ML20213C887

Forwards Completed Set of Round One Questions.Review Covered Info Contained in FSAR Sections 5.2.2,6.3 & 15.0, Including Secondary Review Areas

ML20213C887
Person / Time
Site:	Grand Gulf, Susquehanna, Columbia, 05000000
Issue date:	03/07/1979
From:	Mazetis G Office of Nuclear Reactor Regulation
To:	Parr O, Stolz J, Varga S Office of Nuclear Reactor Regulation
References
CON-WNP-0265, CON-WNP-265 NUDOCS 7903230330
Download: ML20213C887 (25)

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!!EMORANDUM FOR: J. F. Stolz, Chief, Light Water Reactors Branch No.1, DPM

0. D. Parr, Chief Light Water Reactors Branch No. 3, DFM

. S. A. Varga, Chief, Light Water Reactors Branch No. 4, DPM THRU: T. M. Novak, Chief, Reactor Systems Branch, DSS FROM:

G. R. Mazetts Section Leader., Reactor Systems Branch, DSS

SUBJECT:

REVIEW OF WPPSS NUCLEAR PROJECT NO. 2. SUSQUEHANNA UNITS 1 AND 2, AND GRAND GULF UNITS 1 AND 2 - ROUND ONE QUESTIONS Plant Name: WPPSS-2 Susquehanna Docket Numbers:

Grand Gulf 50-397 50-337/333 50-416/417 titlestone Number: 05-21 05-21 05-21 Licensing Stage: OL OL OL Responsible Branch LWR-4 LWR-3 LWR-1 and Project !4nage': D. Lynch S. Miner C. Thomas Systems Safety Branch Involved: RSB RSB RSB Description of Review: Q-1 Q-1 Requested Completion Date: 0-1 Feb. 20,1979 Feb. 20,1979 Feb. 20, 1979 Review Status: Complete Complete Complete The Reactor Systesrts Branch has consolidated the reviews of the above three plants. As discussed in previous correspondance, enclosed is the completed set of Round One Questions. We have reviewed the information contained in the FSAR Sections 5.2.2, 6.3, and 15.0, including selected secondary review l areas. Please note that the format of the submitted questions does not i

follow the numbering sequence subsequent to the original questions from the acceptance review. This consolidation of questions was used to expedite transmittal to your office. Margin notations were made to identify plant applicability. We are available should further clarification be necessary.

. Ort:1sel alt **d by:

Gerald R. flazetis, Section Leader Reactor Systems Branch Division of Systems Safety

Enclosure:

25 Round One Questions M 3230 T3OI

Contact:

Ronald Frahm. PIRR Al Ignatonis, NRR k

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211-15 l Enclosure 211 .0 REACTOR SYSTEMS BRANCH 211.68 The analyses presented to show conformance to the ASME Boiler and GG (5.2.2) Pressure Vessel Code for overpressure protection references

SSES NEDO-10802 as the analytical model for plant transient evaluation.

WNP-2 General Electric has submitted to the staff an updated analytical model (00YN) to evaluate plant transients. Reanalyze the over-pressure sizing transient using the ODYN code unless assurance i

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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.

211.59 Sensitivity studies showing the effect of initial operating

GG (5.2.2) pressure on the peak transient pressure attained during a

, WNP-2 limiting overpressure event have not been provided. Therefore, either:

(1) provide a sensitivity study which shows that increasing i the initial operating pressure (up to the maximum per-

! mitted by the high pressure trip set point) will.have j negligible effect on the peak transient pressure, or i (2) propose a technical specification which will assure that

the reactor operating pressure will not exceed the initial pressure assumed in the overpressure analysis. l I 211.70 Your startup testing acceptance criteria for the mean CROS scram il GG (5.2.2) -

times shown in Section 14.2.12.3.5 appears to be inconsistent (14.2.12) with the Fast Scram Orive characteristics shown in Figure SA-4.

(15.0) Correct this discrepancy so that the startup testing of the CROS will assure the reactivity insertion rates assumed in the over-j pressure and transient analyses.

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

211.72 The performance of essentially all types of safety / relief valves GG (5.2.2) has been less than expected for a safety ccmconent. Because of SSES reportable events involving malfunctions of these valves on WNP-2 operating BWRs, 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 improvement.

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. 211-16 (5.2.2) (1) Valve and valve operator tyoe and/or desien. 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 examole, what tests are perfomed by the applicant to assure that the blowdown j capacity is correct?

(5) Valve Operability. Provide your surveillance program to i 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?

4 (6) Valve Insoection and Overhaul. The FSAR states that one l 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 the 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?

211.73 (The response to Question 211.4 is insufficient to allow an GG (5.2.2) adequate evaluation.P Provide all system and core parameter SSES initial values assumed in the overpressure analyses. Include WNp-2 their nominal ooerating range with uncertainties and technical specification. limits. ( )*SSES I

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211-17 211.74 Delete (5.2.2) 211.75 Page 5.2-5, Section 5.2.2.2.2.4 discusses safety / relief valve GG (5.2.2) characteristics which include: (1) valve groups; and (2) pres-sure 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 p:;ig 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.

211.76 Page 5.2-9a discusses ADS valve actuations and states that the GG (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 211.77 Page 5.2-6, Section 5.2.2.2.4, discusses safety / relief valve WNP-2 (5.2.2) characteristics which include: (1) valve groups; and (2) pres-sure set point. It is not apparent how these two items are factored into the analysis. For example, the set point range for spring actuation safety mode is 1165-1205 psig. Table 5.2-2 uses 1130-1205 psig for this range. Define " valve groups,"

and how they are used in the analysis. Discuss the use of these different set point values.

211.78 The peak pressures for MSIV closure with flux scram and high WNP-2 (5.2.2) pressure scram do not agree on figures 5.2-4 and 5.2-5.

Section 5.2.2.2.3.1 erroneously states that generator load rejection with bypass failure is shown on figure 5.2-4.

Correct these inconsistencies.

211.79 Does your design incorporate a fast scram system? (Correct SSES (5.2.2) figure 15.0-2)* ( )*SSES WNP-2 211.80 Identify the safety / relief valve manufacturer.

SSES (5.2.2)

WNP-2 211.81 Provide the calculations to support your relief valve discharge WNP-2 (5.2.2) coefficients and flow capacities.

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211-18 211.82 Page5.2-6statesthatthespringsafetymodeintheanalysih SSES (5.2.2) is assumed to be 1177 to 1217 psig; Table 5.2-2 states 1146 to 1205 psig for spring set pressure. Explain the differences

, and how these values are used in the overpressure analysis.

Define the transient analysis specification of valve groups and how they are used in the analyis.

211.83 Provide the power-operated pressure relief set points and SSES (15.0) capacities used in the transient analyses of Chapter 15.

WNP-2 211.84 Delete (5.2.2) 211.85 Delete (5.2.2) l-e i

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. 211-19 211.86 Confirm that adequate NPSH will exist if operator action is not SSES (6.3) initiated prior to 20 minutes after a LOCA. Provide your detailed WNP-2 NPSH calculation to demonstrate conformance to Regulatory Guide 1.1 GG for the ECCS pumps. (Provide the information stated on pages 6.3-7 and 6.3-14 on Figure 6.3-3 and 6.3-6, respectively.

Provide a discussion of the significance of Figure 6 3-7 with regard to NPSH margin)* ( )*SSES only 211.87 (Your FSAR states that no operator action is required until 10 SSES (6.3) minutes after an accident. It is our position that no operator WNP-2 action be required for 20 minutes after an accident.)* Dis::uss GG 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. (

)* WNP-2, GG only 211.88 Item 5 on page 6.3-2 is not clear. Identify the ECCS line SSES (6.3) break as well as the single failure assumed to yield the available operating ECCS equipment shown.

211.89 Page 6.3-9 (Page 6.3-10)* of your SAR states that the HPCI (HPCS)*

SSES (6.3) is automatically shutdown on a RPV high water level signal. What WNP-2 provisions are incorporated in the design to prevent premature termination of the HPCI flow. Are any interlocks provided, such as a LOCA signal, that prevent automatic shutoff?

Note: "( )* applies to WNP-2 only 211.90 When the water level in the condensate storage tanks (CST)

SSES (6.3) drops to a predetermined level, the HPCS (HPCI)* pump switches WNP-2 automatically to the suppression pool. Provide assurance that GG adequate NPSH exist up to switchover. In addition, show that the minimum suction piping submergence in the CST will preclude undesirable vortex formation. Describe preoperational testing that will be performed to demonstrate that such vortex formation will not occur. ( )* for SSES only 211.91 Figure 6.3-6 shows a core spray head flow curve as used in the SSES (6.3) LOCA analysis. Credit for core spra until rated core spray is achieved (y heat transfer approximately 75isseconds not used for DBA), even though flow begins to enter the core at approximately 50 seconds. Is this flow included in the inventory calculation for reflood time? How are CCFL effects considered in the calcu-lation in this earlier time frame?

211.92 Provide the Figure 6.3-8c that is discussed in Section 6.3.2.2.4 SSES (6.3) (page 6.3-15).

211-20 211.93 A recent GE report, "DC Power Source Failure for BWR 3 and BWR 4,"

SSES (6.3) dated 11/1/78, provides a generic response to staff concerns relative to loss of DC power sources on peak cladding temperature (PCT). For smaller break sizes, this failure yields higher PCT's than failure of HPCI. Provide assurance that this failure has been properly taken into account in your single failure analysis.

In this regard, Table 6.3-5 should be clarified. For example, a loss of a diesel generator would cause a loss of a core spray pump plus an LPCI pump. Also, it is not clear what is being presented in the column headed, "Effect on Safety Function." Is Table 6.3-5 intended to agree with Table 6.3-7? Is break location considered? Define the asterisk used on DC power failure.

211.94 SSES (6.3) Provide assurance that adequate NPSH exists for an WNP-2 ECCS passive failure in a water-tight pump room. Address the GG possibility of vortex formation at the suction of the remaining ECCS pumps with the lowered-pool level. Discuss preoperational tests to be performed to demonstrate that there is no impairment of ECCS function due to lowered suppression pool level.

211.95 Confirm that the LPCI system does not perform any other function, SSES (6.3) such as containment cooling, during the short term portion of the WNP-2 LOCA recovery? If so, this feature must be taken into account in your LOCA analyses. See Questions 211.125 and 211.126.

211.96 The discussion of the LPCI system is not complete. Discuss the SSES (6.3) status of valves (open or closed) in the LPCI system and the recirculation system during the LOCA. Provide the initiation signals, interlocks, and time delays associated with each valve movement during the LOCA.

211.97 Delete 211.98 Provide the assumed values that comprise the total break area for SSES the (recirculation line break)*; steam line break (inside and WNP-2 outsidecontainment);feedwaterlinebreak;andcoreinjectionspray GG line break. ( )*WNP-2,GGonly 211.99 Correct Figure 6.3-64 orn discuss why the initial PCT for the core SSES (6.3) spray line break is 1700 F.

211.100 Delete 211.101 What are the differences between steam line breaks inside and SSES (6.3) outside containment with regard to break area? The analyses WNP-2 suggest that core uncovery could occur if no operator action GG took place before 20 minutes. Provide the effect on peak clad temperature of no action prior to 20 minutes and discuss all assumotions. -

211-21 211.102 Section 6.3.3.4 (page 6.3-23) states that operator action SSES (6.3) is not required during the short term cooling mode following a LOCA. Since the short term mode may extend past ten minutes for smaller breaks, discuss in detail what operator actions are required in view of what is stated in Section 6.3.2.8 (page 6.3-19) regarding throttling requirements. In your discussion include the instrumentation that the operator has available, what actions he must perform, and the instructions available to the operator in the emergency procedures. Also include a plot of NPSH margin versus time for the worst case break.

211.103 The SSES design uses a swing bus arrangement. In accordance with SSES (6.3) the staff policy discussed in NUREG-0138, provide an ECCS calcu-lation for the suction line break assuming no LPCI injection.

211.104 Delete 211.105 SSES (6.3) Identify all ECCS valves that may be potentially submerged or WNP-2 subject to spray impingement following a LOCA. Discuss environ-mental qualification of these valves for these conditions.

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

WNP-2 GG 211.107 Justify selection 'of a lead plant for the LOCA break spectrum WNP-2 (6.3) analysis.

GG 211.108 Correct the small break model curves on Figure 6.3-13 for both WNP-2 (6.3) LPCI 0/G and LPCS 0/G failure. Also, correct the apparent inconsistency between Figures 6.3-39 and 6.3-32 and Figure 6.3-13 for PCT at 0.8 x OBA and 0.6 x OBA.

211.109 Demonstrate that HPCS/(HPCI)* failure from 1.0 ft2 to the 08A SSES (6.3) is not more limiting than the LPCI 0/G failure.

WNP-2 .

GG ( )* SSES 211.110 Why are the water level versus time plots for the 1.0 ft2 transition WNP-2 (6.3) break with HPCS failure different for SSM and LBM calculations?

211.111 WNP-2 (6.3)

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

211.112 For the HPCS pumps, provide the available NPSH, NPSH recuired, head

GG (6.3) and norsepower 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.

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, 211-22 211.113 Delete .'

211.114 Table 6.3-5 is not clear. Discuss the intent of the column headed, WNP-2 (6.3) "Effect on Safety Function" with regard to the particular break GG location.

211.115 There have been damaging water hamer occurrences in the SSES (6.3) turbine supply or exhaust lines of HPCI systems that were attributed to steam driven slugs of water. Contributing causes included a) water drawn into the exhaust line from the suppression pool, b) inadequate draining of the steam supply line, and c) trapping of water slugs upstream of the supply line isolation valves during maintenance. Also, check valves in the turbine exhaust lines of the HPCI system which serve a containment isolation function have been damaged as the result of intennittent closures which arise from flow oscillations in the exhaust line associated with formation and collapse of steam bubbles in the suppression pool. One type of corrective action involved the use of a sparger to reduce the oscillations. What design features are used at Susquehanna to prevent these types of damage?

211.116 Check valves in the discharge side of the HPCS (HPCI)*, LPCI/RHR, SSES (6.3) LPCS systems perform an isolation function in that they protect WNP-2 low pressure systems from full reactor pressure. The staff will GG require that these check valves be classified ASME IWV-2000 Category AC, with the leak testing for this class of valve being perfonned 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 b& 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.

• ( ) For SSES Only 211.117 What provisions are made to protect level instrumentation for the SSES (6.3) condensate storage tank and the lines from this tank leading to the WNP-2 HPCS (HPCI)* systems from the effects of cold weather. (and dust GG storms)**.

( )* SSES Only ( )**WNP-2Only

211-23 211.118 Some relief valve discharge lines on ECCS penetrate primary SSES (6.3) containment and have outlets below the surface of the suppression WNP-2 pool. Since these lines form part of the primary containment, the GG 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.

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

SSES (6.3) Consideration must be given to the possibility that manual WNP-2 valves might be left in the wrong position and remain undetected GG 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 staff will require remote indication in the control room for all critical ECCS valves (manual or motor-operated).

211.120 Recent operating experience identified a potential common mode flooding SSES' (6.3) of ECCS equipment rooms. The problem involved the equipment drain WNP-2 lines (see IE Circular No. 78-06, May 25,1978). Verify that the GG 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. (If isolation valves or limit switches are used to prevent common flooding, identify these valves and switches and discuss provisions to be included in the Technical Specifications to assure adequate surveillance.)*

(The response to 211.22 is not detailed enough to determine whether a coninon mode flooding condition exists for Grand Gulf.)**

( )* SSES Only ( )** GG Only 211.121 The discussion in section 6.3.2.2.5 of the fill system used to SSES (6.3) prevent water hamer due to empty discharge lines in the RHR and WNP-2 ECC systems is inadequate. Since there have been about fifteen GG 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 apoarently are not used to detect trapped air bubbles uostream of injection valves. Pressure read downstream of a pump discharge check valve that is greater than the gravity head corresponding to the highest ootnt in the system does not necessarily indicate the absence of trapped air pockets? What provisions are made to avoid traoping of air pockets? In the discussion include consideration of leaking valves in byoass test lines.

. 211-24 211.121 3. If maintenance is required on a particular loop (e.g., in '

(Cont.) RHRs) requires draining, how does the fill system protect the other loop and systems (e.g., CS)?

4. What surveillance testing will be reouired 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?

6. Assuming the jockey pump system does not maintain full 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.

211.122 The ECCS should be designed to provide sufficient capability WNP-2 (6.3) to cool the reactor in the event of any single active or passive failure in the ECCS during the long-term cooling phase following an accident. Insufficient information is presented in the FSAR to demonstrate that this requirement will be satis-fied with regard to passive fai' lures.

The staff position is that leakage detection and alarms be provided to alert the operator to passive ECCS failures during long-term cooling which allow sufficient time to identify and isolate the faulted ECCS iine. The following considerations should be addressed:

1. Identification and justification of the maximum leak rate should be provided.

2. Maximum allowable time for corrective operator action should be provided and justified.

3. Demonstration should be provided that the leak detection system will be sensitive enough to initiate (by alarm) operator action, permit identification of the faulted line, and permit isolation of the line prior to the leak creating undesirable consequences such as flooding of redundant equipment. The minimum initiation time for operator action is 30 minutes after the alarm.

4 It should be shown that the leak detection system can identify the faulted ECCS train and that the leak is isolable.

211-25 211.122 The leak detection system must meet the following standards:

(Cont.) -

(a) Control Room Alarm (b) IEEE-279, except single failure requirements Your should determine the effects of ECCS of passive failures such as pump seals, valve seals, and measurement devices. The analysis should address the potential for ECCS flooding and ECCS inoperability that could result from a depletion of suppression pool water inventory. The analysis should include consideration of (1) the flow paths of the radioactive fluid through floor drains, sump dump discharge piping, and the auxiliary building; (2) the operation of the auxiliary systems that would receive this radio-active fluids; (3) the ability of the leakage detection system to detect the passive failure. Also, examine the auxiliary system piping in the location of ECCS equipment and address the potential for flooding from nonsafety-grade piping.

211.123 During long-tenn cooling following a small LOCA, the operator SSES (6.3) must control primary system pressure to preclude over-WNP-2 pressurizing the pressure vessel after it has been cooled off.

GG

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

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

3. List the instrumentation and components needed to perform this action and confirm 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 show the important features during this period.

The above discussion should account for the following: ,

1. Loss of offsite power.

2. Operator error or single failure.

211.124 The answer to 211.10 is not complete. Explain how the leakage SSES (6.3) detection system meets the requirements of IEEE-279. Provide the minimum time available before operator action is taken after initiation of an alarm. Examine auxiliary system piping in the location of ECCS equipment and address the potential break of a non-safety grade pipe that may cause flooding.

211-26 211.125 Your response to 211.13 requires supplemental discussion.

SSES (6.3) Demonstrate that for all sizes of breaks in a recirculation loop or in ECCS lines requiring ECCS actuation the core is covered sufficiently so that LPCI diversion to wetwell, spray af ter 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. Confirm that no operator action affecting ECCS perfannance is required prior to 20 minutes after the initiation of the accident.

Discuss the effects of the following on core coolir.g 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) 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 flow rate vs. time.

(3) ' Justify that diversion at times greater thar$ 10 minutes will have less severe consequences than diversion at 10 minutes (considering appropriate break size for later diversion).

(4) Provide a discussion which balances the need for LPCI diversion for this limitin cooling (GOC 35)gFor break example, size with thisthe need for could discussion abundant relatecore to the likelihood of LPCI diversion for this size break.

211.126 Demonstrate that for all sizes of breaks in a recirculation loop WNP-2 (6.3) or in ECCS linesrequiring ECCS actuation, the core is covered GG sufficiently so that LPCI diversion to wetwell spray after 10 minutes is acceptable and the ECCS systems continue to satisfy

211-27 ,

211.126 the requirements of GDC 35 and 10 CFR 50.46. Consideration (Cont.) should be given to the full spectrum of potential single failure and break locations. Confirm that no operator action affecting ECCS performance 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 %nen 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 flow 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.

211.127 Your response to question 211.22 is incomplete. Item 1 requested GG (6.3) identification and justification of a maximum leak rate. Provide 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. Confirm that the leakage detection system meets IEEE-279 standards as requested in Item 5.

m

211-28 211.128 Your response to Question 211.11 indicates that your ECCS pumps SSES (6.3) are designed to operate 100 days for any one accident during the 40 year plant lifetime. Provide information that demonstrates that your ECCS pumps will function for that time period as well as any maintenance assumed to occur during that time period.

211.129 Provide assurance that fast closure of a recirculation flow control WNP-2 (6.3) valve coincident with a loss-of-coolant is not expected to occur or provide the results of a sensitivity study to evaluate the effects of fast closure of a recirculation ficw study valve coincident with the design basis loss-of-coolant accident and worst postulated emergency core cooling system failure.

211.130 Your break spectrum analysis is insufficient to allow an adequate SSES (6.3) evaluation. To confirm that a sufficient number of breaks have been analyzed to generate Figure 6.3-10, values of peak cladding temperature (PCT) andprovide the tabulated break area used.

Provide small break calculations of approximately 0.02 ft2 and 1.0 ft2 with an HPCI failure to verify that these break sizes remain non-limiting (see more complete curve in WPPSS-2 FSAR, Figure 6.3-13). Also, submit a large break model calculation for a 1.0 ft2 break with HPCI failure to similarly verify that the worst break has been properly identified. Provide a discussion on why the 0.68 discharge DBA yields the limiting PCT for Susquehanna. The discussion should include transition boiling time, hot node uncovery time, rated core spray time, and reflood time. This discussion should also describe the trend in suction line breaks (i.e., does this trend also exist for smaller than the largest suction break area, with perhaps a smaller suction break yielding the highest PCT).

211.131 SSES (6.3) For the BWR-4's potentialwith thefor exists LPCI modification isolating (no 1000 selection a recirculation break withloaic) the core uncovered before the pressure has decreased sufficiently to pemit the low pressure ECCS to enter the core. In particular, the single failure considered is an inadvertent closure of the recirculation suction valve with a break between the discharge and suction valves. Analyze the consequences of this failure for the Susquehanna ECCS.

211.132 Provide the missing footnote on Table 6.3-3.

SSES (6.3)

. 211-29 211.133 Correct Figure 15A.6-31, " Protection Sequences Main Turbine SSES (15.A) Trip--Without Bypass:"

(1) for the event to occur at <30". power, protection sequences should be the same as for generator trip without bypass as shown in Figure 15A.6-30.

(2) delete HPCS that is connected with incident detection circuitry.

Also, confirm that subsequent to initial core cooling the sequence of operations to extended core cooling would be the same as shown in Figure 15A.6-26, " Protection Sequences for loss of Main Condenser Vacuum."

211.134 Per your response to Q211.19 regarding the analyses for SSES (15.2) generator load rejection and turbine trip transient, explain your statement that "...a loss of offsite power would improve the results of the above transient since the only additional effect would be a slow coastdown (in comparison to the RPT function) of the recirculation pumps", particularly since the RPT was intended to imorove thermal margin.

211.135 Since the reclassification of the generator and turbine trip SSES (15.2) without bypass transients has not been accepted by the staff WNP-2 and is still under generic review, reanalyze the above events for determination of the operating limit MCPR in which the results would not violate the safety limit MCPR of 1.06. Also, it is our position that the limiti19 transient be reanalyzed with the 00YN code.

211.136 Modify NSOA drawings to include benefits of nonsafety-grade SSES (15.A) equipment which mitigate transients and accidents. Such WNP-2 equipment includes relief valves, turbine bypass valves, and vessel level (high) trip.

211.137 GE calculations performed for rapid pressurization and for GG (15.0) decrease in core coolant temperature (Feedwater Controller Failure, Maximum Demand) events using the ODYN model have shown that in some cases a more severe aCPR is predicted than that by the REDY model (NE00-10802). Show that the loss of feedwater heating event would still remain the most limiting by assuming the following transient events to be analyzed with the ODYN model: (1) generator load rejection without bypass; (2) turbine trip without bypass; (3) feed-water controller failure, maximum demand; and (4) loss of

, feedwater heating.

211-30 211.138 Your response to Q212.28 regarding modification of NSOA GG (15.A) drawings to include use of nonsafety-grade equipment which mitigata 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. (Specif-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).

211.139 During recent meetings with General Electric the staff has GG (15.1.2) discussed the use of nonsafety-grade equipment for anticipated SSES transient analyses. It is our understanding that one of the WNP-2 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 requirements.

211.140 With regard to your response to 0212.32 (GG) (Q211.24, SSES),

GG (15.3) you state that the limiting pump trip is assumed in analyzing SSES 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 point, motor branch circuit over-current protection, etc.) can be expected to produce the most severe pumo coastdown.

211.141 Per Table 15.0-1, the most limiting transient with respect GG (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 witvut 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.

211.142 It is not evident that the assumed drop of 100 F in feedwater GG (15.1) temperature gives a conservative result of this transient SSES with manual recirculation flow control. UFor example, a WNP-2 feedwater temperature drop of about 150 F occurred at one

O .m.

211-31

% 211.142 domestic BWR resulting from a single electrical component SSES (15.1) failure. The electrical equipment malfuncticn (circuit WNP-2 break-trip of a motor control center) caused a complete loss of all feedwater heating due to total loss of extraction steam. Accordingly, either (1) submit a sufficiently detailed failure modes andg effects analysis (FMEA) to demonstrate the 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.

Also, temperature drops of less than 100 0F can occur and involve more realistic slow changes with time. Assuming all combinations result in slow 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 and time r' ate of change in the feedwater temperature are conservative.

211.143 In the evaluation of the generator load rejection transient GG (15.2) you assume 0.15 second for full stroke closure time of the WNP-2 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 0.07 second (0.08 second for GG). Explain this discrepancy.

GG Also, closure times from partially open to fully closed position SSES are not addressed in the FSAR. For full-stroke closure, the WNP-2 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 105". NBR steam flow and valves wide open initial conditions, may give a less conservative result than an initial condition at a somewhat lower pcwer with centrol valves partially open as expected. Demonstrate that control valve closure times smaller than 0.150 second do not result in unacceptable increases in aMCPR and reactor peak pressure or provide either I

(1) justification that smaller closure times cannot occur er i (2) a minimum closure time to be incorporated in the Technical Specifications.

I

211-32 211.144 For the loss of feedwater heating transient in the manual flow GG (15.1.1) control mode the thermal power monitor (TPM) is used to scram SSES the reactor. Explain the need for the TPM and provide specific WNP-2 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 established for the themal power monitor (TPM).

If so, explain the inconsistency of maximum percent power trip function where you indicate in Table 7.1-2, Note 4, item d(2),

that the maximum trip set point for the TPM is approximately 115 percent power 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 the station technical specifications.

( )* Add to GG only.

211.145 Provide assurance that t': pressure time plots in Chapter 15 WNP-2 (15.4) are consistent with the initiation logic for the safety-relief valves. For example, modifications may have been made to the safety / relief system to prevent subsequent reopening of these valves during pressure increase transients to meet containment design bases loadings.

211.146 Table 15.0-2 provides the required MCPR operating and safety M (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.

211.147 For the recire flow control failure with increasing flow m (15.4.5) transient (15.4.5) provide the initial operating MCPR SSES detemined at 56% (65% SSES) (75% GG) NB rated power and WNP-2 36% (60% SSES) (50% GG) core ficw. In addition, provide the Kf factors as a function of core flow for the automatic and manual flow control modes of operation. Furthermore, provide the maximum flow control set point calibration limit (e.g.,100% or 105% of rated flow) for the recirc loop flow control valves used in the transient analysis.

(Provide recirculation pump M-G set points for the manual ficw control mode assumed in the analysis.*) Also, you reference the GE topical report NE00-10802 as the dynamic model to simulate this event. Since NE00-10802 does not describe the complete event, discuss in greater detail the overall method used to calculate the ACPR.

• Applies to SSES only.

L

211-33 211.148 For the recircul'ation pump seizure accident we note in -

GG (15.3.3) Table 15.3-5 that credit is taken for nonsafety-grade SSES equipment to terminate this event. Section 15.3.3 of the WNP-2 Standard Review Plan, Revision 1, requires use of only safety-grade equipment 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 transition.

211.149 For the feedwater controller failure to maximum flow demand WNP-2 (15.1.2) transient, Table 15.1-3 shows 146% of feedwater flow whereas page 15.1-12 shows 135% of feedwater flow as the maximum flow setting for which the transient was simulated. Clarify this discrepancy.

, 211.150 With a sudden increase in feedwater flow, there will be a GG (15.1.2) drop in the feedwater temperature which contributes to the SSES reactivity increase during the first part of the transient.

WNP-2 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 temperature 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.

211.151 Figure 15.5-1 (Inadvertent startup of HPCI) is inconsistent SSES (15.5.1 ) with the text described in Section 15.5.1.3.3. For example, the figure shows no change in drive and core inlet flow after 20 seconds when the turbine is tripped nor are there any changes shown for such parameters as steam line pressure rise and bypass flow. Please correct these inconsistencies. Also, based on the text, the sequence of events shown in Table 15.5-1 is incomplete. Finally, the assumption that the HPCI tempera-ture is 400F does not appear to be conservative if the text description of the course of this transient is correct. A higher HPCI temperature could result in a level 8 trip of

• the turbine at neutron flux just below scram set point, with a resultant lower MCPR than that obtained using the 400F value. Provide a reanalysis using more conservative temperatures or justify present results.

211.152 In the analysis of inadvertent opening of a safety / relief GG (15.1.4) valve, it is stated that a plant shutdown should be initiated SSES ff the valve cannot be closed. How much time does the operator PIP-2 have to initiate plant shutdown before exceeding Technical Specification limits for suppression pool temperature?

e k-

211-34 211.153 The transient analysis for loss of all grid connections shows GG (15.2.6) main steam line isolation valve (MSIV) closure at 28 seconds SSES (36.8 seconds for SSES) (30 seconds for WNP-2), due to loss WNP-2 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 normal 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 assumed 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 icgic and actuators fail safe to cause an MSIV isolation signal on loss of electrical power? l 211.154 Operation of Grand Gulf, Susquehanna, WNP-2 with partial feed-GG (15.0) water heating might occur during maintenance or as a result SSES of a decision to operate with lower feedwater temperature near WNP-2 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 e.MCPR 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 limi tations) .

211.155 Since systems such as the HPCS, HPCI, and RCIC are initially SSES (7.5) aligned to the condensate storage tank (CST) and switch to WNP-2 the suppression pool on low water level in the CST, the CST water level should be included in Table 7.5-1, entitled

" Safety Related Display Instrumentation." Add the above for display in Table 7.5-1 or justify its omission.

211.156 For the safety-related display instrumentation shown in SSES (7.5) Table 7.5-1, identify which parameters serve a post-accident WNP-2 tracking or monitoring function.

211.157 Regulatory Guide 1.97, Secticn C, paragraph 3, requires the GG (7.5) instrument monitoring range of the reactor vessel pressure SSES to be three times design pressure. In Table 7.5-1 you WNP-2 identify the range to be from 0 to 1500 psig, which does not meet this requirerent. Include this monitoring capability or justify your departure frem the Guide.

. 211-35 211.158 In Table 7.4-4, you identify a shutdown cooling manual suction GG (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.

211.159 Display instrumentation for the condensate storage tank level SSES (7.4.1.4) should be provided on the remote shutdown centrol panel.

WNP-2 Secondly, you state that the RHR flow indicator will be located on the remote shutdown panel. Verify that flow indication will be provided for both RHR systems (A and B),

and that the flow range will be the same as that shown in Table 7.5-1.

211.160 Table 7.4-3 identifies certair. valves actuated by the SSES (7.4) transfer switches. Why are .;irculation suction valves F023B and F023A actuated cic wj? What is the status of the remaining recirculation suction valves? Discuss when the closure of these valves would be initiated and' clarify why valve "A" is closed in Unit 2 while valve "B" is closed in Unit 1. Relate the above discussion to the potential for pump cavitation.

211.161 Per Section 7.4.1.4.3, transfer switches on the remote SSES (7.4.1.4) shutdown panel are operated to transfer control to the remote shutdown panel. Provide a list of valves in the nuclear boiler, RHR, and RCIC systems, if any, that would be actuated to the " safe condition" by a signal from the transfer switches.

211.162 In Table 9.2-5 you show a flow rate of 7400 gpm from the WNP-2 (9.2.7) standbyservicewatersystemgotheRHRheatexchanger.

This flow rate is based on 95 F inlet temperature. However, in Section 5.4.7.2.2 the service water side flow rate of 7400 gpm to the RHR heat exchanger is based on a rated inlet temperature of 850F. Explain this oiscrepancy.

Secondly, show that you have adequately sized the ' required Standby Service Water System flow rates for heat load removal from the ECCS pumps as shown in Table 9.2-5. Support the above information by providing a list of design duty heat loads for the equipment identified in Table 9.2-5.

211.163 Provide a table describing the Standby Service Water System GG (9.2) cooling duty loads as a function of time intervals following WNP-2 a DBA and the operating status of the safeguards equipment (e.g., RHR pumos, 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.

p "a 211-36 211.164 In Table 3.11-3 you identify the co'mpenents and accident GG (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. This accident environ-ment is inconsistent for component operability of such equipment 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 higher by 100 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.

211.165 Add to Table 3.11-3 the Control Rod Hydraulic System (portions SSES (3.11) of system necessary for scram) and its ccmponent operability under abnormal environmental conditions. Clarify whether the RHR steam isolation valves are included in item 4 of Table 3.11-3. Also, provide the basis for selecting an abnormal temperature of 1480F for component operability.

211.166 The following questions pertain to our review of Table 3.9-1 GG (3.9.1.1) which shows the number of plant cycles (events) considered SSES for reactor assembly design and fatigue analysis.

NNP-2 (1) Explain the events in (Item 11 for GG) (Item i for WNP-2)

(Item 9 for SSES) and relate to the transients analyzed in Chapter 15.0. Also, (provide the number of cycles for safety or relief valve blowdown)* 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.)**

(b) (Clarify whether the loss of feedwater pumps in item i (11c for GG) of Table 3.9-1 is due to MSIV closure or both of these events occur independently.

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.)**

• Add to SSES only.

• • Add to GG and WNP-2 cnly, m

a , .. ....- . .-.- . -

211-37 GG 211.166 (2) In Table 3.9-1, item 1-2 (14b for GG) (item 16b for SSES)

SSES (3.9.1.1) is the indicated automatic blowdown feature related to WNP-2 the ADS function?

(3) Explain event (14a for GG) (item 1-2 for WNP-2) (item 15a for SSES) 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."

211.167 In Table 15.0-2, item 32, provide the ccrrect units (or value)

GG (15.0)

SSES for recirculation pump trip inertia for transient analysis.

WNP-2 211.168 Confirm that Figure 15.0-2 includes the effect of the scram GG (15.0) reactivity multiplier. Also, provide in Table 15.0-2, item 28, the correct high pressure scram set point.

211.169 In Table 15.0-2, item 26, you show the high flux trip set point SSES (15.0) of 120% as an input value for transient analysis. Justify for WNP-2 not using the 122% instead of 120% set point which accounts for calibration error, instrument accuracy, and transient overshoot as shown in Table 7.2-4.

b