ML19276F513

Forwards First Round Requests for Addl Info.Requests Response as FSAR Amend by 790622 to Maintain Review Schedule

ML19276F513
Person / Time
Site:	Grand Gulf
Issue date:	03/15/1979
From:	Stolz J Office of Nuclear Reactor Regulation
To:	Stampley N MISSISSIPPI POWER & LIGHT CO.
References
NUDOCS 7903300553
Download: ML19276F513 (27)

Text

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p UNITED STATES

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t NUCLEAR REGULATORY COMMisslON j

.j WASHINGTON, D. C. 20555 p*~

MAR 151979 Docket Nos: 50-416 and 50-417 Mr. N. L. Stampley, Vice President Production and Engineering Mississippi Power & Light Company P. O. Box 1640 Jackson, Mississippi 39205

SUBJECT:

FIRST-ROUND REQUESTS FOR ADDITIONAL INFORMATION - GRAND GULF NUCLEAR STATION, UNITS 1 AND 2 As a result of our review of the information contained in the Final Safety Analysis Report for the Grand Gulf Nuclear Station, Units 1 and 2, we have developed the enclosed first-round requests for addi-tional infonnation. As suggested by cur review schedule, a copy of which was forwarded to you by our letter dated December 8,1978, additional first-round requests are being developed by other review branches. We will forward these additional requests as they become available.

In order to maintain our current review schedule, we request that you amend your Final Safety Analysis Report to reflect your responses to the enclosed requests by June 22, 1979.

If you cannot meet this date, please advise us as soon as possible so that we may consider the need to revise our review schedule.

Please contact us if you desire any discussion or clarification of the enclosed requests.

Sincerely, o 'n F. Stolz, Chie ght Water Reactors Branch No.1 Division of Project Management

Enclosure:

Requests for Additional Information cc:

See next page 70033005W

MAR 151979 Mr. N. L. Stampley cc: Mr. RQbert B. McGehee, Attorney Wise, Carter, Child, Steen &

Caraway P. O. Box 651 Jackson, Mississippi 39205 Troy B. Conner, Jr., Esq.

Conner, Moore A Corber 1747 Pennsylvania Avenue, N. W.

Washington, D. C.

20006 Mr. Adrian Zaccaria, Project Engineer Grand Gulf Nuclear Station Bechtel Power Corporation Gaithersburg, Maryland 20760

ENCLOSURE

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FIRST-ROUND REOUESTS FOR ADDITIONAL INFORMATION GRAND GULF NUCLEAR STATION UNITS 1 A.iD 2 DOCKET N05. 50-416 AND 50-417 kk e

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4 010.0 AUXILIARY SYSTB15 You state that waterstops will be provided in all construction joints below flood level and that watertight doors and equipment hatches will be installed in compartments located below maximum flood (pmf) level.

Verify that all penetrations i.e. piping and electrical, in structures housing safety-related equipment located. below the PMF level will also

' be watertight.

010.4 Your compartment flooding analysis is incomplete. Expand the analysis (3.4 &

3C.4) to include the component cooling water system and any other system that could flood out safety-related equipment. On a room by room basis demonstrate that the plant will be able to achieve safe shutdown considering the height to which the water would rise assumine the failure of one of the sump pumps.

010.5 Expand Section 3.5 to include a tabulation of all safety related (3.5) components located outdoors and describe the protection to be afforded to these components to prevent their being damaged by tornado generated missiles, turbine missiles, or a seismic event. Include in this tabulation all HVAC system air intakes and exhausts on the plant arrangement drawings.

. 010.6 Verify that your design censidered both horizontal and vertical tornado-(3.5) generated missiles.

010.7 Your design criteria for high energy and moderate energy lines as (3.6 &

3C) stated is incomplete. We further require that the compartment between the containment and the reactor building which houses the main steam lines and feedwater lines and the isolation valves for those lines, be designed to consider the environ-mental effects (pressure, temperature, humidity) and potential flooding consequences from an assumed crack, equivalent to the flow area of a single ended pipe rupture in these lines. We require that essential equipment located within the compartment, including the main steam isolation and feedwater valves and their operators be capable of operating in the environment resulting from the above crack. We also will require that if this assumed crack could cause the structural failure of this compartment, then the failure should not jeopardize the safe shutdown of the plant.

In addition, we require that the remaining portion of the pipe in the tunnel between the reactor building and the turbine building meet the guidelines of Branch Technical Position APCSB 3-1.

We require that you submit a subcompartment, pressure analysis to confim that the design of both areas of the pipe tunnel conforms to our position as outlined above.

. Justify that your method provides adequate design margins and identify' the margins that are available. When you submit the results of your evaluation, identify the comuter codes used, the assumptions used for mass and energy release rates, and sufficient design data so that we may perform independent calculations.

The peak pressures and temperatures resulting from the postulated break of a high energy pipe located in compartments or buildings is dependent on the mass and energy flows during the time of the break. You have not provided the information necessary to deter-mine what teminates the blowdown or to detemine the length of time blowdown exists. For'each pipe break or leakage crack analyzed, provide the total blowdown time and the mechanism used to teminate or limit the blowdown time of flow so that the environ-mental effects will not affect safe shutdown of the facility.

010.8 (a) The design criteria for the main steam isolation valve leakage con-(RSP)

(6.7) trol system indicates that you propose to allow a main steam isolation valve (MSIV) leakage rate up to 100 SCFH for each MSIY in each steam-line.

It is our position that the design basis leak rate of 100 SCFH is not an acceptable MSIV leakage rate for nonnal operation.

Therefore, we will still impose a technical specification limit of 11.5 SCFH for the MSIV leak r. ate and a leak rate verification testing frequency consistent with the plant Technical Specifications used for other operating BWR's.

(b) You state that the MSIV stem leakage system will be designed to the same standards of the MSIV-LCS. However, the leakage rate you stated for the MSIV-LCS exceeds the allowable rate required by the Tech Specs. Therefore, the leakage rate for the stem will also be unacceptable. Verify that you will comply with our guidelines.

(c) Your description of the design criteria does not clearly indi-cate that an electrical interlock will be provided to allow the leakage control system actuation valves to open only if their associated inboard MSIV is io the fully closed position thus maintaining the potential doses at the site boundary within acceptable limits. Verify that such as interlock will be provided.

Provide a tabulation of all valves in the reactor pressure boundary and in other seismic Category I systems (per Regulatory Guide 1.20) whose operation is relied upon either to assure safe plant shutdown or to mitigate the consequences of a transient accident e.g., safety valves, stop valves, relief valves, stop-check valves, and control velves.

.The tabulation should identify the system in which it is installed, the type and size of valves, the actuation type (s), and the environment of conditions to which the valves are qualified.

. 010.10 You state that for new fuel the arrangement of the fuel assemblies in (9.1.1 )

the flooded condition Keff will not exceed 0.95.

Confirm that a Keff equal to or less than 0.98 will be maintained with fuel to the highest anticipated reactivity in place in the new fuel storage racks assuming optimum moderation (foam, small droplets, etc.)-

010.11 In the FSAR you state that the spent fuel and cask storage pools will (9.1.2) be lined on the inside surfaces with stainless steel liner plates and that leak tightness will be assured by means of a leak chase sys-tem. You do not, however, state that the plates will be designed to seismic Category I. requirements. Show that a failure of the liner plate as a result of an SSE will not result in any of the following:

significant release of radioactive material due to mechanical damage to the spent fuel; significant loss of water from the pool which could uncover the fuel and lead to release of radioactivity due to heat-up; loss of ability to cool the fuel due to flow blockage caused by a portion or one complete section of the liner plate falling on top of the fuel racks.

010.12 Verify that the maximum normal decay heat load assumed in your cal-jc (9.1.3) culations is for a spent fuel batch discharged from a 12 month equili-brium fuel cycle removed 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> after shutdown.

. 010.13 You state that travel of the crane will preclude transporting the cask (9.i.4 &

3A/1.104) over the spent fuel. However, your discussion of the fuel handling system does not clearly indicate how the travel of the crane will be limited to prevent being transported over the spent fuel. Verify that by both electrical interlocks and mechanical stops the travel of the crane will be limited from going over the spent fuel.

010.14 You state that a containment polar crane load drop analyses has been (9.1.4) performed. Provide the details of a reactor head drop analyses and the resulting conclusions reached.

010.15 Table 9.2 l " Standby Service Water System Passive Failure Analysis" (9.2.1 &

9.2.2) is incomplete.

Expand the table to include all the components of this safety-related system which also includes the cooling towers of the ultimate heat sink. The analyses should consider all possible y

single failures. The results of the analyses should show that safe cold shutdown will not be precluded as a result of any single failure.

010.16 In order to permit an assessment of the Ultimate Heat Sink, provide (9.2.5)

(RSP) the results of an analysis of the thirty-day period following &

design basis accident in one unit and a normal shutdown and cooldown in the remaining unit, that determines the total heat rejec'ad, the sensible heat rejected, the station auxiliary system heat rejected, and the decay heat reN;;se from the reactors.

In submitting the results of the analysis requested, include the following information on a day by day basis in both tabulate and graphical presentations:

1.

The total integrated decay heat.

2.

The heat reject'on rate and integrated heat rejected by the station auxiliary systems, including all operating pumps, ventilation equipment, diesels, spent fuel pool makeup, and other heat sources for both units.

3.

The heat rejection rate and integrated heat rejected due to the sensible heat removed from containment and the primary system.

4.

The total integrated heat rejected due to the above.

5.

The maximum allowable inlet water te perature taking into account the rate at which the heat energy must be removed, cooling water flow rate, and the capabilities of the respective heat exchangers.

6.

The required and available NpSH to the Emergency and RHR service water pumps at the minimum Ultimate Heat Sink water level.

The above analysis, including pertinent backup information, is to demonstrate the capability to provide adequate water inventory and provide sufficient heat dissipat2on to limit essential cooling water operating temperatures within the design ranges of system components.

8-Use the methods set forth in Branch Technical Position ASB S-2,

" Residual Decay Energy for Light Water Reactors for Long Term Cool-ing," to establish the input due to fission product decay. Assume an initial cooling water temperature based on the most adverse conditions for normal operation.

010.17 Your design criteria and Fig SFD-0049, Control Room HVAC System, do (9.4.1) not clearly indicate how the standby air unit will be assured of air flow in the recirculation mode. Demonstrate how the air flow will be prevented from bypassing the standby air unit when the recir-culation mode is required.

1.8 Your FSAR does not evaluate the effects of an expansion joint failure at the condenser. Expand the information prcvided to include an evaluttion regarding the effects of possible circulating water sys.em failure inside the turbine building.

Include the following:

(1) The maximum flow rate through a completely failed expansion joint.

(2) The potential for and the means provided to detect a failure in the circulating water transport system barrier such as the rubber expansion joints. Include the design and operating pressures of the various portions of the transport system barrier and their relation to the pressures which could exist during malfunctions and failures in the system (rapid valve closure).

(3) The time required to stop the circulating water flow (time zero being the instant of failure) including all inherent delays such as operator reaction time, drop out times of the control circuitry and coastdown time.

(4) For each postulated failure in the circulating. water transport system barrier give the rate of rise of water in the associated spaces and total height of the water when the circulating water flow has been stopped or overflows to site grade.

(5) For each flooded space provide a discussion, with the aid of drawings if necessary, of the protective barrier provided for all essential systems that could become affected as a result of flooding.

Include a discussion of the consideration given to passageways, pipe chases and/or the cableways joining the flooded space to the spaces containing safety related system components.

Discuss the effect of the flood water on all submerged essential electrical systee.s and components.

/

211.0 REACTOR SYSTEMS 211.45 The analyses presented to show conformance to the ASME Boiler and (5.2.2)

Pressure Vessel Code for overpressure protection references NED0-10802 as the analytical model for plant transient evaluation.

General Electric has submitted to the staff an updated analytical model (0DYN) to evaluate plant transients. Reanalyze the over-pressure sizing transient using the ODYN code unless assurance can be provided that the NED0-10802 analysis is bounding with regard to predicting peak pressure. The analysis must include the effects of the high pressure recirculation pump trip (RPT) and the turbine stop valve / control valve closure recirculation pump trip where applicable. Provide analysis to justify that the closure of all main steam isolation valves (MSIV) is the most severe overpressure transient when considering the new code, the second safety-grade scram and the effects of RPT.

211.46 Sensitivity studies showing the effect of initial operating (5.2.2) pressure on the peak transient pressure attained during a limiting overpressure event have not been provided. Therefore, either:

(1) provide a sensitivity study which shows that increasing the initial operating pressure (up to the maximum per-mitted by the high pressure trip set point) will have negligible effect on the peak transient pressure, or (2) propose a technical specification which will assure that the reactor operating pressure will not exceed the initial pressure assumed in the overpressure analysis.

211.47 Your startup testing acceptance criteria for the mean CRDS scram (5.2.2) times shown in Section 14.2.12.3.5 appears to be inconsistent (14.2.12) with the Fast Scram Drive characteristics shown in Figure SA-4 (15.0)

Correct this discrepancy so that the startup testing of the CRDS will assure the reactivity insertion rates assumed in the over-pressure and transient analyses.

211.48 In the Grand Gulf analysis, what capacity is assumed for the (5.2.2) valves that are actuated at their power-operated relief set point?

211.49 The performance of essentially all types of safety / relief valves (5.2.2) has been less than expected for a safety ccm::enent.

Because of reportable events involving malfunctions of these valves on operating SWRs, the staff is of the opinion that significantly better safety / relief valve performance should be required of new plants.

Provide a detailed description of improvements between your plant and presently operating plants in the areas listed below.

In addition, explain why the noted differences will provide the required performance imorovement.

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211 2 (5.2.2)

(1) Valve and valve coerator tyce and/or design.

Include discussion of improvements in the air actuator, especially materials used for components such as diaphrams and seals.

Discuss the safety margins and confidence levels associated with the air accumulator design. Discuss the capability of the operator to detect low pressure in the accumulator (s).

(2) Specifications. What new provisions have been employed to ensure that valve and valve actuator specifications include design requirements for operation under expected environmental conditions (esp. temperature, humidity, and vibration)?

(3) Testing. Prior to installation, safety / relief valves should be. proof-tested under environmental conditions and for time periods representative of the most severe operating conditions to which they may be subjected.

(4) Quality Assurance. What new programs have been instituted to assure that valves are manufactured to specifications and will operate to specifications? For example, what tests are performed by the applicant to assure that the blowdown capacity is correct?

(5) Valve Operability. Provide your surveillance program to monitor the performance of the safety / relief valves.

Identify the information that will be obtained and how these data will be utilized to improve the operability of the valves. For example, how will this program reduce the malfunctions that have occurred in operating reactors?

(6) Valve Inspection and Overhaul. The FSAR states that one half of the safety / relief valves will be bench checked and visually inspected every refueling outage. However, depending on operating cycle length, this may result in several years between inspections.

Operating experience has shown that safety / relief valve failure may be caused by exceeding tne manufacturer's recomended service life for the internals of the safety / relief valve or air actuator. At what frequency do you intend to visually inspect and overhaul the ADS portion of the safety / relief valve?

For both safety / relief and ADS modes, what provisions exist to ensure that valve inspection and overhaul are in accordance with the manufacturer's recommendations and that the design service life is not exceeded for any component of the safety /

relief valve?

211.50 Provide all system and core parameter initial values assumed (5.2.2) in the overpressure analyses.

Include their nominal operating range with uncertainties and technical specification limits.

_n M2 211-3 211.51 Page 5.2-5, Section 5.2.2.2.2.4 discusses safety / relief valve (5.2.2) characteristics which include:

(1) valve groups and (2) pressure set point.

It is not clear how these two items are factored into the sizing analysis.

For example, the set point range for power actuation and spring action is 1125-1155 psig and 1175-1205 psig, respectively (Section 5.2.2.2.2.4).

Section 5.2.2.2.3.1 assumes 1125-1155 psig and 1175-1215 psig for power-actuated relief set points and spring action set points. Also, Table 5.2-2 shows 1103-1123 psig and 1165-1190 psig for relief and safety set points, respectively.

Describe the use of these different set point values in evaluating overpressure transients.

211.52 Page 5.2-9a discusses ADS value actuations and states that the (5.2.2) receiver capacity is sufficient to allow the valve to remain open for a prolonged period of time.

Quantify this period of time in relation to long-term capability for operation.

211.53 Provide the calculations to support your relief valve discharge (5.2.2) coefficients and flow capacities.

211.54 Confim that adequate NPSH will exist if operator action is not (6.3) initiated prior to 20 minutes after a LOCA.

Provide your detailed NPSH calculation to demonstrate confomance to Regulatory Guide 1.1 for the ECCS pumps.

211.55 Your FSAR states that no operator action is required until 10 (6.3) minutes after an accident.

It is our position that no operator action be required for 20 minutes after an accident.

Discuss the consequences of not performing operator actions until 20 minutes after a LOCA.

Discuss all actions that are required by the operator to place the plant in the long-term cooling mode subsequent to a LOCA.

211.56 When the water level in the condensate storage tank (CST)

(6.3) drops to a predetermined level, the HPCS pump switches auto-matically to the suppression pool.

Provide assurance that adequate NPSH exist up to switchover.

In addition, show that the minimum suction piping submergence in the CST will preclude undesirable vortex fomation.

Describe preoperational testing that will be performed to demonstrate that such vortex formation will not occur.

211-4 211.57 Provide assurance that adequate NPSH exists for an ECCS passive (6.3) failure in a water-tight pump room. Address the possibility of vortex fomation at the suction of the remaining ECCS pumps with the lowered pool level.

Discuss preoperational tests to be perfomed to demonstrate that there is no impairment of ECCS function due to lowered suppression pool level.

211.58 Provide the assumed values that comprise the total break area for the recirculation line break; steam line break inside and outside containment; feedwater line break; and core injection spray line break.

211.59 What are the differences between steam line breaks inside and (6.3) outside containment with regard to break area? The analyses suggest that core uncovery could occur if no operator action took place before 20 minutes. Provide the effect on peak clad temperature of no action prior to 20 minutes and discuss all assumptions.

211.60 The references provided for the ECCS analysis must include (6.3) references for the latest model changes and corrections.

211.61 Justify selection of a lead plant for the LOCA break spectrum (6.3) analysis.

211.62 Demonstrate that HPCS failure from 1.0 ft2 to the DBA is not (6.3) more limiting than the LPCI D/G failure.

211.63 Provide information on test results that exist to demonstrate that (6.3) the pumps used for long-term cooling (normal and post-LOCA) will operate for the time period required to fulfill that function.

211.64 For the HPCS pumps, provide the available NPSH, NPSH required, (6.3) head and horsepower on Figure 6.3-3 as stated in Section 6.3.2.2.1 (Page 6.3-9).

Provide the relief capacity of the relief valve located on the HPCS and LPCI discharge line.

Provide the set pressure and relieving capacity of the relief valves located on the LPCI suction line.

611.65 Table 6.3-5 is not clear.

Discuss the intent of the column headed, (6.3)

"Effect on Safety Function" with regard to the particular break location.

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211-5 211.66 Check valves in the discharge side of the HPC5, LPCI/RHR, (6.3)

LPCS systems perform an isolation function in that they protect low pressure systems from full reactor pressure. The staff will require that these check valves be classified ASME IWV-2000 Category AC, with the leak testing for this class of valve being performed to code specifications.

It should be noted that a testing program which simply draws a suction on the low pressure side of the outermost check valves will not be acceptable. This only verifies that one of the series check valves is fulfilling an isolation function. The necessary testing frequency will be that specified in the ASME Code, except in cases where only one or two check valves separate high to low pressure systems.

In these cases, leak testing will be performed at each refueling after the valves have been exercised.

Identify all ECCS check valves which should be classified Category AC as per the position discussed above.

Verify that you will meet the required leak testing schedule, and that you have the necessary test lines to leak test each valve.

Provide the leak detection criteria that will be proposed for the Technical Specification.

211.67 What provisions are made to protect level instrumentation for the (6.3) condensate storage tank and the lines from this tank leading to the HPCS systems from the effects of cold weather?

211.68 Some relief valve discharge lines on ECCS penetrate primary (6.3) containment and have outlets below the surface of the suppression pool. Since these lines form part of the primary containment, the concern is that excessive dynamic loads resulting from water hammer during relief valve actuation may cause line cracking or rupture.

Identify these lines penetrating containment and provide information concerning measures taken to prevent line damage.

211.69 The ECCS contains manual as well as motor-operated valves.

(6.3)

Consideration must be given to the possibility that manual valves might be left in the wrong position and remain undetected when an accident occurs. Provide a list of location and type of all manually operated valves in the safety systems and discussion of the methods used for each valve to minimize the possibility of such an occurrence. The sta7f will require remote indication in the control room for all critical ECCS valves (manual or motor-operated).

. rih 211-6 211.70 Recent operating experience identified a potential comon mode (6.3) flooding of ECCS equipment rooms.

The problem involved the equipment drain lines (see IE Circular No. 78-06, May 25,1978).

Verify that the specific design for floor and equipment drains are such that flooding in any one room or location will not result in flooding of redundant ECCS equipment in other rooms. The response to 211.22 is not detailed enough to determine whether a common mode flooding condition exists for Grand Gulf.

211.71 The discussion in section 6.3.2.2.5 of the fill system used to (6.3) prevent water hamer due to empty discharge lines in the RHR and ECC systems is inadequate. Since there have been about fifteen damaging water hammer events resulting from empty discharge lines of core spray and RHR systems, the adequacy of fill systems, including instrumentation and alarms is a matter of concern.

Please respond to the following:

1.

Provide a detailed description of the fill system including instrumentation and alarms with appropriate references to a P&ID.

2.

Level transmitters apparently are not used to detect trapped air bubbles upstream of injection valves. Pressure read downstream of a pump discharge check valve that is greater than the gravity head corresponding to the highest point in the system does not necessarily indicate the absence of trapped air pockets? What provisions are made to avoid trapping of air pockets? In the discussion include consideration of leaking valves in bycass test lines.

3.

If maintenance is required on a particular loop (e.g., in RHRs) requires draining, how does the fill system protect the other loop and systems (e.g., CS)?

4.

What surveillance testing will be recuired to demonstrate that the fill system instrumentation is capable of performing the desired function?

5.

How are surveillance tests made to determine if the discharge lines for the RHR and CS systems are full as required in the Standard Technical Specifications?

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211-7 211.71 6.

Assuming the jockey pump system does not maintain full (Cont.)

lines, water hammer could occur during surveillance tests of the RHR and CS pumps.

If damage occurred, the event would be reported in a LER. However, if special fill and vent procedures were used prior to these tests, water hammer would not occur, but the inadequacies of the jockey pump system might not be evident. Discuss the procedures to be used in surveillance tests involving startup of RHR and CS pumps and the reporting procedures to be used if special filling and venting procedures are used and indicate partially empty lines.

211,72 During long-term cooling following a small LOCA, the operator (6.3) must control primary system pressure to preclude over-pressurizing the pressure vessel after it has been cooled off.

1.

Describe the instructions given the operator to perform long-term cooling.

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2.

Indicate and justify the time frame for performing the required action.

3.

List the instrumentation and components needed to perform this action and confim that these components meet safety grade standards.

4.

Discuss the safety concerns during this period and the design margins available.

5.

Provide temperature, pressure, and RCS inventory graphs that would shew the imoortant features during this period.

The above discussion should account for the fcllowing:

1.

Loss of offsite power.

2.

Operator error or single failure.

L.

211-8 211.73 Demonstrate that for all sizes of breaks in a recirculation loop (6.3) or in ECCS linesrequiring ECCS actuation, the core is covered sufficiently so that LPCI diversion to wetwell spray after 10 minutes is acceptable and the ECCS systems continue to satisfy the requirements of GDC 35 and 10 CFR 50.46. Consideration should be given to the full spectrum of potential single failure and break locations. Confinn that no operator action affecting ECCS perfor: nance is required prior to 20 minutes after the initiation of the accident.

Discuss the effects of the following on core cooling and provide the necessary information to show that the requirements of GDC 35 and 10 CFR 50.46 are not violated:

(1 ) Justify that the system provided for diversion of LPCI flow meets single failure criteria so that diversion before 10 minutes need not be considered.

(2) Justify the conclusion that a break in a ECCS line is the most limiting location wnen evaluating LOCA with diversion.

(3) Provide a sensitivity study showing peak clad temperature as a function of break size for small break LOCA's assuming diversion will be initiated at 10 minutes. Perform this study for ECCS and recirculation line breaks. For the most limiting break, provide the following figures:

(a) Water level inside the shroud as a function of time during the LOCA (b) Reactor vessel pressure vs. time (c) Convective heat transfer coefficient vs. time (d) Peak clad temperature vs. time (e) ECCS fica rate vs. time (4) Justify that diversion at times greater than 10 minutes will have less severe consequences than diversion at 10 minutes (considering appropriate break sizes for later diversion).

(5) Provide a discussion which balances the need for LPCI diversion for this limiting break size with the need for abundant core cooling (GDC 35). For example, this discussion could relate to the likelihood of LPCI diversion for this size break.

211-9 211.74 Your response to question 211.22 is incomplete.

Item 1 requested (6.3) identification and justification of a maximum leak rate. Dmvide this information for such failures as leakage from pump seals and valve stem packing leaks and describe the systems available to the operator for detection of these leaks.

Item 2 requested the maximum allowable time for operator action to detect and isolate the failure.

The response or answer to Item 3 and Item 4 are not apparent in your listed FSAR sections. Confinn that the leakage detection system meets IEEE-279 standards as requested in Item 5.

211.75 GE calculations performed for rapid pressurization and for (15.0) decrease in core coolant temperature (Feedwater Controller Failure, Maximum Demand shown that in some cases) a more severe aCPR is predicted events using the ODYN model have than that by the REDY model (NED0-10802). Show that the loss of feedwater heating event would still remain the most limiting by assuming the following transient events to ba anL -Jed with the ODYN model:

(1) generator load rejection dithout bypass; (2) turbine trip without bypass; (3) feed-water controller failure, maximum demand; and (4) loss of feedwater heating.

211.76 Your response to 0212.28 regarding modification of NSOA (15.A) drawings to include use of nonsafety-grade equipment which mitigate transients and accidents is unacceptable. Since some nonsafety-grade equipment such as reactor vessel high level (Level 8) function to trip the turbine and turbine bypass valves are used for transient mitigation, we request that this type of equipment also be shown in the NSOA figures.

We view this request to be consistent with the general objectives of the NSOA as stated in Appendix 15A.

(Speci f-ically, it is item "d" of subsection 15A.1.1.) Therefore,

modify the NSOA diagrams by including use of nonsafety-grade equipment (phantom lines are suggested).

211,77 During recent meetings with General Electric the staff has (15.1.2) discussed the use of nonsafety-grade equipment for anticipated transient analyses.

It is our understanding that one of the more limiting events is the feedwater controller failure (maximum flow demand). For this transient, the plant operating equipment that have a significant role in mitigating this event are the turbine bypass system and the reactor vessel high water level (Level 8) trip that closes the turbine stop valves. To assure an acceptable level of performance, it is the staff's position that this equipment be identified in the plant Technical Specifications with regard to availa-bility, set points, and surveillance testing. Submit your plan for implementing this requirement along with any system modifications that may be required to fulfill the requiraments.

s 211-10 211.78 With regard to your response to Q212.32, (15.3) you state that the limiting pump trip is assumed in analyzing decrease in reactor coolant system flow rate transients.

Identify what trip signal (e.g., RPT on turbine control valve fast closure or stop valve closure; reactor vessel water level L2 set n' int, motor branch circuit over-current protection, etc.) can be expected to produce the most severe pump coastdown.

211.74 Per Table 15.0-1, the most limiting transient with respect (15.1) to fuel thermal margin is the loss of feedwater heater when (15.2) in manual control.

This result appears to be inconsistent with the GESSAR-238 NSSS and -251 NSSS findings whereby the most limiting event for the latter is generator load rejection without bypass.

Explain this difference.

Secondly, for which core condition was the loss of feedwater heating transient analyzed (e.g., beginning-of-cycle or at the end-of-equilibrium cycle)? Justify selection of the most limiting core condition.

0 211.80 It is not evident that the assumed drop of 100 F in feedwater (15.1 )

temperature gives a conservative result of this transient with manual rec ?culation flow control.

For example, a U

feedwater temperature drop of about 150 F occurred at one domestic BWR resulting from a single electrical component failure. The electrical equipment malfunction (circuit break-trip of a motor control center) caused a complete loss of all feedwater heating due to total loss of extraction steaa. Accordingly, either (1) submit a sufficiently detailed failure modes and effects analysis (FMEA) to demonstrate the 0

adequacy of a 100 F feedwater temperature reduction relative to single electrical malfunctions or (2) submit calculations using a limiting FW temperature drop which clearly bounds current operating experience.

0 Also, temperature drops of less than 100 F can occur and involve more realistic slow changes with time. Assuming all combinations result in slew transients with the surface heat flux in equilibrium with the neutron flux at the occurrence of scram, a smaller temperature drop than 1000F that still causes scram could result in a larger aCPR.

Please evaluate this transient and justify that the assumed values of the magnitude arid time rate of change in the feedwater temperature are conservative.

~

211.11 211.81 In the evaluation of the generator load rejection transient (15.2) you assume 0.15 second for full stroke closure time of the turbine control valve and state that it is conservative compared to actual closure time of more like 0.2 second.

However, in Table 15.2-2 you show the turbine control valves to close in 0.08 second.

Explain this discrepancy.

Also, closure times from partially open to fully closed position are not addressed in the FSAR. For full-stroke closure, the assumed closure time would appear to be conservative in terms of the supplied information. However, for operation in the full arc (full throttling) mode, the closure times may be significantly less than 0.150 second for typical cases where the control valves are only partially open. With respect to this transient, there are two concerns. The first concern is that minimum closure times for part-stroke may be less than those assumed in the analysis. The second concern is that the analysis, which is based on 1055 NSR steam flow and valves wide open initial conditions, may give a less conservative result than an initial condition at a somewhat lower power with control valves partially open as expected. Demonstrate that control valve closure times smaller than 0.150 second do not result in unacceptable increases ir tMCPR and reacter peak pressure or provide either (1) justification that smaller closure times cannot occur or (2) a minimum closure time to be incorporated in the Tecnnical Specifi:ations.

211.82 For the loss of feedwater heating transient in the manual flow (15.1.1) control mode the themal power monitor (TPM) is used to scram the reactor.

Explain the need for the TPM and provide specific transients for which this trip signal initiates scram.

(We are concerned that the value of APRM thermal trip set point shown in Table 15.0-2 may not be appropriate. Verify that the set point for the APRM flow biased trip function shown in Table 7.2-4 is establishee for the themal power monitor (TPM).

If so, exclain the inconsistency of maximum parcent 'ower trip function where you indicate in Table 7.1-2, Note a, item d(2),

that the maximum trip set point for the TPM is approximately 115 percent pcwer as compared to possible maximum of 120 percent power from Table 7.2-4.

Also, explain the inconsistency with the above two values for the input parameter of the APRM thermal trip set point of 118.8 percent NBR used for transient analyses as shown in Table 15.0-2.

Discuss how surveillance testing of the TPM is incorporated in tne station technical specifications.

211-12 211.83 Table 15.0-2 provides the required MCPR operating and safety (15.0) limits for the first core and the reload core. Verify that the results summary of transient events shown in Table 15.0-1 were based on the operating limit MCPR for the first core (MCPR 1.21) and that the input parameters for transient analysis shown in Table 15.0-2 are for the first core.

211.84 For the recirc flow control failure with increasing flow (15.4.5) transient (15.4.5) provide the initial operating MCPR determined at 75% NB rated power and 50% core flow.

In addition, provide the Kr factors as a function of core flow for the automatic and manual flow control modes of operation.

Furthermore, pro-vide the maximum flow control set paint calibration limit (e.g.,

100% of 105% of rated flow) for the recirc loop flow control valves used in the transient analysis.

Also, you reference the GE topical report NED0-10802 as the dynamic model to simulate this event.

Since NED0-10802 does not describe the complete event, discuss in greater detail the overall method used to calculate the ACPR.

211.85 For the recirculation pump seizure accident we note in (15. 3. 3 )

Table 15.3-5 tnat credit is taken for nonsafety-grade equipment to terminate this event. Section 15.3.3 of the Standard Review Plan, Revision 1, requires use of only safety-grade equip.nent and that the safety functions be accomplished assuming the worst single failure of an active component.

Reevaluate this accident with the above specific criteria, and provide the resulting aCPR and percentage of fuel rods in boiling transitica.

211.86 With a sudden ivrease in feedwater flow, there will be a (15.1. 2 )

drop in the feeawater temperature which contributes to the reactivity increase during the first part of the transient.

For example, the combination of feedwater temperature drop and a smaller maximum flow rate could lead to a level 8 trip with the surface heat flux close to the flux scram set point.

If the feedwater temperature at the reactor vessel has been assumed constant, the transient should be analyzed to include the effect of this temperature variation on MCPR. The basis for determining the time variation in FW temoerature at the reactor vessel should be provided. Also show that a smaller increase in feedwater flow rate in conjunction with the change in feedwater temperature does not give a lower MCPR.

211-13 211.87 In the analysis of inadvertent opening of a safety / relief (15.1.4) valve, it is stated that a plant shutdown should be initiated if the valve cannot be closed. How much time does the operator have to initiate plant shutdown before exceeding Technical Specification limits for suppression pool temperature?

211.88 The transient analysis for loss of all grid connections shows (15.2.6) main steam line isolation valve (MSIV) closure at 28 seconds due to loss of condenser vacuum. A concern is that the MSIV's may close at an earlier time in the transient and result in higher system pressures. Apparently, credit is taken for MSIV air accumulator operation since the nomal air supply to the MSIV's would trip at the start of this transient. Discuss design provisions and verification testing which demonstrate that MSIV performance is qualified to the extent aa umed in the analysis.

Related to the same potential for faster MSIV closures, is the design such that a loss of all grid connections may result in an isolation signal which would close the MSIV's?

What sources of electrical power are used for MSIV isolation logic and isolation actuators? Would these sources of power be available following a loss of all grid connections? Do the logic and actuators fail safe to cause an MSIV isolation signal on loss of electrical power?

211.89 Operation of Grand Gulf with partial feed-(16.0) water heating might occur during maintenance or as a result of a decision to operate with lower feedwater temperature near end of cycle. Justify that this mode of operation will not result in (1) greater maximum reactor vessel pressures than those obtained with the assumptions used in Section 5.2.2, or (2) a more limiting AMCPR than would be obtained with the assumptions used in Section 15.0.

The basis for the maximum reduction in feedwater heating considered in the response should be provided (e.g., specific turbine operational limitations).

211.90 In Table 7.5-1, you identify the range of the reactor (7.5) vessel pressure to be from 0 to 1500 psig.

Since the design pressure is 1250 psig, justify the upper bound of the instrumentation range when considering potential events that may cause large pressure excursions (i.e.,

ATWS).

2.-_

211-14 211.91 In Table 7.4-4, you identify a shutdown cooling manual suction (7.4) valve for remote shutdown panel display instrumentation.

This valve should be identified with a number so that we can locate it on the RHRS P&ID.

211.92 Provide a table describing the Standby Service Water System (9.2) cooling duty loads as a function of time intervals following a DBA and the operating status of the safeguards equipment (e.g., RHR pumps, RHR heat exchangers, CS pumps, ADS valves, RCIC,etc.). Typical time intervals would be as follows:

(1) 0-10 minutes; (2) 10-30 minutes; (3) 30 minutes - 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; (4) 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> - 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and (5) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> - 30 days.

211.93 In Table 3.11-3 you identify the components and accident

( 3.11 )

environment inside the drywell in which the components must be operable. The accident environment pressure range is shown to range from -2 to 15 psig. Tnis accident environ-ment is inconsistent for component operability of such ecuipment as safety / relief valves. Section 5.2.2.4.1 indicates that these valves are designed to operate at dry-well design pressure (30 psig per Table 1.3-4) for the first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, 25 psig for additional 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, and 20 psig for the next 99 days. Also, the environmental temperatures are 0

higher by 10 F for the first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> than those shown in Table 3.11-3.

Explain this discrepancy and justify why the other equipment listed in Table 3.11-3 is not subjected to same environmental qualifications as the safety / relief valves discussed above.

211.94 The following questions pertain to our review of Table 3.9-1

( 3. 9.1.1 )

which shows the number of plant cycles (events) considered for reactor assembly design and fatigue analysis.

(1) Explain the events in Item 11 and relate to the transients analyzed in Chapter 15.0.

Also, discuss the following:

(a) The specified eight cycles shown in Table 3.9-1 for single safety or relief valve blowdown for upset conditions appear low over the plant life-time, We note that Table 15.0-1 of the FSAR shows that these valves will lift for a variety of transient events and more than one valve will blow down. Justify your specification of eight

cycles,

211-15 211.94 (b) Clarify whether the loss of feedwater pumps in item (Cont.)

lle of Table 3.9-1 is due to MSIV closure or both of these events occur indeoendently.

For either case, the specified ten cycles for an assumed 40-year plant life appear low.

A number of transients cause feedwater pump trip and MSIV closure, and more than ten events causing the above conditions can be expected. Accordingly, justify your specification of ten cycles.

(2) In Table 3.9-1, is Item 14b the indicated automatic blowdown feature related to the ADS function?

(3) Explain event 14a and relate to Chapter 15.0 or Section 5.2.2 analyses. Justify omission of a reactor overpressure with flux scram and isolation valves stay closed under

" Emergency Conditions."

211.95 In Table 15.0-2, Item 32, provide the correct units (or (15.0) value) for recirculation pump trip inertia for transient analysis.

211.96 Confirm that Figure 15.0-2 includes the effect of the scram (15.0) reactivity multiplier. Also, provide in Table 15.0-2, Item 28, the correct high pressure scram set point.