum flow capacity and baron content equivalent in control espacity to 86 gym of 13 weight percent sodium pentaborate solution for a 251 inch RPV. For new plants, the SLCS initiation must be automatic.

c. Each BWR aust provide equipment to trip the reactor coolant circulating pumps autoraatically under an=&eia=< indicative of an ATWS.

These requirements were derived from evaluations of BWR designs with locking piston control rod drives (LPCRD), which use a hydraulic system to provide normal rod movement and scram functions. For .

ABWR, fine motion control rod drives (FMCRD) are used. These drives use a hydraulic system to provide the scram function, and an electric-driven system to provide normal rod motions. These two systems are independent from each other. Such a control rod drive design is not covered by the ATWS rule. Therefore, we have to go back to the design philosophy which led to the ATWS rule. For ATWS prevention / mitigation for ABWR, the following are provided:

a. An ARI system that utilizes sensors and logic which are diverse and independent of the reactor protection system,

b. Electricalinsertions of FMCRD's that also utilizes sensors and logic which are diverse and independent of the reactor protection system, and .

c. Automatic recirculation pump trip under conditions indicative of an ATWS.

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- r-QUESTION 440.104 la the ABWR design, SLCS pump is started manually. But the ATWS rule 10 CFR 50.62 states that "The SLCS initiation must be automatic and must be designed to perform its function in a reliable manner for plants granted construction permits after July 26,1984.* How does tbc ABWR design satisfies the ATWS rule? (9.3.5)

RESPONSE 440.104 See response to Question 440.103 Amendment 4 20.3 153 1

1

k '

In addition, a manual SLCS is provided as a backup'of ATWS mitigation. This system is designed to meet requirements specified in 10CTR50 Appendix A and is described in Subsection 9.3.5.

In sumcary, The following table.shows compliance with specific q aspects of the ATWS ru}e, 20CTR50.62, for the ABWR design: i

, ATUS Rule ABVR Design

f

1. Diverse scram system- 1. Diverse ARI is provided.

2. Automatic SLCS injection 2a. Diverse and a'Jtomatic FMCRD run-in is provided. {

i 2b. Backup manual SLCS injection

, is provided.

3. Automatic RPT 3. Automatic RPT is provided.

.l The ARI design follows the guidelines for the design objectives and (esign basis requirements for the ARI zystem as documented in GDE-31096-P-A (ATWS, Response to NRC ATWS Rule 10CTR50.62, approved by the NRC in October, 1926). The ABWR ATVS trip logic, as shown in the-attached Figure 440.103-1, is highly reliable and single-failure-proof. 3 In addition, the ABWR design eliminates the scram discharge volume, and, therefore, eliminates an identified common mode failure potential of the existing locking-piston CRDs. The implementation of the diverse and automatic FMCRD run-in as a backup of the ARI system further reduces the probability of an ATWS. It is estimated that the need of boron injection is reduced by at.least a factor of 100. This means that the need of boron injection is less than 10-e/ year. A quantitative probabilistic analysis is presented in Appendix 19D of the SSAR. (See Tables 19D.4-18 and 19D.4-1 and Subsection 19D.6.5.1 through 19D.6.5.5.) Therefore, it is concluded that an automatic boren .

1 injection is not necessary. A manual boren injection as a backup is thus acceptable. I l

In order to further justify the acceptability of the ABVR tesign, performaner analyses were performed for the most limiting ATVS event  !

(i .e. : all nSIV closure event). The analysis results together with the acceptar.re criteria are shown in the following: - i

9 E CO UT) N N System Parameter Criteria With ARI With PMCRD Run-in Peak RPV Pressure (psig) 1500 1336 1336 Peak Pool Temp (P) 207 142 152 Puel Integrity Coolable Met Het Geometry Peak Containment 45 3.7 4.7 Pressure (psig)

It is concluded from above analysis results that both the ARI and the PMCRD run-in could mitigate the most limiting ATVS event. Thus, the ABVR design does not need an SLCS to respond to an ATVS threatening event.

In order to further demonstrate the capability of the ABWR, additional analyses with the assumption that both ARI and PMCRD run-in fail (i.e.; with additional multiple failures) were performed. In these analyses,'it is assumed that the operator follows the emergency procedure guidelines (EPG) to manually initiate the boron injection when the suppression temperature reaches the preset limit (e.g.:

135'P). The time that the suppression pool temperature reaches 135'P depends upon the initial suppression pool temperature and the severity of the ATWS event, which depends on the void coefficient, event type, etc.. It is estimated that this time interval is in the range from about 90 seconds to many minutes. In the analyses shown below, it is assumed that the boren in3ection is initiated at about 90 seconds after the closure of all MSIVs. It is also assumed that the boron starts to enter the vessel 2 minutes after the initiation. The analysis results together with the acceptance criteria are shown in the f ollowing:

With one With Two System Parameter Criteria SLC Pump SLC Pumps Peak RPV Pressure (psig) 1500 1335 1335 Peak Pool Temp (P) Containment 240 206 Design (Met) (Met)

Pressure

• Puel Integrity Coolable Mct Het Geometry Peak Containment 45 30.0 15.2 Pressure (psig)

= Criterion for ATVS with additional multiple failures.

o g ( Coal TlAIW E D ')

It is concluded from above analysis results that manual boron injection with either one or two SLC pumps could mitigate the most limiting ATWS event with margin (at least 15 psi margin in peak containment pressure). From this margin, it is estimated that the operator has about 10 minutes to inject.the boron into the vessel in order to maintain the containment integrity following an ATWS event.

Therefore, a manual SLCS injection (even with one pump) as a backup for ATWS mitigation is acceptable, l.

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. ' 23A6100AC

.. Standard Plant - nrv c and engineered safeguards systems. high-water level signal. The HPCI system will restart on low water level but the RCIC system will (4) Fuel-zone, water-level range: This range used not. The RCIC system is a low flow system when for its RPV taps the elevation above the main compared to the HPCI system. The initiation levels steam outlet nozzle and the tapsjust above the of the HPCI and RCIC system should be separated internal recirculation pump (RIP) deck. The so that the RCIC system initiates at a higher water zero of the instrument is the bottom of the ac- level than the HPCI system. Further, the initiation ;

tive fuel and the instruments are calibrated to be logic of the RCIC system should be modified so that accurate at 0 psig and saturated condition. The the RCIC system will restart on low water level.

water-level measurement design is the conden. These changes have the potential to reduce the sate reference type,is not density compensated, number of challenges to the HPCI system and could and uses differential pressme devices as its pri- result in less stress on the vessel from cold water mary elements. These instruments provide injection. Analyses should be performed to evaluate input to water levelindication only. these changes. The analysis should be submitted to the NRC staff and changes should be implemented if There are common condensate reference cham- justified by the analysis.

bers for the narrow-range; wide-range; and fuel-zone, water level ranges. Response The elevation drop from RPV penetration to the The ABWR Standard Plant design is consistent drywell penetration is uniform for the narrow range .with this position. The high pressure core flooder and wide range water-levelinstrument lines in order - (HPCF) system is initiated at Level 1 1/2, and the to minimize the change in water-level with changes RCIC system is initiated at 1.evel 2. At Level 8, the in drywell temperature. injection valves for the HPCF and the RCIC steam supply and injection valves will automatically close in Reactor water-levelinstrumentation that ini- order to prevent water from entering the main steam tiates safety systems and engineered safeguards is lines.

shown in Figure 113.

In the unlikely event that a subsequent low level 1A.2.21.1 Failure of PORV or Safety to recurs, the RCIC steam supply and injection valves Close ( II.K.3.3 ) will automatically reopen to allow continued flooding of the vessel. The HPCF injection valves will also NRC Position automatically reopen unless the operator previously closed them manually. Refer to Subsections Assure that any failure of a PORV or safety 7.3.1.1.1.1 (HPCF) and 7.3.1.1.1.3 (RCIC) for valve to close will be reported to the NRC promptly, additional details regarding system initiation and 7 All challenges to the PORVs or safety valves should isolation logic.

7 be documented in the annual report. This

$ requirement is to be met before fuel load. 1A.2.23 Modify Break-Detection Logic to Prevent Spurious Isolation of HPCI 2 Response And RCIC Systems [II.K.3(15)]

See Subsection 1 A.3.4 for interface requirement. NRC Position l 1A.2.22.2 Separation of HPCI AND RCIC The high-pressure coolant injection (HPCI) and

) System Initiation Levels [ll.K.3(13)] reactor core isolation cooling (RCIC) systems use l differential pressure sensors on elbow taps in the l NRC Position steam lines to their turbine drives to detect and i icolate pipe breaks in the systems. The pipe-break-Currently, the reactor core isolation cooling detection circuitry has resulted in spurious isolation i (RCIC) system and the high-pressure coolant injec- of the HPCI and RCIC systems due to the pressure i tion (HPCI) systems both initiate en the same low- spike which accompanies startup of the systems. The i water level signal and both isolate on the same pipe-break- detection circuitry should be modified to Amendment B h R A$% 1 A.213

',

• M\ 23A6100AC

. Standard Plant uvc switchover is implemented, licensees should verify that clear and cogent procedures exist for the manual switchover of the RCIC system suction from the con-densate storage tank to the suppression pool.

Response

The RCIC system provided in the ABWR Stan-L dard Plant includes an automatic switchover feature which will change the pump suction source from the RCIC storage pool to the suppression pool. The-safety-grade switchover will automatically occur upon receipt of a low-level signal from the condensate storage pool or a high-level signal from -

the suppression pool.

See Subsection 7.3.1.1.1.3 for additionalinfor-mation.

1A.2.29 Confirm Adequacy of Space Cooling for High Pressure Coolant Injection and Reactor Core Isolation Cooling Systems [II.K.3(24)]

l NRC Position Long-term operation of the reactor core isola-tion cooling (RCIC) and high-pressure coolant injec-tion (HPCI) systems may require space cooling to maintain the pump-room temperatures within allow-able limits. Licensees should verify the acceptability of the consequences of a complete loss of alternat-ing-current power. The RCIC and HPCI systems should be designed to withstand a complete loss of offsite alternating-current power to their support sys- i tems, including coolers, for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

I-

Response

The ABWR high pressure core flooder (HPCF) and the reactor core isolation cooling (RCIC)  ;

systems are provided space cooling via individual O room safety grade air-conditioning systems (See Lil 1 Subsection 9.4.5). If all offsite power is lost, space '

V) cooling for the HPCF and RCIC system equipment

- would not be lost because tl e motor power supply

} for each system is from seperate essential power I

$ supplies.

Ot.

1 I

Amendment B ( O$. A$"T) 1A.2-17

ABWR 23AM00AC Standard Plant nu 1A.2.32 Revised Small-Break 1A.2.33.1 Plant Specific Calculations to l' IAss-of Coolant-Accident Methods to Show Show Compliance with 10 CFR Part 50.46 Compliance with 10 CFR PART 50, [II.K.3(31)] .!

Appendix K [II.K.3(30)] l NRC Position -)

5 NRC Position Plant-specific calculations using NRC-approved  ;

The analysis methods used by nuclear steam models for small-break loss of-collant accidents supply system (NSSS) vendors and/or fuel suppliers (LOCAs) as described in Item II.K330 to show for small-break loss-of coolant accident (LOCA) compliance with 10 CFR 50.46 should be submitted analysis for compliance with Appendix K to 10 CFR for NRC approvalby alllicensees. .

Part 50 should be revised, documented, and submit-ted for NRC approval. The revisions should account Response for comparisons with experimental data, including data from the LOFT Test and Semiscale Test facili- The ABWR standard safety small-break LOCA ties. calculations are discussed in Subsection 633.7. .l Response The references listed in Subsection 63.6 describe the currently approved Appendix K methodology GE has evaluated the NRC request requiring used to perform these calculations. Compliance with that the BWR small-break LOCA analysis methods 10CFR50.46 has previously been established for that are to be demonstrated to be in compliance with Ap- methodology.

pendix K to 10 CFR 50 or that they be brought into compliance by analysis methods changes. The spe- Since, as noted in the previous Item (1A.232), no i cific NRC concerns are contained in NUREG-0626, model changes are needed to satisfy NUREG-0737, 1 Appendix F. The specific NRC concerns identified Item II.K3(30), there is no need to revise the calcu- )

in Subsection 4.2.10 of NUREG-0626 (Appendix F) lations presented in Subsection 633.7.

relate to the following: counter current flowlimiting . .

(CCFL) effects, core bypass modeling, pressme vari- 1A.2.33.2 Evaluation of Anticipated Tran-ation in the reactor pressure vessel, integral ex- sients with Single Failure to Verify No Fuel perimental verification, quantification of uncertain- Failure [II.K.3 (44)] .

ties in predictions, the recirculation line inventory 'j modeling, and the homogeneous / equilibrium model. NRC Position  ;

1 The response to the NRC small break model For anticipated transients combined with the  :

concerns was provided at a meeting between the worst single failure and assuming proper operator NRC and GE on June 18,1981. Information pro- actions, licensees should demonstrate that the core vided at this meeting showed that, based on the remains covered or provide analysis to show that no h TLTA small break test results and sensitivity studies, significant fuel damage results from core uncovery. gl the existing GE small break LOCA model already Transients which in a stuck-open rel.a salve should satisfies the concerns of NUREG 0626 and is in be included in this category. The results of the eval-compliance with 10 CFR 50, Appendix K. There- uation are due January 1,1981.

fore, the GE model is acceptable relative to the con-cerns ofItem II.K3(30), and no model changes need Response be made to satisfy this item.

GE and the BWR Owners' Group have con-Documentation of the information provided at cluded, based on a representative BWR/6 plant the June 18,1981 meeting was provided via the letter study, that all anticipated transients in Regulatory from R. H. Buchholz (GE) to D. G. Eisenhut Guide 1.70, Revision 3, combined with the worst (NRC), dated June 26,1981.

Amendment 8 ( 0 E A N 2^ 219 4

j

= Mb 23A6100AC

,. .

• Standard Plant nov c t l

single failure, the reactor core remains covered with Response water until stable conditions are achieved. Futher- )

more, even with more degraded conditions involving All of the generic February 21,1980 GE re- i a stuck-open relief valve in addition to the sponses are applicable to the ABWR design and are j worsttransient (loss of feedwater) and worst single adequate in terms of a response to the Michelson  !

failure (failure of high pressure core spray), studies concerns for the ABWR Standard Plant. {

show (NEDO-24708, March 31,1980) that the core 1 remains covered and adequate core cooling is 1A.2.34 Primary Coolant Sources Outside j available during the whole course of the transient. Containment Structure [III.D.1.1(1)] .

The conclusion is applicable to the ABWR Since i the ABWR has more high pressure make-up systems NRC Position (2HPCFs and 1 RCIC), the core covering is further assured. Applicants shallimplement a progrrm to reduce s leakage from systems outside containment that would  ;

Other discussions of transients with single fail- or could contain highly radioactive fluids duringa .

ure is presented in the response to NRC Ouestion serious transient or accident to as-low-as-practical 440.111. levels. This program shallinclude the following:

1A.2.33.3 Evaluate Depressurization (1) Immediate leak reduction other than Full ADS [II.K.3 (45)]

(a) Implement all practical leak reduction NRC Position measures for all systems that could carry radioactive fluid outside of Provide an evaluation of depressurization containment.

methods other than by full actuation of the automatic {

E depressurization system, that would reduce the possi- (b) Measure actualleakage rates with systems Z bility of exceeding vessel integrity limits during rapid cooldown. (Applicable to BWR's only) in operation and report them to the NRC. 3 (2) Continuing Leak Reduction--establish and im.

Response plement a program of 'teventive I maintenance to reduce leakage to as-low-as-practical levels.

]

This response is prosided in Subsection 19A.2.11 This 1A.2.33.4 Responding to Michelson Concerns [II.K.3 (46)]

NRC Position General Electric should a response to the Michelson concerns as they relate to boiling water 3 reactors.

N Clarification 2

General Electric provided a response to the Michelson concerns as they relate to boiling water reactors by letter dated February 21,1980. Licens-ces and applicats should assess applicability and ade-quacy of this response to their plants.

Amendment B ( D $ AF) 1A.219a

c

.- ABWR 23A6100AC Standard Plant nev.c 1A.3 INTERFACES appropiate, to improve the availability of the emer-gency core cooling equipment.

1A.3.1 Emergency Procedures and Emergency Procedures Training Program Emergency procedures, developed from the emergency procedures guidelines, shall be provided and implemented prior to fuel loading. (See Subsec-tion 1A.2.1).

1A.3.2 Review and Modify Procedures for Removing Safety-Related Systems From Sen' ice Procedures shall br reviewed and modified (as required) for removing safety-related systems from service (and restoring to service) to assure operabil-ity status is known. (See Subsection 1A.2.19) 1A.3.3 In Plant Radiation Monitoring

( Equipment and training and procedures shall be provided for acetrately e. determining the airborne io-dine concentrat:on in areas within the facility where plant personnel may be present during the accident.

(See Subsection 1A.2.18) 1A.3.4 Reporting Failures of Reactor System Relief Valves Failures of reactor system relief valves shall be reported in the annual report to the NRC. (See Sub-section 1A.2.3.21.1).

IA.3.5 Report or ECCS Outages Staning from the date of commercial opera-tions, an annual report shoald be submitted which in-cludes instance of emergency core cooling system un-availability because of component failure, mainte-nance outage (both forced or planned), or testing, 3 the following information shall be collected:

LD (1) Outage date 2 (2) Duration of outage (3) Cause of outage (4) Emergency core cooling system or component involved (5) Corrective action taken The above information shall be assembled into a report, which will also include a discussion of any changes, proposed or implemented, deemed Amendment B ( 0 IL A M 1A3-1

(

4 4 6

e a

e ATTACHMENT 2 NEW CHAPTER 15 ANALYSES l

AND ADDITIONAL JUSTIFICATION OF EVENT CLASSIFICATION l

l 1

1

NEW CHAPTER 15 ANALYSIS GE will provide new analyses for the following events to reflect the implementation of the M-G sets described heroin:

(1) Loss of offsite power, and (2) Trip of pumps.

ADDITIONAL JUSTIFICATION OF EVENT CLASSIFICATION GE will provide additional justification of the classification for the following events.

Cateaorv Event Decrease in coolant Runout of two feedwater pumps temperature Opening of all control and bypass valves Pressure regulator downscale failure increase in reactor Generator load rejection, failure pressure of one bypass valve Generator load reJectton with bypass off Turbine trip with failure of one bypass valve Turbine trip with bypass off Decrease in coolant Fast runback of all reactor system flow internal pumps increase in reactor inadvertent HPCF pump start-up coolant inventory

< s ,

.+

ABWR MOTOR-GENERATOR SETS Two' motor-genesator (MG) sets, located on the top floor of the control building (SSAR Figures 1.2-15 and 1.2-21), are provided as part of the reactor internal pump (RIP) power-supply system for extending the coast-down time of the connected RIPS. Each MG set receives input power from an independent 6.9 kV power bus and.provides. constant 6.9 kV' output to three adjustable speed drives (See SSAR Figure 8.3-1). Included in each MG set are: (a) an induction motor which drives the MG set at constant speeds (b) an AC synchronous generator and its associated' excitation system (brushless type): (c) a flywheel for adding inertia to extend the coast down time of RIP during a' bus failure transients and (d) control and protection circuits.

The MG set inertia is sized such that RIP speed will be maintained for at least three seconds after the loss of bus' power. Within these 3c seconds, the power from the MGl set I coastdown is capable of maintaining RIP speed at 100% of rated for at least the first second, and then maintain the rate of RIP speed reduction to less than 10% per second for the remaining two seconds.

i

7..

4 ATTACHMENT 3 l

UPDATE OF SUBSECTION 5.4.5

" MAIN STEAMLINE ISOLATION SYSTEM" l

l l

l

i

• 23A6100AB Standard Plant REV A ,

steamline break. The maximum differential - restrictor material because it has excellent re- '

I pressure is conservatively assumed to be 1375 sistance to erosion / corrosion in a high velocity l psi, the reactor vessel ASME Code limit pressure. steam atmosphere. The excellent performance of-stainless steel in high velocity steam appears The ratio of venturi throat diameter to to be due to its resistance to corrosion. A pro-  ;

steamline inside diameter of approximately 0.5 tective surface film forms on the stainless )

results in a maximum pressure differential steel which prevents any surface attack and this 1 (unrecovered pressure) of about 14 psi at 100% of film is not removed by the steam. l rated flow. This design limits the steam flow in I a severed line to less than 200% rated flow, yet Hardness has no significant effect on it results in negligible increase in steam mois- erosion / corrosion. For example hardened carbon ,

ture content during normal operation. The steel or alloy steel will erode rapidly in appli- )

restrictor is also used to measure steam flow to cations where soft stainless steel is unaf- 1 initiate closure of the main steamline isolation fccted. )

valves when the steam flow exceeds preselected op- )

erational limits. The vessel dome pressure and Surface finish has a minor effect on the venturi throat pressure are used as the high erosion / corrosion. If very rough surfaces are and low flow sensing locations. exposed, the protruding ridges or points will crode more rapidly than a smooth surface. Expe-5AA.3 Safety Evaluation rience shows that a machined or a ground surface is sufficiently smooth and that no detrimental In the event a main steamline should break erosion will occur.

outside the containment the critical flow phenom-  ;

enon would restrict the steam flow rate in the SAAA Inspection and Testing j venturi throat to 200% of the rated value. Prior to isolation valve closure, the total coolant Because the flow restrictor forms a perma- i losses from the vessel are not sufficient to nent part of the RPV steam outlet nozzle and has _

cause core uncovering and the core is thus ad- no moving components, no testing program beyond equately cooled at all times. the RPV inservice inspection is planned. Very - I slow crosion which occurs with time, has been ac-  ;

Analysis of the steamline rupture accident counted for in the ASME,Section III design (Subsection 15.6.4) shows that the core remains analysis. Stainless steel resistance to erosion covered with water and that the amount of radioac- has been substantiated by turbine inspections at tive materials released to the environs through the Dresden Unit 1 facility. These inspections the main steamline break does not exceed the have revealed no noticeable effects from erosion guideline values of published regulations, on the stainless steel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec Tests on a scale model determined final design and the exit velocities are 600 to 900 ft/sec.

and performance characteristics of the flow However, calculations show that, even if the restrictor. The characteristics include maximum erosion rates are as high as 0.004 in. per year, flow rate of the restrictor corresponding to the after 40 years of operation, the increase in accident conditions, unrecoverable losses under restrictor-choked flow rate would be no more normal plant operating conditions, and discharge than 5%. A 5% increase in the radiological dose moisture level. The tests showed that flow calculated for the postulated main steamline restriction at critical throat velocities is break accident is insignificant.

stable and predictable.

SA.5 Main Steamline Isolation System The steam flow restrictor is exposed to steam of about 2/10% moisture flowing at velocities of 5A.5.1 Safety Design Bases 150 ft/sec (steam piping ID) to 600 ft/sec (steam restrictor shroat). ASTM A351 Type 304 cast The main steamline isolation valves, indi-stainless steel was selected for the steam flow vidually or co!!ectively, shall:

r

$M

. . t

. i

~

ABM 2W100AB Standard Plant REV C (1) close the main steamlines within the time pressure balancing hole in the poppet. When established by design basis accident the hole is open, it acts as a pilot valve to analysis to limit the release of reactor relieve differential pressure forecs on the coolant; poppet. Vstve stem travel is sufficient to give flow areas past the wide open poppet (2) close the main steamlines slowly enough that greater than the seat port area. The poppet simultaneous closure of all steam lines will travels approximately 90% of the valve stem not induce transients that exceed the travel to close the main steam port area; nuclear system design limits; approximately the last 10% of the valve stem i travel closes the pilot valve. The air j (3) close the main steamline when required cylinder actuator can open the poppet with a i despite single failure in either valve or in maximum differential pressure of 200 psi across {

the associated controls to provide a high the isolation valve in a direction that tends to q level of reliability for the safety func- hold the valve closed. j tion; A Y-pattern valve permits the inlet and j (4) use pneumatic (N2 or air) pressure and/or outlet passages to be streamlined; this spring force as the motive force to close minimizes pressure drop during normal steam flow the redundant isolation valves in the ad helps prevent debris blockage.

individual steamlines.

The valve stem penetrates the valve bonnet (5) use local stored energy (pneumatic pressure through a stuffing box that has two sets of  ;

and/or springs) to close at least one isola- replaceable packing. A lantern ri >g and tion valve in each steam pipeline without leak-off drain are located between the two sets I relying on the continuity of any variety of of packing.

electrical power to furnish the motive force i to achieve closure; Attached to the upper end of the stem is an air cylinder that opens and closes the valve and (6) be able to close the steamlines, either a hydraulic dashpot that controls its speed.

during or after seismic loadings, to assure The speed is adjusted by a valve in the isolation if the nuclear system is breached; hydraulic return line bypassing the dashpot and piston.

(7) have the capability for testing during Valve quick-closing speed is 3-4.5 seconds normal operating conditions to demonstrate when N2 or air is admitted to the upper piston that the valves will function. compartment. The valve can be test closed with a 45-60 second slow closing speed by admitting 5.4.5.2 Description N2 or air to both the upper and lower piston compartments.

Two isolation valves are welded in a horizon-tal run of each of the four main steam pipes; one The pneumatic cylinder is supported on the valve is as close as possible to the inside of valve bonnet by actuator support and spring the drywell, and the other is just outside the guide shafts. Helical springs around the containment. spring guide shafts close the valve if gas pressure is not available. The motion of the Figure 5.4-7 shows a main steamline isolation spring seat member actuates switches in the near valve. Each is a Y-pattern, globe valve. Rated open, near closed vavle positions.

steam flow through each valve is 4.23 x 10' lb/hr. The main disc or poppet is attached to The v'alve is operated by pneumatic pressure l the lower end of the stem. Normal steam flow and by the action of compressed springs.The tends to close the valve, and higher inlet control unit is attached to the gas cylinder.

pressure tends to hold the valve closed. The This unit contains three types of control valves bottom end of the valve stem closes a small that open and close the main valve and excercise Amendment B h $M 5.4-7

O e Mkb 23A6100AD Standard Plant REV.C it at slow speed: pnuematic, a-c from Division I, and a-c from Division II. Remote manual switches in the control room enable the operator .

i to cperate the valves.

Operating gas is supplied to the valves from the plant N2 or air system. An pnuematic j accumulator between the control valve and a check valve provides backup operating gas.

I Each valve is designed to accommodate saturated steam at plat.t operating conditions  !

with a moisture content of approximately 0.25%,

an oxygen content of 30 ppm, and a hydrogen  ;

content of 4 ppm. The valves are furnished in 1 conformance with a design pressure and tem-perature rating in excess of plant operating con-ditions to accommodate plant overpressure condi-tions.

In the worst case, if the main steamline should rupture downstream of the valve, steam flow would quickly increase to 200% of rated flow. Further increase is prevented by the venturi flow restrictor, f Amendment 8 ( D @ A@ 5.4-7a

/

o .

• 23A6100AD Standard Plant nrv. c s

During approximately the first 75% of closing, line valve installations are designed as Seismic the valve has little effect on flow reduction, Category I equipment. The valve assembly is because the flow is choked by the venturi manufactured to withstand the safe shutdown restrictor. After the valve is approximately 75% earthquake forces applied at the mass center of closed, flow is reduced as a function of the the valve with the valve located in a horizontal '

valve area versus travel characteristic, run of pipe. The stresses caused by borizontal and vertical seismic forces are assumed to act The design objective for the valve is a simultaneously. The stresses caused by seismic minimum of 60 years service at the specified oper- loads are combined with the stresses caused by ating conditions. Operating cycles (excluding ex- other live and dead loads including the operat-crcise cycles) are estimated to be 1000 cycles in ing loads. The allowable stress or this combina-60 years and 2500 execise cycles in 60 years. tion of loads is based on a percentage of the al-lowable yield stress for the material. The In addition to minimum wall thickness required parts of the main steam isolation valves that by applicable codes, a corrosion allowance is constitute a process fluid pressure boundary are added to provide for 60 years service. designed, fabricated, inspected, and tested as required by the ASME Code Section III.

Design specification ambient conditions for normal plant operation are 1350F normal tem- 5.4.5.3 Safety Evaluation perature and 60% bumidity in a radiation field of 202 rad /hr neutron plus gamma, continuous for In a direct cycle nuclear power plant the design life. The inside valves are not con- reactor stem goes to the turbine and to other '

tinuously exposed to maximum conditions, par- equipment outside the containment. Radioactive ticularly during reactor shutdown, and valves materials in the steam are released to the envi-outside the primary containment and shielding are rons through process openings in the steam in ambient conditions that are considerably less system or escape from accidental openings. A severe. large break in the steam system can drain the water from the reactor vessel faster than it is l The main steamline isolation valves are de- replaced by feedwater, signed to close under accident environmental con- i ditions of 3400F for one hour at drywell design The analysis of a complete, sudden stea:uline pressure. In addition, they are designed to break outside the containment is described in remain closed under the following post-accident Subsection 15.6.4. The analysis shows that the environment conditions: fuel barrier is protected against loss of cooling if main steam isolation valve closure is  ;

(1) 3400F for an additional 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at drywell within specified limits, including instruments- '

drywell pressure of 45 psig, tion delay to initiate valve closure after the break. The calculated radiological effects of (2) 3200F for an additional 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at drywell the radioactive material assumed to be released design pressure of 45 psig, with the steam are shown to be well within the i guideline values for such an accident. J (3) 2500F for an additional 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> at 25 l psig maximum, and The shortest closing time (approximately 3 j seconds) of the main steam isolation valves is  !

(4) 2000F for an additional 99 days at 20 also shown to be satisfactory. The switches on psig. the valves initiate reactor scram when specific conditions (extent of valve closure, number of To resist sufficiently the response motion pipe lines included, and reactor power level) from the safe shutdown earthquake, the main steam are exceeded (Subsection 7.2.1). The pressure I rise in the system from stored and decay heat Amendment s ( D E AM) 5.4-8

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. < 2moorn aw c may cause the nuclear SRVs to open briefly, but system, each valve is tested as discussed in the rise in fuel cladding temperature will be in- . Chapter 14.

significant. No fuel damage results.

Two isolation valves provide reduridancy in The ability of this Y pattern globe valve to each steamline 'so either can perform the isola-'

close in a few seconds after a steamline break, tion function and either can be tested for under conditions of high pressure differentials leakage after the other is closed. The inside and fluid flows with fluid mixtures ranging from. valve, the outside valve, and the. respective-mostly steam to mostly water, has been demon- control systems are separated physically.'

strated in a series-of dynamic tests ' A full size,20-inch valve was tested in a range of The isolation valve is analyzed and tested steam water blowdown' conditions simulating postu- for earthquake loading. ' The loading caused by lated accident conditions (Reference 1). the specified earthquake loading is required to ~

- be within allowable stress limits and with no The following specified hydrostatic, leakage, malfunctions that would prevent the valve from and stroking tests, as a minimum, are performed closing as required.

by the valve manufacturer in shop tests:

Electrical equipment that is associated with . l the isolation valves and operated in an accident l (1) tings To verify between its3 andcapability to closetime 4.5 sec (response at environment set- is limited to the wiring, solenoid for full closure is set prior to plant op- valves, and position switches on the isolation l eration at 3.0 see minimum, 4.5 sec valves. The expected pressure and temperature maximum), c' ach valve is tested at rated pres- transients following an accident are discussed sure (1000 psig) and no flow. in Chapter 15.

5.4.5.4 Inspection and Testing (2) Leakage is measured with the valve seated. The main steam isolation valves can be func. -]

The specified maximum seat leakage, using tionally tested for operability during plant'op-  !

cold water at design pressure, is 2 eration and refueling outages. The test provi-cm3 /hr/in. of nominal valve size. In addi- sions are listed below. During refueling outage tion, an air seat leakage test is conducted the main steam isolation valves can be function.

l using 40 psi pressure upstream. Maximum per- ally tested, leak tested, and visually inspect '  ;

missible leakage is 0.1 scfh/in. of nominal ed.

valve siz.c.

The main steamline isolation valves can be (3) Each valve is hydrostatically tested in ac- tested and exercised individually to the 90%

cordance with the requirements of the appli- open position in the slow closing mode, cable edition and addenda of the ASME Code.

During valve fabrication, extensive '

nondestructive tests and examinations are conducted. Tests include radiographic, liquid- penetrant, or magnetic-particle ex. Leakage from the valve. stem packing is col-aminations of casting, forgings, welds, lected and measured by the drywell drain-hardfacings, and bolts. system. During shutdown while the nuclear system is pressurized, the leak rate through the inner valve stem packings can be measured by col-lecting and timing the leakage.

The leak through the pipeline valve seats After the valves are installed in the nuclear can be measured accurately during shutdown by Amendment 8 (p $ M' 5.4-9

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the following suggested procedure: long enough period to obtain meaningful data. An alternate means of leak testing (1) With the reactor at approximately 1250F- the outer isolation valve is to utilize the and normal water level and decay heat being previously noted steamline plug and to deter- ,

removed by the RHR system in the shutdown mine leakage by pressure decay or by inflow .I cooling mode, all main steam isolation of the test medium to maintain.the specific valves are closed utilizing both spring test pressure, _l force and air pressure on the operating cyl- )

inder. During pre startup tests following an exten- i sive shutdown, the valves will receive the same (2) Nitrogen is introduced into the reactor hydro tests that are imposed on the primary vessel above normal water level and into the system. 3 connecting main steamlines and pressure is j raised to 20-30 psig. An alternate means of Such a test and leakage measurement program pressurizing the upstream side of the inside ensures that the valves are operating correctly.

isolation valve is to utilize a steamline. <

plug capable of accepting the 20 to 30 psig 5.4.6 Reactor Core Isolation Cooling System . i pressure acting in a direction opposite the hydrostatic pressure of the fully flooded Evaluations of the reactor core isolation g reactor vessel. cooling system against the applicable General De- g sign Criteria are provided in Subsection 3.1.2. 3 (3) A pressure gage and flow meter are connected to the test tap between each set of main 5.4.6.1 Design Basis steam isolation valves. Pressure is held below 1 psig, and flow out of the space The reactor core isolation cooling (RCIC) -3 between each set of valves is measured to system is a safety system which consists of a )

establish the leak rate of the inside isola- turbine, pump, piping, valves, accessories, and l tion valve. instrumentation designed to assure that suffi- I cient reactor water inventory is maintained in (4) To leak check the outer isolation valve, the the reactor vessel to permit adequate core cool-reactor and connecting steamlines are ing to take place. This prevents reactor fuel d flooded to a water level that gives a hydro- overheating during the following conditions:

static head at the inlet to the inner isola-tion valves slightly higher than the pneu. (1) aloss-of-coolant (LOCA) event; matic test pressure to be applied between the valves. This assures essentially zero (2) vessel isolated and maintained at hot leakage through the inner valves. If neces- standby; sary to achieve the desired water pressure at the inlet to the inner isolation valves, (3) vesselisolated and accompanied by loss of ,

gas from a suitable pneumatic supply is in- coolant flow from the reactor feedwater l troduced into the reactor vessel top head, system;  !

Nitrogen pressure (20 to 30 psig) is then applied to the space between the isolation (4) complete plant shutdown with loss of normal l valves. The stem packing is checked for feedwater before the reactor is depressur-leak tightness. Once any detectable stem ized to a level where the shutdown cooling l l packing leakage to the drain system has been system can be placed in operation; or accounted for, the seat leakage test is con-

l. ducted by shutting off the pressurizing gas (5) loss of AC power for 30 mirutes.

and observing any pressure decay. The volume between the closed valves is accu. Acceptence criteria 11.3 of SRP Section 5.4.6 rately known. Correction for temperature states that the RCIC system must perform its variation during the test period are made,if function without the availability of any a-c necessary, to obtain the required accuracy. power. Review Procedure III.7 further requires

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