ML18094A592

Forwards Responses to Questions 1-10 & 13 of NRC 890104 Request for Addl Info Re NUREG-0737,Item II.D.1.Questions 6 & 7 Withdrawn by NRC During 890222 Telcon

ML18094A592
Person / Time
Site:	Salem
Issue date:	08/01/1989
From:	Miltenberger S Public Service Enterprise Group
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM NLR-N89141, NUDOCS 8908080036
Download: ML18094A592 (26)

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• Public Service Electric and Gas Company Steven E. Miltenberger Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 08038 609-339-4199 Vice President and Chief Nuclear Officer August l, 1989 NLR-N89141 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 Gentlemen:

REQUEST FOR ADDITIONAL INFORMATION NUREG 0737 ITEM II.D.1 SALEM GENERATING STATION UNIT NOS. 1 AND 2 DOCKET NOS. 50-272 AND 50-311 The purpose of this letter is to provide responses to questions 1 through 10 and 13 of the NRC request for additional information letter dated January 4, 1989 regarding NUREG 0737, Item II.D.1.

Note that questions 6 and 7 were subsequently withdrawn by the NRC during a telecon on February 22, 1989. This submittal completes the responses to questions 1 through 9 as committed in PSE&G letter NLR-N89048 dated March 31, 1989. A preliminary response is provided for questions 10 and 13. The final.

responses will be provided by October 31, 1989. Questions 11 and 12 and 14 through 16 were responded to in our lette.r dated July 7, 1989 (NLR-N89109). .

Should you have any further questions, please feel free to contact us.

Sincerely, Attachment

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Document Control Desk 2

• August 1, 1989 NLR-N89141 C Mr. J. c. Stone Licensing Project Manager Ms. K. Halvey Gibson Senior Resident Inspector Mr. W. T. Russell, Administrator Region I Mr. Kent Tosch, Chief New Jersey Department of Environmental Protection Division of Environmental Quality Bureau of Nuclear Engineering CN 415 Trenton, NJ 08625

NRC QUESTIONS AND RESPONSES Ql. PORV Loop Seal Reference 4 indicated that the inlet piping to the Salem PORVs were in the loop seal configuration (see table on page 5), but made no reference of the loop seal in its discussion of PORV operability. In addition, the Salem Stress Reports (Reference 2) stated that the PORV inlet piping did not include a loop seal. It is, therefore, not clear whether there is loop seal in the PORV inlet piping or not. Verify whether Salem PORV inlet piping include loop seal and whether a cold or insulated loop seal is used. If a loop seal is, indeed, included in the PORV inlet piping, provide a discussion on the PORV operability in the presence of a loop seal.

Response

Review of the piping arrangement drawings for the Salem PORVs confirms that the piping configuration, although not a classical "U" shaped loop seal, would permit condensate to cbllect for several feet upstream (inlet side) of the valves. This piping, from the pressurizer nozzle to the PORVs, is insulated; insulation varies from 3-inches of reflective type insulation near the pressurizer, to 1.5-inches of encapsulated type insulation adjacent to the valves.

Regarding valve operability in the presence of a.loop seal, reference is made to section 4.6.2 of EPRI Report NP-2628-SR, EPRI PWR Safety and Relief Valve Test Program, which has already been docketed. It is concluded in this report that Copes Vulcan valves, as installed at Salem, opened and closed upon demand and sustained no damage that would affect future valve performance for a variety of valve inlet steam and water conditions, including a simulation of inlet water seal.

Q2. Safety Valve Inlet Pressure Drop The Licensee gave the pressure drop values through the inlet piping as 18.6 psi for the plant specific safety valve and 19.2 psi for the applicable EPRI test valve (see Question 4, Reference 2). These values appear to be extremely low, compared with pressure drops listed in Table B-3 of Reference 3 for various EPRI valve inlet configurations.

Verify the pressure drop values given above. Present a recalculation of the total pressure drops through the inlet piping of Salem Units 1 and 2 safety valves and the applicable EPRI inlet piping arrangement. The total pressure drop should include both the frictional and acoustic wave components evaluated under steam conditions.

Response

The pressure drop of 18.6 psi provided in our August 19, 1985 submittal consisted of frictional component only. is a revised calculation (S-C-R200-MDC-091, Rev. 1) of the pressure drop through the safety valve inlet piping. The total pressure drop calculated includes both frictional and acoustic wave components.

The method and formulas used to calculate the pressure drop are based on MPR Associates, Inc. interim report - Rev. 2 "EPRI PWR Safety Valve and Relief Valve Test Program Guide for Application of Valve Test Program Results to plant Specific Evaluations."

Appendix B to that report provides the procedure for calculation of inlet piping pressure effects.

The Salem plant specific pressure drop is less than the EPRI test configuration pressure drops provided in Table B-3 of the MPR Associates report. Hence, Salem safety valves would be expected to have performance at least as stable as the tested valve.

Q3. Backpressure The submittal did not include a comparison of the maximum backpressure developed in the discharge piping of the Salem safety valve with the EPRI tests. Since the EPRI tests show that safety valve performance is sensitive to backpressure, backpressure should be considered in the safety valve evaluation. Provide the numerical value of the calculated maximum backpressure for the Salem safety valve and explain how the backpressure was calculated.

Response

Backpressure developed in the discharge piping of the Salem safety valves was calculated using Continuum Dynamics Inc.'s quasi-steady backpressure computer program. The program calculated backpressure for all relief and safety valves open, thus predicting the higher and more conservative backpressures (616 to 688 psia). (Note that the backpressure calculated for one of the Salem Unit 1 safety valves was 478 psia for only one safety valve open as identified in Reference 2 of the Continuum Dynamics Report). The Continuum Dynamics Tech.

Note 82-29 documenting the results was forwarded to the NRC along with our August 19, 1985 submittal.

The highest backpressure was predicted for valve 1PR4 which has the longest (actual plus equivalent) length of piping of all the pressurizer safety valves at Salem Unit 1 and 2. Thus it is concluded that the Salem 1 backpressure calculation bounds both Salem Unit 1 and 2 backpressure calculation.

The discharge piping comparison for the Salem units is summarized and attached as Table 1.

Q4. Cold overpressure Transient In the discussion of the PORV inlet fluid condition for cold overpressure transients, the Licensee indicated that the maximum pressure is 446 psig for the mass input case and 424 psig for the heat input case but did not give the temperature range under which the valve is expected to operate (Question 1, Reference 2). Identify the maximum and minimum temperature predicted for cold overpressure transient so as to complete the cold overpressure discussion.

Response

The maximum and minimum temperatures predicted for the cold overpressure transients are 312°F and 80°F.

QS. PORV Control Circuitry The Licensee submitted the Functional Specification:

cn-s-10 for the Pressurizer overpressure Protection System for the Salem plant to demonstrate the qualification of the PORV control circuitry (Question 8, Reference 2). This information, by itself, is not sufficient to demonstrate qualification of the control circuitry at Salem under NUREG-0737. The Nuclear Regulatory Commission staff has agreed that meeting the licensing requirements of 10CFR50.49 for this circuitry is satisfactory and that specific testing per NUREG-0737 requirement is not required. Therefore, verify whether the PORV control circuitry has been reviewed and accepted under the requirements of 10CFR50.49.

If the PORV circuitry has not been qualified to the requirements of 10CFR50.49, provide information to demonstrate that the control circuitry is qualified per the guidance provided in Reg. Guide 1.89, Revision 1, Appendix E.

As an alternative, the staff has determined that the requirements of NUREG-0737 regarding the qualification of the PORV control circuitry may be satisfied if one or more of the following conditions is met.

a. The PORVs are not required to perform a safety function to mitigate the effects of any design basis event in the harsh environment, and failure in the harsh environment will not adversely impact safety functions or mislead the operator (PORVs will not experience any spurious actuations and, if emergency operating procedures do not specifically prohibit use of PORVs in

accident mitigation, it must be ascertained that PORVs can be closed under harsh environment conditions).

b. The PORVs are required to perform a safety function to mitigate the effects of a specific event, but are not subjected to a harsh environment as a result of that event.

c. The PORVs perform their function before being exposed to the harsh environment, and the adequacy of the time margin provided is justified; subsequent failure of the PORVs as a result of the harsh environment will not degrade other safety functions or mislead the operator (PORVs will not experience any spurious actuations, and if emergency operating procedures do not specifically prohibit use of PORVs in accident mitigation, it must be ascertained that PORVs can be closed under harsh environment conditions) .

d. The safety function can be accomplished by some other designated equipment that has been adequately qualified and satisfies the single-failure criterion.

Response

PSE&G elects to show PORV control circuitry compliance to NUREG-0737, Item II. D.1 by satisfying alternative criteria "b" as specified in the NRC letter.

Salem PORVs are assumed to operate or not operate so as to give worst case results for the loss of load accident, loss of feedwater accident and rod withdrawal accident at power.

However, PORVs are not required to perform a safety function to mitigate the effects of the above events.

The only event (although not a design basis) during which PORVs may be relied upon to perform a mitigating function is a steam generator tube rupture (SGTR). During a SGTR event, pressurizer spray is used to control RCS pressure. With Reactor Coolant Pumps stopped and normal pressurizer spray unavailable, PORVs or auxiliary pressurizer spray is used to control RCS pressure.

The use of PORVs to reduce RCS pressure to no load secondary side steam generator saturation pressure does not normally lead to a pressurizer relief tank (PRT) rupture disc rupture as known from a previous simulator run. As such, the containment is not subjected to a harsh environment as a result of a SGTR event.

However, in a case that the PRT rupture disc ruptures with the actuation of a PORV, the containment conditions are judged not to be harsh enough to preclude subsequent PORV actuations, if required.

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In view of the above, it is concluded that the PORVs, when required to mitigate the effects of a SGTR event, are not subjected to a harsh environment as a result of that event.

Q6. Valve Discharge Condition This question withdrawn by NRC staff during February 22, 1989 telecon.

Q7. Pressurization Rate This question withdrawn by NRC staff during February 22, 1989 telecon.

Q8. PORV Loop Seal Referring to Question 1 above the Impell thermal hydraulic and stress analysis of the piping system assumed that there was no water seal upstream of the Salem PORVs. If it is determined that the PORV inlet pipe does include a water seal, identify the water seal temperature and amend the Impell analysis to include the effects of the water seal on the piping stresses.

Response

A full review of PORV piping files has revealed that final calculations did not include consideration of a valve inlet loop seal. Initial data retrieval efforts gave the erroneous impression that a loop seal was included, however this was only for some very early trial calculation cases.

The PORV loop seal was not included in the final analysis as it was felt that it would be an inordinate conservatism in light of the following conservatisms already included or mitigating circumstances present:

a. Conservative assumption of 5 valves discharging simultaneously, as opposed to separate PORV and Safety Valve actuations.

b. Conservative assumption of 150 millisecond relief valve opening time, rather than the EPRI test verified opening time of 500.to 970 milliseconds.

c. Use of the higher maximum EPRI valve test flow rates in the analysis, rather than the lower manufacturer's "rated" flow*

rates.

d. Existence of insulation on the PORV loop seal piping, thus warming the water and tending to lower forces generated.

e.

Identification that the volume of water in the two PORV loopseals is a total of approximately 0.7 cubic feet, or only 15% of the estimated combined loopseal volumes of the three safety valves and the two PORVs.

f. Use of level B (Upset condition) and level c (Emergency condition) allowable stresses for the PORV and Safety Valve discharge piping respectively, rather than the less conservative, yet permissible, levels C and D (Faulted condition), respectively.

g. Conservative assumption of PORV opening pressure of 2500 psi, rather than the actual opening pressure of 2235 psi, (which would generate lower piping loads) .

Given the above, it is our position that the existing analysis without PORV loop seals is acceptable and that no further analysis in this area is required.

Q9. Safety Valve Loop Seal Temperature In the discussion of the thermal hydraulic analysis in Reference 2, the Licensee did not provide information on the loop seal temperature distribution used. Since the fluid forces acting on the piping system can be significantly affected by the loop seal temperature assumed in the analysis, show the loop seal temperature profile used in the thermal hydraulic analysis and provide a field verification by comparing the assumed temperature with the actual temperature measured at the plant.

Response

The loop seal temperature distribution used in the stress analysis for the longest inlet loop seal of all Salem Units 1 & 2 valves are provided in Attachment 2. Node numbers are identified in Sketch 1. Also attached is Sketch 2 showing the loop seal arrangement and Sketch 3 showing the projected loop seal temperature profile developed by Diamond Power, Inc., the designer of the loop seal insulation.

To field verify the temperatures obtained, each of the Salem Unit 2 loop seals was installed with a clamp on style Conax thermocouple in the vertical run from the pressurizer. A similar thermocouple was installed on each safety valve inlet flange.

Salem Unit 1 insulation boxes were installed subsequent to the Salem Unit 2 insulation box installation. Thermocouples on the Salem Unit 1 loop seals were installed similar to the Salem 2 configuration with one exception. The thermocouple on the 1PR3 loop seal was moved from the vertical run to the horizontal run on the steam space close to the pressurizer nozzle. The purpose of this relocated thermocouple was to calibrate the thermocouple readings against the known steam condition in the steam space at the highest elevation.

The field verifications performed using these thermocouples were evaluated and it was concluded that Salem Units 1 and 2 pressurizer loop seal insulation boxes produced the projected temperature profile, thereby validating the Impell analysis.

QlO. Thermal Hydraulic Analysis Inputs In the description of the thermal hydraulic analysis of the safety valve and PORV discharge conditions, the Impell stress report only defined the valve opening pressure and pressurization rate used in the analysis (Reference 2). It did not give details on the important input parameters used in the analysis. Provide information on the peak pressure developed at the safety valve and PORV inlets and other key parameters used in the computer calculations such as piping model node spacing, computation time interval, choked flow locations, etc. so that the review of the thermal hydraulic analysis can be completed.

Response

The thermal hydraulic analyses which provided inputs to the piping stress analyses for the Salem Unit 1 plant were performed by Impell Corporation, while those for Salem Unit 2 were performed by PSE&G and transmitted to Impell for use in the piping stress analyses.

For the Unit 1 analysis, peak pressuies at the Safety Valves and PORV inlets are provided in the following table:

FIRST VOLUME UPSTREAM OF VALVE PEAK INLET PRESSURE VALVE ORIFICE (psia) @ (sec.)

sv 2 312 PR3 2662 7.5 x 10-sv 2 1812 PR4 2656 7.5 x 10-2712 sv PR5 2655 7.5 x 10- 2 4404 RV PR2 2395 5.0 x 10- 2 2

5204 RV PRl 2397 5.0 x 10-

The above peak pressures are obtained from the RELAP5/MOD1 run of record #RELAPPO for the Safety valve hot loop seal (insulation box) discharge analysis.

Unit 1 piping model node spacing was selected in accordance with the ITI recommendations (Reference 8). The size of the control volumes (nodes) was kept close to one foot, and significant differences in length between adjacent control volumes (nodes) were avoided.

Concerning the computation time interval utilized in the Unit 1 thermal hydraulic t~~nsient analysis, the maximum time step was seconds~

limited to 2.0 x 10 used by RELAP was 1.9531 x 10 7 The minimum time step actually s~~onds for the first 50 milliseconds and reached 2.0 x 10 seconds thereafter for the duration of the transient.

Concerning choked flow locations for the Unit 1 analysis, the RELAP5/MOD1 choking option was only used at the safety and relief valve locations. The RELAP run of record RELAPPO results indicate that at those locations, choking was present throughout the transient and that the choking model was applied for a total of 4,353 time steps. Based upon the ITI recommendations and results of the choking sensitivity studies (Reference 8, Section C.3), the choking option was not used elsewhere in the thermal-hydraulic analysis.

As previously mentioned, the Unit 2 thermal-hydraulic analysis was performed by PSE&G and transmitted to Impell for use in the piping stress analysis. Specifically, the analysis was performed by a PSE&G employee, who was then the Technical Chairman of the EPRI Safety and Relief Valve Test Program addressing these issues and who is experienced in this type of analysis. The original input data for the Unit 2 analysis were stored on electronic media (magnetic tape). During the relocation of our Nuclear Department to the Salem site, these tapes were lost, and as such, the data is not retrievable. It is felt however, that the calculated values for node spacing and time step utilized in the Unit 2 analysis were consistent with calculated values of sonic velocity, and that the solutions obtained were reasonable and consistent with accepted practice. Similarly, there is every confidence that the application of the choke flow option was prudently performed.

As an added assurance as to the accuracy of the Unit 2 analysis, a comparison will be made between the physical configuration/modeling of Unit 1 and Unit 2. It is felt that similarity of configuration, modeling, thermal hydraulic inputs, and codes will provide such assurance.

The results of this comparison will be provided by October 31, 1989.

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Q13. Portion of Discharge Piping Not Analyzed The stresses in the piping downstream from the pipe anchor at elevation 131 ft.-4 in. to the pressurizer relief tank were not addressed in the Impell stress reports. The Licensee contended that this portion of the piping was isolated from the Reactor Coolant Pressure Boundary (RCPB) by the pipe anchor, and the piping was dispensable and could be excluded from the analysis. Although the piping downstream of the anchor at elevation 131 ft-4 in. is outside the RCPB, the failure of this piping may still affect valve operability. For instance, if the failure of the downstream pipes results in excessive pipe deformation, the discharge flow may be restricted to such an extent that the valve can no longer function properly. If an abrupt rupture of the pipe occurs, the pipe whip may cause severe damage to the upstream piping and even the valve itself.

Therefore, the piping from the anchor at elevation 131 ft-4 in. to the discharge tank cannot be ignored. Provide an analysis of the piping and supports downstream of the anchor to ensure that the integrity of the piping within the RCPB and the operability of the valves will not be adversely affected by in the downstream piping.

Response

In lieu of performing a complete reanalysis of the downstream piping and supports to ensure no loss of function of the Safety Valves and PORVs and no deleterious effect upon adjacent accident mitigating equipment, it is intended to perform a bounding analysis of sufficient rigor to provide reasonable assurance of the above.

Even though the Stress Reports did not address specifically stress analysis for the piping between elevation 131 ft-4in. and the pressurizer relief tank, a stress analysis of the line was performed to derive the loads for the anchor separating the segments of pipe (Reference 1).

The review of the pipe stress runs for the above mentioned piping has produced the following results:

Piping Stress The original stress run, as it did not intend to qualify the line, but only to develop anchor loads, did not provide for a code check of the load, but it did provide individual load cases for all the analyzed conditions. Therefore, our review included the summing up (by hand) of the stresses for individual load cases (Ref. 2) for the highest stressed node points. The load cases included deadweight, thermal,

seismic, and RVA (Rapid Valve Actuation). The RVA has two load cases which involve water and steam respectively. By reviewing the results of the steam and water load cases (4e and 4d), it is found that the RVAS (steam) loads are almost double RVAW (water) loads. Thus only RVAS loads were used in the evaluation.

The stress check of the highest loaded nodes in the piping between the anchor and the discharge tank (as shown in Table 2) demonstrates that all the stresses are within the required allowables. Therefore, the piping will maintain its structural integrity during any normal, seismic, or faulted condition considered.

Supports The review of the stress runs (Ref. 2) shows that the maximum support load is at Node 993 (Z-snubber) of 40,785 lbs. The support loads in the upstream piping (above elevation 131 ft-4in.

anchor) were reviewed and were found to be much higher.

A more extensive sampling review of support stresses for the downstream piping is in progress; current judgement is that the piping supports can be shown to provide adequate restraint to ensure continued function of the Safety and PORV valves under postulated loading conditions with no unacceptable deleterious effect upon adjacent accident mitigating equipment. We will provide the results of this investigation when it is complete (October 31, 1989).

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• TABLE 1 DISCHARGE PIPING -

PZR SAFETIES SALEM QUESTION 3 ITEM 1PR4 2PR3 2PR4 2PR5 6 II Pipe 42.26' 1. 849 1.851 1.846 Based on Per 13.185 1.000 1.000 567 PDL-S2 Continuum 1.083 1. 542 1. 500 267 PDL-Sl Dynamics 0.418 0.885 0.927 Report 1. 435 1.000 0.687 82-29 1. 739 0.500 0.730

[1PR4 pro- 0.875 0.979 1.083 vides the 1. 069 0.521 1. 617 limiting 1.167 0.396 0.630 conditions 2.625 0. 6.04 0.750 and thus 1. 366 2.498 1. 500 bounds 2.186 0.999 1.380 1PR3 and 1. 687 2.231 0.707 1PR5 also] 0.417 1.036 0.909 0.750 2.932 4.318 0.458 2.293 1.041 0.875 0.583 1.615

1. 801 1.250 1.500

1. 578 1. 714 3.380 0.750 2.349 1.854 2.027 42.26' 36.563' 27.913' 31.001 12 II Piping from PRT to 213.214' 212.451' 212.4~1' 212.451' 131'-4 11 anchor Based on 567-PDL for Unit 2 and 267-PDL for Unit 1.

12 II Piping from 131'-4" anchor to where 6" pipe 7.218' 8.802' 10.802' 9.500' joins Fittings in 12" Identical Identical Identical line 8 elbows to 1PR4 to 1PR4 to 1PR4 Fittings in 6" line 7 elbows 6 elbows 5 elbows 7 elbows CONCLUSION Salem 1 Backpressure is bounding for Sl & 52

Public Service Electric and Gas Company June 9, 1989 0140-039-NY-010 QUESTION 9 ATTACHMENT 2 A. Safety Valve 1PR3 VOLUME LENGTH

("

\ I 301 0.5230 Steam at 668.F' Hater at 668.F 302 0.5890 Steam at 668.F Hater at 668.F 303 1. 1781 Steu at 668.F Hater at 668.F 304 . 1*.4050 Steam at 668.F Hater at 66&-F 305 1.1781 Steam at 668.F Hater at 66&-F 306 1. 1781 Hater at 5so*F Hater at 55Q*F 307 3.0580 Hater at sso*F Hater at 55o*F 308 1. 1781 Hater at 5so*F Hater at sso*F 309 2.5050 Hater at sso*F Hater at sso*F 310 1. 1781 Hater at sso*F Hater at 5so*F 311 0.5830 Hater at So&*F Water at so6*F 312 0.9380 Hater at 21o*F Hater at 21o*F

' fl.. *"

t

' A *

• QUESTION 9 SKETCH 1

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• QUESTION 9 SKETCH 2 1N~TI0~ eox.

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IN!il>-TION ~~

Loop Seal Arrangement Geomet:y Pipe o.o.

• 6.625 in; Pipe Wall Tilickncss * .718 in. (6 11 N.P.S. - Schedule 160)

CenterLine Length of Region 1

• 12.67 CenterLine* Length of Region 2

• 74. 73 See Appendix 8

• CenterLine Length of Region 3

• 36.00 in.

NOTB:***Region 3 length (Valve &Downstream Piping) was determined from previo~

experience so cu to provide sufficient tempeznture decay from tho loop seal pipe/valve interface to ambient temperature. (Ref. Page~3.4;Tempera-t:me Profile of Region 3).

SRS 590348 "

QUESTION 9 SKETCH 3

~

.. t ~.,, '50.1."J m1:1tr.1' at C 4 ti %D ,., 18 ll IC. l5 14 ~ 1& TI 7" '15 14 75' ~ .,, '75 'ft Km:

l

LOOP SEAL TE?*IPERATIJRE PROFILE

• TABIE 2 (Question 13)

STRESS GIECK OF '!HE HIGHEST I.OADED NODES STRESS ClIECK, DEFAUIIl.' OPITON A) E;2 8 PRES + Il'l, allowable 1. 0 SH @ Node 890A Ell:x:M 4250 + 2281 = 6531 psi < 15990 B) E;2 9U PRES + Il'1 + OBE, allowable 1.2 SH @ Node 997B Ell:x:M 4250 + 698 + 2783 = 7731 < 19188 psi C) :m 10 Range of 'lhennal allowable SA= 27497.5 psi @ Node 840A 24778 psi< 27497.5 psi OK no need to check E;2 11 STRESS ClIECK, NON DEFAIJI1I' OPITON D) IC2S PRESS + Il'1 + RVAS allowable 1. 8 SH @ Node 840A Ell:x:M

\

Level C (Attachroont 4) 4250 + 819 + 21948 = 27017 psi < 28782 psi E) IC4S PRESS + Il'1 + (om2 + RVAS2 ) l/2 allowable 1.8 SH level C 2 2 4250 + 819 + (1021 + 21948 ) 112 = 27040 < 28782 psi F) IC4S PRESS + Il'1 + (~ + RVAS2 ) l/2 allowable 2. 4 SH level D 2

4250 + 819 + (2292 + 219482 ) 112 = 27136 38376 psi REFERENCES (Question 13)

1. Impell C_aJ_~_.___ No. 2_()? __ ~~~u-~ctionally Study Elev. 131 Anchors",

5/6/85 2* Computer Runs

a. ACWYWVBM 2/11/85 DW, Thermal, Seismic

b. ACWYNSOC 2/19/85 EVAS Loading

c. MIKEONA 3/23/84 Code Check

d. MIKEORG 3/15/84 Discharge Piping, RVAS

e. MIKEDTA 3/22/84 Discharge Piping RVAW