ML16168A377

4 to Updated Safety Analysis Report, Appendix I, Postulated Pipe Failure Analysis Outside of Containment

ML16168A377
Person / Time
Site:	Prairie Island
Issue date:	06/03/2016
From:	Northern States Power Co, Xcel Energy
To:	Office of Nuclear Reactor Regulation
Shared Package
ML16168A332	List: L-PI-16-049, 4 to Updated Safety Analysis Report, Appendix L, Requirement of Renewed Operating Licenses ML16168A330 ML16168A342 ML16168A344 ML16168A345 ML16168A346 ML16168A347 ML16168A348 ML16168A349 ML16168A350 ML16168A351 ML16168A352 ML16168A358 ML16168A360 ML16168A361 ML16168A362 ML16168A363 ML16168A364 ML16168A374 ML16168A375 ML16168A376 ML16168A377 ML16168A378 ML16168A379
References
L-PI-16-049
Download: ML16168A377 (170)

Text

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page i APPENDIX I POSTULATED PIPE FAILURE ANALYSIS OUTSIDE OF CONTAINMENT TABLE OF CONTENTS Page INTRODUCTION...............................................................................................I.1-1 I.1 HIGH ENERGY PIPING SYSTEMS AND REQUIRED EQUIPMENT.....I.1-2 I.1.1 Definition of High Energy Piping Systems................................I.1-2 I.1.2 Identification of High Energy Piping Systems...........................I.1-2 I.1.3 Selection of Break and Crack Locations..................................I.1-3 I.1.4 Selection of Required Equipment.............................................I.1-4 I.2 FEATURES FOR PROTECTION AGAINST THE EFFECTS OF HELB EVENTS................................................................................................I.2-1 I.2.1 Pipe Rupture Induced Loads....................................................I.2-1 I.2.2 Mitigating Consequences of Pipe Rupture...............................I.2-3 I.2.3 Plant Operability.......................................................................I.2-8 I.2.4 Equipment Operability..............................................................I.2-9 I.3 SYSTEM ROUTING AND RUPTURE EVALUATION OUTSIDE CONTAINMENT......................................................................................I.3-1 I.3.1 Structures.................................................................................I.3-1 I.3.2 High Energy Piping Systems....................................................I.3-2 I.4 FEATURES PROVIDED FOR PIPE RUPTURE EVENTS......................I.4-1 I.4.1 Required Equipment................................................................I.4-1 I.4.2 Steam Exclusion Boundaries...................................................I.4-1 I.4.3 Encapsulation Sleeves and Impingement Barriers...................I.4-3 I.4.4 Rupture Restraints...................................................................I.4-4 I.4.5 Flooding Protection..................................................................I.4-4 I.4.6 Equipment Environmental Qualification...................................I.4-4 I.4.7 Operating Procedures..............................................................I.4-5

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page ii TABLE OF CONTENTS (Continued)

Page I.5 TOPICAL ANALYSIS..............................................................................I.5-1 I.5.1 Pipe Stress...............................................................................I.5-1 I.5.2 Pipe Whip.................................................................................I.5-2 I.5.3 Compartment Pressure and Temperature................................I.5-4 I.5.4 Jet Impingement [Ref. 9.7].......................................................I.5-6 I.5.5 Flooding...................................................................................I.5-7 I.6 MAIN STEAM AND FEEDWATER INSIDE CONTAINMENT..................I.6-1 I.7 HIGH ENERGY LINES IN THE TURBINE BUILDING............................I.7-1 I.8 REFERENCES........................................................................................I.8-1

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page iii TABLE OF CONTENTS [Continued]

LIST OF TABLES TABLE I.1.4-1 REQUIRED EQUIPMENT TABLE I.3.1-1 AUXILIARY BUILDING - COMPARTMENT DATA TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C) LOCATIONS -

OUTSIDE CONTAINMENT TABLE I.3.2-2 HIGH ENERGY LINE BREAK (B) AND CRACK (C) LOCATIONS -

INSIDE CONTAINMENT TABLE I.3.2-3 HIGH ENERGY LINE BREAK (B) AND CRACK (C) LOCATIONS -

AUXILIARY BUILDING COMPARTMENTS TABLE I.3.2-4 HIGH ENERGY LINE BREAK (B) AND CRACK (C) LOCATIONS -

TURBINE BUILDING COMPARTMENTS

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page iv TABLE OF CONTENTS [Continued]

LIST OF FIGURES FIGURE I.3.1-1 DELETED FIGURE I.3.1-2 AUXILIARY BUILDING COMPARTMENT PLAN -

ELEVATION 755 FIGURE I.3.1-3 AUXILIARY BUILDING COMPARTMENT PLAN -

ELEVATION 735 FIGURE I.3.1-4 AUXILIARY BUILDING COMPARTMENT PLAN -

ELEVATION 715 FIGURE I.3.1-5 AUXILIARY BUILDING COMPARTMENT PLAN -

ELEVATION 726 -6 FIGURE I.3.1-6 AUXILIARY BUILDING COMPARTMENT PLAN -

ELEVATION 695 FIGURE I.3.1-7 TURBINE BUILDING COMPARTMENT PLAN -

ELEVATION 735 FIGURE I.3.1-8 TURBINE BUILDING COMPARTMENT PLAN -

ELEVATION 715 FIGURE I.3.1-9 TURBINE BUILDING COMPARTMENT PLAN -

ELEVATION 695 FIGURE I.3.1-10 TURBINE BUILDING COMPARTMENT PLAN -

ELEVATION 679 FIGURE I.3.2-1 MAIN STEAM ISOMETRIC - UNIT 1 FIGURE I.3.2-2 MAIN STEAM ISOMETRIC - UNIT 2 FIGURE I.3.2-3 FEEDWATER ISOMETRIC - UNIT 1 FIGURE I.3.2-4 FEEDWATER ISOMETRIC - UNIT 2 FIGURE I.3.2-5 CVCS LETDOWN ISOMETRIC - UNIT 1 FIGURE I.3.2-6 CVCS LETDOWN ISOMETRIC - UNIT 2

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page v TABLE OF CONTENTS [Continued]

LIST OF FIGURES FIGURE I.3.2-7 STEAM GENERATOR BLOWDOWN ISOMETRIC - UNIT 1 FIGURE I.3.2-8 STEAM GENERATOR BLOWDOWN ISOMETRIC - UNIT 2 FIGURE I.3.2-9 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP ISOMETRIC - UNIT 1 FIGURE I.3.2-10 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP ISOMETRIC - UNIT 2 FIGURE I.3.2-11 TURBINE BUILDING FEEDWATER ISOMETRIC - UNIT 1 FIGURE I.3.2-12 TURBINE BUILDING FEEDWATER ISOMETRIC - UNIT 2 FIGURE I.3.2-13 CONDENSATE ISOMETRIC - UNIT 1 FIGURE I.3.2-14 CONDENSATE ISOMETRIC - UNIT 2 FIGURE I.4.3-1 HIGH ENERGY LINE BREAK - ENCAPSULATION SLEEVES AND IMPINGEMENT BARRIERS FIGURE I.4.3-2 HIGH ENERGY LINE BREAK - TYPICAL DOOR SEALS FIGURE I.5.1-1 STRESS PLOT - MAIN STEAM, #11 STEAM GENERATOR FIGURE I.5.1-2 STRESS PLOT - MAIN STEAM, #12 STEAM GENERATOR FIGURE I.5.1-3 STRESS PLOT - MAIN STEAM, #21 STEAM GENERATOR FIGURE I.5.1-4 STRESS PLOT - MAIN STEAM, #22 STEAM GENERATOR FIGURE I.5.1-5 STRESS PLOT - FEEDWATER, UNIT 1 FIGURE I.5.1-6 STRESS PLOT - FEEDWATER, UNIT 2 FIGURE I.5.1-7 STRESS PLOT - CONDENSATE, UNIT 1 FIGURE I.5.1-8 STRESS PLOT - CONDENSATE, UNIT 2 FIGURE I.5.1-9 STRESS PLOT - CVCS LETDOWN, UNIT 1 FIGURE I.5.1-10 STRESS PLOT - CVCS LETDOWN, UNIT 2 FIGURE I.5.1-11 STRESS PLOT - #11 STEAM GENERATOR BLOWDOWN

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page vi TABLE OF CONTENTS [Continued]

LIST OF FIGURES FIGURE I.5.1-12 STRESS PLOT - #12 STEAM GENERATOR BLOWDOWN FIGURE I.5.1-13 STRESS PLOT - #21 STEAM GENERATOR BLOWDOWN FIGURE I.5.1-14 STRESS PLOT - #22 STEAM GENERATOR BLOWDOWN FIGURE I.5.1-15 STRESS PLOT - #11 STEAM GENERATOR SUPPLY TO AUXILIARY FEEDWATER PUMP FIGURE I.5.1-16 STRESS PLOT - #12 STEAM GENERATOR SUPPLY TO AUXILIARY FEEDWATER PUMP FIGURE I.5.1-17 STRESS PLOT - #21 STEAM GENERATOR SUPPLY TO AUXILIARY FEEDWATER PUMP FIGURE I.5.1-18 STRESS PLOT - #22 STEAM GENERATOR SUPPLY TO AUXILIARY FEEDWATER PUMP FIGURE I.5.1-19 TYPICAL DYNAMIC ANALYSIS MATHEMATICAL MODEL -

UNIT 1 FIGURE I.5.4-1 IMPINGEMENT PRESSURE - 31 MAIN STEAM, DESIGN BASIS BREAK FIGURE I.5.4-2 IMPINGEMENT TEMPERATURE - 31 MAIN STEAM, DESIGN BASIS BREAK FIGURE I.5.4-3 IMPINGEMENT PRESSURE - 31 MAIN STEAM, DESIGN BASIS BREAK FIGURE I.5.4-4 IMPINGEMENT TEMPERATURE - 31 MAIN STEAM, DESIGN BASIS CRACK FIGURE I.5.4-5 IMPINGEMENT PRESSURE - 16 FEEDWATER, DESIGN BASIS BREAK FIGURE I.5.4-6 IMPINGEMENT TEMPERATURE - 16 FEEDWATER, DESIGN BASIS BREAK FIGURE I.5.4-7 IMPINGEMENT PRESSURE - 16 FEEDWATER, DESIGN BASIS BREAK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 Page vii TABLE OF CONTENTS [Continued]

LIST OF FIGURES FIGURE I.5.4-8 IMPINGEMENT TEMPERATURE - 16 FEEDWATER, DESIGN BASIS CRACK FIGURE I.5.4-9 IMPINGEMENT PRESSURE - 2 CVCS LETDOWN, DESIGN BASIS BREAK FIGURE I.5.4-10 IMPINGEMENT TEMPERATURE - 2 CVCS LETDOWN, DESIGN BASIS BREAK FIGURE I.5.4-11 IMPINGEMENT PRESSURE - 2 CVCS LETDOWN, DESIGN BASIS BREAK FIGURE I.5.4-12 IMPINGEMENT TEMPERATURE - 2 CVCS LETDOWN, DESIGN BASIS BREAK FIGURE I.5.4-13 IMPINGEMENT PRESSURE-2 STEAM GENERATOR BLOWDOWN, DESIGN BASIS BREAK FIGURE I.5.4-14 IMPINGEMENT TEMPERATURE - 2 STEAM GENERATOR BLOWDOWN, DESIGN BASIS BREAK FIGURE I.5.4-15 IMPINGEMENT PRESSURE - 2 STEAM GENERATOR BLOWDOWN, DESIGN BASIS CRACK FIGURE I.5.4-16 IMPINGEMENT TEMPERATURE - 2 STEAM GENERATOR BLOWDOWN, DESIGN BASIS CRACK FIGURE I.5.4-17 IMPINGEMENT PRESSURE - 3 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP, DESIGN BASIS BREAK FIGURE I.5.4-18 IMPINGEMENT TEMPERATURE - 3 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP, DESIGN BASIS BREAK FIGURE I.5.4-19 IMPINGEMENT PRESSURE - 3 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP, DESIGN BASIS CRACK FIGURE I.5.4-20 IMPINGEMENT TEMPERATURE - 3 STEAM SUPPLY TO AUXILIARY FEEDWATER PUMP, DESIGN BASIS CRACK

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.1-1 APPENDIX I - POSTULATED PIPE FAILURE ANALYSIS OUTSIDE OF CONTAINMENT INTRODUCTION In an Atomic Energy Commission (A Giambusso) letter to Northern States Power (AV Dienhart) dated December 12, 1972 [Ref. 1], the AEC stated that Prairie Island

...should be designed so that the reactor can be shutdown and maintained in a safe shutdown condition in the event of a postulated rupture, outside of containment, of a pipe carrying high energy fluid, including the rupture of the largest pipe in the main steam and feedwater systems. This letter requested information on how the plant design would be revised to accommodate the postulated pipe ruptures and how any proposed modifications would address the guidelines and criteria contained in the attachment to the letter. Additional requests for information and clarification of AEC criteria are contained in AEC (A Giambusso) letters to NSP (AV Dienhart) dated January 11, 1973 [Ref. 2] and February 9, 1973 [Ref. 3].

Although the Giambusso letters were only applicable to high energy line breaks outside containment, a conservative engineering judgement was made to perform a similar review of the main steam and feedwater lines inside containment utilizing the criteria from the Giambusso letters. This review resulted in installation of impingement barriers on portions of these lines. This information was not included in the FSAR, but was added to this Appendix for completeness.

Nuclear Regulatory Commission (NRC) Generic Letter 87-11 (GL 87-11) [Ref. 4]

relaxed the requirements for postulating arbitrary intermediate breaks and leakage cracks in high energy piping systems. This Appendix includes information on NSPs response to the Giambusso letters and NSPs subsequent application of GL 87-11 criteria. When adopting the relief offered by Generic Letter 87-11, PINGP eliminated arbitrary breaks and utilized the applicable stress equations for break selection in the attached MEB 3-1 and nothing more.

In addition, high energy lines in the Turbine Building were reviewed utilizing the criteria from the Giambusso letters. This review resulted in installation of steam exclusion dampers, impingement barriers and pipe whip restraints on portions of these lines. This information was not discussed in FSAR Appendix I, but was added to USAR Appendix I for completeness.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.1-2 I.1 HIGH ENERGY PIPING SYSTEMS AND REQUIRED EQUIPMENT I.1.1 Definition of High Energy Piping Systems A piping system is defined as having pressure retaining components consisting of straight or curved pipe and pipe fittings such as elbows, tees and reducers. The boundaries of a system are defined in terms of a piping run. A piping run interconnects components such as pressure vessels, pumps and rigidly fixed valves or structural anchors that may act to restrain pipe movement beyond that required for design thermal displacement. A branch run differs from a main piping run only in that it originates at a piping intersection as a branch of the main pipe run.

High energy piping systems are defined as those having a service temperature of 200F and above and a design pressure above 275 psig. The plant operational conditions under which this definition applies, including normal reactor operation and upset conditions (e.g., anticipated operational occurrences). [Ref. 1, 2, 3, 24, 25, and 28]

There is no ASME Section III, Code Class 1 piping outside containment for the Prairie Island Nuclear Generating Plant. Therefore, the criteria used for determining design basis break and leakage crack locations is ASME Section III, Code Class 2 and 3.

I.1.2 Identification of High Energy Piping Systems The piping systems, or portions thereof, of the Prairie Island Nuclear Generating Plant which meet the definition of high energy are [Ref. 9.5]:

Auxiliary Building Main Steam Feedwater Chemical and Volume Control Letdown Steam Generator Blowdown Steam Supply to Auxiliary Feedwater Pump Turbine Turbine Building Main Steam Feedwater Steam Supply to Auxiliary Feedwater Pump Turbine Condensate Heater Drain Pump Discharge Turbine Bleed Steam to Feedwater Heaters Feedwater Heater and Moisture Separator / Reheater Drains

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.1-3 I.1.3 Selection of Break and Crack Locations The December 12, 1972 AEC letter [Ref 1] provided the criteria that was originally used at Prairie Island to select break and crack locations. The break location criteria required selecting the terminal ends of the piping run, any location along the pipe where the combined stress exceeded 0.8 (Sh + SA) or expansion stress exceeded 0.8 SA plus a minimum of two arbitrary intermediate locations based on high stress. The break size was defined to be twice the inside pipe diameter in length and a width that would yield a break area equal to the effective cross-sectional flow area upstream of the break location. The crack criteria required selecting any location along the length of the pipe.

The crack was defined to be one-half the pipe diameter in length and one-half the pipe wall thickness in width.

Longitudinal breaks were to be postulated in piping runs of 4 nominal diameter and larger and would be parallel to the pipe axis oriented anywhere around the pipe circumference. Circumferential breaks were to be postulated in piping runs exceeding a nominal 1 diameter and oriented perpendicular to the pipe axis. Cracks could occur anywhere along the length of pipe. The most adverse locations and orientations were selected after considering potential jet impingement and environmental impact on nearby plant equipment.

GL 87-11 [Ref. 4] provided a relaxation in the criteria for selecting arbitrary intermediate pipe break and leakage crack locations as well as deleted the expansion stress criteria.

This new criteria selected breaks at any location along the pipe where the combined stress exceeded 0.8 (1.8 Sh + SA) and leakage cracks at any location where the combined stress exceeded 0.4 (1.8 Sh + SA). GL 87-11 did not revise the break and crack criteria for type, size and orientation or the terminal ends.

The GL 87-11 crack criteria are less strict than the original licensing basis crack criteria of assuming a crack at any location along the pipe. NRC Information Notice 2000-20 clarified that locations selected based on stress analysis alone may not be sufficient to ensure that the most adverse locations are described. Therefore, cracks at the most adverse locations are assumed in the break location selection.

GL 87-11 [Ref. 4] also requires that breaks should be postulated at the piping welds to each fitting, valve, or welded attachment for piping systems that do not have pipe stress calculations. This requirement applies to the high energy piping systems in the Turbine Building. Breaks were assumed at any point along high energy piping without detailed break selection due to the large number of fittings, welded attachments, valves, and terminal ends.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.1-4 I.1.4 Selection of Required Equipment The equipment required to detect and mitigate the consequences of a high energy line design basis break or leakage crack is selected to accomplish the following functions:

Reactor trip Reactivity control Reactor coolant system pressure control Reactor coolant system inventory control Event monitoring Operability of this equipment provides the capability to achieve Mode 3, Hot Standby, either by operator actions or by automatic reactor protection functions. This equipment also provides the capability for ultimately achieving Mode 5, Cold Shutdown.

The rupture of high energy piping systems is discussed in various sections of the USAR and identifies the assumptions made for those postulated events. Main steam is discussed in Section 14.5, feedwater in Section 14.4, CVCS letdown in Section 10.2, steam generator blowdown in Section 9.2 and steam supply to the auxiliary feedwater pump turbine is considered a small main steam line break.

For the purposes of this Appendix, these assumptions can be summarized as follows:

a.

The methodology used to determine compartment pressure and temperature profiles is described in USAR Appendix I.5.3 (Compartment Pressure and Temperature). Peak pressures and temperatures in principal compartments are identified, and referenced calculations provide peak values in other compartments as well as long-term pressure and temperature time histories.

b.

After a postulated accident in one unit, the other unit is brought to Mode 3 (Hot Standby).

c.

A single active failure is assumed in the short term.

d.

Any rupture in the secondary side main steam system is not isolatable (i.e.,

the rupture is upstream of an MSIV or the assumed single failure is one MSIV does not close) and the entire inventory of one steam generator blows down.

e.

For peak compartment temperature calculations, the main steam released becomes increasingly superheated as steam generator tubes are uncovered.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.1-5

f.

All required equipment is operable from the Control Room or is accessible for manual operation.

g.

The postulated pipe rupture occurs at the following plant operating conditions:

Main Steam - Mode 3 (Hot Standby) for peak compartment pressure calculations and Mode 1 (Power Operation) full NSSS power plus uncertainty (1690 MWt) for peak temperature calculations.

Feedwater - Mode 1 (Power Operation) full NSSS power plus uncertainty (1690 MWt) for peak compartment pressure calculations and 25% full power plus uncertainty (1690 MWt) for flooding evaluations.

CVCS Letdown - Mode 3 (Hot Standby)

Steam Generator Blowdown - Mode 3 (Hot Standby)

Condensate - Mode 1 (Power Operation)

Heater drain pump discharge - Mode 1 (Power Operation)

Turbine bleed steam - Mode 1 (Power Operation)

Feedwater heater drains - Mode 1 (Power Operation)

h.

A loss of offsite power (LOOP) is assumed to occur at reactor protection system (RPS) actuation or turbine trip, whichever results in a more conservative analysis result, and independent of whether the RPS actuation was automatically or manually initiated.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-1 I.2 FEATURES FOR PROTECTION AGAINST THE EFFECTS OF HELB EVENTS I.2.1 Pipe Rupture Induced Loads Pipe Whip The analysis of reaction loads resulting from pipe ruptures took into consideration the duration, initial conditions, jet stream dynamics and system pressure characteristics.

The location of breaks for pipe whip considerations was originally defined by the criteria in the Giambusso letter [Ref. 1]. Application of the GL 87-11 criteria [Ref. 4] eliminated all of the arbitrary intermediate break locations to be considered for pipe whip analysis, except for those piping systems in the Turbine Building without combined stress analysis.

The loads induced from the pipe rupture include the effects of any line restrictions, such as flow limiters, between the pressure source and the break location. The effect of break opening geometry on the magnitude of reaction load is incorporated in the analysis by the application of an appropriate, but conservative, discharge coefficient.

For circumferential breaks, the discharge coefficient has a value of 1.0. For longitudinal breaks, the discharge coefficient is determined by the postulated break opening geometry for each case and is not greater than 0.85.

If a whipping pipe was capable of impacting adjacent pipes of equal or greater nominal pipe size and equal or heavier wall thickness, the adjacent pipe was considered to be free from rupture. Protection from pipe wall whip was not provided if pipe rupture occurred in such manner that the unrestrained pipe movement of either end of the ruptured pipe, in any possible direction about a plastic hinge formed at the nearest pipe whip restraint, cannot impact any structure, system or component required to survive the accident.

Piping that is physically separated or isolated from safety related structures, systems or components was excluded from the analysis. The physical separation or isolation may take the form of distance, protective barriers or pipe restraints designed specifically for pipe whip.

The restraints installed on the high energy piping systems preclude any functional damage to required equipment in the Shield Building Annulus, Auxiliary Building, and other structures.

Compartment Pressure Loading Compartment differential pressure loading from design basis breaks is determined from the mass-energy flow rates, from either a single ended or double ended break, the building compartment characteristics (volumes, heat sink surface areas, vent paths, etc.) and the postulated break locations.

To evaluate the capability of the compartment (walls, floors, etc.) to withstand pipe rupture pressures, methods of analysis described in USAR Section 12 were used.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-2 Jet Impingement Jet Impingement loading on structures, systems or components required for design basis breaks or leakage cracks is determined from the magnitude and area of influence of the jet for each break based on the break size, orientation and fluid conditions. The jet forces at the point of rupture are consistent with those used in the pipe whip analysis and are based on the fluid pressure and temperature conditions occurring during normal plant operating modes. Jet loadings are not considered to vary with time, but are conservatively based on the initial conditions at the time of rupture.

Concrete (Punching) Shear Stress The allowable stresses for shear, bond, etc., are determined from the accident/normal stress ratios associated with the compressive and tensile allowables. The accident/normal stress ratio for A615 reinforcing steel [Ref. 16] is 0.9fy/0.5fy = 1.8 and the accident/normal allowable stress ratio for concrete is 0.86fy/0.45fc = 1.89. Using 1.8 as the ratio for both concrete and steel maintains ductility within the concrete element, since steel is the governing material. The allowable accident stress for (punching) shear during a pipe rupture is therefore 1.8 times the normal provisions of ACI 318-63 Section 1207 [Ref. 15].

The dynamic forces associated with the jets are evaluated with respect to their distance and spread from the pipe separation or crack. The jet geometry, where it impacts a concrete wall, is normally ellipsoidal and its perimeter defines the (punching) shear area. The magnitude of the jet force and area of loading is compared to the (punching) shear capacity. Where shear is found to be adequate, the concrete element is checked for other possible modes of stress or failure.

Jet Erosion of Concrete The erosion of concrete by fluid jets is evaluated in WCAP-7391, Pressurized Water and Steam Jet Effects on Concrete by Westinghouse Atomic Power Division [Ref. 12].

To summarize the tests, five reinforced concrete beams were subjected to steam jets with nozzle diameters of 1, 2 and 4 inches. The distances investigated between nozzles and beams were 1 foot and 4 feet and the initial system pressure was 2250 psi.

The results are as follows:

The erosion under all beam tests was observed to be (at most) 30 mils of surface paste removal, with no significant loss of either fine or coarse aggregate. The resultant surfaces showed the same appearance as would be present after light sandblasting. It is concluded that short term erosion of concrete surfaces as a result of a high energy line break is not a design consideration.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-3 I.2.2 Mitigating Consequences of Pipe Rupture Pipe Restraints Piping restraints are installed on high energy piping systems based on the identification of break locations selected in accordance with the criteria in the Giambusso letter

[Ref. 1]. The piping restraints are designed to accommodate the loading induced by the reaction or whipping forces from the postulated design basis breaks. For a specific break location the pipe restraint accommodates a longitudinal break extending one pipe diameter on each side of the identified pipe stress node location or a circumferential break at the identified pipe stress node location.

Application of the GL 87-11 [Ref. 4] break selection criteria eliminated all high energy line design basis break locations outside containment except the terminal ends, intermediate anchors and identified branch connections.

Structural Components Design Class I structures are reviewed for their adequacy to withstand the effects of postulated high energy pipe breaks. This analysis considers the effects of pressure and temperature transients and the static, thermal and dynamic reactions of the pipe in conjunction with the applicable loads listed in USAR Section 12.

Load combinations for structures used to mitigate a HELB event are in accordance with USAR Table 12.2-4 utilizing the DBE load combination with other loading as appropriate. Allowable stresses are based upon USAR Table 12.2-5 condition 5.

Load combinations for components used to mitigate HELB event are in accordance with USAR Table 12.2-11 condition 5. Allowable stresses are based upon faulted condition allowances.

Design Class I structural elements, such as floors, interior walls, exterior walls, building penetrations and the building as a whole, are analyzed for eventual reversal of loads due to a postulated design basis break.

Guard Pipes Two types of guard pipes are used:

1.

Encapsulation sleeves are installed to reduce the mass-energy released by the postulated break to limit the pressure build-up in the various Auxiliary Building compartments.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-4 The inside diameter of a main steam encapsulation sleeve is designed to be 3/4 greater than the outside diameter of the process pipe yielding an annular gap of 3/8 circumferentially. This produces an escape vent area of 36 in2 per open end for the 30 main steam line. Due to the internal geometry of the encapsulation sleeve at the tee to the safety valve riser (three open ends), the effective annular vent area is the same as an encapsulated sleeve with two open ends [Ref. 9.1]. Application of GL 87-11 criteria eliminated these tees as break locations.

Peak containment pressure from a main steam line break is below the containment design rating, therefore, no encapsulation sleeves are installed in Containment. Since the mass-energy release from the postulated main steam breaks (selection based on the Giambusso letter) was significantly larger than the other high energy lines, encapsulation sleeves were only installed on main steam piping.

Application of the GL 87-11 [Ref. 4] break selection criteria eliminated all high energy line design basis break locations outside containment except the terminal ends, intermediate anchors and identified branch connections. None of the branch connections required installation of an encapsulation sleeve

[Ref. 9.4].

The following requirements [Ref. 10] are applicable to the design and support of encapsulation sleeves at design basis break locations:

a. The encapsulation sleeve is designed to fit closely around the process pipe in a manner that does not introduce significant strain concentrations on the encapsulated portion of the process pipe. The weight of the encapsulation sleeve is added to the mass of the process pipe in the pipe stress analysis and is supported by the process pipes support system.

b. The encapsulation sleeve is designed, constructed and tested in accordance with the requirements of ASME Section III, for Code Class 2 components [Ref. 13] with the added requirement that every other pass of the final assembly welds are non-destructively examined by surface examination techniques (i.e., liquid penetrant or magnetic particle). The stresses imposed are limited to those associated with emergency conditions.

c. The encapsulation sleeve is designed to withstand the dynamic forces of internal pressurization resulting from the escape of high energy fluid at the postulated pipe break location assuming complete pipe severance and axial separation to the extend permitted by the pipe restraints or a longitudinal break as defined in Section I.2.1.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-5

d. The piping beyond the encapsulation sleeve is provided with pipe whip restraints (or anchors) which restrict its axial displacement and motion within the sleeve following a postulated circumferential pipe break.

e. The encapsulation sleeve extends for a minimum distance of two pipe diameters on either side of the design basis break location.

f.

The encapsulation sleeve is designed to allow normal thread expansion movement of the process pipe and is not welded to the process pipe.

g. The materials are ASTM A-516 Grade 70 plate, A-106 Grade B pipe and A-234 Grade WPB fittings [Ref. 16].

h. The encapsulation sleeve is provided with open vent and drain pipe nipples which extend beyond the pipe insulation as a means of monitoring the encapsulated process pipe section for any leaks that might develop in service.

i.

The design of the encapsulation sleeve permits either its removal by machining or flame cutting for the replacement of the encapsulated process pipe section in the event leaks develop.

2.

Impingement barriers are installed to protect a structure, system or component by deflecting the high energy fluid jet generated by the postulated break or crack. Application of the GL 87-11 leakage crack location selection criteria eliminated the need for most of these installations.

The following requirements [Ref. 11] are applicable to the design and support of impingement barriers at design basis break and crack locations:

a. The impingement barrier is designed in a manner which does not introduce significant strain concentrations on the process pipe and is supported independently of the process pipe.

b. The impingement barrier is designed, constructed and tested as a Design Class I structure in accordance with the rules and practices set forth in the following codes:

Code For Welding In Building Construction, AWS D1.1-72, American Welding Society [Ref. 17].

Specification For The Design, Fabrication And Erection Of Structural Steel For Buildings, American Institute Of Steel Construction [Ref. 18].

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-6

c. The impingement barrier is designed to normal working loads and internal pressurization resulting from the escape of high energy fluid at the postulated pipe break location assuming complete pipe severance and axial separation to the extent permitted by the pipe restraints or a longitudinal break/crack as defined in Section I.2.1.

d. The stresses imposed on the impingement barrier during dynamic pressurization are limited to:

Membrane stresses produced by pressure existing in the impingement barrier are 0.90 fy and Membrane stresses and peak bending stresses of short duration in the initial stage of pressurization 1.5 x 0.9 fy.

e. The piping beyond the impingement barrier is provided with pipe restraints which restrict its axial displacement and motion within the impingement barrier following a postulated pipe break.

f.

The impingement barrier is a Design Class I structure and the materials are ASTM A-572 (various type/grades), A-516 Grade 70 plate, A-106 Grade B pipe and A-234 Grade WPB fittings [Ref. 16].

Steam Exclusion Boundary To protect the systems and components required to detect and mitigate the consequences of a high energy line break, steam exclusion boundaries are created to isolate this equipment from those areas containing high energy piping systems or are connected to their potentially harsh environment. These boundaries include the walls, floors, ceilings and doors plus any penetrations of these barriers, such as ventilation systems, cables, cable trays and piping systems.

Areas that house required equipment, but do not contain high energy piping systems and are not connected to areas that might contain a harsh environment are not provided with steam exclusion boundary functions, although they are considered to be steam exclusion areas.

The steam exclusion boundaries are designed for the peak pressure and temperature conditions they are expected to encounter and limit the harsh environment intrusion into the steam exclusion area.

Pre-Service and In-Service Inspection Pipe welds located within an encapsulation sleeve or impingement barrier and, therefore, not accessible for subsequent in-service inspection were non-destructively examined and satisfy the acceptance criteria of ASME Section XI [Ref. 13].

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-7 Pipe welds which are not located within an encapsulation sleeve or impingement barrier and are in the piping runs traversing the Auxiliary Building are subjected to periodic in-service examination in accordance with the ASME Section XI (edition currently invoked by the Prairie Island In-Service Inspection Program) requirements for Code Class 2 piping welds. The inaccessible welds are included in the total number of welds in determining the number of welds to be inspected in each inspection interval.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-8 I.2.3 Plant Operability Control Room Habitability The Control Room is maintained habitable and the equipment required for a specific high energy line break remains functional for all high energy line design basis breaks or leakage cracks with the capability to bring the reactor to a cold shutdown condition from there.

Operation of Required Equipment Electrical equipment that is required for a high energy line design basis break or leakage crack and can be affected by the harsh environment is qualified to perform their intended function in that environment.

Electrical equipment that is not qualified to operate in a harsh environment is located in a steam exclusion area created for that purpose.

Redundancy and Separation Redundancy of required equipment for a specific high energy line design basis break or leakage crack is maintained in the mechanical components, protection systems (Protection Systems are defined in IEEE-279 [Ref. 19]) and Class 1E electrical systems (Class 1E electrical systems are defined in IEEE-308 [Ref. 20]).

The design considers environmentally induced failures caused by a break or leak which would not in itself result in protective action, but may disable a protective function. In this regard, a loss of redundancy is permitted, but a loss of function is not. The capability to bring the plant to cold shutdown is maintained.

The separation criteria for cables associated with the required equipment is identical to that described in USAR Section 8.7.

Operating Procedures Operating procedures allow for evaluation of the specific high energy line break conditions and determination of appropriate actions to be taken to achieve Mode 5, Cold Shutdown. Prompt achievement and maintenance of Mode 3, Hot Standby, is assured by automatic reactor protection functions or by operator action. The operator will determine which specific plant procedure will be used for placing the reactor in Mode 5, Cold Shutdown, based on the equipment available.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-9 I.2.4 Equipment Operability Operability requirements for equipment listed in Table I.1.4-1 are primarily contained within Tech Specs except for the steam exclusion system components, which are included in the Technical Requirements Manual.

Additional requirements for equipment beyond those listed in Tech Specs or the TRM are contained within this section. These additional requirements are used to enhance existing equipment requirements to account for HELB events.

I.2.4.1 Cooling Water System To ensure that the cooling water system will perform its mitigating function in a HELB, 3 safeguards cooling water pumps (pumps 12, 21, and 121) shall be AVAILABLE in Modes 1,2,3, and 4. This requirement does not apply when both reactors are in Modes 5,6, or no mode or Tech Spec LCO 3.7.8 is in effect.

Condition Required Action Completion Time A. One safeguards CL pump not AVAILABLE A.1 Restore the 3rd pump to AVAILABLE status or A.2. Split the cooling water header into two separate trains 7 days

Background:

Availability requirements for a third cooling water pump are based on the need to maintain sufficient system pressure after a HELB with a consequential failure of a large CL pipe. HELB licensing basis requires consequential failures caused by the HELB to be assumed along with a single active failure and a loss of offsite power.

Certain HELB events in the Turbine Building can result in pipe whip that has the potential to break large CL pipes. The added system demand caused by the large CL pipe break, combined with a single failure of one of the two normal safeguards pumps results in exceeding the remaining pump capacity if a third pump is not available.

==

Description:==

The purpose of this requirement is to enhance the out of service time and procedural limitations normally under the scope of Maintenance Rule (10CFR50.65) for the safeguards CL pumps.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 32 Page I.2-10 Availability of the CL system can be ensured in two ways. Required action A.1 maintains this by ensuring that the 3rd pump is available, resulting in at least two pumps after all potential single-failure scenarios are considered. Required action A.2 provides equivalent assurance of availability by splitting the normal ring-header configuration of the CL system into two separate trains. With only two pumps available and the system in two separate trains a single failure of a pump will not result in loss of system function, even with the large consequential failure of a CL pipe.

The completion time for condition A is based on comparison to Tech Spec 3.7.8 condition A.

This completion time was utilized to provide a conservative but reasonable time to allow for normal maintenance of the 3rd cooling water pump without requiring that the CL system be split into two trains.

Two considerations are required to be able to call the third safeguards CL pump AVAILABLE. The first is the pump itself must be capable of performing is function in the HELB event. The second is that all pump power, actuation, and instrumentation supplies must be electrically independent for all three pumps (12, 21, and 121).

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-1 I.3 SYSTEM ROUTING AND RUPTURE EVALUATION OUTSIDE CONTAINMENT I.3.1 Structures I.3.1.1 Description of Auxiliary Building The part of the Auxiliary Building through which the high energy piping systems pass is a Design Class I seismic, concrete structure with tornado resistant outer walls and internal shielding walls. The Auxiliary Building is structurally divided into compartments by the walls and floors required to accommodate the equipment and components of various systems. With the exception of the compartments on elevation 695, the relay room, control room and mechanical equipment rooms, these volumes are vented to each other through corridors, grating openings, stairways, etc. Figures I.3.1-2 through I.3.1-6 describe the boundaries of the individual compartments. The important parameters for the major compartments are provided in Table I.3.1-1.

I.3.1.2 Description of Turbine Building The Turbine Building is a structure with mixed design classification. The Design Class I* steel structure provides a weather-proof enclosure for the turbine-generator and secondary plant auxiliary equipment. Also included within the steel structure is a Design Class I concrete structure (the Class I aisle) that houses safety related components. There are no high energy piping systems within the Class I aisle and it is designed as a steam exclusion area. The remainder of the Turbine Building areas are vented to each other through corridors, grating openings, stairways, etc. Figures I.3.1-7 through I.3.1-10 describe the boundaries of the individual compartments.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-2 I.3.2 High Energy Piping Systems I.3.2.1 Main Steam Routing The main steam piping from steam generator 11 (21) exits the top of the steam generator and runs horizontally through a flow limiter. It then drops vertically to an anchor elbow before exiting Containment. The main steam line exits from the southwest (southeast) quadrant of Containment on Auxiliary Building elevation 715 (compartment Y) and enters the main steam isolation valve (MSIV) stop check - check valve assembly and concrete anchor block. The pipe then rises to elevation 735 (compartment X) where it turns northward and runs horizontally through the Auxiliary Building into the Turbine Building. It then drops vertically to elevation 715, turns northward before rising vertically back to elevation 735 and connects to the turbine nozzle. The main steam piping from steam generator 12 (22) exits the top of the steam generator and runs horizontally through a flow limiter. It then drops vertically to an anchor elbow before exiting Containment. The main steam line exits from the northwest (northeast) quadrant of Containment on Auxiliary Building elevation 715 (compartment C) and rises vertically to elevation 735 (compartment B) where the MSIV assembly and concrete anchor block are located. The pipe then turns northward and runs horizontally parallel to steam line 11 (21) through the Auxiliary Building into the Turbine Building following a path similar to steam line 11 (21) to the turbine. At no point do any of the main steam lines enter the Design Class I portion of the Turbine Building.

These routings are shown isometrically on Figures I.3.2-1 (Unit 1) and I.3.2-2 (Unit 2),

which also show connections to the safety valve header, steam dump to atmosphere header and equalizing line. Additional high energy Main Steam piping is present in the turbine building, such as branch piping to the MSRs and steam dumps to the condenser. This piping is not shown on Figures I.3.2-1 and I.3.2-2.

Pipe Rupture Evaluation The original selection of break and branch connection locations based on the Giambusso letters is shown on FSAR Figures I.3-2 and I.3-3 (Unit 1 only). Cracks were assumed to occur at any location along the pipe. The stresses for the main steam piping were calculated as described in FSAR Section I.9 and depicted on Figures I.9-1 through I.9-4 and I.9-10 through I.9-14.

Postulated break and branch connection locations [Ref. 9.4], selected based on the GL 87-11 criteria, are shown on USAR Figures I.3.2-1 (Unit 1) and I.3.2-2 (Unit 2). The stresses for portions of the main steam piping were calculated as described in Sections I.5.1 and are depicted on Figures I.5.1-1 through I.5.1-4. Portions of main steam piping within the Turbine Building do not have detailed break selection based on combined stress analysis. These portions of the system have breaks assumed at any point on the piping.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-3 At no point does the stress exceed the design basis break criteria. Leakage cracks are postulated at any point on the piping. Branch connections, which are considered the terminal end of the branch runs, exist at the steam supply to the auxiliary feedwater pump turbine, power operated relief valves and steam supply to the moisture separator reheaters, and trap and drain connections. The risers to the safety valve header and steam dump headers are not considered branch connections in accordance with the GL 87-11 criteria (MEB 3-1, B.1.c.(1).(a)). The main steam line terminal ends are the steam generator nozzle connections, anchor elbows in Containment and the turbine nozzle connections. In accordance with GL 87-11 criteria only circumferential breaks are postulated at the terminal ends. A summary of the break, crack, intermediate anchor and terminal end locations is included as Table I.3.2-1. In addition, a summary of the bounding breaks for each HELB compartment is included as Tables I.3.2-3 and I.3.2-4.

I.3.2.2 Feedwater Routing The discharge of each main feedwater pump (Turbine Building elevation 695) is routed through a check valve, motor operated valve and feedwater heater (elevation 715) before joining in the Turbine Building into a single line. Before entering the Auxiliary Building, the common feedwater line bifurcates into two lines - one for each steam generator. At no point do any of the feedwater lines enter the Design Class I portion of the Turbine Building. The line to steam generator 11 (21) enters the Auxiliary Building on elevation 735 (compartment B) running in a southerly direction parallel to main steam line 11 (21) (to compartment X), before entering Containment in the southwest (southeast) quadrant. The feedwater line runs horizontally to an anchor elbow and then rises vertically through an expansion loop and check valve before turning horizontal to connect to the steam generator. The line to steam generator 12 (22) enters the Auxiliary Building on elevation 735 (compartment B) running in a southerly direction parallel to main steam line 12 (22), before entering Containment in the northwest (northeast) quadrant. The feedwater line runs horizontally to an anchor elbow and check valve before turning horizontal to connect to the steam generator. Each line is provided with a flow nozzle, control valves, concrete anchor block and motor operated isolation valve before entering Containment.

The routing of the FW lines is shown isometrically on Figures I.3.2-3 and I.3.2-11 (Unit 1) and I.3.2-4 and I.3.2-12 (Unit 2).

Pipe Rupture Evaluation The original selection of break and branch connection locations based on the Giambusso letters is shown on FSAR Figures I.4-1 and I.4-2 (Unit 1 only). Cracks were assumed to occur at any location along the pipe. The stresses for the main feedwater piping were calculated as described in FSAR Section I.9.1 and depicted on Figures I.9-5 through I.9-9.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-4 Postulated break and branch connection locations [Ref. 9.4], based on the GL 87-11 criteria, are shown on Figures I.3.2-3 (Unit 1) and I.3.2-4 (Unit 2). The stresses for the feedwater piping were calculated as described in Section I.5.1 and depicted on Figures I.5.1-5 through I.5.1-8.

A summary of the break, crack and terminal end locations for each feedwater line is included as Table I.3.2-1. In addition, a summary of the bounding breaks for each HELB compartment is included as Tables I.3.2-3 and I.3.2-4. Leakage cracks are postulated at any point on the piping. In accordance with GL 87-11 criteria only circumferential breaks are postulated at the terminal ends.

Auxiliary Building At no point in the Auxiliary Building does the stress exceed the design basis break criteria. No terminal ends or branch connections, which are considered the terminal ends of the branch runs, exist on the feedwater lines in the Auxiliary Building.

Turbine Building One location in the Turbine Building exceeds the design basis break criteria. Terminal ends exist at the FW pumps, condenser dump connections, and #5 FW inlet and outlet nozzles. Branch connections exist at the downstream portion of the #5 FW heater bypass lines and at the Unit 1 condenser dump branches.

I.3.2.3 CVCS Letdown Routing The CVCS letdown line exits from the northwest (northeast) quadrant of containment into the Auxiliary Building through a penetration on elevation 715 (compartment D).

The line is provided with an isolation valve adjacent to its penetration as well as isolation valves inside containment. The letdown line is then routed in a northerly direction to the letdown heat exchanger (compartment L).

These routings are shown isometrically on Figures I.3.2-5 (Unit 1) and I.3.2-6 (Unit 2).

Pipe Rupture Evaluation The original selection of break and branch connection locations based on the Giambusso letters is shown on FSAR Figures I.5-1 and I.5-2 (Unit 1 only). Cracks were assumed to occur at any location along the pipe. The stresses for the CVCS letdown piping were calculated as described in FSAR Section I.9 and depicted on Figures I.9-15 and I.9-16.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-5 At no point does the stress exceed the design basis break criteria. Leakage cracks are postulated at any point on the piping. There are no branch connections. The CVCS letdown line terminal ends are the containment penetration and the letdown heat exchanger inlet nozzle. There is one intermediate anchor in each letdown line. In accordance with GL 87-11 criteria only circumferential breaks are postulated at the terminal ends and intermediate anchors. A summary of the break, crack and terminal end locations for each letdown line is included as Table I.3.2-1. In addition, a summary of the bounding breaks for each Auxiliary Building compartment is included as Table I.3.2-3.

Postulated terminal end break and intermediate anchor break locations based on the GL 87-11 criteria, are shown on Figures I.3.2-5 (Unit 1) and I.3.2-6 (Unit 2). The stresses for the CVCS letdown line piping were calculated as described in Sections I.5-1 and depicted on Figures I.5.1-9 and I.5.1-10.

I.3.2.4 Steam Generator Blowdown Routing The steam generator blowdown lines exit from the northwest (northeast) quadrant of Containment into the Auxiliary Building through a penetration on elevation 715 (compartment D). Each line is provided with an isolation valve adjacent to its penetration as well as an isolation valve inside Containment. The blowdown line is then routed in a southerly direction to the blowdown flash tank (compartment D).

These routings are shown isometrically on Figures I.3.2-7 (Unit 1) and I.3.2-8 (Unit 2).

Pipe Rupture Evaluation The original selection of break and branch connection locations based on the Giambusso letters is shown on FSAR Figures I.6-1 and I.6-2 (Unit 1 only). Cracks were assumed to occur at any location along the pipe. The stresses for the steam generator blowdown piping were calculated as described in FSAR Section I.9 and depicted on Figures I.9-21 through I.9-24.

At no point does the stress exceed the break criteria. Leakage cracks are postulated at any point on the piping. There are no branch connections. The steam generator blowdown line terminal ends are the containment penetration and the steam generator blowdown flash tank inlet nozzles. There are two intermediate anchors in the #11 and

1. 12 blowdown lines, one intermediate anchor in the #21 blowdown line and no intermediate anchor in the #22 blowdown line. In accordance with GL 87-11 criteria only circumferential breaks are postulated at the terminal ends and intermediate anchors. A summary of the break, crack and terminal end locations for each steam generator blowdown line is included as Table I.3.2-1. In addition, a summary of the bounding breaks for each Auxiliary Building compartment is included as Table I.3.2-3.

Postulated terminal end break and intermediate anchor break locations, based on the GL 87-11 criteria, are shown on Figures I.3.2-7 (Unit 1) and I.3.2-8 (Unit 2). The stresses for the steam generator blowdown line piping were calculated as described in Section I.5.1 and depicted on Figures I.5.1-11 through I.5.1-14.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-6 I.3.2.5 Steam Supply to Auxiliary Feedwater Pump Turbine Routing The steam supply line to the auxiliary feedwater pump turbine from steam generator 11 (21) originates on elevation 735 (compartment X) at branch connection from the safety valve header upstream of the main steam isolation valves. The line is routed in a northerly direction through the Auxiliary Building and joins the supply line from steam generator 12 (22) (compartment B). The common supply line proceeds down to elevation 695 (compartment E) and into the Turbine Building. The steam supply line from steam generator 12 (22) originates on elevation 735 (compartment B) at a branch connection from the main steam line upstream of the main steam isolation valves. The stop valves in the steam supply line to the auxiliary feedwater pump turbine were relocated outside of the auxiliary feedwater pump room. These valves are normally closed and receive a signal to open when the pumps are started. The piping in the room is normally depressurized and the room is considered to be a mild environment for the equipment contained therein [Ref. 6 & 7].

These routings are shown isometrically on Figures I.3.2-9 (Unit 1) and I.3.2-10 (Unit 2).

Pipe Rupture Evaluation The original selection of break and branch connection locations based on the Giambusso letters is shown on FSAR Figures I.7-1 and I.7-2 (Unit 1 only). Cracks were assumed to occur at any location along the pipe. The stresses for the steam supply to the auxiliary feedwater pump turbine piping were calculated as described in FSAR Section I.9 and depicted on Figures I.9-17 through I.9-20.

At no point does the stress exceed the design basis break criteria. Leakage cracks are postulated at any point on the piping. There are no branch connections. The steam supply to the auxiliary feedwater pump turbine line terminal ends are the branch connections from the main steam lines and safety valve headers and an anchor in the Turbine Building down stream of the control valves. There is one intermediate anchor in the line from #11 steam generator and no intermediate anchors in the lines from #12,

1. 21 and #22 steam generators. In accordance with GL 87-11 criteria only circumferential breaks are postulated at the terminal ends and intermediate anchor. A summary of the break, crack and terminal end locations for each supply line is included as Table I.3.2-1. In addition, a summary of the bounding breaks for each HELB compartment is included as Tables I.3.2-3 and I.3.2-4.

Postulated terminal end break and intermediate anchor break locations, based on the GL 87-11 criteria, are shown on Figures I.3.2-9 (Unit 1) and I.3.2-10 (Unit 2). The stresses for the steam supply to the auxiliary feedwater pump turbine line piping were calculated as described in Section I.5.1 and depicted on Figures I.5.1-15 through I.5.1-18.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-7 I.3.2.6 Condensate and Heater Drain Pump Discharge Routing The Condensate system meets the definition of high energy at the #2 FW Heater discharge. The entire system is located within the turbine building. The discharge from the #2 FW heaters originates on the north side of the condenser at the 715 elevation and loops into the #3 FW heaters. The discharge of the two #3 FW heaters combine together to form one common pipe on the 695 level, is routed south around the condenser, and splits into two lines that rise back up to the 715 elevation to the inlet of the two #4 FW heaters. The discharge of the two #4 FW heaters joins into a common line on the 715 elevation before splitting into two lines again prior to the suction of the FW pumps on the 695 elevation.

The Heater Drain system meets the definition of high energy at the discharge of the three Heater Drain Tank Pumps on the 679 elevation. The discharge from the three pumps joins into a common line, passes through the 695 elevation, and connects to the Condensate piping just after the discharge of the #4 FW heaters.

These routings are shown isometrically on Figures I.3.2-13 (Unit 1) and I.3.2-14 (Unit 2).

Pipe Rupture Evaluation The Condensate and Heater Drain systems were not included in the original selection of break and crack locations per the Giambusso letters. Additional discussion of the Turbine Building piping is contained in Section I.7.

Postulated break and branch connection locations [Ref 9.4], based on the GL 87-11 criteria, are shown on Figures I.3.2-13 (Unit 1) and I.3.2-14 (Unit 2). The stresses for the Condensate and Heater Drain piping were calculated as described in Section I.5.1.

I.3.2.7 Heater Drain Tank Pump Discharge Routing The heater drain pump discharge lines connect directly to the condensate system piping just prior to the feedwater pump suction. All heater drain tank pump discharge piping is routed within the non-safety related portion of the Turbine Building.

Pipe Rupture Evaluation The heater drain tank pump discharge piping does not have the benefit of combined stress analysis. As specified previously for high energy piping without combined stress analysis, breaks are assumed at any point along the piping.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.3-8 I.3.2.8 Bleed (Extraction) Steam Routing The only bleed steam lines that meet the definition of high energy are those originating at an intermediate extraction stage of the high pressure turbine and supply steam to the 15 (25) feedwater heaters. All of this bleed steam piping is routed within the non-safety related portion of the Turbine Building.

Pipe Rupture Evaluation The bleed steam piping does not have the benefit of combined stress analysis. As specified previously for high energy piping without combined stress analysis, breaks are assumed at any point along the piping.

I.3.2.9 Feedwater Heater and MSR Drains Routing The only drain piping that meets the definition of high energy are those from the 15 (25) feedwater heaters to the 14 (24) feedwater heaters and from the reheater section of the MSRs to the 15 (25) feedwater heaters. All of this drain piping is routed within the non-safety related portion of the Turbine Building.

Pipe Rupture Evaluation The drain piping does not have the benefit of combined stress analysis. As specified previously for high energy piping without combined stress analysis, breaks are assumed at any point along the piping.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-1 I.4 FEATURES PROVIDED FOR PIPE RUPTURE EVENTS I.4.1 Required Equipment The equipment required to detect and mitigate the consequences of a high energy line design basis break or leakage crack and accomplish those functions identified in Section I.1.4 is summarized in Table I.1.4-1 [Ref. 9.6].

I.4.2 Steam Exclusion Boundaries The various steam exclusion areas created include the Auxiliary Building elevation 695, Relay Room, Control Room, Control Room Ventilation Equipment Rooms, Unit 1 480v Bus and Events Monitoring Rooms, Control Rod Drive Equipment Rooms, Design Class I portion of the Turbine Building and Diesel Generator Rooms. Areas that do not contain high energy piping systems and are not connected to areas that might contain a harsh environment, such as the Screenhouse, are not provided with steam exclusion functions.

Walls, Floors and Ceilings The steam exclusion areas are bounded by concrete (or masonry) walls, floors and ceilings. All penetrations are sealed to prevent intrusion of a harsh environment. The Auxiliary Building stairwells connecting elevation 715 to 695 are enclosed in masonry structures. All boundaries are designed to accommodate the maximum differential pressure expected.

Doors Doors that form part of the steam exclusion boundary in either the Auxiliary Building or Turbine Building are provided with seals to preclude entry of a harsh environment. With the exception of the Control Room Ventilation Equipment Room doors, all of these doors are oriented such that they close against bar stops under the harsh environment pressure.

The Control Room Ventilation Equipment Room doors are held closed by their latch mechanisms. Four sets of doors between the Auxiliary Building (elevations 720, 735 and 755) to the Fuel Handling Building have breakaway ceramic latch pins that permit the doors to open at 0.2 psid during a high energy line break and provide a vent path for Auxiliary Building pressure relief [Ref. 8, 9.11]. Typical door seals are shown on Figure I.4.3-2.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-2 Ventilation The ventilation systems serving the Relay Room, Control Room, Control Room Ventilation Equipment Rooms, Auxiliary Building elevation 695 and Design Class I portion of the Turbine Building are provided with redundant dampers that are closed by resistance temperature detectors (RTDs) located in their respective ductwork. The RTDs for these dampers are set at less than 120F.

The ventilation system Steam Exclusion Actuation System consists of redundant RTDs, resistance to current converter, trip unit with isolation amplifiers plus indicators and recorders. Any one RTD will close the dampers in that train for the associated building.

There are 14 control and 14 check dampers located in the Auxiliary Building and Control Room ventilation systems plus 12 control and 12 check dampers in the Turbine Building ventilation system. The steam exclusion dampers and the ductwork between the wall and outermost damper are seismic Design Class I. The dampers originally installed were tested to a static pressure of 5 psi without the loss of functional operation. The maximum leakage acceptable, when procured, on these dampers is 50 cfm at 0.5 psi.

All dampers were originally procured at a differential pressure of 0.5 psi and the maximum leakage measured by the manufacturer was 30 cfm. These pressure values were based on preliminary compartment X and Y pressure analysis prior to installation of the flow limiting encapsulation sleeves. Subsequent compartment pressure analysis is contained in Reference 9.11. Control and check dampers are checked for functionality and the mating surfaces are visually inspected as required by the plants Technical Requirements Manual.

The Control Room has its own independent outside make-up air supply. Air is supplied through the Auxiliary Building roof at column rows G-6 (Unit 1) and H-14 (Unit 2) into elevation 755 (compartment A) and ducted to the Control Room Ventilation Equipment Room through redundant steam exclusion dampers. The air is cooled, if necessary, filtered, humidified and ducted through the floor into the Control Room. This system is described in more detail in Section 10.3.3.

The Control Room is automatically isolated from any adverse environment created by a high energy line break or crack by closure of the redundant steam exclusion dampers.

Redundant fans and air conditioning systems maintain the Control Room habitable with regard to temperature, humidity* and airborne radioactivity.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-3 An analysis [Ref. 9.13] was performed to determine the environmental conditions on Auxiliary Building elevation 695¢ in the unlikely event that both sets of steam exclusion control dampers in the ventilation supply duct failed to close or the entering steam-air mixture temperature was below the steam exclusion actuation setpoint. The steam exclusion check dampers in the ventilation return ducts would prevent backflow into elevation 695 from the other Auxiliary Building compartments. This analysis demonstrated that the resultant temperatures on elevation 695 remained below the environmental qualification of the required equipment.

Shield Building Seals Bellows (similar to those used on the penetrations from the Auxiliary Building to the Shield Building annulus) have been tested [Ref. 22] at the Kewaunee Nuclear Power Plant. These tests showed that, with differential pressures of up to 20 psi internally, no rupture occurred. Tests with external pressurization equal to 50% of the internal differential pressure loadings were also conducted without any failure. The maximum calculated external pressure difference these bellows would be required to withstand is less than 0.3 psi for less than 2 minutes. The maximum calculated temperature these bellows would be exposed to during this time period is 300F. The typical tensile strength of this material is 1443 psi with a temperature capability up to 325F.

I.4.3 Encapsulation Sleeves and Impingement Barriers Based on the break location and size criteria in the Giambusso letters, design basis breaks and leakage cracks were postulated in the Containment, Auxiliary Building and Turbine Building. An analysis revealed that the Auxiliary Building did not have the capability to withstand the pressure resulting from a design basis main steam line break.

Encapsulation sleeves were installed at all postulated design basis break locations in the Auxiliary Building to reduce the peak compartment pressure. The criteria for the design of the encapsulation sleeves is contained in Section I.2.2 and their location was described in FSAR Figure I.3-3 for Unit 1. Although not described in the FSAR, encapsulation sleeves were installed at the same locations on Unit 2. No encapsulation sleeves were required on the other high energy piping systems. Typical encapsulation sleeves are shown on Figure I.4.3-1.

Impingement barriers were installed to protect required equipment from the effects of high energy fluid jets. Those impingement barriers that were installed around the various high energy piping systems are identified on Figures I.3.2-1 through I.3.2-10.

Other impingement barrier designs were used for local protection, such as flat steel plates, steel shapes, etc. Typical impingement barriers are shown on Figure I.4.3-1.

Application of the GL 87-11 break selection criteria eliminated all main steam and feedwater design basis breaks except those at the terminal ends and greatly reduced the locations for leakage cracks. This process eliminated the need for most of these encapsulation sleeves and impingement barriers. Therefore, many of the modifications previously installed may be removed or abandoned in place.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-4 I.4.4 Rupture Restraints Based on the pipe rupture analysis discussed in FSAR Section I.10 rupture restraints were added to the main steam and feedwater system piping. No new rupture restraints were required on the other high energy systems. Typical tie rod restraints are shown on Figure I.4.3-1.

Application of the GL 87-11 break selection criteria eliminated all main steam and feedwater design basis breaks except those at the terminal ends, thereby eliminating the need for all other of these restraints. However, they may be removed or abandoned in place.

I.4.5 Flooding Protection Based on the HELB flooding analysis discussed in USAR Section 1.5, changes to the facility were made to ensure adequate flooding protection. The following flood mitigating features are credited in the analysis:

Flood barriers to protect the D1, D2, D5, and D6 diesel generators Access covers in the AFW rooms were fastened to prevent differential pressure from opening them Roll-up doors at the east and west ends of the turbine building were blocked open Security barriers at each roll-up door were opened or modified Safeguards battery room doors and door seals were credited to minimize flow into the rooms around door gaps on the HELB unit and allow flow out on the non-HELB unit.

AFW pump room doors and door seals were credited to prevent water flow into the room around door gaps.

I.4.6 Equipment Environmental Qualification Location of Required Equipment The location of the equipment required to bring the reactors to a safe shutdown condition, after a high energy line break event, is described in Table I.1.4-1.

01507184

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-5 The safety injection and component cooling pumps for both units are located in a steam exclusion area on Auxiliary Building elevation 695 (compartment E). The auxiliary feedwater pumps and batteries for both units plus the Unit 1 4160/480v switchgear are located in a steam exclusion area in the Turbine Building Class I corridor. Diesel generators D1 and D2 (Unit 1), D5 and D6 (Unit 2), the Unit 2 4160/480v switchgear and the cooling water pumps for both units are located in compartments separated from those containing high energy piping systems. The control room/relay room ventilation system is located in a steam exclusion area on Auxiliary Building elevation 755 (compartment A). The reactor trip breakers for both units are located in steam exclusion areas on Auxiliary Building elevation 735 (Compartment B). The motor control centers/motor starters for all identified motor operated valves are located in one of the steam exclusion areas of the plant.

Equipment Qualification All instrumentation and electrical equipment required for high energy line break events, that are located in a post-accident harsh environment, are qualified in accordance with the Equipment Qualification Final Rule, 10CFR50.49. The establishment, documentation, maintenance and guidance for these components is contained within the plants Equipment Qualification (EQ) Program.

Ancillary equipment (e.g., cable, fuses, splices, terminations, etc.), associated with any required equipment, that is located in an area where a harsh environment might exist are qualified and configured for that environment in accordance with the plants EQ program.

I.4.7 Operating Procedures The operating procedures discussed below are general in nature since it is appropriate to allow the operator to assess the incident and determine the equipment available prior to initiating any action. The plant can achieve and maintain Mode 3, Hot Standby, for an extended time by automatic reactor protection functions or operator action.

Following the high energy line break, the operator would have alternate systems (residual heat removal, chemical and volume control, component cooling, etc.) available to facilitate an orderly shutdown of the reactor. The methods presented use equipment determined to be available following a high energy line break event. The operator would determine the appropriate methods for achieving Mode 5, Cold Shutdown based on the systems and components available.

Main Steam Design Basis Break For a design basis break, safety injection would be initiated by either low pressurizer pressure or low steam line pressure in either steam line. The main steam isolation valves are designed to close on the coincidence of a safety injection signal with either high-high steam flow or high steam flow coincident with low-low Tavg. The safety injection signal would cause a reactor trip, isolate the main feedwater system, initiate containment isolation and start the auxiliary feedwater pumps.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-6 Following initiation of safety injection, the safety injection pumps deliver borated water from the refueling water storage tank.

The following equipment will accomplish the required safety functions:

1.

Safety injection to pump borated water into the core, thereby limiting the core power transient following the break and bringing the reactor to a subcritical condition.

2.

Closure of the main steam isolation valves to limit the reactor coolant system cooldown.

3.

Isolation of the main feedwater system: Sustained feedwater flow would cause additional cooldown and mass-energy release to the Auxiliary Building.

A safety injection signal would close the main feedwater control valves, close the feedwater containment isolation valves and trip the main feedwater pumps, which closes the feedwater pump discharge valves.

4.

Following a reactor trip, auxiliary feedwater is required in approximately 10 minutes to dissipate decay heat. At least one auxiliary feedwater pump is available to supply the intact steam generator. After the affected steam generator has emptied or the break has been isolated, the auxiliary feedwater system and main steam power operated relief valves provide heat removal capability for maintaining Mode 3, Hot Standby, conditions.

Main Steam Leakage Crack For a leakage crack in the main steam piping system (7.3 in2) steam release for the Mode 3, Hot Standby, condition is approximately 100 lbs/sec and for the full power condition, 80 lbs/sec or five percent and four percent of full load turbine steam flow, respectively. This would not be sufficient to cause an overpower reactor trip.

A leakage crack would result in a loss of water inventory in the secondary plant that would lower the level in the condenser hotwell from the normal operating level to the low level alarm setpoint. Should the operator fail to take action at this point, the loss of secondary inventory would continue until the condensate pumps tripped. The following table provides the times involved if the leakage crack occurred at either Mode 3, Hot Standby, or full power [Ref. 9.3]:

Time in Minutes Hotwell Level Hot Shutdown Full Power Normal operating level 0

0 Low alarm setpoint 9

11 Condensate pump trip 64 85

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-7 The following automatic actions occur following the condensate pump trip:

1.

main feedwater pump trip on loss of condensate pumps or low feedwater pump suction pressure,

2.

turbine trip on loss of main feedwater pumps if turbine latched,

3.

reactor trip due to low-low steam generator level or turbine trip if power greater than 10% power,

4.

auxiliary feedwater pump start on loss of main feedwater pumps or low-low steam generator level.

The auxiliary feedwater pumps would deliver water to the steam generators from the condensate storage tank or cooling water system. After the reactor trip, continued steam release from the crack would cool the reactor coolant system down slower than if the largest relief valve were open. If the steam leak were not isolated by manual main steam isolation valve closure cooldown would continue resulting in safety injection being initiated by low pressurizer pressure or low steam line pressure. The safety injection pumps deliver boric acid from the refueling water storage tank to insert sufficient reactivity to bring the reactor to Mode 5, Cold Shutdown boron concentration.

In the event of a leakage crack, the auxiliary feedwater system and steam dump system (power operated relief, atmospheric or condenser, depending on component availability) would be used to dissipate reactor decay heat and cool the plant to 350F. The residual heat removal system would then normally be used to cool the plant to Mode 5, Cold Shutdown.

Feedwater For a feedwater line design basis break, the reactor is automatically tripped due to low-low steam generator level. The auxiliary feedwater system in conjunction with the steam generator safety valves and power operated relief valves provide the ultimate heat sink for the reactor coolant system for maintaining Mode 3, Hot Standby, conditions. In order to take the reactor from Mode 3, Hot Standby, to Mode 5, Cold Shutdown conditions, boron is added to achieve Mode 5, Cold Shutdown concentration.

Additional water is added to replace the volume lost due to shrinkage during cooldown.

This can be accomplished by opening the pressurizer power operated relief valves to temporarily reduce reactor coolant system pressure below the safety injection pump shutoff head. After re-closing the pressurizer power operated relief valves, the auxiliary feedwater system and main steam power operated relief valves provide heat removal capability for maintaining Mode 3, Hot Standby, conditions and cooling the reactor coolant system to 350F (Mode 4, Hot Shutdown).

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-8 If a rupture should occur in the feedwater line that would not directly cause a reactor trip, the operator has numerous devices (steam generator pressure, steam generator level, etc.) to detect such an event. The operator would assess the plant conditions (location of break, ability to isolate, equipment available, etc.) and determine actions to be taken. If necessary, the reactor could be shutdown by manually tripping the reactor or initiating safety injection which would trip the reactor, start the safety injection and auxiliary feedwater pumps and initiate containment isolation. The plant would remain in Mode 3, Hot Standby, conditions until the appropriate method for going to Mode 5, Cold Shutdown was determined.

A feedwater system leakage crack would result in a loss of water inventory in the secondary plant in a manner similar to a main steam leakage crack.

Chemical & Volume Control System Letdown For a design basis break or leakage crack in a CVCS letdown line the operator has numerous devices (pressurizer level, pressurizer pressure, area radiation monitors, etc.)

to detect such an event. The break or crack would be terminated by closing the inside containment letdown isolation valve in the affected line. This isolation could also be accomplished by closing all of the letdown orifice isolation valves.

Steam Generator Blowdown For a design basis break or leakage crack in a steam generator blowdown line the operator has numerous devices (steam generator level, feedwater flow, steam/feedwater flow deviation, etc.) to detect such an event. The break or crack would be terminated by closing one of the redundant motor operated containment isolation valves in the affected line.

Steam Supply To Auxiliary Feedwater Pump Turbine A design basis break or leakage crack in the steam supply line to the auxiliary feedwater pump turbine would be similar to an unisolatable main steam line leakage crack if the steam supply isolation valve could not isolate the break.

Condensate A design basis break in the condensate line would reduce the supply to the feedwater pumps causing them to trip on low suction pressure. The condensate pumps would trip on low condenser hotwell level. This sequence would lead to a reactor trip on low-low steam generator level.

A condensate system leakage crack would result in a loss of water inventory in the secondary plant in a manner similar to a main steam or feedwater leakage crack.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-9 Heater Drain Tank Pump Discharge A design basis break in the heater drain tank pump discharge line would reduce the supply to the feedwater pumps causing them to trip on low suction pressure. The heater drain tank pumps would trip on low heater drain tank level or turbine stop valve closure. This sequence would lead to a reactor trip on low-low steam generator level.

A heater drain tank pump discharge line leakage crack would result in a loss of water inventory in the secondary plant in a manner similar to a main steam or feedwater leakage crack.

Bleed (Extraction) Steam A design basis break in bleed steam line to the 15 (25) feedwater heater would result in significant imbalance in the distribution of turbine steam flow and loss of feedwater heating to the 14 (24) and 15 (25) feedwater heaters. The ensuing turbine trip (manual or automatic) would cause a reactor trip.

A bleed steam line leakage crack would result in a loss of water inventory in the secondary plant in a manner similar to a main steam or feedwater leakage crack.

Feedwater Heater and MSR Drains A design basis break or leakage crack in a feedwater heater or MSR drain line would result in a loss of water inventory in the secondary plant in a manner similar to a main steam or feedwater leakage crack.

Cold Shutdown The plant is designed to achieve Mode 3, Hot Standby, (automatically or by operator action) and maintain that condition for an extended time using the auxiliary feedwater system and main steam power operated relief valves for decay heat removal. The safety injection system provides the boric acid for reactivity control and reactor control inventory make-up. After assessment of the event and evaluation of the equipment available, the operator would determine the most appropriate method and procedure for achieving cold shutdown. The auxiliary feedwater system and main steam power operated relief valves would be used to cool the plant to 350F.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.4-10 The residual heat removal system would normally (and preferentially) be used to reduce the reactor coolant system temperature to Mode 5, Cold Shutdown. If the residual heat removal systems are not available, the auxiliary feedwater system and plant secondary side systems can be used to bring the reactor coolant system to Mode 5, Cold Shutdown. However, this process would require a much longer time. This could be accomplished by converting a steam generator into a water to water heat exchanger by filling it with cold water from the auxiliary feedwater pumps. The warmer water could be discharged through a combination of the steam generator blowdown flash tank, main steam line traps and drains, main steam line power operated relief valve, steam dump to condenser, etc.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-1 I.5 TOPICAL ANALYSIS I.5.1 Pipe Stress Stress analysis was performed on the five identified high energy piping systems in the Auxiliary Building using a computer program with the capability to analyze piping systems subjected to thermal expansion, pressure, weight, static seismic and dynamic seismic loading conditions. These analyses were performed in accordance with the requirements of the Power Piping Code (ANSI B31.1 - 1967). The program incorporated special conditions such as anchor movements, intermediate point forced movements, limit stops, external forces, rigid supports, restraints, etc. The combination of stresses due to pressure, thermal, weight and seismic loading conditions was also determined.

These stress analyses were utilized to determine the design basis break locations in accordance with the criteria contained in the Giambusso letters. They were presented graphically as FSAR Figures I.9-1 through 24. Based on these analyses, modifications (encapsulation sleeves, impingement barriers, etc.) were made to the plant.

Generic Letter 87-11 relaxed the requirements for selecting arbitrary intermediate break locations by utilizing threshold stress criteria based on the ASME Section III Code. The most recent analysis of record for the high energy piping systems was retrieved and the combined stresses recalculated by using the ASME stress indices instead of the ANSI stress intensification factors. The new combined stress was compared to the GL 87-11 criteria for selecting design basis break and leakage crack locations.

Initial application of the GL 87-11 selection criteria to high energy lines outside containment eliminated all arbitrary intermediate design basis breaks and reduced the number of leakage cracks to a few locations. Therefore, many of the modifications previously installed may be removed or abandoned in place.

Combined stress analysis using the ASME Section III code has not been performed for some of the high energy piping systems in the Turbine Building. Therefore, breaks are assumed at any point along the piping as specified previously.

Several piping stress analyses have subsequently been re-performed using the applicable design code requirements for the piping. Additional combined stress analysis was performed for the purposes of high energy line break selection using the ASME Section III Code equations specified in GL 87-11 in lieu of manually recalculating the stress indices.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-2 I.5.2 Pipe Whip Restraints are provided to prevent pipe whip where there is a possibility that whip following a pipe rupture would damage structures, systems or components that are required to mitigate the consequences of that pipe rupture.

A nonlinear elastic-plastic analysis [Ref. 21] is performed to evaluate the adequacy of the pipe rupture restraint system to provide protection following postulated circumferential and longitudinal pipe breaks. The coupled nonlinear dynamic analysis of the restraint-piping system accounts for the dynamic nature of the rupture force, the elastic-plastic deformation of the pipe restraint system and the impact between the restraint and pipe.

The results of the analysis include identification of plastic hinges formed in the pipe, strain in the hinges and restraint status, including gap closure, elastic or plastic deformation and reacting loads.

Blowdown Forces Blowdown forces resulting from pipe rupture were originally determined using a computer program [Ref. 21] based on RELAP-3, the loss of coolant accident program accepted by the AEC at that time. The approved method of evaluation was subsequently changed from RELAP-3 to RELAP-5/MOD 2 - B&W in Reference 40. The program computes and plots the force-time history curve of the reaction loads resulting from a circumferential or longitudinal pipe break subcooled liquid, flashing liquid and steam systems.

The system of interest is modeled as an assembly of volumes connected by flow paths.

In a flow path there can be inserted a valve, check valve or pump. The program solves the transient energy, momentum and state equations for the volumes and flow paths.

The program can also solve the state equation for subcooled water, two phase steam-water mixtures and superheated steam. The ASME Steam Tables are tabulated within the program and table lookup methods are used to determine the state within each volume. An optional bubble separation model can be used to represent a vapor phase above the liquid phase (e.g., steam generator). The program calculates the flow in each junction using both an inertial model (nonchoking) and a flow model (choking).

The lower of the flows calculated from the two models is limiting and thus taken as the actual flow.

The program allows for special component characteristics as applicable in different systems. Leaks can open instantaneously or as a function of time. Pumps can continue to operate or coast down. Valves can be opened or closed and check valves follow a prescribed pressure loss, flow characteristic.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-3 The break force is calculated using the one dimensional momentum equation. The resultant force on the broken piping is the algebraic sum of the following three forces:

Momentum flux g

AV 2

Momentum change (zero for steady state)

tg mV

Pressure force (zero for non-choking flow)

A P

P e

t Where:

Pt = throat pressure Pe = exit pressure A = break area

= density V = velocity g = acceleration of gravity m = mass t = time The results of the analysis for the main steam and feedwater systems are presented in four Nuclear Services Corporation Topical Reports [Ref. 21].

Computation of piping system response to pipe rupture forces is determined with a computer program using an adaptation of the finite element method to the specific requirements of pipe rupture analysis. A dynamic response time history of the piping system is determined which includes elastic-plastic pipe behavior and nonlinear effects of pipe rupture restraints.

The piping system is modeled as an assemblage of straight and curved beams (elbows) connecting discrete nodal points. Weight of the piping system (including offset weights of valve operators) is lumped at selected nodal points. The blowdown force versus time history as developed by the previously discussed transient flow analysis computer program is then applied as an excitation force to the appropriate piping node point.

Dynamic response of the piping system is computed at iterative increments of time and includes forces, moments, deflections and rotations at each node. The resulting bending and torsional moments at each node are used to predict both initial yielding (at which time the elastic modulus at the affected point is replaced by the strain hardening modulus) and ultimate load (i.e., formation of a plastic hinge, after which the modulus is set to a very low value). In situations where stress reversal occurs, an isotopic strain hardening model is used. The strain in plastic hinges and deflections of node points are used to identify the pipe trajectory.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-4 Pipe rupture restraints are modeled with initial design gaps and then both elastic and plastic moduli. At each time step, the programs determine gap closure, elastic or plastic deformation and the resulting impact load.

A model of a typical main steam line is shown in Figure I.5.1-19.

I.5.3 Compartment Pressure and Temperature The GOTHIC code (Version 7.2a) was used to predict the pressure and temperature response of compartments to a high energy line break [Ref. 9.15, 9.17, 9.22, and 9.23].

Separate models were developed to represent the Auxiliary Building and Turbine Building [Ref. 9.18 and 9.19]. The original FSAR pressure and temperature analysis was performed using the CONTEMPT computer code. Use of GOTHIC was approved in Ref 41. Use of GOTHIC version 7.2a was approved via Ref 42.

The analysis assumes that a high energy line break event can be separated into phases such that the result of the analysis of one phase serves as the conditions of the time dependent input to the next phase. The calculation accounts for the description of the high energy line blowdown characteristics, including the effects of steam superheating addressed in NRC Information Notice 84-90 [Ref. 5].

The blowdown rate and duration depend on the system operating conditions and break size. Heat sinks are included in the model to absorb energy. No credit is taken for heat removal capability of individual unit coolers or ventilation systems.

The building compartments are separated into a liquid and vapor region. Each region is assumed to have a uniform temperature, but the temperatures of the two regions may be different. The Auxiliary Building is represented as a multi-compartment structure whose behavior can be described by the one dimensional, multi-region, heat conduction equation.

The calculation proceeds as follows: The initial compartment conditions are determined from ambient pressure, temperature and relative humidity. Heat sinks are initialized at the initial temperature of the compartment. Time advancement is started by evaluating the fluid mass and energy input rates at the midpoint of a time interval, multiplying by the time interval and adding these increments to the current amounts in the compartment. Heat losses or gains to the heat conducting surfaces are estimated by using the heat transfer rates from the previous time step or the steady state conditions for the initial time step. Pressure and temperature of the liquid and vapor regions are then calculated from the mass, volume and energy balance equations. These new temperatures are used for the boundary conditions for the heat conduction solution.

The resulting heat transfer rates for the end of the time step are averaged with the heat transfer rates at the beginning of the time step to correct the previous estimate of the energy in the compartment volume. Mass, momentum and energy equations are then solved for the second time for the pressure and temperatures within the compartment volume. These conditions are then used as the initial conditions for the next time step.

Calculations are performed for selected break sizes and locations at Mode 3, Hot Standby, main steam conditions to obtain the peak compartment pressure and at full power main steam conditions to obtain the peak compartment temperature.

01400725

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-5 Auxiliary Building Model:

The GOTHIC code considers the opening of four sets of steam exclusion boundary doors from the Auxiliary Building (elevations 720, 735 and 755) to the Fuel Handling Building to provide a vent path for pressure relief. The pressure outside the Auxiliary Building remains at atmospheric pressure.

The peak pressure and temperature for some of the compartments are as follows

[Ref. 9.15]:

Compartment Elevation Peak Temp. F Peak Press. psig A

755 337 0.34 B

735 353 0.26 C

715 258 0.25 D

715 317 0.51 X

735 412 0.54 Y

720 410 0.54 Elevation 695 of the Auxiliary Building and selected areas of the plant such as the Control Room, Relay Room and Mechanical Equipment Room are isolated from the effects of the high energy line break environment.

Turbine Building Model:

In the Turbine Building model, the GOTHIC code considers the opening of blow off panels and failure of portions of the turbine building siding for pressure relief. The code also considers the automatic opening of smoke hatch vents for exhaust of high temperature air. Various flowpaths are available to account for cases with normally open or normally closed doors. Pressure and temperature outside the Turbine Building remain at initial atmospheric conditions throughout the transient.

The peak pressure and temperature for areas of interest in the Turbine Building are as follows [Ref 9.22 & 9.23].

Area (See Note)

Peak Temp.

(F)

Peak Pressure (psig)

Unit 1, 679 elevation 361 0.47 Unit 1, 695 elevation 309 0.52 Unit 1, 715 elevation 287 0.48 Unit 2, 679 elevation 386 0.47 Unit 2, 695 elevation 310 0.51 Unit 2, 715 elevation 293 0.46 Turbine Deck, 735 elevation 211 0.47 Note: Each level of the building is made up of several compartments. The highest value from all compartments in the area stated in the table is given.

01406858 01406858

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-6 I.5.4 Jet Impingement [Ref. 9.7]

Jet-impingement load is defined as the force exerted on a component or structure from an undeflected fluid resulting from an instantaneous break or crack in a high-energy pipe.

Maximum impingement pressure along the jet centerline is determined in Reference 9.7 using a combination of several methodologies including; original FSAR, ANSI/ANS-58.2-1988, and the Moody critical flow method. Due to the complexity of the equations involved, the required method of evaluation is explained in detail within the calculation and will not be restated here. Several assumptions are utilized in the methodology as follows:

1. Jet loadings due not vary with time and are conservatively based on the initial conditions at the time of rupture.

2. The jet discharge coefficient is equal to 1 and piping frictional effects are ignored.

Transient pressure changes are not considered.

3. The impinging jet proceeds along a straight path.

4. The jet cross section is an elliptical shape with axes proportional to the width and length of the original break or crack.

5. After the fluid in the jet has undergone free expansion to ambient pressure, the jet area expands uniformly at a divergence half angle of 10 degrees.

6. Ideal gas critical isentropic flow is assumed.

7. Ambient pressure outside the jet is atmospheric pressure.

The methodology models jet-impingement load by dividing the expansion of the jet into three regions.

Region 1: Near the jet discharge there is a conical jet core region. The maximum impingement pressure and temperature along the jet centerline within this jet core are the system pressure and temperature, respectively, prior to pipe rupture.

Region 2: In the second region, the jet outside the conical jet core undergoes free expansion to a static jet pressure, which is related to jet stagnation quality and pressure and the ambient pressure in the subsonic portion of the jet. The area of the jet at the point in which static jet pressure is reached is called the asymptotic plane. Since depressurization out to the asymptotic plane is almost equal to the axial and radial directions, the jet expands with a jet half angle of 45 degrees out to the asymptotic plane.

Region 3: In the third region the jet continues to expand after passing the asymptotic plane with a jet half angle of 10 degrees.

01362721

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-7 Jet centerline temperature outside the jet core region is taken as the saturation temperature at pressure P.

The average jet pressure at a distant target is:

ave l

C P

P where:

Cave

= averaging factor based on experimental velocity profiles (use 1.0, which is the worst case)

The effective load on a distant target is:

t i

e A

P f

F where:

At

= projected area of the target object f

= shape factor to account for deflection, rather than stagnation, of the jet. The only value used is unity.

Typical targets are walls, cables, cable trays and instrumentation. Jet impingement loads on these potential targets are determined and, if necessary, barriers or other protection is installed to reduce the forces on the targets. Calculations show that the functions of cables and cable trays are not affected by jet forces of 2 psi or less (Reference 9.14). The instrumentation and cables associated with the equipment required to bring the reactor to cold shutdown after a high energy line break are qualified for the resultant environment in accordance with the plants EQ program.

When the temperature of a high energy jet exceeds their qualification, jet impingement barriers are installed to protect them or they are relocated.

For each of the five identified high energy piping systems, pressure and temperature were calculated at various distances from postulated pipe breaks and cracks.

Examples of the resulting curves appear in Figures I.5.4-1 through I.5.4-20.

I.5.5 Flooding In support of original plant licensing, PINGP was required to review the effects of flooding for two types of pipe failure events. These event types are: 1) breaks and leakage cracks in high energy piping systems, and 2) leakage cracks in non-high energy, non-Class I systems that are capable of providing high flooding rates or which have an unlimited water supply.

For convenience, the results of flooding reviews for non-HELB events in the auxiliary building were included in Appendix I of the original FSAR. Results for non-HELB flooding reviews now reside in USAR Section 6.1.2.8.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-8 I.5.5.1 HELB Flooding Review Basis The original licensing basis for HELB related flooding was contained in Reference 1.

Flooding was discussed in paragraph 9.29.15 (below).

9.29.15 A discussion should be provided of the potential for flooding safety related equipment in the event of failure of a feedwater line or any other high energy fluid line.

AEC/NSP meetings were held on January 4, 1973, to clarify requirements of the Giambusso letter. The meeting minutes and clarifications were provided by AEC in a letter dated January 11, 1973 (Reference 2).

NSP addressed the requirements of the Giambusso letter in FSAR Amendment 28 (Reference 33).

The AEC performed a review of FSAR Amendment 28 and responded to NSP through a letter dated February 9, 1973 (Reference 3). The AEC concluded that NSP's response was not complete for several of the items requested in the Giambusso letter. One of those items was response to paragraph 9.29.15 (flooding).

NSP addressed flooding with regard to the Giambusso letter in FSAR Amendment 31,Section I.4-4, on March 17, 1973 (Reference 34). This section is specific to the Auxiliary Building, but it establishes a basis for NSP evaluation of high energy line break flooding. One of the systems evaluated for flooding potential was the feedwater system.

The system was described as having a volume of 200,000 gallons at a flow rate of 28,000 gpm.

The evaluation states, The total water volume of the feedwater system would not flood the Class I areas of the Auxiliary Building to a level sufficient to endanger any equipment required for safe reactor shut down.

This indicates that the flooding associated with high energy line break was confined to the contents of the line itself and did not include flooding from any other sources that may have been impacted and damaged from the whipping feedwater line.

The AEC approved the NSP response to the Giambusso letter through SER Supplement 1 dated March 21, 1973 (Reference 35).

01367047

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-9 As stated above, the original interpretation of the flooding requirements by NSP was that flooding due to the line break was the only water required to be considered. The NRC later provided clarification of the flooding analysis requirements in TIA 2011-007 (Reference 36). This TIA concluded the following:

The NRR staff concludes that if a ruptured high energy line can whip and strike another fluid-filled line which meets the criteria for being ruptured by a whipping high energy line, the second (target) pipe must also be assumed to rupture. There is no basis for not including the water contribution from the target pipe rupture in the facility's flooding analysis. Therefore, the NRR staffs position is that the fluid from the target pipe must also be included in the flooding analysis at PINGP. Further, if the HELB can also result in actuation of the fire sprinkler system, then the water from that system must also be included in the flooding analysis at PINGP.

PINGPs later commitment to implementing the high energy pipe break and leakage crack criteria in NRC Branch Technical Position MEB 3-1, as attached to NRC Generic Letter 87-11, Relaxation in Arbitrary Intermediate Pipe Rupture Requirements, (Ref. 4) is discussed in Sections I.1 and I.2. When adopting the relief offered by Generic Letter 87-11, PINGP used only the applicable equations in MEB 3-1 and nothing more.

I.5.5.2 Deleted

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-10 I.5.5.3 Auxiliary Building Flooding Review Results (Ref. 9.12)

The Design Class I area of the Auxiliary Building was reviewed for the effects of flooding due to HELB events. Failures in main steam, feedwater, and blowdown, were selected for analysis.

The analysis determined the times flooding would reach critical flood levels in the Auxiliary Building for each of the postulated pipe failures. Due to the high flow rates from a pipe break in the steam generator blowdown system, the shortest of the required response times for any HELB event was 52.7 minutes. The required response times from failures in any other non-Class I piping system are bounded by these results.

In addition, the auxiliary building was evaluated for potential damage to required equipment due to cascading water as it passes through floor openings (stairwells, pipe chases, floor drains, etc.) on its way to elevation 695 and for damage due to water spray. Most of the required equipment is located on elevation 695', which is a steam exclusion area; all penetrations from elevation 715' are sealed. Water from the upper elevations would be directed through the floor drain system and not cascade on required equipment located on elevation 695'. Due to the physical separation of the opposite-trained equipment, water spray from any leakage crack can only affect the operability of one train of any required equipment. This satisfies the required review criteria of Reference 1.

The routing and pipe rupture evaluation of the feedwater line, as described in Section I.3.2.2, revealed no design basis break or leakage crack locations in the main piping in the Auxiliary Building. The Unit 2 feedwater flow control by-pass lines (4) have several leakage crack locations as identified on Figure I.3.2-4.

The routing and pipe rupture evaluation of the steam generator blowdown line is described in Section I.3.2.4. Each 2 line has terminal end design basis break locations in the Auxiliary Building. These locations are identified on Figures I.3.2-7 and I.3.2-8.

For #21 feedwater flow control valve by-pass line leakage cracks, the water would flow down to elevation 723-4 and spill over the fuel transfer canal into the steam generator blowdown flash tank and filter/demineralizer areas. Fire doors separating these areas from the remainder of the Auxiliary Building were conservatively assumed closed and any leakage was contained inside these areas before flowing through the floor drain system to the building sump. For #22 feedwater flow control by-pass line leakage cracks, the water would flow through floor openings and floor drains to the building sump.

Steam generator blowdown line design basis breaks occur in areas similar to those feedwater flow control by-pass line leakage cracks discussed above and flow to the building sump in a similar manner.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-11 I.5.5.4 Turbine Building Flooding Review Results The Design Class 1 area of the Turbine Building was reviewed for the effects of flooding due to HELB events. No high energy piping is present in the Design Class 1 area of the Turbine Building so no evaluations of high energy line breaks in this area were required.

Additional flooding evaluations were performed outside of the Design Class 1 area of the Turbine Building to determine the potential effects on engineered safety systems due to flooding from the broken high energy pipe, consequential piping ruptures due to the HELB, and sprinkler flow due to the HELB environment. Water spray effects were determined to be not applicable because all engineered safety system components in the turbine building are enclosed in rooms in the Design Class 1 area.

Walkdowns were performed in the Turbine Building to determine HELB piping breaks and cracks which could cause consequential failures of piping systems with unlimited water sources such as fire protection, cooling water, and circulating water (Ref 9.20).

These results showed that numerous potential interactions were present between these systems and high energy piping that required additional evaluation.

An analysis was performed to determine the steady state flow rate of water into the Turbine Building that could be tolerated without causing failure of engineered safety systems with the mitigating features previously discussed in section I.4.5 (Ref 9.21).

The results of the flooding analysis were compared to the expected flow rates from each interaction found during the walkdowns. The evaluation of expected flow rates showed that flooding caused directly or indirectly by a HELB in the turbine building will not result in flow rates high enough to cause engineered safety system failure with the flooding mitigating features in place.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.5-12 THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 22 Page I.6-1 I.6 MAIN STEAM AND FEEDWATER INSIDE CONTAINMENT Although the December 1972 Giambusso letter only requested information concerning high energy line breaks outside Containment, a conservative engineering judgement was made to perform a similar review of the main steam and feedwater lines inside Containment utilizing the criteria from the Giambusso letters. However, the results of that review were not incorporated into the FSAR/USAR or addressed by the AEC Safety Evaluation Report.

The Containment is designed for the peak pressure resulting from the rupture of a main steam or feedwater line, therefore, no encapsulation sleeves to limit mass-energy release are required. To avoid jet impingement damage to required equipment, some instrumentation on the 11 (21) steam generator was relocated. Guard pipes were installed on portions of the main steam and feedwater lines associated with the 12 (22) steam generator. This was done to protect the cables in the electrical penetration area from the crack that was assumed to occur anywhere along the pipe and the arbitrary intermediate break locations. Application of the criteria contained in GL 87-11 eliminated all arbitrary intermediate break and leakage crack locations on the main steam lines and the need for the guard pipes and it eliminated most arbitrary intermediate breaks and leakage cracks on the feedwater lines. However, one intermediate break location on #22 steam generator feedwater line and some leakage crack locations on each feedwater line were identified. These break and crack locations and impingement barrier installations are depicted on Figures I.3.2-3 & 4 and Table I.3.2-2.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 22 Page I.6-2 THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.7-1 I.7 HIGH ENERGY LINES IN THE TURBINE BUILDING Although the December 1972 Giambusso letter requested information concerning high energy line breaks outside the Containment, only the effects on the Auxiliary Building were described in the FSAR. However, high energy lines in the Turbine Building were evaluated also as demonstrated by the installation of steam exclusion dampers, impingement barriers, rupture restraints, etc. to protect the safety related equipment in the Class I aisle. It was assumed that the large net free volume, extensive metal and concrete heat sinks plus leakage to the atmosphere would prevent any significant pressure or temperature conditions in the Turbine Building. The ventilation systems for the safety related areas of the Class I aisle are equipped with steam exclusion dampers as described in Section I.4.2 to prevent creation of a harsh environment in those areas.

01204043

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 Page I.7-2 THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-1 I.8 REFERENCES

1.

Letter, A Giambusso to AV Dienhart, Request for Additional Information Concerning a Postulated Steam Pipe Break Outside of Containment, December 12, 1972. (7208/1431)

2.

Letter, A Giambusso to AV Dienhart, Clarification of Guidelines and Criteria Regarding a Postulated Break in a Pipe Carrying a High-Energy Fluid, January 11, 1973. (7208/1180)

3.

Letter, A Giambusso to AV Dienhart, Request for Additional Information Concerning a Postulated Rupture, Outside of Containment, of a Pipe Carrying High Energy Fluid, February 9, 1973. (7208/1472)

4.

USNRC Generic Letter 87-11, Relaxation In Arbitrary Intermediate Pipe Rupture Requirements, June 19, 1987. (30404/2619)

5.

USNRC Information Notice 84-90, Main Steam Line Break Effect on Environmental Qualification of Equipment, December 7, 1984. (1254/1560)

6.

Letter, D C DiIanni (NRC) to NSP, Summary of September 19, 1984, meeting with NSP Regarding the Resolution of Environmental Qualification of Equipment in the Auxiliary Feedwater Pump Room at PI 1&2, October 22, 1984.

7.

Letter from D Musolf to Director, NRR, Resolution of Environmental Qualification of Equipment in the Auxiliary Feedwater Pump Room, November 28, 1984. (19897/2439)

8.

Letter from USNRC (Kim) to NMC (Sorenson) dated May 30, 2001, Issuance of Amendment Approving the Use of Breakaway Ceramic Pins to Restrain Doors to the Auxiliary Building Special Ventilation Zone.

9.

Calculations 9.1 ENG-ME-304, Rev. 0, Main Steam Line Encapsulation Sleeve Vent Area, April 10, 1997. (3228/2079) 9.2 ENG-ME-319, Rev. 0, Addenda 1, Feedwater System Piping Analysis, August 14, 1997. (3282/1982) (3481/2542) 9.3 ENG-ME-351, Rev. 0, Depletion of Condenser Hotwell Inventory, April 2, 1998. (3395/1205) 9.4 ENG-ME-357, Rev. 3, Break Location Selection, March 15, 2010.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-2 9.5 ENG-ME-358, Rev. 0, Piping System Selection, April 2, 1998.

(3395/1156) 9.6 ENG-ME-360, Rev. 0, Required Equipment Selection, February 2, 1999. (3499/0660) 9.7 ENG-ME-369, Jet Impingement 9.8 ENG-ME-400, Stress Plots For High Energy Piping Systems 9.9 ENG-CS-127, Rev. 1, Auxiliary Building HELB Compartment Volumes, May 18, 2004.

9.10 ENG-CS-141, Rev. 1, Auxiliary Building HELB Surface Areas and Flow Paths, May 18, 2004.

9.11 Not Used.

9.12 ENG-ME-448, Rev. 1, Auxiliary Building Flooding Analysis, January 6, 2006.

9.13 NSPNAD 00007P, Gothic Results for High Energy Line Breaks in Prairie Island Auxiliary Building (Elev. 695-0), Rev. 0, October, 2000.

9.14 ENG-CS-238, Structural Integrity Evaluation of Cable Trays for Jet Impingement, Rev. 0, September 20, 2001. (3941/1509) 9.15 AES PI-P602232-400, Revised Auxiliary Building HELB Analysis.

9.16 Deleted 9.17 ENG-ME-767, GOTHIC Results for Turbine Building After Main Steam HELB Scenarios that Cause Flooding.

9.18 ENG-ME-696, Inputs to Auxiliary Building GOTHIC Model for HELB Analysis.

9.19 ENG-ME-708, Inputs to Turbine Building GOTHIC Model for HELB Analysis.

01362721 01400725 01406858

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-3 9.20 ENG-ME-732, Determination of HELB / Flooding Interactions in the Turbine Building 9.21 ENG-ME-759, GOTHIC Internal Flooding Calculation for the Turbine Building 9.22 ENG-ME-709, Turbine Building HELB Output 160.9 in2 MSLB 9.23 ENG-ME-710, Turbine Building HELB Output 101.6 in2 MSLB

10. Pioneer Service & Engineering Co., Mechanical Specification Encapsulation Sleeves (MPF-10), April 12, 1973. (6511/1763)

11. Pioneer Service & Engineering Co., Technical Specification For Impingement Barrier Guard Pipe (TS-S971), April 5, 1973. (6511/1784)

12. Westinghouse Atomic Power Division, WCAP-7391, Pressurized Water and Steam Jet Effects on Concrete.

13. American Society of Mechanical Engineers, Boiler & Pressure Code,Section III (Nuclear Power Plant Components) & Section XI (In-Service Inspection),

Winter 1972 Addenda.

14. American National Standards Institute, USA Standard Code for Pressure Piping, Power Piping, B31.1.0-1967.

15. American Concrete Institute, Code 318-63, Building Code Requirements Structural Reinforced Concrete.

16. American Society for Testing and Materials (ASTM) A-572, High-Strength Low-Alloy Structural Steel; A-615, Deformed and Plain Billet-Steel Bars for Concrete Reinforcement; A-106, Seamless Carbon Steel Pipe; A-516, Carbon Steel Plate; A-234, Piping Fittings of Wrought Carbon Steel and Alloy Steel.

17. American Welding Society, AWS D1.1-72, Structural Welding Code.

18. American institute of Steel Construction, Specification for the Design, Fabrication and Erection of Structural Steel for Buildings.

19. Institute of Electrical and Electronics Engineers, IEEE-279-1968, Proposed IEEE Criteria for Nuclear Power Plant Protection Systems.

20. Institute of Electrical and Electronics Engineers, IEEE-308, Criteria for Class I Power Systems for Nuclear Generating Plants.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-4

21. Nuclear Services Corporation, Topical Reports 21.1 PI 0-01-01, Unit 1 - Pipe Rupture Analysis of Main Steam Piping Outside Containment, June 12, 1973. (7391/0521) 21.2 PI 0-01-24, Unit 2 - Pipe Rupture Analysis of Main Steam Piping Outside Containment, August 15, 1974. (7391/0860) 21.3 PI 0-01-02, Unit 1 - Pipe Rupture Analysis of Feedwater Piping Outside Containment, June 12, 1973. (7391/0656) 21.4 PI 0-01-27, Unit 2 - Pipe Rupture Analysis of Feedwater Piping Outside Containment, April 18, 1974. (7391/0960)

22. Wisconsin Public Service Corporation, Test Report on Shield Building Penetration Seals for Kewaunee Nuclear Power Plant.

23. American National Standards Institute, ANSI/ANS 58.2, Design Basis For Protection Of Light Water Nuclear Power Plants Against Effects Of Postulated Pipe Rupture, October 6, 1988.

24. Amendment to the License Application #34.

25. Letter Karl Kniel to AV Dienhart, Review of Amendments 34 and 35 to the Prairie Island Nuclear Generating Plant operating license application, August 6, 1973 (7209/2201).

26. Letter, DJ Skovholt (AEC) to AV Dienhart (NSP), Flooding of Critical Equipment, August 3, 1972.

27. Letter, RC DeYoung (AEC) to AV Dienhart (NSP), September 26, 1972.

28. Letter, AV Dienhart (NSP) to RC DeYoung (AEC), October 23, 1972.

29. NRC Information Notice 2000-20, Dec 11, 2000, Potential Loss of Redundant Safety-Related Equipment Because of the Lack of High Energy Line Break Barriers

30. Deleted

31.

Deleted

32.

Deleted

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-5

33.

FSAR Amendment 28, dated February 1, 1973.

34.

FSAR Amendment 31, dated March 17, 1973.

35.

Supplement 1 to Safety Evaluation by the Directorate of Licensing U. S. Atomic Energy Commission in the matter of Northern States Power Company Prairie Island Units 1 & 2 Docket Nos. 50-282 & 50-306, March 21, 1973.

36.

NRC Office of Nuclear Reactor Regulation Letter to NRC Region Ill, dated 1/28/2011, Task Interface Agreement - Evaluation of Flooding Licensing Basis at PINGP (TIA 2011-007, NRC Adams #ML110240359)

37.

Deleted

38.

Deleted

39.

Deleted

40. 10CFR50.59 Evaluation #1093, dated 4/06/2012, Use of RELAP-5 vs.

RELAP-3 for FW Line Break, HELB.

41. 10CFR50.59 Evaluation #1039, dated 5/18/2006, Revised Auxiliary Building High Energy Line Break analysis.

42. 10CFR50.59 Evaluation #1073, dated 2/25/2010, Change in Methodology to GOTHIC Version 7.2a for Compartment Environmental Response Outside Containment.

01400725

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 33 Page I.8-6 THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 1 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF MECHANICAL 034-011, 034-021 D1/D2 diesel generator X

X X

X X

234-031, 234-032 D5/D6 diesel generator X

X X

X X

045-591, 045-592 Chilled water pump X

X X

X X

145-071, 145-072 Safety injection pump X

X X

X X

245-071, 245-072 Safety injection pump X

X X

X X

145-201, 145-331 Auxiliary feedwater pump X

X X

X X

245-201, 245-331 Auxiliary feedwater pump X

X X

X X

045-091 Cooling water pump X

X X

X X

145-392, 245-392 Cooling water pump X

X X

X X

145-121, 145-122 Component cooling pump X

X X

X X

245-121, 245-122 Component cooling pump X

X X

X X

145-261, 145-262 Feedwater pump TB X

X X

X X

245-261, 245-262 Feedwater pump TB X

X X

X X

045-271, 045-272 D1/2 fuel oil transfer pump X

X X

X X

045-273, 045-274 D1/2 fuel oil transfer pump X

X X

X X

045-301, 045-302 DDCLP fuel oil transfer pump X

X X

X X

245-881, 245-882 D5/6 fuel oil transfer pump X

X X

X X

245-883, 245-884 D5/6 fuel oil transfer pump X

X X

X X

067-011, 067-012 Safeguard traveling screen X

X X

X X

146-011, 246-011 DDCLP starting air receiver X

X X

X X

Note 1:

Code Location Outside areas that experience a harsh environment following a break.

TB Located in the Turbine Building in an area that experiences a harsh environment.

Other Refer to Auxiliary Building compartment codes as shown on Figures I.3.1-2 thru I.3.1-6.

Codes

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 2 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF MECHANICAL 046-031, 046-032 D1/2 starting air receiver X

X X

X X

246-031, 246-032 D5 starting air receiver X

X X

X X

246-033, 246-034 D5 starting air receiver X

X X

X X

246-035, 246-036 D6 starting air receiver X

X X

X X

246-037, 246-038 D6 starting air receiver X

X X

X X

158-011, 158-012 Cooling water strainer X

X X

X X

258-011, 258-012 Cooling water strainer X

X X

X X

032-041, 032-042 D1/D2 room supply fan X

X X

X X

032-011, 032-012 D1/D2 room exhaust fan X

X X

X X

032-291, 032-292 Control room clean-up fan X

X X

X X

132-281, 232-281 DDCLP roof exhaust fan X

X X

X X

076-021, 076-022 Control room air handler X

X X

X X

232-441, 232-442 D5/D6 building supply fan X

X X

X X

232-443, 232-444 D5/D6 building supply fan X

X X

X X

232-451, 232-452 D5/D6 building exhaust fan X

X X

X X

232-453, 232-454 D5/D5 building exhaust fan X

X X

X X

232-421, 232-422 D5/D6 room cooling fan X

X X

X X

074-031, 074-032 Relay room unit cooler X

X X

X X

074-033, 074-034 Relay room unit cooler X

X X

X X

174-031, 174-032 Bus 15/16 room unit cooler X

X X

X X

274-031, 274-032 Bus 111/121 room unit cooler X

X X

X X

174-161, 274-161 Bus 112/122 room unit cooler X

X X

X X

01517422

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 3 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF MECHANICAL 174-162, 274-162 EMA/B room unit cooler X

X X

X X

174-163 EMA room unit cooler X

X X

X X

075-011, 075-012 Control room chiller X

X X

X X

CONTROL VALVE (CV-)

31127, 31128 Feedwater flow - main B/X X

X X

X X

31135, 31136 Feedwater flow - main B/X X

X X

X X

31369, 31370 Feedwater flow - bypass B/X X

X X

X X

31371, 31372 Feedwater flow - bypass B/X X

X X

X X

31245, 31246 RCP thermal barrier return X

X X

X X

31247, 31248 RCP thermal barrier return X

X X

X X

31381, 31411 CC Hx cooling water outlet X

X X

X X

31383, 31384 CC Hx cooling water outlet X

X X

X X

31231, 31232 Pressurizer PORV X

X X

X X

31233, 31234 Pressurizer PORV X

X X

X X

31084, 31089 Steam generator PORV A/X X

X X

X X

31102, 31107 Steam generator PORV A/X X

X X

X X

31998, 31999 Steam supply to AFWPT TB X

X X

X X

31059, 31060 AFW Pump trip throttle X

X X

X X

31153, 31154 AFW pump oil cooler X

X X

X X

31418, 31419 AFW pump oil cooler X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 4 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF CONTROL VALVE (CV-)

31423, 31457 DDCLP jacket water cooler X

X X

X X

31505, 31506 D1/D2 heat exchanger X

X X

X X

31769, 31785 Control room chiller X

X X

X X

31786, 31768 Control room air handler X

X X

X X

31755, 31756 Bus 111/112 room unit cooler X

X X

X X

31759, 31760 Relay room unit cooler X

X X

X X

31761, 31762 Relay room unit cooler X

X X

X X

31757, 31758 Bus 15/16 room unit cooler X

X X

X X

31764, 31765 Bus 112/122 room unit cooler X

X X

X X

31766, 31767 EMA/B room unit cooler X

X X

X X

31788 EMA room unit cooler X

X X

X X

31953, 31954 D1 starting air X

X X

X X

31955, 31956 D2 starting air X

X X

X X

31098, 31099 Containment isolation - MS B/Y X

X X

X X

31116, 31117 Containment isolation - MS B/Y X

X X

X X

31339, 31430 Containment isolation - VC D

X X

X X

X 31325, 31347 Containment isolation - VC X

X X

X X

31326, 31348 Containment isolation - VC X

X X

X X

31327, 31349 Containment isolation - VC X

X X

X X

31255, 31279 LTDN Line Isol - VC X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 5 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF SOLENOID VALVE (SV-)

37903, 37904 D5 starting air X

X X

X X

37906, 37907 D5 starting air X

X X

X X

37933, 37934 D6 starting air X

X X

X X

37936, 37937 D6 starting air X

X X

X X

33464, 33465 12 DDCLP starting air X

X X

X X

33466, 33467 22 DDCLP starting air X

X X

X X

MOTOR VALVE (MV-)

32016, 32017 Steam supply to AFWPT B/X X

X X

X X

32019, 32020 Steam supply to AFWPT B/X X

X X

X X

32025, 32027 AFW pump suction - CL X

X X

X X

32026, 32030 AFW pump suction - CL X

X X

X X

32031, 32033 CL header to Turb Bldg X

X X

X X

32034, 32035 CL pump header isolation X

X X

X X

32036, 32037 CL pump header isolation X

X X

X X

32045, 32047 MSIV bypass B/Y X

X X

X X

32048, 32050 MSIV bypass B/Y X

X X

X X

32068, 32070 SI cold leg injection X

X X

X X

32073, 32176 SI cold leg injection X

X X

X X

32171, 32173 SI cold leg injection X

X X

X X

32079, 32080 SI pump suction from RWST X

X X

X X

32182, 32183 SI pump suction from RWST X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 6 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF MOTOR VALVE (MV-)

32083, 32186 SI pump suction from BAST X

X X

X X

32089, 32091 RCP CC inlet C

X X

X X

X 32124, 32126 RCP CC inlet C

X X

X X

X 32090, 32092 RCP CC outlet C

X X

X X

X 32125, 32127 RCP CC outlet C

X X

X X

X 32120, 32121 CC Hx outlet crossover X

X X

X X

32122, 32123 CC Hx outlet crossover X

X X

X X

32145, 32146 Cooling water to CC Hx X

X X

X X

32160, 32161 Cooling water to CC Hx X

X X

X X

32144, 32159 Cooling water header crossover X

X X

X X

32162, 32163 SI pump suction X

X X

X X

32190, 32191 SI pump suction X

X X

X X

32195, 32196 Pressurizer PORV isolation X

X X

X X

32197, 32198 Pressurizer PORV isolation X

X X

X X

32200, 32201 CC surge tank to pump X

X X

X X

32211, 32212 CC surge tank to pump X

X X

X X

32238, 32381 AFW to steam generator X

X X

X X

32246, 32383 AFW to steam generator X

X X

X X

32239, 32382 AFW to steam generator X

X X

X X

32247, 32384 AFW to steam generator X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 7 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF MOTOR VALVE (MV-)

32266, 32267 CC to RCP X

X X

X X

32268, 32269 CC to RCP X

X X

X X

32323, 32324 Feedwater pump discharge TB X

X X

X X

32325, 32326 Feedwater pump discharge TB X

X X

X X

32332, 32334 Cooling water return header X

X X

X X

32023, 32024 Containment isolation - FW B/X X

X X

X X

32028, 32029 Containment isolation - FW B/X X

X X

X X

32040, 32043 Containment isolation - SB X

X X

X X

32046, 32049 Containment isolation - SB X

X X

X X

32044, 32058 Containment isolation - SB C

X X

X X

X 32051, 32059 Containment isolation - SB C

X X

X X

X 32073, 32176 Containment isolation - SI X

X X

X X

32242, 32243 Containment isolation - AF B/X X

X X

X X

32248, 32249 Containment isolation - AF B/X X

X X

X X

DAMPER (CD-OR MD-)

34177, 34176 Control room outside air A/*

X X

X X

X 34142, 34145 Control room outside air X

X X

X X

34143, 34144 Air handler discharge X

X X

X X

34146, 34147 Control room exhaust X

X X

X X

34179, 34181 Control Room PAC filter inlet X

X X

X X

34178, 34180 Control Room PAC filter outside air X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 8 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF DAMPER (CD-OR MD-)

34182, 34183 Control Room PAC filter outlet X

X X

X X

34185, 34186 Waste gas storage area FH X

X X

X X

34187, 34188 Supply to elevation 695 C

X X

X X

X 34189, 34190 Supply to elevation 695 X

X X

X X

34191, 34192 480V Bus Room return X

X X

34193, 34194 480V Bus Room return X

X X

34195, 34196 Battery room supply TB X

X X

34197, 34198 Battery room supply TB X

X X

34199, 34200 4kv bus room supply X

X X

34201, 34202 480v bus room supply X

X X

34049 D1/D2 outside air supply X

X X

X X

34136, 34139 DDCLP air supply X

X X

X X

34137, 34138 DDCLP roof exhaust X

X X

X X

32420, 32426 D5/D6 room outside air X

X X

X X

32421, 32427 D5/D5 room exhaust X

X X

X X

32422, 32428 D5/D6 room recirc X

X X

X X

32423, 32429 D5/D6 outside air X

X X

X X

32424, 32430 D5/D6 building exhaust X

X X

X X

32425, 32431 D5/D6 building recirc X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 9 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF INSTRUMENTATION (Unit 1, 2 or Common Prefix)

NM-51, 52 Nuclear Instrumentation X

X X

X X

PT-429, 430 Pressurizer pressure X

X X

X X

PT-431, 449 Pressurizer pressure X

X X

X X

PT-709, 710 RCS wide range pressure X

X X

X X

PT-468, 469, 482 Steam generator pressure X/Y X

X X

X X

PT-378, 479, 483 Steam generator pressure C

X X

X X

X PT-751, 761 RVLIS wide range pressure B

X X

X X

X LT-723, 724 Condensate tank level TB X

X X

X X

LT-426, 427, 428 Pressurizer level X

X X

X X

LT-751, 752, 753 RVLIS level B

X X

X X

X LT-761, 762, 763 RVLIS level B

X X

X X

X LT-461, 462, 463 Steam generator level X

X X

X X

LT-471, 472, 473 Steam generator level X

X X

X X

LT-460, 470 Steam generator level X

X X

X X

LT-487, 488 Steam generator level X

X X

X X

LT-920, 921 RWST level X

X X

X X

FT-464, 465 Main steam line flow X

FT-474, 475 Main steam line flow X

13234, 13235 Core exit thermocouple X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 10 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF INSTRUMENTATION (Unit 1, 2 or Common Prefix) 13237, 13238 Core exit thermocouple X

X X

X X

13239, 13240 Core exit thermocouple X

X X

X X

13241, 13242 Core exit thermocouple X

X X

X X

13243, 13245 Core exit thermocouple X

X X

X X

13246, 13247 Core exit thermocouple X

X X

X X

13248, 13249 Core exit thermocouple X

X X

X X

13250, 13251 Core exit thermocouple X

X X

X X

13252, 13253 Core exit thermocouple X

X X

X X

13255, 13256 Core exit thermocouple X

X X

X X

13258, 13259 Core exit thermocouple X

X X

X X

13260, 13261 Core exit thermocouple X

X X

X X

13262, 13263 Core exit thermocouple X

X X

X X

13264, 13265 Core exit thermocouple X

X X

X X

13266, 13267 Core exit thermocouple X

X X

X X

13268, 13269 Core exit thermocouple X

X X

X X

13270, 13271 Core exit thermocouple X

X X

X X

13272, 12407 Core exit thermocouple X

X X

X X

13408, 13410 Core exit thermocouple X

X X

X X

13411, 13412 Core exit thermocouple X

X X

X X

13413, 13414 Core exit thermocouple X

X X

X X

13415, 13416 Core exit thermocouple X

X X

X X

13418, 13419 Core exit thermocouple X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 11 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF INSTRUMENTATION (Unit 1, 2 or Common Prefix) 13420, 13421 Core exit thermocouple X

X X

X X

13422, 13423 Core exit thermocouple X

X X

X X

13424, 13425 Core exit thermocouple X

X X

X X

13426, 13428 Core exit thermocouple X

X X

X X

13429, 13431 Core exit thermocouple X

X X

X X

13432, 13433 Core exit thermocouple X

X X

X X

13434, 13435 Core exit thermocouple X

X X

X X

13436, 13437 Core exit thermocouple X

X X

X X

13438, 13439 Core exit thermocouple X

X X

X X

13440, 13441 Core exit thermocouple X

X X

X X

13442, 13443 Core exit thermocouple X

X X

X X

13444, 13445 Core exit thermocouple X

X X

X X

TE-401, 402 RCS hot/cold leg temperature X

TE-403, 404 RCS hot/cold leg temperature X

TE-450, 451 RCS hot/cold leg temperature X

X X

X X

15297, 15407 Waste gas storage area FH X

X X

X X

15298, 15408 Supply to elevation 695 X

X X

X X

15299, 15409 Supply to elevation 695 X

X X

X X

15300, 15415 Control room exhaust A

X X

X X

X 15301, 15421 Control room outside air X

X X

X X

15302, 15422 Control room outside air X

X X

X X

15684, 15690 480V Bus room return TB X

X X

01483911

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 12 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF INSTRUMENTATION (Unit 1, 2 or Common Prefix) 15685, 15691 480V Bus room return TB X

X X

15686, 15692 Battery room supply TB X

X X

15687, 15693 Battery room supply X

X X

15688, 15694 4 kv bus room supply TB X

X X

15689, 15695 480v bus room supply TB X

X X

CS46331, 46450 Reactor trip breaker X

X X

X X

CS49629, 49562 Reactor trip breaker X

X X

X X

CS46180, 49610 SI actuation X

X X

X X

CS46408, 49545 SI actuation X

X X

X X

CS46158, 46159 MSIV closure X

X X

X X

CS49620, 49621 MSIV closure X

X X

X X

FT-924, 925 Safety injection flow X

X X

X X

23122, 23127 Auxiliary feedwater flow X

X X

X X

23128, 23219 Auxiliary feedwater flow X

X X

X X

PZ-HTRA/XD Przr heater watts X

X X

X X

PZ-HTRB/XD Przr heater watts X

X X

X X

XE-443, 444, 445 Przr safety valve flow X

X X

X X

RE-01 Control room rad monitor X

X X

X X

4190201, 4190202 Electrical bus status X

X X

X X

4190203, 4190204 Electrical bus status X

X X

X X

4190205, 4190206 Electrical bus status X

X X

X X

4190301, 4190302 Electrical bus status X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 13 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF INSTRUMENTATION (Unit 1, 2 or Common Prefix) 4190303, 4190304 Electrical bus status X

X X

X X

4190305, 4190306 Electrical bus status X

X X

X X

4190401, 4190402 Electrical bus status X

X X

X X

4190403, 4190501 Electrical bus status X

X X

X X

4190502, 4190503 Electrical bus status X

X X

X X

4190504, 4190505 Electrical bus status X

X X

X X

4190506, 4190701 Electrical bus status X

X X

X X

4190702, 4190703 Electrical bus status X

X X

X X

4190704, 4190705 Electrical bus status X

X X

X X

4190706, 4192401 Electrical bus status X

X X

X X

4192402, 4192403 Electrical bus status X

X X

X X

4191801, 4191802 Electrical bus status X

X X

X X

4191803, 4192301 Electrical bus status X

X X

X X

4192302, 4192303 Electrical bus status X

X X

X X

ELECTRICAL 1-52/RTA, 1-52/RTB Reactor trip breaker X

X X

X X

1-52/BYA, 1-52/BYB Reactor trip breaker X

X X

X X

2-52/RTA, 2-52/RTB Reactor trip breaker X

X X

X X

2-52/BYA, 2-52/BYB Reactor trip breaker X

X X

X X

11 Batt, 12 Batt Battery X

X X

X X

21 Batt, 22 Batt Battery X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 34 TABLE I.1.4-1 REQUIRED EQUIPMENT LIST Page 14 of 14 DESCRIPTION LOCATION Note 1 MS FW VC SB AF ELECTRICAL Bus 15, 16 4160 volt switchgear X

X X

X X

Bus 25, 26, 27 4160 volt switchgear X

X X

X X

Bus 111, 112 480 volt switchgear X

X X

X X

Bus 211, 212 480 volt switchgear X

X X

X X

Bus 121, 122 480 volt switchgear X

X X

X X

Bus 221, 222 480 volt switchgear X

X X

X X

MCC 1S, 2S Pressurizer heater group A X

X X

X X

MCC 1R, 2R Pressurizer heater group B X

X X

X X

DOORS Door 133, 182 Aux Bldg to Fuel Handling X2 X

X X

X X

Door 134, 184 Aux Bldg to Fuel Handling X1 X

X X

X X

Door 147, 273 Aux Bldg to Fuel Handling A0 X

X X

X X

Door 155, 177 Aux Bldg to Fuel Handling Y1 X

X X

X X

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 29 TABLE I.3.1-1 AUXILIARY BUILDING - COMPARTMENT DATA Page 1 of 2 A1 A0 A2 Gross Volume (ft3) 146,034 37,411 149,207 Equipment (20,603)

(4,047)

(15,574)

Net Volume (ft3) 125,431 33,364 133,633 Surface Area (ft2) 50997 12,421 49,996 B1 B0 B2 Gross Volume (ft3) 101,128 38,727 114,851 Equipment (23,036)

(6,806)

(26,652)

Net Volume (ft3) 78,092 31,921 88,199 Surface Area (ft2) 36,492 13,699 43,057 X1 X2 Gross Volume (ft3) 23,456 23,269 Equipment (2,019)

(2,171)

Net Volume (ft3) 21,437 21,098 Surface Area (ft2) 8,281 8,755 C1 C0 C2 Gross Volume (ft3) 171,616 44,612 171,806 Equipment (50,119)

(20,915)

(21,379)

Net Volume (ft3) 121,497 23,697 150,427 Surface Area (ft2) 57,399 20,289 61,489 01031067

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 29 TABLE I.3.1-1 AUXILIARY BUILDING - COMPARTMENT DATA Page 2 of 2 D1 D0 D2 Gross Volume (ft3) 11,932 86,163 11,932 Equipment (1,393)

(32,770)

(1,268)

Net Volume (ft3) 10,539 53,393 10,664 Surface Area (ft2) 4,650 39,306 4,600 Y1 Y2 Gross Volume (ft3) 15,806 11,975 Equipment (3,317)

(2,384)

Net Volume (ft3) 12,489 9,591 Surface Area (ft2) 7,321 7,041 NOTE: Surface areas include concrete and metal.

Volume For Compartment Includes Volume For Compartment B1 F1 & G1 B2 F2 & G2 D0 H0, M0, N0, N1 & N2 C1 K1 & L1 C2 K2 & L2 Y2 O2 01031067 01031067

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 1 of 6 Main Steam from Steam Generator #11 Break ID No.

Description Building HELB Comp.

MS1-B3 30 nozzle @ HP Turbine Turbine Bldg 3A1 MS1-B4 10 branch connection to MSRs Turbine Bldg 2D1 MS1-B5 6 branch connection to PORV Aux Bldg X1 MS1-B6 6 branch connection to AFWP Aux Bldg X1 MS1-B7 1 1/2 drain line from CV-31098 Aux Bldg Y1 MS1-B8 1 1/2 drain line from valve RS-19-1 Aux Bldg Y1 MS1-B9 1 1/2 drain line at drip pocket after RS-19-1 Aux Bldg Y1 MS1-B10 1 1/2 drain line at pipe 12-MS-3 Turbine Bldg 2D4 MS1-B11 Drain line from turbine stop valve Turbine Bldg 3A1 Main Steam from Steam Generator #12 Break ID No.

Description Building HELB Comp.

MS1-B14 30 nozzle @ HP Turbine Turbine Bldg 3A1 MS1-B15 16 branch connection to MSRs Turbine Bldg 2D4 MS1-B16 6 branch connection to PORV Aux Bldg A1 MS1-B17 6 branch connection to AFWP Aux Bldg B1 MS1-B18 1 1/2 drain line from CV-31099 Aux Bldg B1 MS1-B19 1 1/2 drain line from valve RS-19-2 Aux Bldg B1 MS1-B20 1 1/2 drain line at drip pocket after RS-19-2 Aux Bldg B1 MS1-B21 1 1/2 drain line at pipe 12-MS-4 Turbine Bldg 2D4 MS1-B22 Drain line from turbine stop valve Turbine Bldg 3A1 MS1-B23 Drain line upstream of CV-31099 Aux Bldg B1 01204043 01222109 01222109 01222109 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 2 of 6 Main Steam from Steam Generator #21 Break ID No.

Description Building HELB Comp.

MS2-B3 30 nozzle @ HP Turbine Turbine Bldg 3A1 MS2-B4 10 branch connection to MSRs Turbine Bldg 2H1 MS2-B5 6 branch connection to PORV Aux Bldg X2 MS2-B6 6 branch connection to AFWP Aux Bldg X2 MS2-B7 1 1/2 drain line from CV-31116 Aux Bldg Y2 MS2-B8 1 1/2 drain line from valve RS-19-3 Aux Bldg Y2 MS2-B9 2 drain line at drip pocket after RS-19-3 Aux Bldg Y2 MS2-B10 1 1/2 drain line at pipe 12-2MS-3 Turbine Bldg 2H4 MS2-B11 Drain line from turbine stop valve Turbine Bldg 3A1 Main Steam from Steam Generator #22 Break ID No.

Description Building HELB Comp.

MS2-B14 30 nozzle @ HP Turbine Turbine Bldg 3A1 MS2-B15 16 branch connection to MSRs Turbine Bldg 2H4 MS2-B16 6 branch connection to PORV Aux Bldg A2 MS2-B17 6 branch connection to AFWP Aux Bldg B2 MS2-B18 1 1/2 drain line from CV-31117 Aux Bldg B2 MS2-B19 1 1/2 drain line from valve RS-19-4 Aux Bldg B2 MS2-B20 1 1/2 drain line at drip pocket after RS-19-4 Aux Bldg B2 MS2-B21 1 1/2 drain line at pipe 12-2MS-4 Turbine Bldg 2H4 MS2-B22 Drain line from turbine stop valve Turbine Bldg 3A1 MS2-B23 Drain line upstream of CV-31117 Aux Bldg B2 Feedwater from #15A/B FW Heaters to Steam Generators #11 & #12 Break ID No.

Description Building HELB Comp.

FW1-B1 16 Nozzle @ 15B FW Heater Turbine Bldg 2D4 FW1-B4 16 Nozzle @ 15A FW Heater Turbine Bldg 2D4 Feedwater from #15A/B FW Heaters to Steam Generators #21 & #22 Break ID No.

Description Building HELB Comp.

FW2-B1 16 Nozzle @ 25B FW Heater Turbine Bldg 2H4 FW2-B4 16 Nozzle @ 25A FW Heater Turbine Bldg 2H4 01204043 01222109 01222109 01222109 01222109 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 3 of 6 Feedwater from FW Pumps #11 & #12 to #15A/B FW Heaters Break ID No.

Description Building HELB Comp.

FW1-B7 16 outlet nozzle @ #11 FW pump Turbine Bldg 1D1 FW1-B8 16 outlet nozzle @ #12 FW pump Turbine Bldg 1D1 FW1-B9 20 nozzle @ 15A FW heater inlet Turbine Bldg 2D4 FW1-B10 20 nozzle @ 15B FW heater inlet Turbine Bldg 2D4 FW1-B11 10 condenser dump (#11 FW pump)

Turbine Bldg 1D3 FW1-B12 10 condenser dump (#12 FW pump)

Turbine Bldg 1D3 FW1-B13 14 branch (15A FW heater bypass)

Turbine Bldg 2D4 FW1-B14 14 branch (15B FW heater bypass)

Turbine Bldg 2D4 FW1-B15 6 branch to condenser (#11 pump)

Turbine Bldg 1D1 FW1-B16 6 branch to condenser (#12 pump)

Turbine Bldg 1D1 Feedwater from FW Pumps #21 & #22 to #15A/B FW Heaters Break ID No.

Description Building HELB Comp.

FW2-B8 16 outlet nozzle @ #21 FW pump Turbine Bldg 1J1 FW2-B9 16 outlet nozzle @ #22 FW pump Turbine Bldg 1J1 FW2-B10 20 nozzle @ 25A FW heater inlet Turbine Bldg 2H4 FW2-B11 20 nozzle @ 25B FW heater inlet Turbine Bldg 2H4 FW2-B12 10 condenser dump (#21 FW pump)

Turbine Bldg 1J3 FW2-B13 10 condenser dump (#22 FW pump)

Turbine Bldg 1J3 FW2-B14 14 branch (25A FW heater bypass)

Turbine Bldg 2H4 FW2-B15 14 branch (25B FW heater bypass)

Turbine Bldg 2H4 FW2-B16 10 branch to condenser (#21 pump)

Turbine Bldg 1J1 01204043 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 4 of 6 Condensate from #12A/B FW Heaters to FW Pumps #11 & #12 Break ID No.

Description Building HELB Comp.

CD1-B1 16 nozzle @ 12A FW heater outlet Turbine Bldg 2D2 CD1-B2 16 nozzle @ 12B FW heater outlet Turbine Bldg 2D2 CD1-B3 16 nozzle @ 13A FW heater inlet Turbine Bldg 1D1 CD1-B4 16 nozzle @ 13B FW heater inlet Turbine Bldg 1D1 CD1-B5 16 nozzle @ 13A FW heater outlet Turbine Bldg 2D2 CD1-B6 16 nozzle @ 13B FW heater outlet Turbine Bldg 2D2 CD1-B7 16 nozzle @ 14A FW heater inlet Turbine Bldg 2D4 CD1-B8 16 nozzle @ 14B FW heater inlet Turbine Bldg 2D4 CD1-B9 16 nozzle @ 14A FW heater outlet Turbine Bldg 2D4 CD1-B10 16 nozzle @ 14B FW heater outlet Turbine Bldg 2D4 CD1-B11 12 nozzle @ #11 HD pump outlet Turbine Bldg 1D3 CD1-B12 12 nozzle @ #12 HD pump outlet Turbine Bldg 1D3 CD1-B13 12 nozzle @ #13 HD pump outlet Turbine Bldg 1D3 CD1-B14 16 inlet nozzle @ #11 FW pump Turbine Bldg 1D1 CD1-B15 16 inlet nozzle @ #12 FW pump Turbine Bldg 1D1 CD1-B16 Bypass line tee at 14B FW htr inlet Turbine Bldg 2D4 CD1-B17 20 Tee at branch to #11 FW pump Turbine Bldg 2D4 CD1-B18 Second elbow upstream of 14A FW heater inlet Turbine Bldg 2D4 CD1-B19 Tee upstream of 14B FW heater inlet Turbine Bldg 1D1 CD1-B20 Tee downstream of Valve C-5-1 Turbine Bldg 1D1 CD1-B21 Tee downstream of 13A FW Htr outlet Turbine Bldg 1D1 CD1-B22 Third elbow downstream of 13A FW heater outlet Turbine Bldg 1D1 CD1-B23 Second elbow downstream of 13A FW heater outlet Turbine Bldg 2D2 CD1-B24 Second elbow upstream of 14B FW heater inlet Turbine Bldg 2D4 CD1-B25 Third elbow upstream of 14B FW heater inlet Turbine Bldg 1D1 CD1-B26 Second elbow downstream of 13B FW heater outlet Turbine Bldg 2D2 CD1-B27 Elbow downstream of Valve C-5-1 Turbine Bldg 1D1 01222109 01204043

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 5 of 6 Condensate from #22A/B FW Heaters to FW Pumps #21 & #22 Break ID No.

Description Building HELB Comp.

CD2-B1 16 nozzle @ 22A FW heater outlet Turbine Bldg 2H2 CD2-B2 16 nozzle @ 22B FW heater outlet Turbine Bldg 2H2 CD2-B3 16 nozzle @ 23A FW heater inlet Turbine Bldg 1J1 CD2-B4 16 nozzle @ 23B FW heater inlet Turbine Bldg 1J1 CD2-B5 16 nozzle @ 23A FW heater outlet Turbine Bldg 2H2 CD2-B6 16 nozzle @ 23B FW heater outlet Turbine Bldg 2H2 CD2-B7 16 nozzle @ 24A FW heater inlet Turbine Bldg 2H4 CD2-B8 16 nozzle @ 24B FW heater inlet Turbine Bldg 2H4 CD2-B9 16 nozzle @ 24A FW heater outlet Turbine Bldg 2H4 CD2-B10 16 nozzle @ 24B FW heater outlet Turbine Bldg 2H4 CD2-B11 12 nozzle @ #21 HD pump outlet Turbine Bldg 1J3 CD2-B12 12 nozzle @ #22 HD pump outlet Turbine Bldg 1J3 CD2-B13 12 nozzle @ #23 HD pump outlet Turbine Bldg 1J3 CD2-B14 16 inlet nozzle @ #21 FW pump Turbine Bldg 1J1 CD2-B15 16 inlet nozzle @ #22 FW pump Turbine Bldg 1J1 CD2-B16 Elbow downstream of valve 2CD-5-1 Turbine Bldg 1J1 CD2-B17 Tee downstream of valve 2CD-5-1 Turbine Bldg 1J1 CD2-B18 Tee downstream of 23A FW Htr outlet Turbine Bldg 1J1 CD2-B19 Second elbow downstream of 24B FW heater outlet Turbine Bldg 2H2 CD2-B20 Second elbow downstream of 24A FW heater outlet Turbine Bldg 2H2 CD2-B21 Tee to 24B FW heater inlet Turbine Bldg 1J1 CD2-B22 Third elbow upstream of 24B FW heater inlet Turbine Bldg 1J1 CD2-B23 Second elbow upstream of 24B FW heater inlet Turbine Bldg 2H4 CD2-B24 Bypass line tee at 24B FW htr inlet Turbine Bldg 2H4 CD2-B25 Third elbow upstream of 24A FW heater inlet Turbine Bldg 1J1 CD2-B26 Second elbow upstream of 24A FW heater inlet Turbine Bldg 2H4 CD2-B27 Bypass line tee at 24A FW htr inlet Turbine Bldg 1J1 CD2-B28 20 Tee at branch from #22 FW pump Turbine Bldg 2H4 01222109 01204043

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-1 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS OUTSIDE CONTAINMENT Page 6 of 6 CVCS Letdown line - Unit 1 Break ID No.

Description Building HELB Comp.

VC1-B1 2 Containment penetration Aux Bldg D1 VC1-B2 2 Intermediate anchor Aux Bldg D1 VC1-B3 2 Letdown heat exchanger nozzle Aux Bldg L1 CVCS Letdown line - Unit 2 Break ID No.

Description Building HELB Comp.

VC2-B1 2 Containment penetration Aux Bldg D2 VC2-B2 2 Intermediate anchor Aux Bldg H0 VC2-B3 2 Letdown heat exchanger nozzle Aux Bldg L2 Unit 1 Steam Generator Blowdown Break ID No.

Description Building HELB Comp.

SB1-B1 2 Containment penetration Aux Bldg C1 SB1-B2 2 Intermediate anchor Aux Bldg C1 SB1-B3 2 Intermediate anchor Aux Bldg D1 SB1-B4 2 Flash tank nozzle Aux Bldg D1 SB1-B6 2 Containment penetration Aux Bldg C1 SB1-B7 2 Intermediate anchor Aux Bldg C1 SB1-B8 2 Intermediate anchor Aux Bldg D1 SB1-B9 2 Flash tank nozzle Aux Bldg D1 Unit 2 Steam Generator Blowdown Break ID No.

Description Building HELB Comp.

SB2-B1 2 Containment penetration Aux Bldg C2 SB2-B2 2 Intermediate anchor Aux Bldg C2 SB2-B4 2 Flash tank nozzle Aux Bldg D2 SB2-B5 2 Containment penetration Aux Bldg C2 SB2-B7 2 Flash tank nozzle Aux Bldg D2 Unit 1 Steam Supply to Aux Feedwater Pump Break ID No.

Description Building HELB Comp.

AF1-B1 3 Intermediate anchor Aux Bldg X1 Unit 2 Steam Supply to Aux Feedwater Pump Break ID No.

Description Building HELB Comp.

No breaks present 01204043 01204043 01222109 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-2 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS INSIDE CONTAINMENT Page 1 of 2 Main Steam from Steam Generator #11 Break ID No.

Description Building HELB Comp.

MS1-B1 32 nozzle @ Steam Generator Containment N/A MS1-B2 31 Intermediate anchor elbow Containment N/A Main Steam from Steam Generator #12 Break ID No.

Description Building HELB Comp.

MS1-B12 32 nozzle @ Steam Generator Containment N/A MS1-B13 31 Intermediate anchor elbow Containment N/A Main Steam from Steam Generator #21 Break ID No.

Description Building HELB Comp.

MS2-B1 32 nozzle @ Steam Generator Containment N/A MS2-B2 31 Intermediate anchor elbow Containment N/A Main Steam from Steam Generator #22 Break ID No.

Description Building HELB Comp.

MS2-B12 32 nozzle @ Steam Generator Containment N/A MS2-B13 31 Intermediate anchor elbow Containment N/A Feedwater to Steam Generator #11 Break ID No.

Description Building HELB Comp.

FW1-B2 16 Intermediate anchor elbow Containment N/A FW1-B3 16 nozzle @ steam generator Containment N/A 01204043 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-2 HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS INSIDE CONTAINMENT Page 2 of 2 Feedwater to Steam Generator #12 Break ID No.

Description Building HELB Comp.

FW1-B5 16 Intermediate anchor elbow Containment N/A FW1-B6 16 nozzle @ steam generator Containment N/A Feedwater to Steam Generator #21 Break ID No.

Description Building HELB Comp.

FW2-B2 16 Intermediate anchor elbow Containment N/A FW2-B3 16 Nozzle @ steam generator Containment N/A Feedwater to Steam Generator #22 Break ID No.

Description Building HELB Comp.

FW2-B5 16 Intermediate anchor elbow Containment N/A FW2-B6 16 at Aux feedwater nozzle Containment N/A FW2-B7 16 Nozzle @ steam generator Containment N/A 01204043 01222109 01222109 01222109 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-3 BOUNDING HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS AUXILIARY BUILDING COMPARTMENTS A summary of the bounding break and crack locations within the Auxiliary Building and sorted by compartment is as follows. Bounding breaks are selected based on break size and analysis type. The two major analysis types are temperature (T) and flooding (F).

Other analyses may result in different bounding breaks or cracks depending on the SSC being evaluated. Use caution when utilizing this table for analyses other than temperature.

755 Level Comp. A2 Comp. A0 Comp. A1 MS2-B16 (T)

None MS1-B16 (T) 735 Level Comp. B2 Comp. B0 Comp. B1 MS2-B17 (T) 16 FW Pipe (F)

(crack in most adverse location)

None MS1-B17 (T) 16 FW Pipe (F)

(crack in most adverse location)

Comp. X2 Comp. X1 MS2-B5 / MS2-B6 (T) 16 FW Pipe (F)

(crack in most adverse location)

MS1-B5 / MS1-B6 (T) 16 FW Pipe (F)

(crack in most adverse location) 715 Level Comp. C2 Comp. L2 Comp. L1 Comp. C1 31 MS Pipe (T)

(crack in most adverse location)

SB2-B1 / SB2-B2 / SB2-B5 (F)

VC2-B3 (T) (F)

VC1-B3 (T) (F) 31 MS Pipe (T)

(crack in most adverse location)

SB1-B1 / SB1-B2 /

SB1-B6 / SB1-B7 (F)

Comp. D2 Comp. H0 Comp D0 Comp. D1 VC2-B1 SB2-B4 / SB2-B7 VC2-B2 (T) (F) 2 SB Pipe (T) (F)

(crack in most adverse location)

VC1-B1 / VC1-B2 SB1-B3 / SB1-B8 / SB1-B9 Comp. Y2 Comp. Y1 31 MS Pipe (T)

(crack in most adverse location) 31 MS Pipe (T)

(crack in most adverse location) 695 Level Notes:

(1)

AFW piping on the 695 level of the Aux Bldg is encapsulated and will not release energy into the steam exclusion area. Therefore, no adverse crack is listed for this piping.

(2)

Cracks in the most adverse location are shown where the crack bounds all breaks or cracks in the compartment selected using the GL 87-11 criteria or if no other breaks are present.

01204043 01222109 01222109 01222109 01222109 01222109

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Appendix I Revision 31 TABLE I.3.2-4 BOUNDING HIGH ENERGY LINE BREAK (B) AND CRACK (C)

LOCATIONS TURBINE BUILDING COMPARTMENTS A summary of the bounding break and crack locations within the Turbine Building and sorted by compartment is as follows. Bounding breaks are selected based on break size and energy level for peak temperature purposes.

Other analyses may result in different bounding breaks or cracks depending on the SSC being evaluated. Use caution when utilizing this table for analyses other than temperature.

735 Level Comp. 3A1 MS1-B3 / MS1-B14 / MS2-B3 / MS2-B14(1) 6 MS Pipe (T)

(arbitrary break) 715 Level Comp. 2H4 Comp. 2H2 Comp. 2H1 Comp. 2D1 Comp. 2D2 Comp. 2D4 MS2-B15 (T) 8 MS Pipe (arbitrary break)

MS2-B4 MS1-B4 8 MS Pipe (arbitrary break)

MS1-B15 695 Level Comp. 1J1 Comp. 1D1 12 MS Pipe (arbitrary break) 12 MS Pipe (arbitrary break) 679 Level Comp 1J3 Comp 1D3 12 MS Pipe (arbitrary break) 12 MS Pipe (arbitrary break)

Notes:

(1)

These breaks will not be evaluated for HELB effects due to their effect on the Turbine Building roof.

(2)

Arbitrary circumferential breaks are shown where no detailed break selection has been performed or if the arbitrary break bounds breaks selected with the GL 87-11 criteria.

01204043 01222109 01222109 01222109 01222109 01222109

USAR Section APP I Revision 31 Figure I.3.1-1 has been Deleted 01248495

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-2 withheld from public disclosure under 10 CFR 2.390 01521968

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-3 withheld from public disclosure under 10 CFR 2.390 01521968

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-4 withheld from public disclosure under 10 CFR 2.390 01521968

8 D

c B

A 8

7 7

6 Reoctor Building Unit 2 0----

6 5

4 LJLJ.L_jLJ Elev. 126'*-6*

~~,----r--~1 ~~

II

!II Aux. Bldg. 726'-6" Area HO 5

4 3

Reactor Building UnitJ 3

1 Note:

This Simplified Floor Plan Is Only Intended To Identify Those Comportments Utilized In The Building Computer Model ( Cole.

NSPN~9900tH' ) And Does Not Depid All Installed Components.

FIGURE I.3.1-5 REV. 22 D

c B

A

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-6 withheld from public disclosure under 10 CFR 2.390 01521968

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-7 withheld from public disclosure under 10 CFR 2.390 01521968

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-8 withheld from public disclosure under 10 CFR 2.390 01521968

USAR SECTION APPENDIX I Revision 34 Figure I.3.I-9 withheld from public disclosure under 10 CFR 2.390 01521968

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT A

D TURBINE BUILDING COMPARTMENT PLAN-ELEVATION 679'

---

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4 5

Unit I REF. DWGS.

NF-38210-4 NF-38211-2 NF-38215-1, 3, 4, & TO 6

NOTE, THIS SIMI'UFIED FlOOR PLAN IS ONLY INTENDED TO IDENTIFY THOSE COMI'ONfNTS UTIUZlD IN THE MflB ANAlYSIS BUILDJNG MODEL AND DOES NOT OEI'ICT ALL INSTALJ.ED COMPONENTS

• 7 C"J

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!!. -ENCAPSULATION SLEEVE MS1-BX BREAK LOCATION

<ON CONTAINMENT 2

3 MSl-Bl STEAM GENERATOR

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4 MSI-820 STEAM GENERATOR "12 MSl-BlS

<ON VALVE BODYl

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6 MS1-Bl3 5

6 NH--172998-1 MS1-B3 HIGH PRESSURE TURBINE MS1-Bl4 8

RE"MIONS 77 AS9UILT*

UPDATED HELB LOCATJG'IS AHO RE110V£0 SPCIFIC CRACK LOCATIONS.

PER ORR Pi-10*0~!5 OWHo ICJF 3*26*10 Clf('Oo9CS 4*5* 11 1100* 1 EC*l554q APP'D*C~ 4*5-10

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NG-ME-357 ANO 400 "77" MS2-B2 STEAM GENERATOR

1. 22 MS2-B12 4

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'1._ HIGH PRESSURE TURBINE 6

NH-172998-2

2 3

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5 4

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NH-172998-3 CAL.CULAT IONS ENG-ME-357.O.NO 400 III - ANCHOR

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lt.PINGEt.'C:NT BARRIER

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7 8

l.POATEO ME\\.8 LOCATIONS AHO R£M0VED SPECIFtr CRACK LOCATIONS, PR ORA Pl-1&-111*!5 DWN!KJF 3*26*10 CHK'Oo8CS 4*!HB lo()(I*1EC*l554q N'f><O. CHA 4*~Hil A

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1. ZI 2

3 4

5

'77'

'77'

'77' 3

4 5

6

'77'

'77' CALCULATIONS ENG-ME-357 AND 400 G - ANCHOR E;J-IMPINGEMENT BARRIER F"W2-BX BREAK LOCATION NOTE: LEAKAGE CRACKS MUST BE ASSUI-4(0 Al ANY PO I NT.

6 Nl-l-172'l'l8-4 HEATER

1. Z5A

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__.loQ. ETNSI.fl UPOAT£0 HELEI LOCATIONS AND Ft(HOYED SPECIFIC C:RIICI< LOCATIONS.

PEROFIAPI-16-0*5 OWNo IIJI' 3-26-111 em:~ EiltS 4*5*11!1 K00"1EC*i5!i4q APP'O.CMR 4-!i-llil

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CALCULATIONS ENG-ME-357 AND 400 lEGE NO:

G - ANCHOR

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IMPINGEMENT BARRIER VCt-BX BREAK LOCATI ON NOTE: LEAK ACE CRACKS MUST BE ASSUMED AT ANY POINT.

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4 "76" VC1-B2 2

3 4

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1. 11 LETDOWN HEAT EXCHANCER 5

6 NH-172"l"l8-5 6

8 ACOf:O NOTE 10 \\.E(iENO, PEA [lfi:A PI*IIH!I~5 0'11'NrKJF J-2&*10 CHIC'Or BCS

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-.. NONE' 76 NH-172"l"l8-5 MN7~1 -~.QCH IW Q¥fiU!c& <iiI FIGURE 1.3.2*5 REV. 31 A

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CONTAINMENT CALCULATIONS [NC-ME-3S7 AND 400 LEGEND:

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ANCI-IOR ISJ -

IMPINCEt.I£NT BARRI ER VC2-BX -

BREAK lOCAl ION VC2-C1 -

CRACK LOCAl ION NOTE: LEAKAGE CRACKS MUST BE ASSUMED AT ANY PO I NT,

2 3

4 5

6 3

4 5

NH-1 72998 -6 H~H IIA* 6*23*'1"1

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1. 21 LETDOWN MEAT EXCHANGER

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PEROARPI-lliHH!I 0\\INoiCJF J*21H0 CHK'OoBCS 4*!H0 MOO** EC-1!554'1 j:IPP'Ot CHR 4*5 *11!1 CVCS LETDOWN ISOMETRIC

-.. NOHE 18 76 NH-172998-6 NH*l?l'N*6.0Cof1:1W QH@IW CJ! I FlllURE 1.3.2-6 !lEY. 31 A

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A B

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2 CALCULATIONS ENG-ME-35 7 AND 400 LEGEND:

EJ - ANCHOR ISJ -

IMPINGEMENT BARRIER 581-BX BREAK LOCATION NOTE: LEAKAGE CRACI(S MUST BE ASSUt.£0 AT ANY POINT.

581-89 SGB FLASH TANK NO. 11 581-84 3

581-88 2

3 4

5 IS!

EJ 581-82 IS!

IS!

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5 6

NH-172"!"!8-7 FLOW ELEMENT 6

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INPINGEMENT BARRIER c

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S.C.B. HASH TANK R21 3

4 5

6 5

6 NH--172998-8 7

8 l.lf'OAr£0 HEL8 LOCA110HS.

FIE110VEDSPECIFIC CRo\\CK L0CATI<W3 AND ADDED NOTE TO LEGEI<.I.

PERORRPI-liHI45 OWN! II:JF 3*26*18 CI<<'01BCS 4*'5*lli:l I'I()O*, EC*!554q APP-0. CHR 4*!1* 18 STEAM GENERATOR BLOWNOOWN ISOMETRIC

-n NH--172998-8 FlOUR£ 1.3.2*8 REV. 31 A

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AF1-BX c

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(!] -

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2 "77" AF1-B1

'77"~

2 3

SUPPI. Y TO

,_11 TURBINE DRI VEN AUX. FEEDWATER PUioP "77" 4

1. 11

~AIN STEAM SAFETY V"LVE HEADER t.4S1-8S 3

4 5

6 lSI 5

6 NH-172998-9

-TAM Dln:li*2J*qq 8

UPDATED HELB LOCATIONS AND AEHOVEO SPECIFIC:

CAACl( LOCATI!)'IIS, PEAOARPI-!111-~'!i OWNo ICJF 3*26-19 CI<<'OoatS 4*5*11 HOO"oEC*\\554'1 APP'Oo CHR 4*5-111 STEAM SUPPLY TO AUX. FEEDWATER PUMP ISOMETRIC

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PRAIRIE ISLAND NUCLEAR QENERATINC3 PLANT 7

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c D

CALCULATIONS ENG-ME-357 AND 400

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IMPINGEMENT BARRIER AF'2-BX BREAK lOCATION

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UI'O~TEO HEt.B l.OCtHIONS AHtl REMOV£0 SPECIFIC CRACK LOCATI()OS.

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2 CALC ULATIONS ENG-ME-357 AND 40~

LEGEND:

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3 5

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6. -ENCAPSULATION SLEEVE

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2 3

3 4

5 6

NH-172998-12 4

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8 0

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2 3

4 5

3 4

5 6

6 NH-172CJ% -13 8

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4 5

6

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NH-!72qqs-I 4 8

REVISIONS 0

AS 8UILl-

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FIGURE 1.3.2*14 REV.31

3' Tl<<, IHSUI.A TIOH lTYI'1 31' 0. 0. PIPE ENCAPSULATION SLEEVE 31' 0. 0.

3' INSU.A liON 311' 1.0.

TYPICAL IMPINGEMENT BARRIER W8X31 MOlE 6' X 6' X "'

IMPINGEMENT WALL P\\.AIH EICl_......

3' SCH.Y X 4' LG. UlAAINI IMPINGEMENT ELBOW

~ SHlELD VQLL 31' 0.0. PIPE 0.0. PIPE ENCAPSULATION TEE AND RESTRAINTS PLAIN EICl SECTION A-A REVISIONS ENCAPSULATION SLEEVE AND IMPINGEMENT BARRIER

-TAM 8-21-17 CAD FilEt Ull43fll.DON NOTE:

THIS FIGURE IS INTENDED TO ONLY DEPICT TYPICAL INSTALLATI<W DETAILS AND DOES NOT REPRESENT ALL INSTALLED CONFIGURATIONS.

HIGH ENERGY LINE BREAK ENCAPSULATION SLEEVES AND IMPINGEMENT BARRIERS NORTHERN STATES POWO COI#N4Y PRAIRE ISUHO NUCLEM PlANT liED _

FIGURE L4.3-1 REV. 2

r-- --------------- ---i BAR STO THRESHOLD TYPICAL DOOR FRAME CLOSED CELL SPONGE NEOPRENE

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I SECTiON B-B REVISIONS

~ _a *

.. ~~

CLOSED CELL --t--~-fliilr:m FRAME AND BAR STOPS SPONGE NEOPRENE

<OR EOUAU DOOR ADJ. SEAL STOP SAGER *766

<OR EOUAU SECTION A-A HEAD-JAMB DETAIL WEATHER STRIPPING SAGER *38-5

<OR EOUAU MASTIC FILL NOTE:

THIS FIGURE IS INTENDED TO ONLY DEPICT TYPICAL INSTALLATION DETAILS AND DOES NOT REPRESENT ALL INSTALLED CONFIGURATIONS.

SILL DETAIL

~---r----~--------~--~--~~--~--rr~

C><t<<>U PICVKT NO.

AW'II I (11\\1 HIGH ENERGY LINE BREAK DOOR SEALS NORTI£RN STATES POWER CDI'ANY t-"""--..:.;NCINE;:.;;::.. __....._ ______ --1 PRAIRIE ISLAN~

N~~NERATING PLANT FIGURE I *4.3*2 AEV.22

REVISIONS I I I I I I I I I I II o.ao (1.1&.. s.)

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!Combined Thermal Lcq ltudlnal Pressure, Weight *nd OBE J-t--

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0.80 (1.8Sh +Sa) *..ZOO psi I

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