ML18155A455

Updated Safety Analysis Report (USAR) Revision 35, Section 11, Plant Power Conversion System

ML18155A455
Person / Time
Site:	Prairie Island
Issue date:	05/18/2018
From:	Xcel Energy, Northern States Power Company, Minnesota
To:	Office of Nuclear Reactor Regulation
Shared Package
ML18155A439	List: L-PI-18-018, Updated Safety Analysis Report (USAR) Revision 35, Appendix I, Postulated Pipe Failure Analysis Outside of Containment ML18155A440 ML18155A445 ML18155A446 ML18155A447 ML18155A448 ML18155A449 ML18155A450 ML18155A451 ML18155A452 ML18155A453 ML18155A454 ML18155A455 ML18155A456 ML18155A457 ML18155A465 ML18155A466 ML18155A467 ML18166A204 ML18166A205 ML18166A206 ML18166A208 ML18166A209 ML18166A210
References
L-PI-18-018
Download: ML18155A455 (93)

Text

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page i SECTION 11 PLANT POWER CONVERSION SYSTEM TABLE OF CONTENTS Page 11.1

SUMMARY

DESCRIPTION....................................................................11.1-1 11.1.1 Performance Description..........................................................11.1-1 11.1.2 Load Change Capability...........................................................11.1-1 11.1.3 Functional Limits......................................................................11.1-2 11.1.4 Secondary Functions...............................................................11.1-2 11.1.5 Codes and Classifications........................................................11.1-2 11.1.6 Schematic Flow Diagrams........................................................11.1-2 11.1.7 Single Failure Analysis.............................................................11.1-2 11.1.8 Shielding..................................................................................11.1-2 11.2 TURBINE-GENERATOR SYSTEM.........................................................11.2-1 11.2.1 Design Basis............................................................................11.2-1 11.2.2 Description...............................................................................11.2-1 11.2.3 Performance Analysis..............................................................11.2-2 11.3 MAIN CONDENSER SYSTEM................................................................11.3-1 11.3.1 Condenser................................................................................11.3-1 11.3.2 Main Condenser Air Removal System.....................................11.3-2 11.3.3 Condenser Spray System........................................................11.3-2 11.4 STEAM SAFETY, RELIEF AND DUMP SYSTEMS................................11.4-1 11.4.1 Design Basis............................................................................11.4-1 11.4.2 Description...............................................................................11.4-2 11.4.3 Performance Analysis..............................................................11.4-2 11.5 CIRCULATING WATER SYSTEM..........................................................11.5-1 11.5.1 Design Basis............................................................................11.5-1 11.5.2 Description...............................................................................11.5-1 11.5.3 Performance Analysis..............................................................11.5-2

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page ii TABLE OF CONTENTS [Continued]

Page 11.6 COOLING TOWER SYSTEM..................................................................11.6-1 11.6.1 Design Basis............................................................................11.6-1 11.6.2 Description...............................................................................11.6-1 11.7 MAIN STEAM SYSTEM..........................................................................11.7-1 11.7.1 Design Basis............................................................................11.7-1 11.7.2 Description...............................................................................11.7-1 11.7.3 Performance Analysis..............................................................11.7-2 11.7.4 Inspection and Testing.............................................................11.7-3 11.8 CONDENSATE POLISHING SYSTEM...................................................11.8-1 11.8.1 Design Basis............................................................................11.8-1 11.8.2 Description...............................................................................11.8-1 11.8.3 Performance Evaluation...........................................................11.8-3 11.9 CONDENSATE, FEEDWATER AND AUXILIARY FEEDWATER SYSTEMS............................................................................................11.9-1 11.9.1 Design Basis............................................................................11.9-1 11.9.2 Description...............................................................................11.9-3 11.9.3 Performance Analysis..............................................................11.9-9 11.9.4 Inspection and Testing.............................................................11.9-17 11.10 REFERENCES........................................................................................11.10-1

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page iii TABLE OF CONTENTS [Continued]

LIST OF TABLES TABLE 11.1-1 STEAM AND POWER CONVERSION SYSTEM COMPONENT DESIGN PARAMETERS TABLE 11.1-2 STEAM AND POWER CONVERSION SYSTEM CODE REQUIREMENTS TABLE 11.1-3 STEAM AND POWER CONVERSION SYSTEM SINGLE FAILURE ANALYSIS Table 11.9-1 CRITERIA FOR AUXILIARY FEEDWATER SYSTEM DESIGN BASIS CONDITIONS Table 11.9-2

SUMMARY

OF ASSUMPTIONS USED IN AFWS MINIMUM FLOW EVALUATION TABLE 11.9-3

SUMMARY

OF SENSIBLE HEAT SOURCES

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page iv TABLE OF CONTENTS [Continued]

LIST OF FIGURES FIGURE 11.1-1 FLOW DIAGRAM - MAIN, AUXILIARY STEAM AND STEAM DUMP - UNIT 1 FIGURE 11.1-2 FLOW DIAGRAM - MAIN, AUXILIARY STEAM AND STEAM DUMP - UNIT 2 FIGURE 11.1-3 FLOW DIAGRAM - CONDENSATE SYSTEM - UNIT 1 FIGURE 11.1-4 FLOW DIAGRAM - CONDENSATE SYSTEM - UNIT 2 FIGURE 11.1-5 FLOW DIAGRAM - FEEDWATER SYSTEM - UNIT 1 FIGURE 11.1-6 FLOW DIAGRAM - FEEDWATER SYSTEM - UNIT 2 FIGURE 11.1-7 FLOW DIAGRAM - BLEED STEAM AND HEATER VENTS - UNIT 1 FIGURE 11.1-8 FLOW DIAGRAM - BLEED STEAM AND HEATER VENTS - UNIT 2 FIGURE 11.1-9 FLOW DIAGRAM - FEEDWATER HEATER, MOISTURE SEPARATOR AND REHEATER DRAIN SYSTEM - UNIT 1 FIGURE 11.1-10 FLOW DIAGRAM - FEED HEATER, MOISTURE SEPARATOR AND REHEATER DRAIN SYSTEM - UNIT 2 FIGURE 11.1-11 FLOW DIAGRAM - AIR REMOVAL - UNITS 1 & 2 FIGURE 11.1-12 FLOW DIAGRAM - TURBINE BUILDING TRAPS AND DRAINS - UNIT 1 FIGURE 11.1-13 FLOW DIAGRAM - TURBINE BUILDING TRAPS AND DRAINS - UNIT 2 FIGURE 11.1-14 FLOW DIAGRAM - FEEDWATER PUMP INJECTION AND GLAND SEAL PIPING - UNIT 1 FIGURE 11.1-15 FLOW DIAGRAM - FEEDWATER PUMP INJECTION AND GLAND SEAL PIPING - UNIT 2 FIGURE 11.1-16 FLOW DIAGRAM - CIRCULATING WATER - UNITS 1 & 2

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page v TABLE OF CONTENTS [Continued]

LIST OF FIGURES [Continued]

FIGURE 11.1-17 FLOW DIAGRAM - EXTERNAL CIRCULATING WATER FIGURE 11.1-18 PLOT PLAN FIGURE 11.1-19 FLOW DIAGRAM - CONDENSATE POLISHING - UNITS 1 & 2 FIGURE 11.1-20 FLOW DIAGRAM - CONDENSATE FILTER DEMINERALIZER -

UNIT 1 FIGURE 11.2-1 DELETED FIGURE 11.2-2 EXISTING HP TURBINE, MUR UPGRADE, VWO FIGURE 11.2-3 DELETED FIGURE 11.2-4 EXISTING HP TURBINE, MUR UPGRADE, 50% LOAD FIGURE 11.2-5 UNIT 1 - TURBINE GENERATOR HEAT BALANCE - 100%

POWER - VALVES WIDE OPEN AT 1.60 IN HGA CONDENSER VACUUM FIGURE 11.2-6 UNIT 1 - TURBINE GENERATOR HEAT BALANCE - MAXIMUM STEAM FLOW WITH VALVES WIDE OPEN AT 1.60 IN HGA CONDENSER VACUUM FIGURE 11.2-7 PRAIRIE ISLAND UNIT 1 HBD-MUR FIGURE 11.2-8 EXISTING HP TURBINE, MUR UPGRADE, 1684 MWt FIGURE 11.9-1 AUXILIARY FEEDWATER PUMP CHARACTERISTIC CURVES FIGURE 11.9-2 DELETED FIGURE 11.9-3 DELETED FIGURE 11.9-4A DECAY HEAT CURVE - 1 TO 1000 SECONDS FIGURE 11.9-4B DECAY HEAT CURVE - GREATER THAN 1000 SECONDS

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 35 Page vi THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 27 Page 11.1-1 SECTION 11 POWER PLANT CONVERSION SYSTEM 11.1

SUMMARY

DESCRIPTION The Steam and Power Conversion Systems of Units 1 and 2 are identical except as noted.

11.1.1 Performance Description The steam and power conversion system consists of a closed, regenerative cycle in which steam from the main turbine is condensed and returned to the steam generators as heated feedwater.

The turbine-generator system consists of components of conventional design, designed for use in large central power stations. The equipment is arranged to provide high thermal efficiency with no sacrifice in safety. The component design parameters are given in Table 11.1-1.

The Main Steam and Feedwater Systems are designed to remove heat from the reactor coolant in the two steam generators, producing steam for use in the turbine-generator.

The Main Steam System can receive and dispose of the total heat existent or produced in the Reactor Coolant System following a turbine-generator trip at full load.

Two auxiliary feedwater pumps, one turbine-driven and one electric-driven are provided for each unit to ensure that adequate feedwater is supplied to the steam generators for heat removal under all circumstances, including loss of power and normal heat sink.

Feedwater flow can be maintained until power is restored or reactor decay heat removal can be accomplished by other systems. The Auxiliary Feedwater System is designed as a Class I system, and is described in Section 11.9.

11.1.2 Load Change Capability The plant can accommodate step load changes of 10% or ramp load changes of 5% per minute without reactor trip as described in USAR Sections 4 and 7. The Reactor Coolant System will accept a complete loss of load from full power with reactor trip. In addition, both units are designed to accept a step decrease of 40.0% of nominal full load with the combined operation of the Reactor Rod Control System and the Steam Dump System.

04--024

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 27 Page 11.1-2 11.1.3 Functional Limits The system incorporates backup means (power operated relief valves and code safety valves) for heat removal under any loss of normal heat sink (i.e., main-steam stop valves trip, condenser isolation, loss of circulating water flow) to accommodate reactor shutdown heat rejection requirements.

11.1.4 Secondary Functions The Steam and Power Conversion System also provides steam for driving the turbine-driven auxiliary feedwater pump and for turbine gland steam, reheater steam, condenser and water box steam-jet air ejectors, hogging ejectors, waste evaporator, boric acid evaporator packages and building heating.

11.1.5 Codes and Classifications The pressure boundary components comply with the codes given in Table 11.1-2.

11.1.6 Schematic Flow Diagrams The Main, Auxiliary Steam and Steam Dump, Condensate, Feedwater, Bleed Steam and Heater Vents, Feedwater Heater, Moisture Separator and Reheater Drains, Air Removal, Turbine Building Traps and Drains, Feedwater Pump Injection and Gland Seal Piping, Circulating Water, and Condensate Polishing Flow Diagrams are given in Figures 11.1-1 through 11.1-20, respectively.

11.1.7 Single Failure Analysis A single failure analysis has been made for all active components of the system which have an emergency function. The analysis, which is presented in Table 11.1-3, shows that the failure or malfunction of any single active component will not reduce the capability of the system to perform its emergency function.

11.1.8 Shielding No radiation shielding is required for the components of the Steam and Power Conversion System. Continuous access to the components of this system is possible during normal conditions, except for the components located inside the containment.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-1 11.2 TURBINE-GENERATOR SYSTEM 11.2.1 Design Basis The turbine is designed to produce a maximum calculated gross rating of 591,988 KW when operating with inlet steam conditions of 702 psia and 503.4F, exhausting at 1.6 in. Hg absolute, zero percent makeup, and with five stages of feedwater heating in service. The expected throttle flow at 591,988 KW is 7,370,720 lb/hr of steam. See Figures 11.2-1 through 11.2-5 for various turbine/condenser/reheat heat balance gross loads.

The Unit 1 hydrogen inner-cooled generator is designed to produce rated 659,000 KVA at 1800 RPM and 60 psig hydrogen gas pressure. The Unit 2 hydrogen inner-cooled generator is designed to produce rated 730,000 KVA at 1800 RPM and 60 psig hydrogen gas pressure.

11.2.2 Description The turbine is a three-element, tandem-compound, four-flow exhaust, 1800 rpm unit that has moisture separation and reheating between the HP and LP elements. The a-c generator and rotating rectifier exciter are direct-connected to the turbine shaft. The turbine consists of one double-flow HP element in tandem with two double-flow LP elements. Four combination moisture-separator reheater assemblies are located alongside the turbine.

The turbine oil system is of a conventional design. It consists of three parts: a) a high pressure oil system, b) a lubrication system, and c) an Electro-Hydraulic (E/H) control system. The E/H control system is completely separate from the other two parts. Lube oil is also used to seal the generator glands to prevent hydrogen leakage from the machine. The fluid used for E/H control system is a fire resistant synthetic oil. The maximum available steam temperature is not capable of initiating a fire in the E/H oil system.

The turbine oil system supplies all of the oil required for the emergency trip and lubrication system during normal operation. A turbine lube oil purification and filtration system purifies the lube oil for the turbine.

A gland steam condenser maintains a pressure slightly below atmospheric in the Turbine Gland Leakoff System. Sealing steam and air leakage along the shaft at each turbine gland is fed to this condenser, thus preventing any leakage of steam into the turbine room. Two motor-driven exhausters are mounted on the gland condenser to remove noncondensable gases, as shown in Figure 11.1-11.

The turbine has low speed, motor-driven spindle turning gear equipment which is side mounted on the outboard bearing of the low-pressure turbine nearest the generator.

01435983

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-2 11.2.3 Performance Analysis 11.2.3.1 Turbine Controls High-pressure steam enters the turbine through two turbine stop valves and four governing valves. One turbine main steam stop and two main steam governing valves form a single assembly which is anchored above the turbine room floor line. An electro-hydraulic (E-H) actuator controls each turbine stop valve so that it is either in the wide-open or closed position. One of the control signals for this actuator comes from the mechanical-hydraulic overspeed trip portion of the Electro-Hydraulic Control System. The safety function of these turbine stop valves is to shut off the flow of steam to the turbine in the event the unit overspeeds beyond the setting of the overspeed trip.

These valves are also tripped when the other protective devices function. The main steam governing valves are positioned by an electrical signal from the main governor portion of the Electro-Hydraulic Control System.

Additionally, there are Reheat Steam Stop Valves (at the outlet of each reheater) and reheat steam intercept valves (in each reheat steam line just ahead of the low pressure turbine inlet). These reheat stop and intercept valves limit the reheated steam flow available to the low pressure turbine.

The Electro-Hydraulic Turbine Control System combines triple modular redundant controller with a high-pressure fire-resistant fluid supply system which is independent of the lubricating oil. The design features and response characteristics of the E-H control system increase the reliability and availability of the power plant.

The Electro-Hydraulic Control System includes the following features:

a.

Governor valve controller

b.

Load limit controller

c.

Overspeed Protection Controller

d.

Load Controller

e.

Operators touch screens on the control room control panel

f.

High-pressure hydraulic fluid pumping unit

g.

Turbine protective devices, including function limit trips, automatic load reference runback upon receipt of the OTT and OPT signal, and extraction line non-return valves closing signal.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-3 In the steam admission system, each steam path has two valves in series which are controlled by the high pressure E-H oil system. Loss of hydraulic fluid pressure or power supply causes closure of the steam valves.

The auto-stop oil is dumped to drain, directly and indirectly via the interface valve, when any one of the protective trip devices is actuated. Independent reactor trip signals will actuate the EH controller trip logic to dump ET, OPC, and auto-stop oil to drain.

Automatic turbine load reference runback is initiated as described in Section 7.2.

11.2.3.2 Turbine Overspeed Control Turbine overspeed, upon loss of electrical load, is prevented by the rapid cut-off of steam admission to the high pressure turbine, and to the low pressure turbine. Main steam admission to the high pressure turbine is controlled by a series array of main steam stop and governor valves; and reheat steam admission to the low pressure turbine is controlled by a series array of reheat steam stop and reheat steam intercept valves. All these valves are held open against strong spring pressure by high-pressure hydraulic fluid.

Should loss of electrical load occur, the turbine will tend to accelerate, and the E-H control automatically switches from load follow to speed follow and calls for the maintaining of a turbine synchronous speed of 1800 rpm such that the main E-H governor calls for modulated closing of the main steam governor valves.

(Should the loss of load be from maximum calculated load to zero load, the E-H overspeed protection controller alone limits turbine speed to a maximum of 108% of synchronous speed.)

Overspeed control is accomplished by trip-valve release of hydraulic fluid pressure.

Redundant shaft-speed sensors and trip-valving systems assure a highly reliable prevention of turbine overspeed and prevention of resultant turbine missiles.

The Electro-Hydraulic Control System contains turbine shaft speed probes. At 103% of rated shaft speed the E-H controller releases actuating hydraulic fluid pressure to close the main steam governor and the reheat steam intercept valves, which cut off both high pressure and low pressure turbine steam admission.

(Should this trip be from maximum calculated load to zero load, the 103% E-H overspeed trip function alone limits the turbine speed to a maximum of 111% of synchronous speed.)

In addition to the two protective functions already described, the turbines are provided with three emergency overspeed trip functions which are activated at less than 111% of rated shaft speed.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-4 The first of these emergency overspeed trip functions is the conventional back-up control consisting of an overspeed trip valve and mechanical overspeed mechanism which consists of a spring-loaded eccentric weight mounted in the end of the turbine shaft. At 110% of rated speed, centrifugal force moves the weight outward to mechanically actuate the overspeed trip valve which dumps auto-stop oil pressure and in turn releases the actuating hydraulic fluid pressure to close the main steam stop valves, the main steam governor valves, the reheat steam stop valves, and the reheat steam intercept valves. The supply steam pressure and the spring force act to hold the stop valves closed.

Upon loss of the actuating hydraulic fluid pressure, an air pilot valve closes the extraction non-return valves to heaters No. 14 and 15. Baffles in feedwater heaters No. 11, 12, and 13 minimize flashback of water in these heaters.

The secondary emergency overspeed control is provided by the Electro-Hydraulic Control system if the turbine speed exceeds 108% of rated speed by 10 rpm. At this point ET, OPC, and AST solenoids are actuated to dump the auto-stop oil which in turn dumps the actuating hydraulic fluid pressure to ensure closing of the main steam stop valves, the main steam governor valves, the reheat steam stop valves and the reheat steam intercept valves.

The third emergency overspeed control is provided by the Electro-Hydraulic Control system if the turbine speed exceeds 109% of rated speed. At this point the independent Protech system actuates the ET and OPC solenoids to dump ET oil header pressure, thereby depressurizing the AST header via the interface valve which in turn dumps the actuating hydraulic fluid pressure to ensure closing of the main steam stop valves, the main steam governor valves, the reheat steam stop valves and the reheat steam intercept valves. The Protech also provides trip input to the main EH controller to actuate the ET, OPC, and AST solenoids.

The reheat steam stop valves and reheat steam intercept valves stop the steam flow to the low pressure turbine, such that assuming a single failure of one reheat steam intercept valve, the 111% overspeed trip point limits turbine shaft speed to less than the 120% of synchronous speed which was used as a design basis for the turbine-generator.

Thus a 100% maximum calculated load rejection (with no in-plant load) cannot result in destructively excess overspeed.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-5 The overspeed trip function is tested periodically. The turbine valves function to control and protect the main turbine. They must be capable of moving freely in response to control and protection signals. In an effort to develop a reasonable basis for frequency of turbine valve testing, a probabilistic study of turbine valve failure mechanisms was undertaken by the Westinghouse Owners Group. This work was reported in WCAP-11525: Probabilistic Evaluation of Reduction in Turbine Valve Test Frequency (Reference 7). This study concluded that the Prairie Island turbine valves could be tested at a reduced frequency not exceeding one year while not exceeding NRC guidance for acceptable turbine missile ejection probability. A change to the Prairie Island Technical Specifications allowing the interval between turbine valve tests to be up to, but not exceeding one year, was approved by NRC SER dated February 7, 1989.

(Reference 8). IT.S. has subsequently relocated these requirements to the TRM.

In accordance with the program plan for tracking turbine valve failure rates, the Westinghouse Owners Group performed evaluations and updates of turbine stop and control valve failure rates. The evaluation is an ongoing process and the most recent study results set the requirements for turbine valve testing.

The turbine valve failure rates through January 1998 were reevaluated in March 1999 (reference 13) in accordance with the program plan established in WCAP 11525. This reevaluation resulted in conservative missile ejection probabilities relative to previous studies. WCAP-16054 was commissioned to re-check WCAP-11525. WCAP 16054 confirmed WCAP-11525 with the inclusion of recent valve failure data and increasing the valve exercise surveillance interval to 6 months. The total probability continues to be maintained at less than 1x10-5.

11.2.3.3 Variables Limit Functions Trips, automatic control actions and alarms will be initiated by deviations of system variables within the Steam and Power Conversion System. The more significant malfunctions or faults which cause trips, or automatic actions in the Steam and Power Conversion System are listed below.

Turbine Trips

a.

Generator electrical faults

b.

Low condenser vacuum

c.

Thrust bearing failure

d.

Low turbine bearing lubricating oil pressure

e.

Turbine overspeed

f.

Reactor trip

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.2-6

g.

Manual trip

h.

Loss of both main feedwater pumps

i.

Loss of E/H system internal power

j.

Low auto-stop oil pressure

k.

Steam generator High-High level.

l.

MSIV closure initiated turbine trip

m.

AMSAC actuation

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 23 Page 11.3-1 11.3 MAIN CONDENSER SYSTEM 11.3.1 Condenser The condenser is the double-flow, dual-pressure, single-pass vertically divided surface type with fabricated steel water boxes at both ends. The hotwell has sufficient storage for three minutes operation at maximum throttle flow with an equal free volume for surge protection.

There are two air coolers built integral with each condenser shell, located in the center of each tube bundle, extending from face to face of the tube sheets. The coolers are subdivided by the main support plates.

The direct steam flow type tube bundle in each shell is arranged so that steam will enter at the top, outboard and inboard sides, and bottom where it flows through the tubes until reaches a common area at the center of the tube nest before entering the air coolers.

The arrangement of the tubes in the tube bundle allows the steam to effectively feed to all the tubes. This tube arrangement creates decreasing cross-sectional area, and as the volume of steam is decreased by being condensed as it penetrates the depth of the tube bank, a brisk velocity is maintained at all times, assuring maximum condensation at maximum efficiency.

In its passage through the tube bundle most of the steam is condensed and when the flow reaches the air cooler there remains only a mixture of air, non-condensible vapor and water vapor.

The air and non-condensible vapors are cascaded from the outlet end to the inlet end of each condenser. This is accomplished by having each section of the condenser arranged so that the air and non-condensible vapors from preceding sections will be forced to pass over cooler tubes in every section of each condenser.

In passing through the air coolers, the air and non-condensible vapors are cooled and a large part of the water vapor is condensed. This reduces the partial vapor pressure of the mixture which is analogous to shrinking what was originally a large volume of rarefied air into a small volume of dense air. In this state it is drawn into the air removal equipment where it is compressed to atmospheric pressure with a minimum expenditure of energy.

Each condenser is divided into two sections by means of separate water boxes. This construction for practical purposes may be considered as two condensers placed side by side, having a common steam inlet and condensate outlet, but with separate air-vapor outlets. This construction also makes it possible to open the water boxes on one section of the condenser to clean and inspect the tubes while there is vacuum on the condenser and the turbine is operating.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 23 Page 11.3-2 11.3.2 Main Condenser Air Removal System The steam-jet air ejector maintains a vacuum in the condenser. This ejector has three first-stage elements and three second-stage elements mounted on the shells of the intermediate and after-condensers. Only two of the three stages are required during normal operation. During startup, a separate hogging ejector is used to evacuate the condenser. The ejectors are supplied with steam from the main steam line, as shown in Figures 11.1-1,-2,-11, or from the plant heating boiler. They are used in parallel with the second stage of the steam jet air ejectors which are also started at the same time. After a vacuum of 20 to 25 Hg. has been established, the first stage jets of the air ejector are started automatically. Operation of the first and second stages of the air ejector will lower the turbine condenser steam space to its operating vacuum. The hogging ejectors are removed from service by closing, first, the suction valves, and second, closing their steam supply valves.

The discharge of the hogging ejectors is not monitored for radioactivity because this parameter can be measured by the radiation monitor in the discharge of the normal steam jet air ejector which discharges to the Auxiliary Building Ventilation System.

11.3.3 Condenser Spray System The condenser spray system, as shown in Figures 11.1-3, -4, consists of a pump, filters, strainers, and spray nozzles. The system is designed to eliminate stratification which causes vacuum problems during unit startup. When steam dump and other steam sources enter the condenser, the steam in the process of going to a low pressure condition goes to a superheated condition. Since the superheated steam has a higher specific volume the steam rises to the top of the condenser. To prevent this steam from reaching the top of the condenser, the condenser spray system blankets the condenser with a water spray below the feed water heater level.

Hydrazine is injected into the condenser spray system to start the O2 scavenging sooner in the condensate and feed water cycle. This will help reduce the dissolved O2 in the condensate pump suction. In this way the quantity of iron oxides produced in the condenser and carried to the steam generators is reduced.01-003

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 Page 11.4-1 11.4 STEAM SAFETY, RELIEF AND DUMP SYSTEMS 11.4.1 Design Basis If the condenser heat sink is not available during a turbine trip, excess steam generated as a result of Reactor Coolant System sensible heat and core decay heat is discharged to the atmosphere.

There are five 6-in. by 10-in. code safety valves located on each of the two 30-in. main steam lines outside the reactor containment and upstream of the main steam isolation and non-return valves. Discharge from these safety valves is carried to the atmosphere through individual vents. The total relieving capacity of all 10 valves is 7,745,470 lb/hr at 1194 psig. The five safety valves on each main steam line are set to relieve at 1077, 1093, 1110, 1120, and 1131 psig. The main steam safety valve Technical Specification originally required lift setpoints to be within + 1% of the specified setpoint. The Specification was difficult to meet when test instrument error and repeatability were considered. A License Amendment Request justified increasing the as-found setpoint tolerance to + 3%, provided the setpoint was returned to + 1% following testing.

License Amendments 123 and 116 approving the request were issued May 21, 1996.

In addition, one 5-in. power-operated relief valve is provided in each main steam line which is capable of releasing the sensible and core decay heat to the atmosphere.

These valves are automatically controlled by pressure or may be manually operated from the main control board and have a total capability of ten per cent of the maximum calculated steam flow (405,000 lb/hr each at 1100 psia). Discharge from each power relief valve is carried to the atmosphere through an individual vent stack. In addition, the power-operated relief valves may be used to release the steam generated during reactor physics testing, operator license training, plant cooldown, and Mode 2, Startup, if the condenser is not available. Two steam dump systems, the condenser steam dump system and the atmospheric steam dump system, are available to remove energy for the steam generators downstream of the mainsteam isolation and non-return valves. The condenser steam dump system taps off one main steam line (downstream of the 20 bypass/equalizing line connecting the two lines) with a 16 then to 12 line.

From the 12-in. line two valves are installed in parallel (one 8-in. and one 4-in.). These valves discharge through a 16-in. pipe into the condenser through a perforated diffuser.

The 8-in. valve has a capacity of 590,000 lb/hr, at an inlet pressure of 722 psia. The 4-in. valve has a capacity of 200,000 lb/hr. However, the 4-inch valve receives no automatic control signals and can only be operated by manipulating it locally, intended to be used only if the 8-inch valve is out of service (i.e., unavailable for cooldown).

Therefore, the effective capacity is only that of the 8-inch valve, at least 7.0% of full load steam flow.

01183316 01183316

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 Page 11.4-2 The atmospheric dump system provides two atmospheric dump valves on each steam generator main steam line. Each 8-in. valve is capable of dumping 590,000 lb/hr at an inlet pressure of 721 psia. Total capacity of all four atmospheric dump valves is at least 28.6% of full load steam flow. Two valves were installed to limit the maximum steam flow from one valve stuck open to 890,000 lb/hr at 1100 psia. A potential hazard in the form of an uncontrolled plant cooldown is thus eliminated. Manual isolation valves are provided at each control valve.

11.4.2 Description The relief, safety and steam dump system is shown in Figures 11.1-1 and 11.1-2.

The atmospheric dump valves and the condenser dump valve are controlled by a servoloop. Either a Tavg error signal or a main steam pressure error signal may be selected as the loop error signal. The Tavg error signal is used for normal at power operation. Under this condition, the loop provides the capability for rejecting a minimum 40.0% of nominal full load without reactor trip.

During a normal orderly shutdown of the turbine generator leading to plant cooldown, the operator may select pressure control for more accurate maintenance of no-load conditions using the steam dump valves to release steam generated by the residual heat. Plant cooldown, programmed to minimize thermal transients and based on residual heat release, is effected by a gradual manual adjustment of this pressure setpoint or by controlling the valve position in Manual until the cooldown process is completed or transferred to the Residual Heat Removal System.

During start-up, Mode 2, Startup, or physics testing, the steam dump valves are remotely controlled from the main control board.

The automatic condenser steam dump valve is prevented from opening on loss of condenser vacuum; it is also blocked on trip of both circulating water pumps that supply water to the Unit.

11.4.3 Performance Analysis The condenser and atmospheric Steam Dump System has been included to increase the transient capability of the plant to provide a means for an orderly reactor power reduction in the event the load is suddenly decreased. The time for a return to full power operation is therefore minimized. The minimum dump capacity is equal to 35.6%

of full load steam flow. Dump is initiated by a large rapid load change. Steam Dump Control is described in section 7.2.2.3.

Table 4.1-8 lists the number of these type transients expected during the plant lifetime.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 Page 11.4-3 If the condenser heat sink is not available during a turbine trip, excess steam, generated as a result of Reactor Coolant System sensible and core decay heat, is discharged to the atmosphere.

The amount of steam that will be dumped to atmosphere during load reduction is as follows:

Load Reduction of 10%

no steam released Load Reduction of 20%

no steam released Load Reduction of 30%

7000 lbs.

Load Reduction of 40%

30,000 lbs.

Load Reduction of 50%

75,000 lbs.

Based on a 50% load loss and the subsequent release of 75,000 lbs. of steam, the total radioactivity release to atmosphere would be 1.4 curies of I-131 equivalent. Using the yearly average X/Q, the site boundary thyroid inhalation dose associated with this release would be less than 0.5 mrem. This value additionally assumes that the secondary system radioactivity level is at 0.1 Ci/gm and only 10% of the activity contained in the steam generator secondary side is available for dispersion to atmosphere. The analysis neglected any plate-out or condensation effects on the release plume.

The requirement for monitoring the secondary coolant water chemistry is specified in the PINGP Chemistry Procedures.

If the control valves should fail to dump steam, the result is a loss-of-load transient. If they operate to dump steam inadvertently, the result would be a load increase equivalent to a small steam break. In either case, the Reactor Control and Protection System precludes unsafe operation. These protection systems are provided to trip the reactor in the event of a sustained load mismatch between the reactor and turbine.

Continuous radioactive monitoring of the secondary loops of the steam generators is provided by the Steam Generator Blowdown System Liquid Sample Monitor and the Condenser Air Ejector Gas Monitor as discussed in Sections 7.5.2.13 and 7.5.2.6.

Once there is an indication of tube leakage in a steam generator, the affected units steam generators will be sampled and actual release documentation will be based on the known isotopic inventory and ODCM requirements. Isotopic analyses will quantify activity of the individual nuclides and total nuclide activity. Partitioning Factors will be applied to the steam generator bulk water particulate and iodine concentrations, to adjust activity results for a steam release, based on the differences in the volatility of individual isotopes. Radiation monitors will provide confirmation that no change in the system activity has taken place during the release.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 Page 11.4-4 Normal turbine overspeed protection and the steam generator safety valves provide protection for these systems completely independent of any steam dump valve operation.

In the event of failure of one feedwater pump, the feedwater pump remaining in service will carry approximately 65% of full load feedwater flow. If both main feedwater pumps fail, the turbine and the reactor will be tripped, and the auxiliary feedwater pumps start automatically.

Pressure relief is required at the system design pressure of 1085 psig. The first safety valve is set to relieve at 1077 psig. Additional safety valves are set at pressures up to 1131 psig, as allowed by the ASME Code. In addition to the safety valves, one power-operated relief valve is installed for each steam generator which can be manually operated from the control room. The power-operated relief valves are set to open at a pressure slightly below that of the main steam safety valves.

The original Westinghouse sizing criteria for the code safety valves was a flow rate equal to the original maximum calculated steam generation rate.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 23 Page 11.5-1 11.5 CIRCULATING WATER SYSTEM 11.5.1 Design Basis The circulating water system provides the heat sink for the generating plant. Excess heat from the steam leaving the turbine is transferred to circulating water flowing through the condenser tubes. Based on seasonal limitations heat is transferred to the environment either by the use of the cooling towers, discharge to the river, or a combination of cooling towers and river discharge. Operating restrictions are governed by National Pollutant Discharge Elimination System (NPDES).

During startup and shutdown of the steam plant, the Circulating Water System removes the heat of steam dumped to the condenser at low power.

The Circulating Water System is designed to supply 294,000 gpm to each Unit in normal operation. Each Unit has two condenser circulating water pumps, each rated at 147,000 gpm at a TDH of 45 ft. The system is designed for condenser heat rejection of 3.88 x 109 BTU/hr from each Unit with a temperature rise across the condensers of 27F. Total plant heat rejection by the Circulating Water System is 8.09 x 109 BTU/hr.

The Circulating Water System also supplies the water for the Cooling Water System and Fire Protection System. Water flows from the Intake Bay into the Plant Screenhouse. The Cooling Water pumps draw water from the screenhouse, pump it through the system and discharge to the warm circulating water leaving the condensers.

Thus, the Circulating Water System indirectly cools the plant auxiliary equipment. The Intake Bay is required to remain intact during and after a design basis seismic event.

The Intake Bay is classified as a Class I* structure. Refer to Section 12.2 for more discussion on classification of structures and components. Refer to Section 10.4 for more discussion on the cooling water system response to a seismic event.

The circulating water system flow diagrams are shown in Figures 11.1-16 and 17. The general plan of the system external to the plant is shown in Figure 11.1-18.

11.5.2 Description Circulating water for the generating plant is taken from the Mississippi River and directed to the plant site by the intake canal. The quantity of river water which may be appropriated for use in the Circulating Water System is specified in Water Appropriations Permit #69-072 (issued by the Minnesota Department of Natural Resources).01-009 01-009 01-015

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 23 Page 11.5-2 Circulating water flows through the intake screenhouse to the intake canal and into the Screenhouse. Trash racks and traveling water screens located in the intake screenhouse collect fish, fish larvae and debris from the intake stream and return these organisms to the river to prevent them from entering plant systems.

Two circulating water pumps for each unit individually pump circulating water through one side of each condenser for the associated unit. As the circulating water passes through the condenser tubes, it absorbs the heat of vaporization from the low pressure turbine exhaust system.

The heated circulating water leaving the condenser is directed to the discharge basin through 102-in. concrete piping. From the discharge basin the water is directed to the river or to the cooling towers (see Section 11.6). From the cooling tower, the water flows through the cooling tower return canal to the distribution basin.

A recycle canal is provided to recycle circulating water from the distribution basin back to the intake canal. Recycle control gates between the distribution basin and the recycle canal control the recycle flow rate. Guide walls and submerged mixing blocks are located in the intake canal to mix the warm recycle and cool river water to prevent large temperature differences between the four circulating water pumps. Water returned to the river is dispersed through pipes into the main body.

The exterior circulating water system is operated to NPDES Permit MN0004006.

11.5.3 Performance Analysis The design of the circulating water system allows for a variety of operating conditions that are governed by power levels and NPDES Permit requirements. In the open cycle mode the cooling towers are not used and the system acts as a once through design.

In the closed cycle mode the cooling towers are in operation and there is limited return flow to the river. Depending on cooling requirements the system may be operated with cooling towers on line in addition to substantial blowdown to the river.

System discharge to the river, blowdown, is measured in cubic feet per second (CFS) and is restricted by environmental impact considerations. The system can be operated with complete reliance on the cooling towers and a nominal (150 cfs) blowdown, as a once through system with maximum allowed blowdown, or at any desired blowdown rate in between in order to meet environmental impact based restrictions. Operations that exceed NPDES permit limits are reported to the appropriate state officials in accordance with the NPDES permit.

Limitations are placed on the discharge flow rates by the NPDES permit April through June.

During other periods of the year the intake flow rate may vary to provide maximum plant efficiency provided the thermal criteria of the NPDES permit are not exceeded.01-015 01-015

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 0 Page 11.6-1 11.6 COOLING TOWER SYSTEM 11.6.1 Design Basis The cooling tower system is designed to dissipate to the atmosphere the heat rejected to the cooling water system and the entire circulating water flow passing through the condensers.

11.6.2 Description The cooling tower system is comprised of four towers, fans, water distribution headers and basins as shown in Figure 11.1-17. Each tower has one cooling tower pump. Each tower is made up of 12 cells grouped together (a bank).

The cooling tower pumps intake water from the discharge basin and discharge into individual distribution pipes to the top of the cooling towers. The pumps are vertical, dry pit pumps mounted so that the casing will be flooded with the water in the discharge basin at normal level. The pump motors are mounted on, and supported by, the pump.

The intakes to the pumps are submerged to prevent the intake of air from any cause.

Spray nozzles at the top of the cooling towers break-up the water stream into small streams which drop by gravity through a maze of fill to a basin at the base of the towers. Fans draw air up through the streams of water and the heat of the water is carried into the atmosphere by the airstream. From the cold water basin at the bottom of the towers, the water flows through the cooling tower return canal to the distribution basin.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 33 Page 11.7-1 11.7 MAIN STEAM SYSTEM 11.7.1 Design Basis The Main Steam System is designed to remove heat from the reactor coolant in the two steam generators, producing steam for use in the turbine generator. The system can receive and dispose of the total heat existent or produced in the Reactor Coolant System following a turbine generator trip at full load.

The steam and feedwater lines from the steam generators to their respective isolation valves are Class I. A failure either of the main steam or feedwater lines, or malfunction of a valve installed therein, will not impair the reliability of the Auxiliary Feedwater System, render inoperative any engineered safety feature, initiate a loss-of-coolant condition, or cause failure of any other steam or feedwater line.

11.7.2 Description Steam from each of the two steam generators supplies the turbine, where the steam expands through the double-flow, high-pressure turbine, and then flows through moisture separator reheaters to two, double-flow, low-pressure turbines, all in tandem.

Five stages of extraction are provided, two from the high-pressure turbine (one of which is the exhaust) and three stages from the low-pressure turbines. The feedwater heaters for the lowest three stages are located in the condenser neck. All feedwater heaters are horizontal, halfsize units (two strings), including those for the lowest two extraction stage points, which are of the duplex type. The feedwater string is the closed type with deaeration accomplished in the condenser.

The four reheaters drain to the No. 5 high-pressure heaters. The No. 5 heaters drain to the No. 4 feedwater heaters. The No. 4 heaters and the moisture separators drain to the heater drain tank. The heater drain pumps take suction from the drain tank and discharge to the feedwater pump suction. Drains from the three lower pressure heaters cascade to the condenser.

The Main Steam System conducts steam in a 30-in. pipe from each of the two steam generators within the reactor containment through a swing-disc type isolation valve and a swing-disc type non-return valve to the turbine stop and control valves. The isolation and non-return valves are located outside of the containment. The two lines are cross-connected by a 20-in. equalizing line downstream of the isolation valves. The design pressure of the system is 1085 psig at 600F. A steam flow nozzle is provided in the line from each steam generator upstream of the isolation and non-return valves, to meter steam flow from each steam generator and to limit the rate of steam release in the event of a main steam line break. Steam flow signals are used by the Automatic Feedwater Flow Control System as discussed in Section 7.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 33 Page 11.7-2 The steam for the turbine-driven auxiliary feedwater pump is obtained from both main steam lines, upstream of the main steam isolation valves, as shown in Figures 11.1-1 and 11.1-2.

Main steam for the turbine gland steam supply control valve, the air ejectors, the reheater section of the four moisture separator reheaters, and the priming ejector, is obtained from branches on the main steam lines ahead of the turbine stop valves.

Steam from five extraction points in the turbine casings is piped to the shells of the two parallel strings of feedwater heaters. The first point of extraction originates at the high-pressure turbine casing and supplies steam to the shell of the No. 5 high-pressure feedwater heater. The second point of extraction originates in the high-pressure turbine exhaust piping ahead of the moisture separators, and supplies steam to the No.

4 low-pressure feedwater heater. The third, fourth, and fifth point extractions all originate at the low-pressure turbine casings and supply steam to the No. 3, No. 2, and No. 1 low-pressure feedwater heaters, respectively, as shown in Figures 11.1-7 and 11.1-8.

To prevent turbine overspeed from backflow of flashed condensate from the heaters after a turbine trip, non-return valves are provided in the extraction lines to heaters No. 4 and 5. The non-return valves are air-cylinder operated valves which are closed automatically upon a signal from the turbine trip circuit and on high level in the feedwater heater.

11.7.3 Performance Analysis The main steam line isolation and check valve assemblies have been modified by changing valve disc material to 410 stainless steel and by adding a rupture disc assembly to the isolation valve air-cylinder actuator. An extensive design analysis has shown that disc, linkage and valve body will perform as required for the entire range of valve closure incidents.

In both the check and the isolation valve, the disc has been designed to withstand the maximum energy impact from closure. Separate valve models were made for the analysis of isolation valve and check valve. In order to determine the flow parameters of the fluid passing through the valve, a blowdown computer program was used. The relevant equations required to determine the angular acceleration, angular velocity and angular position of the valve disc are incorporated into the program. Valve flow coefficients were employed to calculate the frictional pressure drop across the valve at the various angular positions of the disc. Using appropriately conservative conditions, the highest closure energy calculated was 1.252 x 106 in.-lb.

However, an additional margin was arbitrarily added to the closure energy (raising it to 1.35 x 106 in.lb.) for design.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 33 Page 11.7-3 Details of the closure energy analysis are presented in a topical report PI0- 02-03 (Reference 15) titled: Analysis Report - Maximum Energy of Disc Impact - Main Steam Check and Isolation Valves for Kewaunee Unit 1, submitted to the Regulatory Staff on Kewaunee Docket 50-305. Because the main steam isolation and check valves for the Prairie Island and Kewaunee plants are identical, a jointly sponsored program was undertaken by Northern States Power Company and Wisconsin Public Service Corporation to determine disc closure energies. Due to the locations of postulated breaks relative to the valves, the Kewaunee plant has the highest disc closure energies.

Therefore, in the analysis, the Kewaunee values were used; and the report, PI0-02-03 (Reference 15), not only applies to Prairie Island but also gives a margin of safety. Due to changes in the full power operating characteristics the MS check and isolation valve disc impact energies were updated in 09Q4836-CAL-002 (Reference 11); however, the Hot-Zero Power condition disc impact energies for the check and isolation valves of PI0-02-03 (Reference 15) remains applicable.

A finite element model of the disc linkage and valve body was developed and an elastic plastic analysis was made to determine deformations. The elastic plastic design of the valve allows for permanent deformation of the disc upon spurious valve closure at full load steam flow conditions. A detailed presentation of the stress analysis was presented in a topical report PI0- 01-06 (Reference 9) titled: Analysis Report -

Structural Analysis of Main Steam Check and Isolation Valves for Prairie Island Unit 1.

An updated structural analysis of the main steam check and isolation valves is presented in 09Q4836-CAL-003 (Reference 10).

The non-return valves prevent reverse flow of steam. If a steam line ruptures between a non-return valve and a steam generator, the affected steam generator will blow down.

The non-return valve in the line eliminates blowdown from the other steam generator.

The steam break incident is analyzed in Section 14.5.

11.7.4 Inspection and Testing The main steam line valves can be tested at regular intervals.

The main steam isolation valves serve to limit an excessive reactor coolant system cooldown rate and resultant reactivity insertion following a main steam break incident.

Their ability to close upon signal within a specified time interval is verified each refueling outage or when work has been performed on the valves.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 32 Page 11.8-1 11.8 CONDENSATE POLISHING SYSTEM 11.8.1 Design Basis The condensate polishing system is typically used during unit start-up and is designed to remove suspended and dissolved impurities from the condensate so that the secondary water chemistry is maintained within specified limits. The system is designed to accommodate a maximum condenser tube leak of 0.5 gpm. The system was originally sized to process approximately 10,000 gpm of condensate. The peak flow capacity of the system is 11,000 gpm.

The system is designed with 50% redundant capacity to provide for continuous operation when portions of the system are shutdown for maintenance or repair.

The system also provides storage, handling and processing of waste solids with interfaces to the ultimate means of disposal via the plant waste solidification system, portable onsite solidification equipment, offsite solidification or offsite landfill.

The system is provided with a process air supply which is designed with sufficient excess capacity to supplement the plant station air system. Chemistry sampling and monitoring is provided to ensure proper system operation. Shielding is provided for the protection of plant personnel. The design of the shielding is based on the maximum primary-to-secondary leakage allowed by the Technical Specifications.

11.8.2 Description The condensate polishing system (Figures 11.1-19 through 11.1-20) consists of the following subsystems:

a.

filter/demineralizer

b.

backwash and flush water

c.

spent resin disposal

d.

backwash air supply

e.

resin disposal building sump All system functions are controlled locally. System malfunctions are alarmed locally and in the control room.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 32 Page 11.8-2 11.8.2.1 Filter/Demineralizer System The filter/demineralizer (F/D) system is shown in detail in Figure 11.1-20 and consists of three 50%-capacity, precoat-type F/D vessels per unit arranged in parallel in the condensate pump discharge header. Each F/D vessel is rated at 5500 gpm and 30 psi max P across the filter elements. During normal operation two vessels are online while the third is in backwash, precoat, shutdown or standby.

One full-capacity bypass is provided for all three F/D vessels. The bypass valve is automatically actuated by F/D differential pressure to maintain a maximum total system P of 45 psid. Full capacity manual bypass is provided in parallel with the automatic bypass.

A holding pump is provided for each vessel to retain the precoat on the filter elements.

The holding pump maintains a 750 gpm flow through the F/D vessel and is automatically actuated on low F/D vessel effluent flow.

Backwash air and water are supplied to each vessel for the purpose of dislodging precoat from the filters by pressurizing and then rapidly depressurizing the vessel.

Separate precoating equipment is provided for each F/D train. The vessels are individually precoated via cross-ties to the precoat equipment.

Adequate shielding is provided in the vicinity of the F/D vessels to allow personnel access through the area during design basis primary-to-secondary leakage conditions.

11.8.2.2 Backwash and Flush Water System Backwash and flush water is stored in the backwash water storage tank (BWST) which is manually supplied from the condensate storage tank (CST). A cross-tie is provided so that the BWST for one unit may be supplied from the CST of the other unit.

Backwash waste water and resin from the F/D vessels dumps by gravity to the backwash waste receiving tank (BWRT). The slurry is then transferred to the resin disposal building (RDB). After dewatering via clamshell filters, the spent resin is diverted to the spent resin disposal system, and the backwash waste water is filtered and directed to the turbine building sump. The backwash waste water may be directed to the BWST should circumstances warrant. Each Units BWST and BWRT have capacity for two backwashes. Cross-ties are provided such that the dewatering equipment for each unit is interchangeable with the other unit.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 32 Page 11.8-3 11.8.2.3 Spent Resin Disposal System Dewatered, spent resin from backwash system operations of both units is transferred, via the drain diverters and spent resin disposal chutes, to the spent resin transfer tank (SRXT) in the resin disposal building, or to barrels or to other containers, depending on ultimate disposal. Flush water is also supplied to the SRXT for disposal and/or processing of spent resins.

Flush water or resin slurry in the SRXT can then be pumped under manual control to one of the following places for further processing and/or disposal:

a.

Atcor waste metering tank for solidification via the plant waste solidification system in the radwaste building

b.

Normally-closed, blind-flanged line in the resin disposal building for transfer to truck or portable solidification equipment

c.

backwash system for further reprocessing

d.

recirculation line to SRXT 11.8.2.4 Backwash Air Supply System Compressed air for resin backwashing operations is supplied from the Compressed Air System. The Compressed Air System is discussed in Section 10.3.10.

11.8.2.5 Resin Disposal Building Sump System The resin disposal building sump system consists of two sumps, each equipped with a redundant set of sump pumps.

Sump A handles the RDB floor drains and may be discharged to either the miscellaneous drains collection tank or the waste holdup tanks.

Sump B handles the truck loading enclosure floor drains and discharges to the aerated drains sump tank.

11.8.3 Performance Evaluation The condensate polishing system is designed to maintain the EPRI PWR Secondary Water Chemistry Guidelines (Reference 1). During normal power operation, sampling of steam generator blowdown, condensate and feedwater is performed in accordance with these guidelines per plant chemistry procedures.

System high conductivity is annunciated at local control panels and actuate the system trouble alarms in the main control room.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 32 Page 11.8-4 The volume of spent powdered resin throughput from the plant is conservatively estimated at 3525 cubic feet annually for both units. Almost all of the spent powdered resin contains negligible radioactivity and can be safely disposed of by landfill burial.

The annual volume of radioactive spent powdered resin depends on the amount of primary-to-secondary leakage. In general, the annual volume of radioactive spent powdered resin is extremely small and has sufficiently low activity to be disposed of as low level waste in accordance with applicable federal regulations.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-1 11.9 CONDENSATE, FEEDWATER AND AUXILIARY FEEDWATER SYSTEMS 11.9.1 Design Basis 11.9.1.1 Condensate and Feedwater Systems The Condensate and Feedwater System design is based on removing condensate from the hotwell of the condenser and supplying heated feedwater to the steam generators at all load conditions.

There are three multi-stage, vertical, pit-type, centrifugal condensate pumps with vertical motor drives. Each pump is half capacity with the turbine operating at the maximum calculated rating.

Two half-capacity, high speed, centrifugal, vertically-split case, motor-driven main feedwater pumps increase the pressure of the condensate for delivery through one stage of feedwater heating and the feedwater regulating valves to the steam generators.

The main feedwater pumps are single-stage, horizontal, centrifugal pumps with barrel casings. Each feedwater pump is rated at 8600 gpm and 2100 ft. TDH. Shaft sealing is accomplished by a pressure breakdown style arrangement cooled with seal water injection. Bearing lubrication for the motor, the pump, and its step-up gear is accomplished by an integral Lubrication Oil System mounted on the pump base.

Normal circulation of the lubrication oil is by shaft-driven pump. The Lubricating Oil System includes a reservoir, a cooler, and an ac motor-driven back-up oil pump.

Feedwater pump bearing temperatures are available on ERCS. The feedwater pumps are started and stopped from the main control board. A minimum flow control system is provided to ensure 925 gpm flow during low system flow conditions.

Should there be a loss of suction pressure, an automatic bypass around the low-pressure feedwater heaters ensures sufficient suction pressure at the feedwater pumps.

11.9.1.2 Auxiliary Feedwater System The Auxiliary Feedwater System supplies feedwater following interruption of the main feedwater supply. Feedwater must be provided for the removal of residual heat from the core by heat exchange in the steam generators if the main feedwater pumps cease to operate for any reason.

The Auxiliary Feedwater System delivers feedwater from the condensate storage tank (or from the cooling water system) to the main feedwater piping at a location near the steam generator inlet. The system consists of the auxiliary feedwater pumps, associated valves and piping, and control systems. The entire system is redundant.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-2 The Auxiliary Feedwater System provides three essential functions during abnormal conditions:

a.

prevents thermal cycle of the steam generator tube sheet upon loss of main feedwater pump;

b.

removes residual heat from the reactor coolant system until the RCS temperature drops below 300-350F and the RHR system is capable of providing the necessary heat sink;

c.

maintains a head of water in the steam generator following a loss of coolant accident.

The feedwater flow rate required to prevent thermal cycling of the tube sheet and for removing residual heat is the same and is about 160 gpm (historical) per Unit (or 80 gpm per steam generator). A 200-gpm flow is therefore sufficient to fulfill all the three functions stated above. However, since the Auxiliary Feedwater System is a safety features system, an additional 200-gpm pump is provided as a backup for the first for each Unit. 200 gpm is the design sizing of the AFW Pumps and not a minimum flow requirement.

In other 2-loop plants (R.E. Ginna, Point Beach, etc.) prior to Prairie Island, the inventory of secondary side water in the steam generator versus secondary side water level was such that the pump size required to prevent thermal cycling was larger than the pump size required for removing the residual heat in the core (almost twice as big).

As a result of this difference in capacity requirement between the two functions, these plants used the turbine driven pump to meet the larger capacity since it was not a safeguards requirement and therefore did not require redundancy. Smaller motor driven pumps are used for the safeguards requirements of removing fission product decay heat so as not to unnecessarily increase the diesel-generator size. The recent designs use a large steam generator with a different dimensional configuration. This reduces the pump size required to prevent thermal cycling, such duty being about the same as for removing residual heat, 160 gpm (historical) per unit or 80 gpm per steam generator. 160 gpm (historical) minimum flow rate is based on normal SG water levels at the time of the event (Reference 2). [Only one steam generator is required to remove all decay heat in the core.]

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-3 11.9.2 Description 11.9.2.1 Condensate and Feedwater Systems Condensate is taken from the condenser hotwell by the condensate pumps and pumped through the filter/demineralizer system or its bypass line, the air ejector condensers, gland steam condenser, and low-pressure heaters to the suction of the feedwater pumps. The feedwater pumps then send feedwater through the high-pressure heaters to each steam generator. The condensate and feedwater systems flow diagrams are shown in Figures 11.1-3 to 11.1-6.

The two main feedwater pumps operate in series with the condensate and the heater drain pumps, discharging through check valves and motor-operated gate valves into the No. 5 heaters. The feedwater flows through the two parallel, high-pressure feedwater heaters and flows into a common header. Two 16-in. lines containing the feedwater control stations feed the two steam generators from the header.

Bypass valves together with shutoff valves at the inlets and outlets of the feedwater heaters are provided to permit heaters to be taken out of service.

The steam generator feedwater control system indicates, records and controls the water level in each of the two steam generators.

Reactor trip is actuated by low-low steam generator water level. These trips are discussed in further detail in Section 7.

The main feedwater control valves are closed when any one of the following conditions occurs:

Abnormally high steam generator level Safety injection signal Reactor trip in coincidence with low Tavg Any safety injection signal will isolate the main feedwater lines by closing all control valves (main and bypass valves) and tripping the main feedwater pumps, which causes the discharge valves to close.

One manual control station is provided for each feedwater valve. This unit consists of auto/manual transfer capability and analog output control. When in automatic, flow is adjusted as necessary to maintain narrow range steam generator level at its set point, which is programmed as a function of load.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-4 The reheater and moisture separator are housed in one pressure vessel. Reheaters are provided with drain tanks and level controls. The moisture separators are also provided with level control, while feedwater heater No. 15 is equipped with a duplex level control.

All the low-pressure feedwater heaters, No. 11, 12, and 13, are located in the condenser neck. Feedwater heaters No. 11 & 12 are combined into one shell (duplex) with bolted-head construction. Feedwater heater No. 11 is provided with a separate Feedwater Heater Drain Cooler (No. 11). Drain from moisture separator and Feedwater heater No. 14 are drained directly to the Heater Drain Tank, as shown in Figures 11.1-9, 10.

The level controllers operate the emergency drain dump valves which dump the various drains directly to the condenser in case of abnormally high level. Three half-capacity, vertical, centrifugal heater drain pumps are provided for pumping the heater drainage into the condensate line ahead of the feedwater pumps. The pumps are started and stopped from the main control board. Tank level is controlled by variable-speed pump drives. An emergency dump valve to the condenser is sized to pass all condensate from Feedwater Heater No. 14.

11.9.2.2 Auxiliary Feedwater System The Auxiliary Feedwater System is the most reliable system for decay heat removal following any reactor shutdown. Full flow capability is reached within a maximum response time of one minute when the pump drives are automatically energized from an open-valve standby status, when the normal coolant source is available. As discussed below, response time to other scenarios such as seismic events and tornadoes may take longer if there is a need to realign pump suction to the backup coolant source.

Redundancy of flow paths, valving, pumps, and redundancy and diversity of coolant sources, and pump energy sources assures a high degree of system reliability.

The Auxiliary Feedwater System consists of one steam turbine-driven pump and one motor-driven pump per operating unit, with each capable of delivering coolant to either or both steam generators of the same operating unit. Check valves are provided to prevent a rupture in either pumps discharge from negating the other pumps effectiveness. Welded construction is used where possible throughout the Auxiliary Feedwater System piping, valves, and equipment to minimize the possibility of leakage.

The Auxiliary Feedwater System is shown on the Main Steam System and Feedwater System flow diagrams, Figures 11.1-1, 11.1-2, 11.1-5 and 11.1-6. Pump characteristic curves are shown on Figure 11.9-1.

There is no interconnection between the two turbine-driven pumps, and there is no sharing of the Auxiliary Feedwater System components by the two operating units during normal operations. However, a cross-connection between the discharge lines of the motor-driven pumps is provided to achieve greater flexibility during operational emergencies. By incorporating two valves in this cross-connection, the Auxiliary Feedwater System has the capability to take an active or passive failure and still fulfill its functional requirements.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-5 The turbine-driven auxiliary feedwater pumps operate independent of all plant AC power sources and are supplied steam from both main steam lines of their associated operating unit. The two steam lines join together downstream of motor-operated isolation valves (one per line) to supply steam to the turbine through a single air-operated, fail open, steam admission valve.

The air-operated steam admission valve has two safety related functions:

1)

Open: To allow passage of steam to start the associated turbine-driven auxiliary feedwater pump.

2)

Close: Tripping the pump on low turbine-driven auxiliary feedwater pump suction or discharge pressure.

The steam admission valve safety related air pressure boundary is from the safety related check valve to the air-operated steam admission valve actuator. The instrument air system supplies air to the steam admission valve air pressure boundary. The air supply to the steam admission valve is controlled by a three-way DC powered solenoid.

The air-operated steam admission valve opens automatically on a turbine-driven auxiliary feedwater pump start signal. Additionally, the turbine-driven auxiliary feedwater pump may also be started locally using a 3-way manual valve to locally bleed air pressure from the steam admission valve air pressure boundary.

Failure of control power to the three-way DC powered solenoid valve causes the air pressure boundary to be vented, which results in the steam admission control valve to open, starting the associated pump. On failure of the instrument air system, the accumulator is capable of maintaining sufficient air pressure for the steam admission valve. The steam admission valve will remain closed until accumulator pressure is lost or an automatic start signal is received. In the case of loss of instrument air, the most likely start signal will be from Low-Low Steam Generator Water Level.

The motor-driven auxiliary feedwater pumps are fed by separate safeguard buses, one each per operating unit, and are included in the load restoration sequencing onto the emergency buses. Motor-operated valves are not stripped from the emergency buses.

A failure in the automatic circuitry will not affect the capability to manually initiate auxiliary feedwater from the control room.

Instrumentation and logic circuits for starting both the motor-and turbine-driven pumps meet the single failure criterion (except for AMSAC) for actuation and are capable of being tested at power.

Instrumentation power supplies are from the sites four vital 120 VAC buses, each supplied by an inverter connected to the associated 480 VAC emergency bus and 125 VDC power system. Motor-driven pump breaker controls are powered by the respective train of the 125 VDC system. Control power for the turbine-driven pumps steam admission control valves is also supplied from the Safeguards 125 VDC battery systems.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-6 The following signals automatically start the pump motors and open the steam admission control valve to the turbine-driven pumps:

a.

Low-low water level in either steam generator.

b.

Trip of both main feedwater pumps (bypassed during startup and shutdown operation).

c.

Safety injection.

d.

Loss of both 4.16 KV normal buses (turbine-driven pump only).

e.

AMSAC actuation.

In addition, the motor-driven pumps and the turbine-driven pumps can be manually started locally or remotely.

Each auxiliary feedwater pump has a pressure switch on its suction and on its discharge piping. If a low pressure setpoint is reached on either switch, the pump will trip either by closing the air-operated steam admission control valve on the turbine-driven auxiliary feedwater pumps, or by opening the motor breaker on the motor-driven auxiliary feedwater pumps. The low discharge pressure trip protects the pump from damage due to runout. The low suction pressure trip prevents damage to the pump from loss of suction. In either case, the pump will be protected so it can be restarted once the cause of low pressure is corrected.

On 11 and 22 Turbine-Driven Auxiliary Feedwater Pumps, the low discharge pressure trip is blocked when in AUTO and the Reactor Trip Breakers are closed (RTA for relay contact for 11 TD AFW pump and RTB relay contact for 22 TD AFW pump). This circuit ensures that following the completion of the AMSAC initiation of Auxiliary Feedwater during an ATWS transient, the TD AFW pump will continue to run.

During reactor operation, all pumps are on standby, and the isolation valves and pump suction and discharge valving are open. Start of an auxiliary feedwater pump causes the steam generator blowdown flow control valves in the associated operating unit to auto close.

Auxiliary feedwater system coolant sources are redundant and diverse. The normal source is by gravity feed from the three cross-connected 150,000 gallon condensate storage tanks. The safety related (backup) water supply is provided by the Design Class I Cooling Water System. If an external event such as a tornado or seismic event were to cause flow disruption from the condensate storage tanks, the auxiliary feedwater pumps would likely trip on low suction pressure. Piping connecting the three condensate storage tanks has been evaluated against failure under seismic loads.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-7 An auxiliary feedwater reliability study [Ref. 14] was performed after the Three Mile Island accident and in response to NUREG-0611. This study determined steam generator dryout times with no auxiliary feedwater flow available. For a loss of normal feedwater event, the dryout time is approximately 30 minutes. For a loss of offsite power event, the dryout time is approximately 60 minutes. (Additional reliability study information follows near the end of this section.) Additional analysis (NSP-07-33, Reference 5) has determined that additional time is available for reinitiating of A.F. flow based on the effect on the primary system for a loss of offsite power due to an external event.

PINGP has standing operating procedures for realigning the auxiliary feedwater pump suction from the condensate storage tanks to the Cooling Water System and for flow restoration after a low suction/low discharge pressure auxiliary feedwater pump trip.

These procedures have been time-validated and can be accomplished within the SG dryout time frames listed above.

In the normal cooldown procedure, after programmed reactor shutdown or trip, steam generator levels may be maintained by control of the feedwater flow control valves. If the Main Feedwater System is inoperable or its flow is too great, steam generator levels are controlled by local or remote manual operation of the auxiliary feedwater flow control valves for the turbine-and motor-driven pumps.

When reactor containment isolation is initiated, the normally-open auxiliary feedwater containment isolation valves receive an open signal.

Following blowdown in the loss-of-coolant accident, the Auxiliary Feedwater System maintains a positive pressure differential from the secondary side to the primary side of the steam generators, providing a barrier to prevent possible fission product escape to the Main Steam System.

The SI actuation circuits which initiate auxiliary feedwater addition are safety grade, separated and trained. The SI actuation contacts which trip the normal feedwater pumps off are also safety grade, using additional relays to maintain separation even though both pumps are tripped off by both Train A and Train B SI signals. In addition, either Train A or Train B SI Signal causes closure of the parallel flow control valves downstream of the feedwater pumps. The SI signal causes closure of the containment isolation valves downstream of the normal feedwater flow control valves through the containment isolation signals.

A cycle timer control circuit automatically runs the auxiliary motor-driven lube oil pump on each auxiliary feedwater pump for approximately 10 minutes twice per week. The minimum requirement is 5 minutes once per week. If the proper lube oil pressure is not reached following the lube oil pump start, an alarm is sounded in the control room. This ensures that sufficient auxiliary feedwater pump oil film for pump start is maintained at all times. Thus, the auxiliary motor-driven lube oil pump is not required for auxiliary feedwater pumps starting.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-8 The bearing oil coolers are cooled by recirculation flow from the discharge of the auxiliary feedwater pumps back to the condensate storage tanks. Oil cooling is thus available whenever the pump is running.

As a result of the Three Mile Island accident, reliability of the auxiliary feedwater system received additional attention. The NRC issued Generic Letter 81-14, Seismic Qualification of AFW Systems. Several responses to the NRC were made from which the NRC concluded in a letter dated June 16, 1983 that, following a number of minor modifications, the auxiliary feedwater system had sufficient capability to withstand a safe shutdown earthquake and accomplish its safety function.

Generic Issue No. 124, Auxiliary Feedwater System Reliability was also identified as a result of the Three Mile Island accident. The Prairie Island Auxiliary Feedwater System was determined to be in the low reliability range based on an NRC reliability analysis reported in NUREG-0611. As a result of Generic Issue No. 124, Northern States Power Company performed a probabilistic risk assessment study on the auxiliary feedwater and supporting systems, Prairie Island Units 1 and 2 Auxiliary Feedwater System Reliability Study [Ref 14]. Based on the NSP study, and an NRC staff audit of plant variables affecting the Auxiliary Feedwater system, Generic Issue No. 124 was closed out by an NRC Safety Evaluation Report transmitted by letter dated November 26, 1986.

The following is a list of actions that were taken as a result of the NSP study and remaining NRC concerns expressed in the NRC Safety Evaluation to close out Generic Issue 124.

a.

Lube Oil Cooling - AFW pump discharge recirculation flow was rerouted to supply cooling water for pump lube oil coolers. This action removed the AFW dependency on cooling water for lube oil cooling.

b.

Manual Control of TDAFW Pump - A three way solenoid valve has been added to the air supply line to the TDAFW pump steam inlet supply control valve. This valve allows the pump to be run manually by locally opening the control valve by venting diaphragm air. A procedure has been written for manual auxiliary feedwater pump operations. All operations crews have been trained in use of the procedures.

c.

Eliminate Auto Open Signal to MV-32041 & MV-32042 - The auto open signal to the Condensate Emergency Supply Valve, MV-32041 (Unit 1) and MV-32042 (Unit 2), has been removed.

d.

Drain Valves from AFW Steam Lines to the Main Condenser - All drain valves from the AFW steam lines to the main condenser have been blocked open using safeguards hold cards.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-9

e.

Proceduralize Bypass of Control/Actuation Faults - The subject procedures have been written as subsections of the Auxiliary Feedwater System procedure.

f.

AFW System Valve Integrity - Check valve integrity is assured by monitoring the temperature of AFW discharge lines during each shift.

g.

Trip/Throttle Leakoff - Both the high and low pressure leakoff for the TDAFW pump trip/throttle valves have been rerouted to discharge into the turbine exhaust lines. This modification was completed to eliminate the potentially for creating a steam environment in the auxiliary feedwater pump room during operation of the turbine-driven auxiliary feedwater pump.

h.

Condensate Header Valve C-41 Condensate header valve C-41-1 was installed during plant construction to facilitate isolation and testing of systems.

This valve was not used after plant startup and represented a potential for loss of AFW pump suction supply, it was removed from service and replaced by a spoolpiece.

i.

Actions Taken to Eliminate Final NRC Concerns:

1. Administratively locked open the condensate storage tank isolation valves to ensure AFW pumps suction supply.

2. A step ladder is located in each AFW pump room to aid operators in manipulating overhead AFW valves in emergency situations.

3. Installed additional emergency lighting in the area of the TDAFW pumps.

4. Work toward maintaining similarity between Unit 1 and Unit 2 AFW surveillance and maintenance procedures.

11.9.3 Performance Analysis The Auxiliary Feedwater System serves as a backup system for supplying feedwater to the secondary side of the steam generators at times when the feedwater system is not available, thereby maintaining the heat sink capabilities of the steam generator. As an Engineered Safeguards System, the Auxiliary Feedwater System is directly relied upon to prevent core damage and system overpressurization in the event of transients such as a loss of normal feedwater or a secondary system pipe rupture, and to provide a means for plant cooldown following any plant transient.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-10 Following a reactor trip, decay heat is dissipated by evaporating water in the steam generators and venting the generated steam either to the condensers through the steam dump or to the atmosphere through the atmospheric steam dump valves, steam generator safety valves or the power-operated relief valves. Steam generator water inventory must be maintained at a level sufficient to ensure adequate heat transfer and continuation of the decay heat removal process. The water level is maintained under these circumstances by the Auxiliary Feedwater System which delivers an emergency water supply to the steam generators. The Auxiliary Feedwater System must be capable of functioning for extended periods, allowing time either to restore normal feedwater flow or to proceed with an orderly cooldown of the plant to the reactor coolant temperature where the Residual Heat Removal System can assume the burden of decay heat removal. The Auxiliary Feedwater System flow and the emergency water supply capacity must be sufficient to remove core decay heat, reactor coolant pump heat, and sensible heat during the plant cooldown. The Auxiliary Feedwater System can also be used to maintain the steam generator water levels above the tubes following a LOCA. In the latter function, the water head in the steam generators serves as a barrier to prevent leakage of fission products from the Reactor Coolant System into the secondary plant.

The reactor plant conditions which impose performance requirements on the design of the Auxiliary Feedwater System are as follows for the Prairie Island plants.

Loss of Main Feedwater Transient Loss of main feedwater with offsite power available (*)

Loss of main feedwater without offsite power available (*)

Secondary Pipe Ruptures Feedline rupture Steamline rupture (*)

Loss of All AC Power (station blackout)

Loss of coolant Accident (LOCA) (*)

Cooldown

a.

Loss of Main Feedwater Transients The design loss of main feedwater transients are those caused by:

Interruptions of the Main Feedwater System flow (LONF) due to a malfunction in the feedwater or condensate system Loss of offsite power (LOOP) with the consequential shutdown of the system pumps, auxiliaries, and controls

(*) Impose safety related performance requirements

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-11 Loss of main feedwater (LONF) transients are characterized by a rapid reduction in steam generator water levels which results in a reactor trip, a turbine trip, and auxiliary feedwater actuation by the protection system logic.

Following reactor trip from high power, the power quickly falls to decay heat levels. The water levels continue to decrease, progressively uncovering the steam generator tubes as decay heat is transferred and discharged in the form of steam either through the steam dump valves (to the condenser or atmosphere) or through the steam generator safety or power-operated relief valves to the atmosphere. The reactor coolant temperature increases as the residual heat in excess of that dissipated through the steam generators is absorbed. With increased temperature, the volume of reactor coolant expands and begins filling the pressurizer. Without the addition of sufficient auxiliary feedwater, further expansion will result in water being discharged through the pressurizer safety and relief valves. If the temperature rise and the resulting volumetric expansion of the primary coolant are permitted to continue, then (1) pressurizer safety valve capacities may be exceeded causing overpressurization of the Reactor Coolant System and/or (2) the continuing loss of fluid from the primary coolant system may result in core uncovering, loss of natural circulation, and core damage. If such a situation were ever to occur, the Emergency Core Cooling System would be ineffectual because the primary coolant system pressure exceeds the shutoff head of the safety injection pumps, the nitrogen over-pressure in the accumulator tanks, and the design pressure of the Residual Heat Removal Loop. Hence, the timely introduction of sufficient auxiliary feedwater is necessary to arrest the decrease in the steam generator water levels, to reverse the rise in reactor coolant temperature, to prevent the pressurizer from filling to a water solid condition, and eventually to establish stable hot standby conditions.

Subsequently, a decision may be made to proceed with plant cooldown if the problem cannot be satisfactorily corrected.

The LOOP transient differs from a simple loss of main feedwater in that emergency power sources must be relied upon to operate vital equipment.

The loss of power to the electric driven condenser circulating water pumps results in a loss of condenser vacuum and condenser dump valves. Hence, steam formed by decay heat is relieved through the atmospheric steam dump valves, steam generator safety valves or the power-operated relief valves.

The calculated transient would be similar for both the loss of main feedwater and the LOOP, except that reactor coolant pump heat input is not a consideration in the LOOP transient following loss of power to the reactor coolant pump bus.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-12 The LONF transient serves as the basis for the minimum flow required for the smallest capacity single auxiliary feedwater pump for the Prairie Island plants due to the additional heat from Reactor Coolant Pump operation. The pump is sized so that any single pump will provide sufficient flow against the steam generator safety valve set pressure (with accumulation) to prevent water relief from the pressurizer. For decay heat removal using the safety valve(s),

actual accumulation is a function of the steam flow rate required for the decay heat load and if the decay heat load is being removed by one or both Steam Generators.

b.

Secondary System Pipe Ruptures The feedwater line rupture accident not only results in the loss of feedwater flow to the steam generators but also results in the complete blowdown of one steam generator within a short time if the rupture should occur downstream of the last nonreturn valve in the main or auxiliary feedwater piping to an individual steam generator. Another significant result of a feedline rupture may be the spilling of auxiliary feedwater out the break as a consequence of the fact that the auxiliary feedwater branch line may be connected to the main feedwater line in the region of the postulated break. Such situations can result in the spilling of a disproportionately large fraction of the total auxiliary feedwater flow because the system preferentially pumps water to the lowest pressure region in the faulted loop rather than to the effective steam generator which is at a relatively high pressure. The system design must allow for terminating, limiting, or minimizing that fraction of auxiliary feedwater flow which is delivered to a faulted loop or spilled through a break in order to ensure that sufficient flow will be delivered to the remaining effective steam generator. The concerns are similar for the main feedwater line rupture as those explained for the loss of main feedwater transients.

Main steamline rupture accident conditions are characterized initially by plant cooldown and, for breaks inside containment, by increasing containment pressure and temperature. Auxiliary feedwater is not needed during the early phase of the transient but flow to the faulted loop will contribute to the release of mass and energy to containment. Thus, steamline rupture conditions establish the upper limit on auxiliary feedwater flow delivered to a faulted loop. Eventually, however, the Reactor Coolant System will heat up again and auxiliary feedwater flow will be required to be delivered to the unfaulted loop, but at somewhat lower rates than for the loss of feedwater transients described previously. Provisions must be made in the design of the Auxiliary Feedwater System to allow limitation, control, or termination of the auxiliary feedwater flow to the faulted loop as necessary in order to prevent containment overpressurization following a steamline break inside containment, and to ensure the minimum flow to the remaining unfaulted loops.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-13

c.

Loss of All AC Power The loss of all AC power is postulated as resulting from accident conditions wherein not only onsite and offsite AC power is lost but also AC emergency power is lost as an assumed common mode failure.

Battery power for operation of protection circuits is assumed available. The impact on the Auxiliary Feedwater System is the necessity for providing both an auxiliary feedwater pump power and control source which are not dependent on AC power and which are capable of maintaining the plant in Mode 3, Hot Standby until AC power is restored.

d.

Loss-of-Coolant Accident (LOCA)

The loss of coolant accidents do not impose on the auxiliary feedwater system any flow requirements in addition to those required by the other accidents addressed in this response. The following description of the small LOCA is provided here for the sake of completeness to explain the role of the auxiliary feedwater system in this transient.

Small LOCAs are characterized by relatively slow rates of decrease in reactor coolant system pressure and liquid volume. The principal contribution from the Auxiliary Feedwater System following such small LOCAs is basically the same as the systems function during Mode 3, Hot Standby or following spurious safety injection signal which trips the reactor. Maintaining a water level inventory in the secondary side of the steam generators provides a heat sink for removing decay heat and establishes the capability for providing a buoyancy head for natural circulation. The auxiliary feedwater system may be utilized to assist in a system cooldown and depressurization following a small LOCA while bringing the reactor to Mode 5, Cold Shutdown.

e.

Cooldown The cooldown function performed by the Auxiliary Feedwater System is a partial one since the reactor coolant system is reduced from normal zero load temperatures to a hot leg temperature of approximately 350F. The latter is the maximum temperature recommended for placing the Residual Heat Removal System (RHRS) into service. The RHR system completes the cooldown to Mode 5, Cold Shutdown conditions.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-14 Cooldown may be required following expected transients, following an accident such as a main feedline break, or during a normal cooldown prior to refueling or performing reactor plant maintenance. If the reactor is tripped following extended operation at rated power level, the AFWS is capable of delivering sufficient AFW to remove decay heat and reactor coolant pump (RCP) heat following reactor trip while maintaining the steam generator (SG) water level. Following transients or accidents, the recommended cooldown rate is consistent with expected needs and at the same time does not impose additional requirements on the capacities of the auxiliary feedwater pumps, considering a single failure. In any event, the process consists of being able to dissipate plant sensible heat in addition to the decay heat produced by the reactor core.

Table 11.9-1 summarizes the criteria which are the general design bases for each event. Specific assumptions used in the analyses to verify that the design bases are met are discussed below.

The primary function of the Auxiliary Feedwater System is to provide sufficient heat removal capability for heatup accidents following reactor trip to remove the decay heat generated by the core and prevent system overpressurization. Other plant protection systems are designed to meet short term or pre-trip fuel failure criteria. The effects of excessive coolant shrinkage are bounded by the analysis of the rupture of a main steam pipe transient. The maximum flow requirements determined by other bases are incorporated into this analysis, resulting in no additional flow requirements.

Analyses have been performed for the limiting transients which define the AFWS performance requirements. Specifically, they include:

- Loss of Main Feedwater (LONF)

- Rupture of a Main Feedwater Pipe

- Rupture of a Main Steam Pipe Inside Containment The analyses described below are for determining the performance requirements of the AFWS; for example, sizing of the AFW Pumps. The description below, the criteria in Table 11.9-1, and the inputs and assumptions in Table 11.9-2 may be different than those used for the accident and transient analyses described in Section 14. In addition, the accidents and transients evaluated for AFW sizing may be different than those analyzed in Section 14. For example, the rupture of Main Feedwater Line (cannot be isolated from the associated SG) is evaluated for AFW sizing, but is not an analyzed accident in Section 14. That is, the Main Feedwater Line Break is not a design basis accident for Prairie Island.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-15 In addition to the above analyses, calculations have been performed specifically for the Prairie Island plants to determine the plant cooldown flow (storage capacity) requirements. The Loss of All AC Power is evaluated via a comparison to the transient results of a LOOP, assuming an available auxiliary pump having a diverse (non-AC) power supply. The LOCA analysis, as discussed in Item (d) above, incorporates the system flow requirements as defined by other transients, and therefore is not performed for the purpose of specifying AFWS flow requirements. Each of the analyses listed above are explained in further detail below.

Loss of Main Feedwater (LONF)

A loss of feedwater (LONF) transient assuming a single auxiliary feedwater pump delivering flow to both steam generators was evaluated to show that this event does not result in filling the pressurizer, that the peak RCS pressure remains below the criterion for Condition II transients and that no fuel failures occur (refer to Table 11.9-1). As previously discussed, for determining AFW flow requirements, maintaining off-site power is more conservative than losing off-site power. Table 11.9-2 summarizes the assumptions used in this analysis. The transient analysis begins at the time of the loss of main feedwater. The analysis assumes that the plant is initially operating at the power shown on the table, a very conservative assumption in defining decay heat and stored energy in the RCS. The reactor is assumed to be tripped on low-low steam generator level. Steam generator level at the time of reactor trip was assumed to be 0%

NRS for additional conservatism; to that, allowance for level uncertainty was also accounted for. The analysis shows that there is a considerable margin with respect to filling the pressurizer.

This analysis establishes the capacity of the smallest single pump and also establishes train association of equipment so that this analysis remains valid assuming the most limiting single failure.

Rupture of Main Feedwater Pipe The double ended rupture of a main feedwater pipe inside of containment is analyzed for determining AFW performance requirements (Reference 3). Table 11.9-2 summarizes the assumptions used in the analyses. Reactor trip is assumed to occur as a result of a safety injection signal based on high containment pressure. This is a conservative time assumption which increases the stored heat prior to reactor trip and minimizes the ability of the steam generator to remove heat from the RCS following reactor trip due to a conservatively small total steam generator inventory. As in the loss of normal feedwater analysis, the initial power rating was assumed to be 1683 MWt.

The analysis allows for 180 gpm auxiliary feedwater delivered to the intact loop within 10 minutes of the reactor trip (10 minutes for operator action to reroute flow paths and to start the auxiliary feedwater pumps). The criteria listed in Table 11.9-1 are met.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-16 The outside of containment main feedwater line break and subsequent blowdown of a steam generator is precluded by the closing of the check valve inside containment.

However, the Turbine Building or Auxiliary Building would experience the break flow from the feedwater pump discharge. The reactor coolant system would experience an event which would be similar to the loss of normal feedwater transient.

This analysis establishes the capacity requirements for a single pump, establishes requirements for layout to preclude indefinite loss of auxiliary feedwater to the postulated break, and establishes train association requirements for equipment so that the AFWS can deliver the minimum flow required in 10 minutes following operator actions assuming the worst single failure. Primary system heat removal due to blowdown is included in our analytical code model and is correctly simulated during the feedline rupture analysis.

Rupture of a Main Steam Pipe Inside Containment Because the steamline break transient is a cooldown, the AFWS is not needed to remove heat in the short term. Furthermore, addition of excessive auxiliary feedwater to the faulted steam generator will affect the peak containment pressure following a steamline break inside containment. This transient is performed for several break sizes.

Auxiliary feedwater is assumed to be initiated at the time of the break, independent of system actuation signals to provide the most conservative analysis with respect to containment pressure.

Table 11.9-2 summarizes the assumptions used in this analysis. The criteria stated in Table 11.9-1 are met.

This transient establishes auxiliary feedwater flow rate to a single faulted steam generator assuming one pump operational and establishes layout requirements so that the flow requirements may be met considering the worst single failure. Primary system heat removal due to blowdown is included in our analytical code model and is correctly simulated during the steamline rupture analysis.

Plant Cooldown Maximum and minimum flow requirements from the previously discussed transients meet the flow requirements of plant cooldown. This operation, however, defines the basis for tankage size, based on the required cooldown duration, maximum decay heat input and maximum stored heat in the system. As previously discussed above the auxiliary feedwater system partially cools the system to the point where the RHRS may complete the cooldown, i.e., 350F in the RCS. Table 11.9-2 shows the assumptions used to determine the cooldown heat capacity of the auxiliary feedwater system.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-17 The cooldown is assumed to commence at the maximum rated power, and maximum trip delays and decay heat source terms are assumed when the reactor is tripped.

Primary metal, primary water, secondary system metal and secondary system water are all included in the stored heat to be removed by the AFWS. See Table 11.9-3 for the items constituting the sensible heat stored in the NSSS.

This operation is analyzed to establish minimum tank size requirements for auxiliary feedwater fluid source which are normally aligned. This analysis is documented in Reference 6.

11.9.4 Inspection and Testing 11.9.4.1 Auxiliary Feedwater System The auxiliary feedwater pumps can be periodically operated to verify their operability, as discussed in Section 11.9.1.

Proper functioning of the steam admission valve and subsequent starting of the steam-driven pump demonstrates the integrity of the system. Verification of correct operation can be made both from instrumentation within the main control room and direct visual observation of the pump.

The actions required to provide a head of water in the steam generator after a loss of coolant accident are exactly the operations required to fill a tank with fluid using a pump.

The test for the auxiliary feedwater system is to confirm the operability of the pumps, valves, and flow paths. The operability of the Auxiliary Feedwater System will be proven by starting any one of the pumps and demonstrating that steam generator water level is controlled using auxiliary feedwater during startup operations. Testing requirements are specified in Prairie Island Technical Specifications. If these operate, the ability of the system to maintain a water level in the steam generators is confirmed.

The Auxiliary Feedwater System is operated during reactor shutdown until the reactor conditions permit use of the Residual Heat Removal System. The active components (valves, pumps and pump drives, lube-oil pumps) of the system can be tested at any other time.

NRC IE Bulletin 85-01 presented a concern over the operability of a steam driven auxiliary feedwater pump due to steam binding (Generic Issue 89). Steam binding incidents have been observed as a result of back leakage through check valves from steam generators to the auxiliary feedwater pump casing. To alleviate concerns over auxiliary feedwater pump steam binding, Prairie Island has implemented procedures to monitor the temperature of pump discharge piping each shift. Procedures have also been implemented to recognize steam binding and for restoring the Auxiliary Feed System to operable status.

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PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.9-18 11.9.4.2 Wall Thickness Monitoring of High-Energy Piping An Erosion/Corrosion program or Flow-Accelerated Corrosion program as referred to by EPRI to survey high-energy pipe wall thickness was begun at Prairie Island in 1983 and expanded following a feedwater pump suction line rupture event at the Surry plant in December 1986.

The Prairie Island program incorporates guidelines from NRC Bulletin 87-01 (Reference 4), NRC Generic Letter 89-08 (Reference 12), and EPRI NSAC-202L to evaluate piping components susceptible to erosion/corrosion.

Sample size and inspection frequency are adjusted based on engineering review of the operating conditions, previous inspection results, experience gained, and results of an analytical program.

Non-Destructive Examination (NDE) methods such as: Ultrasonic Testing (UT) or Radiography Testing (RT) are used to determine pipe wall thickness for run/repair/replace decision.

Run/repair/replace decisions are made by the plant system engineers following evaluation of the inspection data.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.10-1 11.10 REFERENCES

1.

EPRI PWR Secondary Water Chemistry Guidelines

2.

Westinghouse Letter PIW-N-50, Auxiliary Feedwater System, dated Sept. 4, 1968. [Film Loc. 7497-No Blip]

3.

NSP NAD-98006, Analysis of a Feedwater Line Break for Prairie Island, dated September 1998. [NAD Files]

4.

NRC Bulletin 87-01, Thinning of Pipe Walls in Nuclear Power Plants, July 9, 1987. (1400/0304)

5.

NSP-07-33, Loss of Offsite Power with Delayed AFW Analysis Results

6.

Calculation ENG-ME-443, latest Rev, Condensate Storage Tank Sizing

7.

WCAP-11525, Probabilistic Evaluation of Reduction in Turbine Valve Test Frequency, June, 1987. (1729/0009)

8.

Letter, D C DiIanni (NRC) to D M Musolf (NSP) Amendment Nos. 86 and 79 to Facility Operating Licenses Nos. DPR-42 and DPR-60: Turbine Valve Test Frequency Reduction (TACS Nos. 66867 and 66868), February 7, 1989.

(1664/2491)

9.

PI0-01-06, Analysis Report - Structural Analysis of Main Steam Check and Isolation Valves for Prairie Island Unit 1, September 14, 1973 (7346/515)

10. 09Q4836-CAL-003, Updated Structural Analysis of Main Steam Check and Isolation Valves

11. 09Q4836-CAL-002, Updated Disc Impact Analysis of Main Steam Check and Isolation Valves

12. NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, May 2, 1989. (1771/0376)

13. Westinghouse Owners Group Report, Update and Evaluation of BB-95/96 Turbine Valve Failure Data Base, March 1999 (Westinghouse Letter WOG-TVTF-99-007, March 24, 1999) (see PI copy of WCAP 11525).

14. NSPNAD-8606, Auxiliary Feedwater System Reliability Study, Rev. 0, April 1986, [Location: Library Manual and film at 1270-645].

15. PI0-02-03, Analysis Report Maximum Energy of Disc Impact Main Steam Check and Isolation Valves for Kewaunee Unit 1, dated December 23, 2009.

01477171

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 Page 11.10-2 THIS PAGE IS LEFT INTENTIONALLY BLANK

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 TABLE 11.1-1 STEAM AND POWER CONVERSION SYSTEM COMPONENT DESIGN PARAMETERS (Page 1 of 3)

Turbine-Generator Turbine Three element, tandem-compound four-flow exhaust Turbine Capacity KW Maximum guaranteed 583,722 (Unit 1); 575,642 (Unit 2) (Note 1)

Maximum calculated 591,988 Generator Rating (Kva) - Unit 1 659,000 Generator Rating (Kva) - Unit 2 730,000 Turbine Speed (rpm) 1800 Condensers Type Double flow, single pass deaerating Number 2

Steam Load, Lb./hr.

4,111,711 BTU Rejected per hour (total condenser A & B) 3,873,616,764 Absolute Pressure, Ins. Hg.

Cond. A - 1.82 Cond. B - 1.28 Percent Cleanliness 85 Circulating Water Temperature, °F 60 Circulating Water Quantity, gpm 294,000 Water Velocity, fps 8.49 Friction in Water Circuit, ft.

35.7 Guaranteed 02 Content, CC/liter 0.003 Notes:

(1) For various turbine / condenser / reheat heat balance gross loads see Figures 11.2-1 through 11.2-5.

01435983

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 TABLE 11.1-1 STEAM AND POWER CONVERSION SYSTEM COMPONENT DESIGN PARAMETERS (Page 2 of 3)

Condensate Pumps Type Multi-stage, vertical, pit-type, centrifugal Number 3

Design Capacity (each-gpm) 5250 Motor Type Vertical Motor Rating (hp) 1750 Feedwater Pumps Type High speed, vertically split single stage, double suction centrifugal Number 2

Design Capacity (each-gpm) 8600 Motor Type Horizontal Motor Rating (hp) 5000 Heater Drain Pump Type Multi-stage, vertical, can-type centrifugal Number 3

Design Capacity (each-gpm) 2800 Motor Type Vertical Motor Rating (hp) 500

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 TABLE 11.1-1 STEAM AND POWER CONVERSION SYSTEM COMPONENT DESIGN PARAMETERS (Page 3 of 3)

Emergency Feedwater Source Three 150,000 gallon condensate storage tanks. Alternate supply from the cooling water system.

Auxiliary Feedwater Pumps 2 total. One steam turbine-driven pump and one electric motor-driven pump.

Design Capacity (gpm) 200 (turbine driven) 200 (motor driven)

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 23 TABLE 11.1-2 STEAM AND POWER CONVERSION SYSTEM CODE REQUIREMENTS System Pressure Vessels ASME VIII*

Steam Generator Vessel See USAR Table 4.1-11 System Valves, Fittings and Piping USAS B31.1, 1967**

American Society of Mechanical Engineers, Boiler and Pressure Vessel Code.

Section VIII. (The Code version applicable to that which was in effect at the date of placement of order for each individual component).

• • Code for Pressure Piping.01-010 01-010

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 18 TABLE 11.1-3 STEAM AND POWER CONVERSION SYSTEM SINGLE FAILURE ANALYSIS Component or System Malfunction Comments and Consequences Auxiliary Feedwater System Auxiliary feedwater pump fails to start (following loss of main feedwater)

One full-capacity steam driven pump and one full-capacity motor-driven auxiliary feedwater pumps are provided. Hence either of the two auxiliary feedwater pumps provide the required flow of feedwater.

Steam Line Isolation System Failure of steam line isolation valve to close (following a main steam line rupture)

Each steam line contains an isolation valve and a non-return valve in series. Hence a failure of an isolation (or non-return) valve will not permit the blowdown of more than one steam generator regardless of the steam line rupture location.

Bypass and Atmospheric Steam Dump System Steam dump valve sticks open (following operation of the system resulting from a turbine trip)

This steam dump system comprises one steam bypass valve and four atmospheric dump valves. One valve will only pass 12% of the maximum calculated steam flow and there is no hazard in the form of an uncontrolled plant cool down if a steam dump valve sticks open.

99057

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 27 TABLE 11.9-1 CRITERIA FOR AUXILIARY FEEDWATER SYSTEM DESIGN BASIS CONDITIONS3 Condition or Transient Classification1 Criteria1 Additional Design Criteria Loss of Main Feedwater Condition II Peak RCS pressure not to exceed design pressure. No consequential fuel failures Pressurizer does not fill with 1 single motor driven aux. feed pump feeding 2 SGs.

Loss of Offsite Power (LOOP)

Condition II (same as LMFW)

Pressurizer does not fill with 1 single motor driven aux. feed pump feeding 2 SGs.

Feedline Rupture Condition IV 10CFR100 dose limits.

Containment design pressure not exceeded Core does not uncover Steamline Rupture Condition IV 10CFR100 dose limits.

Containment design pressure not exceeded Loss of all A/C Power N/A Note2 Same as LOOP assuming turbine driven pump Loss of Coolant Condition III 10CFR100 dose limits 10CFR50 PCT limits Condition IV 10CFR100 dose limits 10CFR50 PCT limits Cooldown N/A 100F/hr 547F to 350 OF 1 Ref:

ANSI N18.2 2 Note: Although this Transient establishes the basis for AFW pump powered by a diverse power source, this is not evaluated relative to typical criteria since multiple failures must be assumed to postulate this transient 3 Note: These criteria and conditions/transients were used for determining the performance capabilities for AFW and may be different than those used to analyze design basis accidents and transients in Section 14.05-002 05-002

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 TABLE 11.9-2

SUMMARY

OF ASSUMPTIONS USED IN AFWS MINIMUM FLOW EVALUATION (Page 1 of 2)

Input Loss of Normal Feedwater or Loss of Off Site Power Cooldown Main Feedwater Line Break (Not isolated from SG)

Main Steam Line Break (Containment)

Initial Reactor Power (%)

1683 MWt 1683 MWt 1683 MWt Most limiting as determined in the analysis Time Delay from event to Rx Trip 15 seconds after Lo-Lo SG Level signal N/A Time for containment pressure to reach 4 psig +

time delay for rod insertion Time for containment pressure to reach 4 psig +

time delay for rod insertion.

AFWS Actuation Signal Lo-Lo SG Level N/A SI SI Time Delay for AFWS flow (after initiating signal) 60 seconds N/A 10 minutes None (for containment pressure response)

Initial SG liquid level 55% Narrow Range Level Nominal Nominal Greater than maximum operational band

1. of SGs which receive AFW flow 2

2 1

• 1

• AFW Temperature 100°F 100°F 100°F 100°F AFW flow rate 190 gpm Variable (as necessary for plant cooldown) 180 gpm AFW flow is initially maximized for core and containment pressure analyses. Minimum AFW flow is variable and corresponds to the flow rate used for decay heat removal.

01183316

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 31 TABLE 11.9-2

SUMMARY

OF ASSUMPTIONS USED IN AFWS MINIMUM FLOW EVALUATION (Page 2 of 2)

Input Loss of Normal Feedwater or Loss of Off Site Power Cooldown Main Feedwater Line Break (Not isolated from SG)

Main Steam Line Break (Containment)

MFW Purge Volume/Temp.

Included in Computer Model N/A Included in Computer Model Included in Computer Model Operator Action N/A (immediately)

Control Cooldown Rate Start Pump and Realign AFW flow path within 10 minutes Start Pump and Realign AFW flow path within 10 minutes RCP Status**

Running for LONF/

secured for LOOP Secured Running Running Sensible Heat See Cooldown Table 11.9-3 See Cooldown See Cooldown Decay Heat ANS 5.1-1979 + 2 Sigma Reference 6 120% of ANS 5.1-1971 120% of ANS 5.1-1971 or ANS 5.1-1979 + 2 Sigma Time at standby/time to cooldown to RHR See Cooldown 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s/6 hours See Cooldown See Cooldown Initially the faulted SG receives the AFW flow. Following the system flow path realignment, the intact SG receives the AFW flow.

Availability of RCPs is a function of whether or not off-site power is available. For each transient, it is determined if it is worse to maintain off-site power or loss off-site power.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 0 TABLE 11.9-3

SUMMARY

OF SENSIBLE HEAT SOURCES Primary Water Sources (initially at rated power temperature and inventory)

RCS fluid Pressurizer fluid (liquid and vapor)

Primary Metal Sources (initially at rated power temperature)

Reactor coolant piping, pumps and reactor vessel Pressurizer Steam generator tube metal and tube sheet Steam generator metal below tube sheet Reactor vessel internals Secondary Water Sources (initially at rated power temperature and inventory)

Steam generator fluid (liquid and vapor)

Main feedwater purge fluid between steam generator and AFWS piping.

Secondary Metal Sources (initially at rated power temperature)

All steam generator metal above tube sheet, excluding tubes.

PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 0 THIS PAGE IS LEFT INTENTIONALLY BLANK

603000001331 CAD FILE:

FIGURE 11.1-1 REV. 35 U11101.DGN 464 474 475 CS 46309 PI 17002 DPI 17652 CS 46127 PT 17003 1" FROM TRAP

" RESTRICTION "L" GLAND STEM DRAIN NF-98894 6" RUPTURE DISC 820 NF-98894 P

21116 P

21117 PI 41211 02 SHIELD WALL PI 483 PI 478 PI 479 PI 483 32" 32" 1-MS-1 1-MS-2 M

3"

-MS-64 M

M 1 -MS-62 M

10-MS-13 16-MS-13 10-MS-9 10-MS-10 16-MS-10 10-MS-12 16-MS-12 14-MS-19 10-MS-20 10-MS-19 BELLOWS 14-MS-20 VENT SILENCERS 10-MS-17 16-MS-17 10-MS-14 10-MS-15 16-MS-15 10-MS-18 16-MS-18 10-MS-16 16-MS-16 1-MS-2 10-MS-11 16-MS-11 16-MS-9 16-MS-14 11711 PI

" PLUG REGULATOR

" PLUG

-MS-63 1"

S 30-MS-4 30-MS-3 6-MS-29 1-MS-56 12-MS-4 12-MS-3 30-MS-4 10-MS-27 16-MS-36 1-MS-40 30-MS-3 20-MS-4 PI 41210 04 1-PI 484 1B CONDENSER (III/3) 6-MS-35 8-MS-35 SPRAY PIPE 1A CONDENSER (III/3) 6-MS-37 11177 16-MS-37 6-MS-36 12-MS-36 12-MS-35 (III/3)

STOP VALVES 11176 8-MS-27 1-MS-34 16-MS-36 11459 8-MS-27 2-MS-34 1"

6" 6-MS-29 1-MS-29 PI 41211 01 (II/3)

PI 41212 02 P

21115 18371 1-MS-38 1-MS-28 6-MS-28 (II/3)

(II/3) 6-MS-38 1-MS-38 18370 PI 41212 01 1-MS-39 1-MS-39 6-MS-39 (II/3) 6-MS-38 6-MS-28 CS 46400 2ND STAGE (III/3)

CS 46402 ES 46401 6-MS-39

-MS-31

-MS-33

-MS-68 1-MS-68

-MS-59

-MS-32 CS 46396 1A/2A 1B/2B 4-MS-31 CS MS-9-3 11872

-MS-31 3-MS-30 11389 PI PI PI PI PI DPI DPI A

A A

B A

12" 12" A

B A

A A

PI 41210 03 1-MS-66 1-MS-67 24-MS-24 8"

8" 8"

8" 16-MS-22 16-MS-23 16-MS-26 TE-13131 16-MS-25 TE-13114 TE-13113 14-MS-16 14-MS-14 818 14-MS-17 817 815 1-MS-71 14-MS-15 14-MS-18 816 819 1"

14-MS-10 14-MS-12 1-MS-75 1FE 814 812 14-MS-9 14-MS-11 14-MS-13 VENT TO ATMOSPHERE THRU ROOF TE-13075 TE-13080 TE-13073 TE-13074 TE-13078 TE-13088 1FE 810 1FE 811 1FE 813 1FE NF-39233 30-MS-1 31084 CV 31089 CV 1-MS-1 D

F-11 6-MS-1 6-MS-2 2"

2" 2"

2" 2"

TE-13092 TE-13091 TE-13090 TE-13089 TE-13111 TE-13112 D

30-MS-2 2"

2" 2"

2" 27017 23014 23013 4113902 4113901 30-MS-1 CONTAINMENT VESSEL 11323 4113701 469 1PT 482 1PT 3-MS-1

-MS-57 30-MS-1 6A 6B 1"

TE-15053 1-MS-53

}

1-MS-54 3-MS-5 1-MS-58

-MS-48

-MS-49 3-MS-6

-MS-52

-MS-51 EXHAUST HEAD 10-MS-8 6-MS-8 6-MS-7 STM RING DRAIN CASING DRAIN

-MS-50 1-MS-47 1-MS-51 10-MS-7 THROT VLV

-MS-65

-MS-47 30-MS-2 30-MS-2 4113801 4113802 4113803 11324 478 1PT 479 1PT 483 1PT 21204 21205 31-MS-2 30-MS-3 3-MS-87

-MS-60 30-MS-4 24-MS-21 DPI 18368 27254 FE 8"

1" DPI 18369 FE 27155 6"

FE 27256 M

M 46395 11873 PI M

M M

M M

M 4-MS-35 4-MS-35 (III/3)

(III/3)

TE-15056 TE-15055 P

21035 P

21036 484 1PT 21199 41132 HP TURBINE LP TURBINE LP TURBINE XH-2-15, 16 1"

1" 1"

1" 6"

1" 6"

6" EJECTOR (TYP)

LP HP 1"

& ABANDONED IN PLACE. CV-31093 A

463 461 462 A

471 472 473 A

A 4113301 24080 4113302 24081 4113303 24082 24084 24085 24086 4113403 4113402 4113401 1LR 460 487 487 B

A 488 488 A

B 1LR 470 MS-125-16 V

V V

V MS-125-18 MS-125-19 MS-125-17 MS-302-11 MS-125-20 MS-125-23 MS-125-21 MS-125-22 MS-302-12 CONT V

V V

V MS-302-13 MS-125-24 MS-125-25 MS-302-14 MS-125-26 MS-125-27 MS-125-28 MS-125-29 MS-302-15 MS-125-31 MS-125-30 MS-302-16 1LI 1LI 1LI 1LI 1LI 1LI 1FE 1FE 1FE 1FE 1FE 1FE 1FE FI FI 1FT 475 1FT 474 1FT 496 4114003 4114002 21203 21202 21201 23016 23015 4114001 4113703 42068 4113702 HI LO 1"

21012 PT 11427 PI 21013 PT 1"

11426 PI 1-MS-41 67 7

62 62 4"

8" 12" 32355 MV 32328 MV 32327 MV 31382 CV 32358 MV 31101 CV 31182 CV 31183 CV 32010 MV 31083 CV 32006 MV 31656 CV 32316 MV 32317 MV 31096 CV 31097 CV 31094 CV 31095 CV 31099 CV 32017 MV 31098 CV 32045 MV 32016 MV 31059 CV 31998 CV 31090 CV 31085 CV 31091 CV 31086 CV P

21114 4"

1" 11 CNDSR WTRBOX EJCTR (III/3) 2" 2"

V 1"

1" 6" ON 30" FLANGED LENAPE NOZZLE (TYP)

SAFETY RLF VALVES 1"

1" 6"

6" CONT RE FE 27257 6"

4" HI LO RE D

1" 31100 CV HS-12-4 2"

10" 4"

4" 8"

1ST STAGE EJECTORS 1

2 3

1" DRAIN

-MS-46 1"

3-MS-86

-MS-61 32047 MV 1-MS-55 3-MS-2 31-MS-2 16-MS-20 16-MS-19 31-MS-1 31-MS-1 SV-33299 506 1PI 507 1PI 11 AIR EJECTOR CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT (TYP)

CONT CONT CONT CONT ATM E-9 NF-39233 5"

5" ATM 4113903 6"

51 52 VENT TO ATM 1"

(TYP)

NF-39226 6"

(TYP)

ORIFICE C-12 NF-39233 C-3 NF-39233 F-11 NF-39233 E-12 NF-39233 D-4 NF-39244 C-11 NF-39233 G-4 NF-39222 G-4 NF-39222 F-11 NF-39233 F-9 NF-39233 F-10 NF-39233 F-10 NF-39233 F-10 NF-39233 F-1 NF-39233 C-2 NF-39233 C-4 NF-39233 NF-39233 C-9 F-2 NF-39605-1 A-9 A-8 NF-39224 C-2 NF-39233 C-2 NF-39233 C-2 NF-39230 C-10 NF-39233 C-2 NF-39230 F-4 NF-39230 F-3 NF-39230 F-2 NF-39605-1 (TYP)

NF-39224 C-2 NF-39233 F-11 NF-39233 C-9 NF-39247 REFERENCE DRAWINGS:

NF-39222 - AF SYS FLOW DIA. UNIT 1 NF-39230 - AR SYS FLOW DIA. UNIT 1&2 NF-39244 - SA SYS FLOW DIA. UNIT 1&2 NF-39247 - CG SYS FLOW DIA. UNIT 1&2 NF-39233 - TD SYS FLOW DIA. UNIT 1 NF-39226 - HD SYS FLOW DIA. UNIT 1 NF-39224 - BL SYS FLOW DIA. UNIT 1 NF-39605 HS SYS FLOW DIA. UNIT 1&2 F-2 NF-39605-1 B-9 B-7 B-6 B-8 A-8 B-9 B-7 B-11 1"

8" A-5 B-6 B-7 B-8 6"

7 67 THRU CONNECTION NUMBER.

7. CS4304S DELETED. E/P DISCONNECTED MANUALLY OPERATED ONLY.

NOTE 7 (TYP 3)

F-2 NF-39605-1 1"

3" 31093 CV D-10 NF-39215-1 1"

1" 1"

8" 8"

8" 4"

6-MS-29 LO LO LO LO LO LO 27018 1FE 474 145-201 (III/3)

TD AFWP 11 (III/3)

MOISTURE SEPERATOR 2B (III/3) 2B REHEATER (III/3) 1B REHEATER (III/3)

MOISTURE SEPERATOR 1B (III/3) 2A REHEATER (III/3)

MOISTURE SEPERATOR 2A (III/3) 1A REHEATER (III/3)

MOISTURE SEPERATOR 1A 134-012 (I/1)

GENERATOR STEAM 12 134-011 (I/1)

GENERATOR STEAM 11 LEVEL ALARM PIPING ON THIS DWG FOR SEE DETAIL "A" NF-39215 CR SYS FLOW DIA. UNIT 1&2

8. DENOTES FURNISHED WITH EQUIPMENT.

9. DENOTES CONDENSER TERMINAL

10. DENOTES CONTAINMENT PENETRATION NUMBER 8-MS-35 3"

3" A-8 XH-248-1-1 A-7 XH-248-1-1 XH-248-1 SM SYS FLOW DIA. UNIT 1&2 1"

C-2 NF-39233 3-MS-5 V

V 468 1PT 21200 1FT 465 1FT 464 1FT 494 1LT 487 1LT 460 1LT 470 1LT 488 473 1LT 472 1LT 471 1LT 463 1LT 462 1LT 461 1LT SG LEVEL CONTROL & ALARM PIPING DETAIL "A" V

MS-302-18 1LT 503 CONT 1LI 1LI MS-302-9 MS-302-17 V

1LT 502 CONT 1LI 1LI MS-125-34 MS-125-35 MS-125-32 17001 PI 17651 DPI C-3 NF-39233 C-2 NF-39230 C-9 NF-39233 IB C2 SR IB IB C2 SR IB IB IIA C2 SR IB IB NSR C2 IB IIA C3 C2 IB IC IB III C2 NSR C2 SR IB IB IB IIB NSR C2 IB IIB NSR C2 IB IC NSR C3 IC IIA C2 C3 IC SR IC C3 NSR III NSR C2 IB IIA CS 46128 CS 46308 IC C3 NSR IIB IB C2 NSR III MS-125-6 MS-125-7 SR IB IB C2 NSR C3 IC IIA NSR IC III C3 IC C3 NSR IIB NSR IC IIA C3 NSR IB IIA C2 IB IIB NSR C2 NSR IB III C2 30-MS-3 C-9 NF-39247 NSR C2 IB III 30-MS-1 IB IIB NSR C2 NSR C2 IB IIB IB IIB NSR C2 IB III C2 NSR CONT IB IIB NSR C2 NSR C2 IB IIB IB IIB NSR C2 NSR C2 IB IB III C2 NSR NSR IB IIA C2 NSR IC IIB C3

}

}

NSR III C2 IB C2 NSR IB C2 NSR IB C2 IB 1-MS-72 1-MS-73 IIA IIA IIA IIA IIB IIA IIB IIA IIB IIA IIB IIB IIA IIA

}

3" III III III III IIA III IIB IIA III IIA IIA IIA III III

}

IIA IIA IIA IIA III IIB IIB 3"

3" RS-19-2 TD-24-4 RS-22-2 TD-24-3 RS-15-1 TD-15-7 TD-15-5 RS-22-1 TD-24-2 RS-19-1 TD-24-1 MS-24-1 MS-22-3 RS-15-2 TD-15-4 TD-15-2 MS-20-7 TD-13-1 MS-41-11 MS-20-4 SS-2-4 SS-2-3 SS-2-2 SS-2-1 TB-123-2 TB-6-2 MS-145-7 MS-125-1 RS-10-1 TB-6-1 TB-123-1 HS-12-5 MS-38-1 TD-6-11 TD-6-12 MS-42-1 1GST-1 TD-16-1 MS-20-6 RS-20-3 RS-20-1 HS-93-1 MS-36-3 RS-20-2 RS-12-3 IIA RS-9-2 TD-25-2 MS-9-4 RS-9-1 MD-12-1 MS-115-3 AR-13-1 AR-13-2 MS-29-3 MS-29-2 MS-29-1 MS-34-1 MS-28-4 MS-33-3 MS-26-3 MS-33-2 MS-28-3 MS-28-2 MS-26-2 MS-33-1 MS-26-1 MS-40-1 TD-13-2 MS-28-1 MS-20-5 MS-31-1 MS-25-1 MS-30-1 MS-39-1 MS-32-1 MS-113-1 TD-6-40 MS-115-2 TD-10-12 TD-13-6 RS-3-1 MS-5-1 RS-5-2 RS-2-1 TD-11-9 RS-11-2 RS-11-1 TD-11-5 RS-13-1 MS-115-1 RS-8-1 RS-7-1 MS-145-4 TD-4-1 MS-125-2 MS-125-3 MS-145-3 MS-125-4 MS-125-13 MS-302-5 MS-125-5 MS-125-14 MS-302-6 MS-125-12 RS-18-6 RS-18-8 RS-18-5 RS-18-7 MS-302-7 MS-125-15 MS-302-8 RS-18-3 RS-18-4 RS-21-7 RS-21-6 RS-21-9 RS-21-8 RS-21-10 MS-36-2 RS-21-4 MS-36-1 RS-4-1 RS-4-2 MS-41-10 MS-41-7 MS-41-4 MS-41-2 RS-21-3 RS-21-5 RS-21-2 RS-21-1 MS-41-1 MS-302-3 MS-302-4 MS-125-11 MS-125-10 MS-302-2 MS-302-1 MS-125-9 MS-125-8 RS-18-2 RS-18-1 MS-41-5 MS-41-3 MS-41-8 MS-41-6 RS-16-2 RS-16-1 MS-41-9 RS-6-1 RS-6-2 RS-6-3 RS-16-4 RS-16-3 RS-6-4 RS-17-1 RS-17-5 RS-1-1 MS-145-13 MS-145-14 MS-145-10 MS-145-11 MS-145-16 MS-145-15 MS-145-17 RS-17-7 RS-17-2 RS-1-3 RS-1-2 RS-17-3 RS-17-6 MS-145-18 MS-145-8 MS-145-9 MS-145-20 MS-145-19 RS-17-8 RS-17-4 RS-1-4 C2 NSR (I/I)

FLOW NOZZLE IIA IB C2 NSR HP VENT HP VENT IIB IIA (TYP)

(TYP)

}

30" 30" 30" 30" 36"36" 36" 36" 1"

8" 8"

1" A-7 (TYP)

B-7 NF-39224 8"

8" B-5 8"

8" (TYP)

B-10 NF-39224 TD-25-3 A-11 F-10 NF-39233 F-12 NF-39233 1"

MS-145-6 MS-113-2 JET (III/3)

1. 11 HOGGING JET (III/3)

1. 12 HOGGING F-3 NF-39230 F-4 NF-39230 V

V V

V 1-MS-69 MS-113-3 SEE NOTE 6 134-012 (I/1)

GENERATOR STEAM 12 134-011 (I/1)

GENERATOR STEAM 11 IIB 6-MS-31 NOTES:

3.

DENOTES CATEGORY I LEGEND VENTILATION ZONE

4. FOR SYMBOLS SEE XH-1-105, NF-39214.

DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

5.

C2 NSR CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS

6. SHELL SIDE C2, TUBE SIDE C1.

IB QA TYPE CLASS BREAK IA,IB,IC,IIA,IIB & III DENOTES PIPING QA TYPES.

A-5 XH-2-15 A-4 XH-2-15 MS-103-2 MS-103-1 III 6"

C2 SR IB IB C2 NSR IB C2 NSR IB C2 SR IB IB NSR C2 SR IB IB NSR C2 SR IB IB C2 NSR IB MS-302-10 MS-125-33 C2 NSR IB NOTE 11 NOTE 11

11. SR/NSR BOUNDARY @ INSTR. VLV. MANIFOLD.

494 1-FI 11710 PI PI 482 LP LP LP 469 PI 468 1PR PI 482 PI 468 LP LP LP 496 1FI 465 FI 464 FI B-8 (TYP.)

NF-39224 11 AIR EJECTOR CONDENSER 1"

1" 1"

CONN SS-10

" SMPL CONN SS-11

" SMPL TE-13132 DWN: JEK 6-5-13 CHKD: RTC 6-11-13 AS BUILT-80 MOD#: EC-20923 ADDED 11 AIR EJECTOR CONDENSER & REDUCERS TO 1" LN TO SMPL CONNS SS-10

& SS-11. CHANGED 1" TO "

PER DRR PI-13-091 APPD: CMR 6-11-13 FOR THE SMPL CONNS FOR CHANGED " TO 1" FOR SS-10 & 11 CONTINUATION.

SPLY LN SIZE FOR 1ST STG EJECTORS. CORRECTED LOCATION FOR CV-31085 &

CV-31086 & TE-13131 &

TE-13132 & CORRECTED VLV NO. FROM MS-33-1 TO MS-26-1.

1" DWN: LAB 11-20-14 CHKD: RTC 11-24-14 AS BUILT-81 MOD#: EC-12200 REPLACED CV-31382 WITH NEW SS VALVE. REPLACED MS-28-1 & MS-31-1 GLOBE CONFIGURATION AS SHOWN.

VALVES. REVD PIPE VALVES WITH NEW GATE PER DRR PI-14-167 APPD: CMR 12-2-14 DWN: JEK 11-9-15 CHKD: KB 11-9-15 AS BUILT-82 MOD#: EC-25879 CORRECTED VALVE NUMBER FROM RS-25-2 TO TD-25-2 AT GRID D-7.

PER DRR PI-15-164 APPD: KJW 11-9-15 TO 1LT-472 (SG-12)

TO 1LT-471 (SG-12)

TO 1LR-470 (SG-11)

TO 1LT-462 TO 1LR-460 "84" "84" DWN: MEA 4-29-16 CHKD: KB 4-29-16 AS BUILT-83 MOD#: EC-26307 SWAPPED CONNECTIONS FOR DUMP VALVES 11 GS ZONE A6.

PER DRR PI-16-126 APPD: DB 5-2-16 DWN: JEK 11-4-16 CHKD: JH 11-11-16 AS BUILT-84 MOD#: EC-23906 ADDED NEW INPUTS TO 1LR-460 AND 470 AND REMOVED FW CHART INPUTS 1LR-461/A AND C.

RECORDER COMPUTER PER DRR PI-16-234 APPD: DB 11-14-16 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

MAW 8-23-07 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1

5 6

4410 4221 CL SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 84 39218 NF-39218 NF-NSP GENERATION CAD NF-39218.DGN FLOW DIAGRAM MAIN AUXILIARY STEAM & STEAM DUMP UNIT 1 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

TE-15054

603000001331 CAD FILE:

FIGURE 11.1-2 REV. 35 U11102.DGN 2FE 464 474 475 CS 49618 CS 46600 PI 17005 DPI 17654 CS 46599 PT 17006

" RESTRICTION "L" GLAND STEM DRAIN 6" RUPTURE DISC 2-FE 820 PT 21118 PT 21119 PI 41706 02 SHIELD WALL 483 478 479 483 32" 32" M

-2MS-61 M

M M

10-2MS-9 VENT SILENCERS 16-2MS-9 11713

" PLUG REGULATOR

" PLUG 6"

-2MS-60 S

30-2MS-4 30-2MS-3 6-2MS-29 12-2MS-4 12-2MS-3 30-2MS-4 2-2MS-40 30-2MS-3 20-2MS-4 2-2MS-41 PI 41708 04 2-PI 484 6-2MS-35 8-2MS-35 SPRAY PIPE 6-2MS-37 11179 6-2MS-36 (III/3) 11178 8-2MS-27 11460 8-2MS-27 2-2MS-34 6-2MS-29 1-2MS-29 PI 41706 01 (II/3) 1B REHEATER (III/3) 1B MOISTURE SEPARATOR (III/3) 2B REHEATER (III/3) 2B MOISTURE SEPARATOR (III/3)

PI 41705 02 PT 21121 FE 27261 18373 1-2MS-38 1-2MS-28 6-2MS-28 (II/3)

(II/3) 6-2MS-38 1-2MS-38 18372 PI 41705 01 1-2MS-39 6-2MS-39 (II/3) 6-2MS-38 6-2MS-28 ES 46797 2ND STAGE (III/3)

CS 46799 CS 46798 6-2MS-39

-2MS-31

-2MS-33

-2MS-68

-2MS-32

-2MS-32 CS 46793 1A/2A 1B/2B 4-2MS-31 CS

-MS-31 3-2MS-30 11390 PI PI PI PI DPI DPI A

A B

A 30-2MS-3 12" A

B A

A A

PI 41708 03 1-2MS-68 1-2MS-69 8"

8" 8"

8" TE-13397 TE-13400 TE-13399 2FE 819 2FE 817 2FE 815 1-2MS-65 2FE 818 2FE 816 1"

1-2MS-64 2FE 814 812 1A MOISTURE SEPARATOR (III/3) 2A MOISTURE SEPARATOR (III/3)

TE-13389 TE-13388 TE-13395 2FE 810 2FE 811 2FE 813 2FE 30-2MS-1 31102 CV 31107 CV D

2" 2"

2" 2"

2" 30-2MS-1 TE-13392 TE-13391 TE-13390 TE-13393 TE-13398 D

30-2MS-2 2"

2" 2"

2" TE-13396 27019 27020 23018 30-2MS-1 CONTAINMENT VESSEL 11343 469 2PT

-2MS-45 30-2MS-1 HP VENTS 6C 6D 1-2MS-53

-2MS-48

-2MS-49

-2MS-52

-2MS-51 10-2MS-8 STM RING DRAIN CASING DRAIN

-2MS-50 10-2MS-7 THROT VLV

-2MS-65

-2MS-47 30-2MS-2 483 2PT 478 2PT 31-2MS-2 30-2MS-3 30-2MS-4 DPI 18374 27258 FE 1"

8" DPI 18375 FE 27259 FE 27260 22 HOGGING JET (III/3)

(III/3)

M M

46792 11976 PI M

M M

M M

M 4-2MS-35 4-2MS-35 (III/3)

(III/3)

P 21037 P

21038 484 2-PT 21214 41704 HP TURBINE LP TURBINE LP TURBINE 1"

1" 1"

1" 6"

10" 21 HOGGING JET 6"

1" EJECTOR (TYP)

LP HP 14-2MS-9 14-2MS-13 TE-13387 TE-13385 TE-13386 10-2MS-13 16-2MS-13 16-2MS-11 10-2MS-10 16-2MS-10 10-2MS-11 16-2MS-12 14-2MS-10 14-2MS-12 10-2MS-19 14-2MS-19 14-2MS-20 10-2MS-20 6-2MS-1 10-2MS-12 14-2MS-17 14-2MS-15 16-2MS-17 10-2MS-17 16-2MS-15 10-2MS-15 TE-13394 16-2MS-14 10-2MS-14 16-2MS-16 14-2MS-16 14-2MS-14 10-2MS-16 10-2MS-18 16-2MS-18 14-2MS-18 16-2MS-25 1-2MS-67 1-2MS-66 24-2MS-24 16-2MS-26 16-2MS-23 16-2MS-22 24-2MS-21 3-2MS-1 1-2MS-43 1-2MS-42 1"

THRU ROOF 8"

8" 8"

V V

4173503 23017 4173502 A

A 4173501 V

V V

V 1-2MS-46 1-2MS-57 4113103 4173102 4173101 42568 21208 21207 21206 HI LO D

3-2MS-5 3-2MS-1 V

V 17301 TT 3-2MS-6 6-2MS-7 NF-100034 V

V V

V 2FT 496 2FT 475 2FT 474 2FI A

A 2FI 474 2FR 4173803 4173802 4173801 4251001 A

LP 2PI 2PI 478 2PR 6-2MS-8 2PI PI PI 2"

31118 CV 16-2MS-37 12-2MS-36 12-2MS-35 8-2MS-35 100 101 102 103 104 105 106 107 16-2MS-36 10-2MS-27 TE-15059 TE-15060 PI PT PT 21019 11437 21018 11436 PI 12-2MS-36 12-2MS-35 30-2MS-3 30-2MS-4 32330 MV 31502 CV 32331 MV 31115 CV 31114 CV PT 21120 6-2MS-28 6-2MS-38 31112 CV 6-2MS-29 A

463 461 462 A

471 472 473 A

A 4173901 24088 4173902 24089 4173903 24090 24092 24093 24094 4174103 4174102 4174101 2LR 460 2LI 487 2LI 487 B

A 488 2LI 488 2LI A

B 2LR 470 V

V V

V V

V V

V 31113 CV CONDENSING CHAMBER (TYP) 2MS-302-10 2MS-125-16 2MS-302-9 2MS-125-18 2MS-125-17 2MS-125-20 2MS-125-19 2MS-125-21 2MS-125-23 2LI 2LI 2LI 2LI 2LI 2LI 32319 MV 32320 MV 6"

PI 11975 1"

32022 MV 32021 MV 31120 CV GLND STM PRESS REG STN XH-1002-44 3"

3" 3"

31410 CV

-2MS-32

-2MS-32 1"

2" 32361 MV 32364 MV 1"

1" 1"

31385 CV 1"

1" 1"

1" 2"

1-2MS-34 16-2MS-36 1"

1 2

3 V

14-2MS-11 V

V 20" EQLZG

& BYPASS LN 8"

23020 23019 4250401 3-2MS-5 12" 1"

1" 1"

1" 1ST STAGE EJECTOR 8"

4173201 4173102 21209 4173203 11344 21210 21211 45269 1 -2MS-2 30-2MS-2 3-2MS-2

-2MS-63

-2MS-62 3-2MS-87 1-2MS-55 1"

1-2MS-56 49619 2MS-125-4 2MS-125-5 2MS-125-6 NF-100034 1-2MS-58 1-2MS-51 1" DRAIN 3-2MS-86 1"

-2MS-44 1-2MS-54 31-2MS-1 BELLOWS 16-2MS-19 16-2MS-20 21 AIR EJECTOR CONT CONT SV-33300 CONT CONT (TYP)

CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT CONT ATM (TYP)

LENAPE NOZZLE 6" ON 30" FLANGED (III/3)

CONDENSER 2A (III/3)

CONDENSER 2B CONT (I/1)

GENERATOR STEAM 22 (I/1)

GENERATOR STEAM 21 ATM VENT TO ATM 1"

EXHT HEAD 5"

5" NF-39234 TD WTRBOX EJCTR (III/3) 21 CNDSR 6"

ORIFICE (TYP)

NOTES:

3.

DENOTES CATEGORY I LEGEND VENTILATION ZONE

4. FOR SYMBOLS SEE XH-1-105, NF-39214.

DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

5.

C2 NSR CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS 1

C-1 4

NF-3923 NF-39234 - TD SYS FLOW DIA. UNIT 2 E-11 NF-39234 245-201 (III/1)

TD AFWP 22 NF-39223 - AF SYS FLOW DIA. UNIT 2 NF-39225 - BL SYS FLOW DIA. UNIT 2 NF-39227 - HD SYS FLOW DIA. UNIT 2 NF-39230 - AR SYS FLOW DIA. UNIT 1&2 NF-39244 - SA SYS FLOW DIA. UNIT 1&2 NF-39605 HS SYS FLOW DIA. UNIT 1&2 C-11 NF-39234 C-3 NF-39234 F-11 NF-39234 E-10 NF-39234 E-10 NF-39234 E-10 NF-39234 F-2 NF-39605-1 C-4 NF-39234 C-9 NF-39234 1"

C-9 NF-39234 G-9 NF-39223 G-9 NF-39223 NF-39225 A-5 NF-39227 B-6 NF-39225 B-7 B-9 B-10 B-10 NF-39225 B-7 NF-39225 A-11 NF-39227 A-8 NF-39227 A-8 NF-39227 B-7 B-6 B-9 (TYP 4)

NF-39227 F-1 NF-39234 D-9 NF-39244 F-9 NF-39234 G-11 NF-39234 F-11 NF-39234 E-10 NF-39230 E-11 NF-39230 A-9 A-7 C-3 NF-39234 C-2 NF-39234 C-2 NF-39234 F-1 NF-39605-1 C-2 NF-39234 4"

D-8 NF-39215-1 E-8 NF-39215-1 C-2 NF-39234 C-8 NF-39230 NF-39605-1 E-1 C-9 NF-39234 C-9 39230 NF-C-9 (TYP 3)

NF-39230 NF-39225 NOTE 6 62 62 67 7

7 67 THRU

8. DENOTES FURNISHED WITH EQUIPMENT

10. DENOTES CONT PENETRATION NUMBER NF-39215 CR SYS FLOW DIA. UNIT 1&2 XH-248-1 SM SYS FLOW DIA. UNIT 1&2 NF-39247 - CG SYS FLOW DIA. UNIT 1&2 REFERENCE DWGS 31104 CV 31109 CV 31108 CV 31103 CV 31117 CV 32050 MV 32020 MV 31116 CV 32048 MV 32019 MV 31060 CV 31999 CV 31362 CV 31363 CV 31119 CV CONNECTION NUMBER

9. DENOTES CONDENSER TERMINAL 2FT 494 2FT 465 2FT 464 482 2PT 468 2PT 479 2PT 2MS-113-3 LEVEL ALARM PIPING ON THIS DWG FOR SEE DETAIL "A" HI LO 17653 DPI 17004 PI 2MS-125-1 2MS-145-3 2MS-125-2 2MS-125-3 2LT 502 2LT 487 2LT 460 463 2LT 2LT 488 2LT 470 2LT 503 CONT DETAIL "A" ALARM PIPING SG LEVEL CONTROL &

CONT 473 2LT 472 2LT 471 2LT 462 2LT 461 2LT 2"

1" 8"

8" 8"

1" 3"

3" 3"

1" 1"

C3 NSR NSR C3 NSR C3 NSR C3 NSR C2 NSR C3 SR C3 C2 NSR C2 C2 NSR C2 NSR NSR C2 C3 C3 C2 NSR NSR C2 C2 NSR IB C2 SR C2 C2 SR C2 C2 NSR C2 NSR NSR C2 C2 NSR NSR C2 B-12 (TYP)

NF-39247 PURGE CONN 1" VENT & N2 C2 NSR C2 NSR C2 NSR NSR C2 NSR C2 C2 C2 SR C2 C2 SR CLASS BREAK QA TYPE IB III OPERATED ONLY.

ABANDONED IN PLACE. CV-31502 MANUALLY

7. CS-43600 DELETED. E/P DISCONNECTED &

IA, IB, IC, IIA, IIB, III DENOTES PIPING QA TYPES.

CONT C2 NSR IB IB IIB IIB IB III IB IIB IB IIB IB IB IIB III IB IIB IB IIB IB NSR C2 IIB IB IIB IB IB IIB III IB NSR C2 IIA IB IB IB C2 NSR TE-15057 CS IC SR NSR C3 IC IIB IC IIB IIB IC IC III NSR III NSR C3 IC IIA IC IIA IC IC IB III IC IIA IB IC IB IIA III IB IB IB IB IB IB SR IB IB IB IB IB III IB SR IB IB CONT CNDSG CHAMBER (TYP) 6-2MS-2 IB IIA IB IIA XH-1002-44 STM PIPING TURB GLND 2A REHEATER 1A REHEATER (III/3)

(III/3)

IIA IIB IIA IIB IIB IIA IIB IIB IIA IIA IIA III IIB IIB IIA IIA IIA III IIA IIA IIA III IIA IIA IIA IIA III IIA IIA

• III IIB III III III 2TD-13-1 2TD-15-4 2TD-15-2 2MS-20-4 2MS-20-7 2MS-41-11 2MS-15-2 2MS-22-3 2MS-24-1 2TD-24-1 2TD-24-2 RS-22-3 2TD-15-7 2TD-15-5 RS-19-3 2SS-2-4 2SS-2-3 2SS-2-1 2SS-2-2 2TD-10-26 RS-19-4 2TD-24-4 RS-22-4 2TD-24-3 2MS-15-1 2TD-4-1 2MS-4-2 2MS-18-5 2MS-18-8 2MS-18-6 2MS-18-7 2MS-302-8 2MS-125-15 2MS-125-14 2MS-125-12 2MS-125-13 2MS-302-7 2MS-302-6 2MS-302-5 2MS-302-2 2MS-125-9 2MS-302-1 2MS-125-8 2MS-125-10 2MS-125-11 2MS-302-4 2MS-302-3 2MS-4-1 2MS-18-2 RS-21-12 2MS-18-1 RS-21-14 RS-21-11 RS-21-13 RS-21-15 2MS-41-5 2MS-41-1 2MS-41-3 2MS-41-4 2MS-41-2 2MS-36-1 2MS-41-7 2MS-41-9 2MS-36-2 RS-21-19 2MS-18-3 RS-21-17 RS-21-16 2MS-18-4 2MS-41-8 2MS-41-6 RS-21-20 RS-21-18 2MS-16-1 2MS-16-2 2MS-16-4 2MS-16-3 2MS-6-1 2MS-6-2 2MS-6-3 2MS-6-4 2MS-41-10 2MS-1-2 2MS-17-3 2MS-17-6 2MS-145-17 2MS-145-18 2MS-145-8 2MS-145-9 2MS-145-19 2MS-145-20 2MS-17-4 2MS-17-8 2MS-17-1 2MS-17-5 2MS-1-1 2MS-1-4 2MS-145-10 2MS-145-11 2MS-17-7 2MS-17-2 2MS-1-3 2MS-145-13 2MS-145-14 2MS-145-16 2MS-145-15 2MS-125-24 2MS-125-26 2MS-125-27 2MS-125-25 2MS-302-14 2MS-302-13 2MS-125-30 2MS-125-28 2MS-125-29 2MS-125-31 2MS-302-15 2MS-302-11 2MS-125-22 2MS-9-3 2MS-9-1 2MS-9-2 2MS-115-3 2MD-12-1 2HS-12-4 2TD-11-1 2MS-36-3 2HS-93-1 2MS-9-4 2HS-12-3 2MS-42-1 2-GST-1 2TD-6-11 2TD-6-12 2MS-38-1 2MS-20-6 2TD-16-1 2MS-20-3 2MS-20-1 2MS-20-2 2MS-13-1 2MS-8-1 2MS-7-1 2TD-11-5 2MS-10-1 2TD-11-9 2TB-123-1 2TB-6-1 2MS-145-7 2MS-145-6 2MS-125-7 2TB-123-2 2TB-6-2 2MS-11-1 2MS-11-2 2MS-115-1 2MS-5-1 2MS-3-1 2MS-2-1 2MS-5-2 2TD-13-6 2MS-115-2 2TD-10-12 2MS-29-3 2AR-13-1 2MS-29-2 2AR-13-2 2MS-29-1 2MS-34-1 2AR-12-3 2MS-28-4 2MS-33-3 2MS-33-2 2MS-33-1 2MS-28-3 2MS-28-2 2MS-26-3 2MS-26-2 2MS-26-1 2MS-30-1 2MS-40-1 2MS-28-1 2MS-39-1 2MS-25-1 2MS-31-1 2MS-32-1 2HS-95-1 2TD-6-41 2MS-113-1 2MS-20-5 (I/1)

FLOW NOZZLE 1"

1-2MS-47 30" 36" 36" 30" 30" 30" 36"36" 8"

8" 8"

1" 1"

1" B-5 NF-39225 B-8 NF-39225 B-11 NF-39225 8"

8" 8"

8" B-8 39225 NF-B-10 F-11 NF-39234 F-9 NF-39234 IIA IIA 2MS-113-2 2MS-145-4 2MS-103-1 2MS-103-2 A-6 XH-1002-43 A-5 XH-1002-43 VALVES STOP IIA IIB C2 234-011 (I/1)

GENERATOR STEAM 21 234-012 (I/1)

GENERATOR STEAM 22 SEE NOTE 6

6. SHELL SIDE C2, TUBE SIDE C1.

6" 6"

NSR C2 IB SR C2 IB IB NSR SR C2 IB IB NSR C2 IB NSR C2 IB IB IB NOTE 11 NOTE 11

11. SR/NSR BOUNDARY @ INSTR. VLV. MANIFOLD.

SEE NOTE 12 LINES AND CAPPED.

12. DPI 17564 IS DISCONNECTED FROM GAGE 2 1/2-2MS-85 2-2MS-85 468 2PI 2PI 482 DWN: JEK 4-3-12 CHKD: SMF 4-10-12 AS BUILT-84 MOD#: EC-17978 RELOCATED CHECK VALVE 2HS-93-1 AND SHOWED SOLID AND MOVED " x 1" REDUCER UPSTREAM OF 2MS-36-3.

PER DRR PI-12-062 APPD: CMR 4-11-12 1-2MS-68 21 AIR EJECTOR CONDENSER DWN: JEK 6-5-13 CHKD: RTC 6-11-13 AS BUILT-85 MOD#: EC-20923 ADDED 21 AIR EJECTOR CONDENSER.

PER DRR PI-13-091 APPD: CMR 6-11-13 DWN: JEK 10-10-13 CHKD: RTC 10-18-13 AS BUILT-86 MOD#: EC-12200 RELOCATED REDUCERS TO SHOW VLVS 2MS-31-1, 2MS-28-1 & CV-31385 &

ASSOCIATED PIPING AS 1" PER DRR PI-13-171 APPD: CMR 10-28-13 NSR IB III C2 V

2PI 506 2MS-126-1 2MS-142-1 2MS-142-2 1-2MS-3 NSR III V

2PI 507 2MS-126-2 2MS-142-3 2MS-142-4 1-2MS-4 IB C2 V

V 2MS-302-12 2MS-302-17 2MS-302-16 2MS-302-18 2MS-125-32 2MS-125-34 2MS-125-33 2MS-125-35 AS BUILT-87 PER DRR PI-14-062 CHKD: RWR 4-16-14 DWN: DB 4-15-14

& SC BRK PER EC 16812 4, 2MS-126-1,2, 2PI-506,7 PI ADDED VLV 2MS-142-1 THRU AS BUILT-APPD: CMR 4-16-14 MOD#: EC-16808 CHKD: RWR 4-16-14 DWN: DB 4-15-14 ADD SECONDARY SIDE INSTR

&VLVS 2MS-125-32 THRU 35, FOR 2LT487 & 488.

2MS-302-17,18. RELOC TIE-IN TO 2LT-471 (SG-22)

TO 2LT-472 (SG-22)

TO 2LR-470 TO 2LR-460 (SG-21)

TO 2LT-462 "89" DWN: JEK 11-20-15 CHKD: JLH 12-9-15 AS BUILT-88 MOD#: EC-23905 ADDED NEW INPUTS TO 2LR-460 AND 470 AND REMOVED FW CHART INPUTS 2LR-461/A AND C.

RECORDER COMPUTER PER DRR PI-15-170 APPD: KJW 12-18-15 "89" 496 2FI 494 2FI DWN: JEK 12-14-17 CHKD: RLM 12-14-17 AS BUILT-89 MOD#: 6DOCEDI23544 CORRECTED LABELING FOR 2FT-494 TO 496, 2FI-494 TO 496, 2FT-496 TO 494 AND 2FI-496 TO 494.

PER DRR PI-17-169 APPD: DB 12-14-17 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

MAW 8-28-07 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1

5 6

4410 4221 CL SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 89 39219 NF-39219 NF-NSP GENERATION CAD NF-39219.DGN FLOW DIAGRAM MAIN AUXILIARY STEAM & STEAM DUMP UNIT 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

11712 PI LP LP LP LP LP 465 2FI 464 2FR 465 2FR 482 2PI 2PI 469 2PR 468 474 2FE 21261 PT 21262 PT 21263 PT 21264 PT 21265 PT 21266 PT 21267 PT 21268 PT 52 2RE 51 2RE C-3 SS-210 XH-248-1 C-3 SS-211 XH-248-1 NF-39234 E-10 TE-15058

603000001331 CAD FILE:

FIGURE 11.1-3 REV. 35 U11103.DGN AZ MOD:

FILMED:

AS BUILT DWN: M.R.H. 01/16/95 CHKD:

REVISED DWG. TO REFLECT AS FOUND COND. ADDED DWG. REF.

NUMBER.

PER DRR: PI-94-196 MOD#:

DWN: DB CHKD:

AS BUILT-FILMED:

REVD. DWG. CONT. TO READ NF-39216-2.

PER DRR PI-95-123 BA MOD#:

DWN: JDS 11-5-97 CHKD: pas 1/29/98 AS BUILT-FILMED: 2/98 ADDED COLOR CODED HEAT TRACINGS.

PER DRR PI-97-120 BC MOD#:

DWN: BMS 2-8-99 CHKD: PAS 2-12-99 AS BUILT-CORRECTED COORDINATES A2 WAS H10 AND C8 WAS F1.

PER DRR PI-98-127 FILMED 2-99 BD F

M DWN: GPL 9-5-03 CHKD: CMR 9-10-03 AS BUILT-PER DRR PI-03-125 FILMED 9/03 BF MOD#:

CD-45-4 & CD-70-1 REVISED TO REFLECT NORMALLY OPEN.

G-2 NF-39222 TD AFWP TO #11 H-6 NF-39222 MD AFWP TO #12 H-3 NF-39223 MD AFWP TO #21 DWN: JK 10-20-08 CHKD: DB 8-21-09 AS BUILT-PER DRR PI-08-080 FILMED 9-09 76 MOD#: EC-13291 ADD DWG CONTS & GRID COORDINATES, NEW BORDER DEL REF MOTOR VALVES 04NS15 2"

REMOVABLE SPOOL PIECE (TYPICAL)

DWN: KJF 11-4-10 CHKD: JLK 11-11-10 AS BUILT-77 MOD#: EC-16990 REVISED TYP NOTE AT GRID F-11 PERTAINING TO REMOVABLE SPOOL PIECES.

PER DRR PI-10-175 APPD: CMR 11-17-10 16896 PS CD-59-18 OMITTED DETAILS SEAL ADDITIONAL DWN: JEK 6-28-12 CHKD: RTC 7-2-12 AS BUILT-78 MOD#: EC-20022 ADDED ISOLATION VALVE FOR PS-16896 & RELOCATED VALVE CD-59-2.

PER DRR PI-12-128 APPD: CMR 7-9-12 LEVEL LOW LEVEL HIGH 6"

III 6-DE-58 6"

6" 6"

VENT IIB BREAKDOWN ORIFICE IIB DRAIN TO GRADE 3"

TRACED BUILDING WALL 2

1" NOZZLE SPARGER 12" FLEXIBLE HOSE II B 6"

3" SEE NF-39221 STORAGE TANK #21 TO CONDENSATE MAKE-UP 3-DE-53 0603 47009 A

0106 47010 A

CONT.

PUMP RECYCLE LEVEL LOW LEVEL LOW-LOW 723 1LI-724 1LI-723 1LT-724 1LT-NF-39222 SEE CONT. ON 26299 TC 2-DE-64 SEE NF-157545 STORAGE TANKS WEST OF RMU SINK LOCATED GRAB SAMPLE 2"

4"

" TUBING 2"

12-DE-54 2-DE-54

-CD-32 LA-4-131 2"

LA-1-1 IIB 2"

LA-2-11 LA-2-81 10 LA-4-5 LA-4-107 LA-2-82 LA-2-12 LA-4-108 LA-4-6 LA-1-2 LA-3-1 10 IIB 16911 LA 16601 LA 0601 47009 A

0501 47009 A

CONDENSER (III/3) 1A LA-2-79 LA-2-9 LA-1-3 CONDENSER (III/3) 1B LA-4-1 LA-4-3 LA-4-105 16600 LA CONTROL 16912 LA CONTROL PMP. TRIP CONTROL 48310 S/CV 01 41223 LI 24004 L

NF-39239 CONN. SEE DWG.

" INST. TEST LA-1-4 LA-2-10 LA-2-80 LA-3-34 LA-4-4 LA-4-2 LA-4-106 CONDENSER LEVEL CONTROL & ALARM PIPING LOW PRESSURE TURBINE (III/3)

LOW PRESSURE TURBINE (III/3)

1. 13B F.W. HEATER (III/3)

1. 13A F.W. HEATER (III/3)

1. 14B F.W. HEATER (III/3)

1. 14A F.W. HEATER (III/3)

(III/3)

EXCHANGER #12 SGB HEAT COOLER (III/3)

1. 11B DRAIN COOLER (III/3)

1. 11A DRAIN

1. 12B F.W. HEATER (III/3)

1. 11B F.W. HEATER (III/3)

1. 12A F.W. HEATER (III/3)

1. 11A F.W. HEATER (III/3)

C-24-5 2" DRAIN C-39-3 C-29-1 C-27-1 CD-61-1 DE-60-2 CD-40-1 SEE NF-39247

" N BLANKETING ELECT. HEAT TRACED BUILDING WALL ELECT. HEAT SEE NF-39605-1 SYSTEM MAKE-UP PUMP 2" MAKE-UP TO #121 HEATING CD-50-2 CD-45-2 CD-52-1 DE-109-1 CD-60-1 DE-110-1 CD-24-7 T

TRAP VENT NF-39247 SEE N SUPPLY 2

2 N SPARGER ATM.

TO TU 723 1LC-TU 724 1LC-31959 CV CD-45-1 CD-39-14 4"

C-30-1 4-DE-54

-DE-63 C-23-1 C-23-3 C-23-2 CD-44-1 DE-59-3 2-CD-11 2-DE-57 2"

2" 2"

C-42-1 2-DE-12 C-34-5 26912 PC NF-39241 DEMINERALIZERS, SEE DWG.

CONDENSATE RECYCLE TO 2"

STR. TKS. SEE DWG. NF-39242 REACTOR MAKE-UP WTR.

CONDENSATE TRANSFER TO #11 & #12 4-DE-55 16800 FS 31001 CV CONTROL 1"

1-CD-11 1"

1" 1"

1" 1"

11089 PI 8

73 SPRAYS EXHAUST IIB IIB SPRAYS EXHAUST 1"

73 8

TE-15430 TE-15433 12025 TI 12034 TI 12" 16" 12" 16" 16" 16" C-6-1 C-6-2 C-39-8 CD-39-11 16-CD-7

-CD-23 16" 16" "

-CD-27 16-CD-7

-CD-22 16-CD-6 16" IIB TE-15429 12022 TI CD-39-7 CD-39-6 16" IIB

-CD-21 17376 TT 3-CD-34 16" 16" 16-CD-5 2"

CD-39-5

-CD-20 27001 FE 8-CD-4 TEST FLOW 18" 8"

16" 18" 18-CD-4 18" 12" 3-CD-34 4-CD-34 12"

-CD-24 12-CD-4 16"

" VENT CD-39-12 17377 TT 12024 TI CD-39-9

-CD-25 IIB 16" 16-CD-9 TE-15432 IIB CD-39-10

-CD-26 16" 1-CD-11 1"

C-5-1 C-37-1 C-37-2 C-37-3 12-CD-7 20-CD-7

-CD-28 20" 1"

1" 1"

1" 1"

CD-24-6 11451 PI 16801 FS 31002 CV CONTROL DWG. NF-39226 PUMP DISCH. SEE 14" HEATER DRAIN 16-CD-10 14" 20" 20" 16" 16" 20" 12" 16" 16" 12-CD-7 12-CD-10 16-CD-7 12-CD-7 12-CD-10 16" 16" 16-CD-10 12" 16" SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-13 17309 TT C-7-3 C-7-4 SS-4-6 C-8-2 C-8-1 C-7-1 C-7-2 16-CD-7 17311 TT 12026 TI 16047 PS TE-15434 TE-15435 TE-15436 TE-15437 IIB IIB IIB IIB 21023 P

42097 PR 41226 PI PUMP START CONDENSATE 20-CD-10 6-CD-34 20" CD-67-1 NF-88740 (C-7)

BLOWDOWN STEAM GEN.

CD-66-2 CD-65-2 CD-66-1 CD-57-1 CD-65-3 CD-57-2 CD-65-1 CD-39-15 C-39-1 C-11-2 SS-4-7 C-9-2 C-39-2 C-9-1 C-25-1 C-25-2 C-24-1 C-24-2 C-13-1 C-11-1 C-10-1 C-15-1 C-20-1 SEE DWG. NF-39226

& REHEATER DRAIN TANKS TO #1A & #1B MOIST. SEPS.

" INSTR. TEST LINE

& NF-39224 SEE DWG. NF-39226 TO #15A & #15B HP HTRS.

" INSTR. TEST LINE SEE DWG. NF-39226 PUMP SUB COOLING TO HEATER DRAIN TANK SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-14 TE-15431 31087 CV 11454 PI 12064 TI 16011 PS 11044 PI 27002 FE CONTROL 16010 PS 11043 PI CONTROL TEST FLOW CONTROL SET AT 550 P.S.I.G.

1"x2" RELIEF VALVE (THIS DWG.)

CONTROL & ALARM PIPING SEE CONDENSER LEVEL 2" DRAIN (TYP.)

4-CD-34 5-CD-34 5-CD-34 16-CD-36

-CD-41

-CD-36 16-CD-4 16-CD-8 16-CD-35

-CD-31 16-CD-10 1-CD-10 2-CD-10 2-CD-10 6-CD-10 16-CD-10 6-CD-10 16-CD-10 1-CD-10

-CD-35 6-CD-4 4-CD-4 6-CD-4 8-CD-4 18" 16" 16" 16" 16" 2"

16" 16" 16" 16" 16" 20" 4"

" 8" 8"

6" 8"

4" 6"

6" 6"

6" 6"

2"

" VENT

" VENT

" VENT D

D 39 37 38 IIB III IIB III IIB IIB IIB IIB TRANSFER PUMP (III/3)

1. 21 CONDENSATE RECYCLE &

RETURN TO CW 31996 CV SEE DWG. NF-39221 CONDENSATE TO UNIT 2, CD-72-1 CD-71-1 CD-70-1 CD-45-4 C-34-2 C-34-4 C-34-3 C-40-1 C-40-2 C-40-3 CD-51-1 CD-46-3 CD-46-1 T

CD-46-2 C-41-2 C-33-1 C-34-1 C-32-1 C-3-1 CD-39-4 DE-34-69 DE-29-5 CD-46-6 CD-46-4 CD-46-5 CD-46-7 CD-52-2 TRANSFER PUMP (III/3)

1. 11 CONDENSATE RECYCLE &

SEE DWG. NF-39236 TANK PUMPS FROM ADT MONITOR NF-39221 SYSTEM, SEE DWG.

UNIT 2 CONDENSATE 2"

2" 2"

2" 2-DE-57 PROT. WTR. HTR.

STOR. TNK. FRZ.

1. 121 COND. M-U DWG. NF-39605-1 3" STEAM, SEE 2"

1" 2-DE-57 2"

26301 TC PUMPS, SEE DWG. NF-39239 GLAND SEAL TO CONDENSATE CONT.

X X

X X

2" 2"

2" 2"

12"

-DE-63 1-DE-57 2-DE-63

-DE-64

-DE-63 2-DE-63 11112 PI 2"

2" 1"

DRAIN 2-DE-56 VENT VENT 2"

2" 2"

3" 3-DE-56 11587 PI 11586 PI 2"

1" DRAIN 8"

3" 4-CD-42 2-CD-42 2-CD-12 REST. ORIF.

4"x2" RED. w/

PIPE, NF-39216-2)

(4" COND. TO STAND-2-DE-56 8-DE-56 SPOOL PIECE 8"

4" 4"

4" 4"

4-DE-56 2"

" VENT 2-DE-54 8-DE-56 8"

12" 2"

IIB IIB IIB IIB SUPPLY & MAKE-UP CONDENSATE EMERG.

12" 12-DE-54 CONDENSATE MAKE-UP

1. 11, SEE DWG. NF-39253 @ LOC. C-11 2" TO BACKWASH WTR. M-U PUMP WATER MAKE-UP PUMP

" RECIRC. FROM BACKWASH C-11-3 27003 FE 23007 F

IN PLACE ABANDON CD-45-3 CONTROL 23009 F

23011 F

27013 FE 31123 CV 02 41222 FI 6-CD-12 4-CD-12 6-CD-2 6"

6"

" VENT 10" CAP 18" FLOW NOZZLE 46 11 10 1"

1" 12" 12-DE-54

-CD-19 18-CD-4 24" 18" 18" 18" 12" 18" IIB IIB IIB IIB 24" 18" 18" TE-15426 48668 T/U CONTROL SEE NF-39240-1 FEED INJECTION,

" CONN. FOR CHEM.

SEE DWG. NF-39253 POLISHING SYS.

TO & FROM COND./

48113 TE-15428 IIB IIB C-12-1 C-24-3 TE-15427 2-CD-4 2"

16" 16-CD-4 C-26-1 C-26-2 C-28-1 C-30-2 C-30-3 C-35-1 8"

8" 6"

6" 6"

3" 4"

4" 3"

4" 4-DE-54 12" 18" 31122 CV 31121 CV 32041 MV 12" 3-DE-54 46421 ES 4-DE-54 4"

9 13 LINE RECIRCULATING SPRAY PIPES COND. MAKE-UP IIB CONTROL 10" BREAKDOWN ORIFICE CONTROL 6-CD-4 17374 TT 16" 11453 PI 12062 TI 48099 S/CV 48114 27029 FE 42095 FR 48020 FI COUNTER DIGITAL LEGEND

- DENOTES EQUIPMENT Q.A. TYPE/DESIGN CLASS II/3

- DENOTES FURNISHED BY WESTINGHOUSE

• - DENOTES FURNISHED WITH EQUIPMENT 10

- DENOTES CONDENSER TERMINAL CONNECTION

- DENOTES THE PIPING Q.A. TYPES

- DENOTES LIMITS OF Q.A. TYPES

- DENOTES TIE-IN TO EXISTING SYSTEM

- DENOTES DISSIMILAR METAL IC-IIB-III REFERENCE PIPING DWG. NOS.

NF-39312-1, NF-39312-2 & NF-39312-3 LEVEL TROL & ALARM GAGE GLASS PIPING NF-39271-1, NF-39271-2 & NF-39271-3 CONDENSATE SYSTEM TURBINE BLDG.

• OVERFLOW

• GAGE GLASS (III/3)

STORAGE TANK MAKE-UP

1. 11 CONDENSATE H-7 NF-39223 TD AFWP TO #22 S

CONDENSER (III/3) 1A CONDENSER (III/3) 1B CONDENSER (III/3)

1. 11 GLAND STEAM

1. 11 AIR EJECTOR (III/3)

(III/3)

1. 11 FEEDWATER PUMP (III/3)

CONDENSATE PUMP

1. 11 (III/3)

CONDENSATE PUMP

1. 12 (III/3)

CONDENSATE PUMP

1. 13 CD-73-1 C-19-1 C-31-1 MD-9-4 C-22-2 C-24-4 C-36-1 CD-39-13 SS-4-26 C-11-4 C-22-1 C-2-1 C-1-1 C-14-1 C-2-2 C-1-2 MD-8-4 MD-7-4 MD-8-5 CD-47-1 CD-48-1 CD-19-3 CD-75-1 CD-75-2 CD-49-1 CD-47-2 CD-48-2 C-14-2 MD-7-5 CD-47-3 CD-48-3 C-2-3 C-1-3 MD-8-6 CD-75-3 C-14-3 MD-7-6 CD-74-1 MANOMETER (TYP.)

" TEST CONN. FOR TEMPORARY STRAINER (TYP.)

REMOVABLE SPOOL PIECE WITH EXPANSION JOINT (TYP.)

(TYP.)

DRNS.

TO FLR.

SUCTION VENTS DISCHARGE VENTS 12018 TI 16087 PS 21022 P

01 41221 PI CONTROL PLUG 18-CD-2 4"

4" 18" 18" 1"

1-CD-2 4"

1" 18" 18" (TYP.)

18-CD-2 (TYP.)

DRAIN 18-CD-2 18" 4"

24" MANWAY GLASS GAGE 1"

1-CD-2 30" 30-CD-1 3"

18" 1"

18" 3"

30" 2"

SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-34 SEE DWG. NF-39239 TO GLAND SEAL PIPING 11038 PS 11039 PS 11040 PS 18-CD-2 30-CD-1 2-CD-2 18" 1"

2" 18-CD-2 48" 3"

3" 18" 3"

30" 30-CD-1 48-CD-1 48" 2-CD-17 3-CD-13 IIB IIB IIB IIB IIB IIB IIB IIB IIB TE-15423 TE-15424 TE-15425 1"

3" 3"

3" 1"

1" 1-CD-14 1-CD-15 1-CD-16 1"

1" C-17-1 MD-8-1 MD-8-2 MD-8-3 MD-7-1 MD-7-2 MD-7-3 MD-9-3 MD-9-2 SS-4-5 SS-4-4 SS-4-3 SS-4-2 SS-4-1 SS-4-36 SS-4-35 SEE DWG. X-HIAW-248-1 SAMPLE CONN. SS-46 SAMPLE CONN. SS-47 SAMPLE CONN. SS-45 SAMPLE CONN. SS-51 SAMPLE CONN. SS-12 SAMPLE CONN. SS-50 SAMPLE CONN. SS-48 SPRAY PUMP

1. 11 CONDENSER CD-59-2 8-CD-34 MD-9-1 CD-53-2 CD-62-2 CD-54-1 CD-62-1 CD-53-1 11 11 12 61 50 3

3 50 10 61 50 52 30-CD-1 2-CD-1 4-CD-1 4" DRAIN 48" 30" 30" 2"

4" 2"

2" 2"

2-CD-18 3"

3" 3"

6" 6-CD-13 24-CD-1 30" 24" 4"

2" IIB IIB IIB IIB IIB IIB 1"

12020 TI 17011 PT 18-CD-3 C-4-2 C-4-1 17303 TT 17010 PT 18895 PI 18896 PI 6-CD-34 2-CD-34

-CD-34

-CD-34 SEE NF-39240-1 CHEM. INJECTION DRAIN CD-59-3 CD-56-1 CD-55-1 CD-59-4 CD-59-7 CD-58-1 CD-59-11 CD-55-2 CD-68-1 CD-69-1 CD-59-1 CD-59-8

• 24" CROSS OVER (III/3)

1. 12 FEEDWATER PUMP 18894 PI CD-59-5 CD-59-6 CD-59-9 PER DRR PI-00-220 BE AS BUILT-SHOW NORMAL POSITION OF VALVE CD-72-1 AS CLOSED.

REDRAW CDSR SPRAY PIPING TO ACCOMODATE ADDITION OF EXISTING VALVES. MOVED LEGEND AND REFERENCES.

DWN: BMS 2-14-01 CHKD: CMR 3/8/01 MOD#:

FILMED 3/01 DWN: JEK 1-28-13 CHKD: JCH 1-30-13 AS BUILT-79 MOD#: EC-20022 CORRECTED DRAWING CONTINUATION FROM NF-39241 TO NF-39241-8.

PER DRR PI-13-021 APPD: CMR 1-30-13 SEE NF-39241-8 FROM DEMINERALIZER 3" RECYCLE LINE SEE NF-39241-8 DEMINERALIZER 4" MAKE-UP FROM VENT 6"

NF-39247 (F8)

SUPPLY SEE NITROGEN BLANKET DWN: MEA 10-21-15 CHKD: RLM 10-23-15 AS BUILT-80 MOD#: EC-24671 ADDD NITROGEN BLANKETING ELIM. BELL ALARM AND ASSOCIATED WIRING.

PER DRR PI-15-134 APPD: KJW 10-28-15 16020 PS 16023 PS "81" "81" DWN: JEK 11-22-16 CHKD: MLM 11-28-16 AS BUILT-81 MOD#: EC-27246 ADDED PRESSURE SWITCHES 16020 AND 16023.

PER DRR PI-16-255 APPD: DB 11-28-16 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1

400 5

6 4410 7400 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 81 39220 NF-39220 NF-NSP GENERATION CAD NF-39220.DGN FLOW DIAGRAM CONDENSATE SYSTEM UNIT 1 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

6"

603000001331 CAD FILE:

FIGURE 11.1-4 REV. 35 U11104.DGN DELETED CONTROL SWITCH 46565 & 46781 INCORPORATED A/ES FOR CONSTRUCTION CHKD: PAS 11/11/94 DWN: WHS 11-3-94 CERTIFIED REV. "AV" CHKD: DPP DWN: LFP WJJ PE# 20013 PROJ#: 90L221 FILMED:

MOD:

CHKD:

DWN: M.R.H. 01/16/95 NUMBER.

COND. ADDED REF. DWG.

REFLECT AS FOUND PER DRR: PI-94-196 DWN: DB REVD. DWG. CONT. TO READ NF-39217-1 DWN: JDS 11-5-97 CHKD: pas 1/29/98 ADDED COLOR CODED HEAT TRACINGS.

MOD#:

DWN: BMS 2-15-01 CHKD: CMR 3/8/01 AS BUILT-SHOW NORMAL POSITION OF VALVE 2CD-72-1 AS CLOSED.

PER DRR PI-00-220 FILMED 3/01 AZ F

M SEE DWG.NF-39236 48-2CD-1 3-2CD-13 3-2CD-13 H-3 NF-39223 MD AFWP TO #21 H-6 NF-39222 MD AFWP TO #12 H-7 NF-39223 TD AFWP TO #22 DWN: JK 10-20-08 CHKD: DB 8-21-09 AS BUILT-PER DRR PI-08-080 FILMED 9-09 76 MOD#: EC-13291 ADD DWG CONTS & GRID COORDINATES, NEW BORDER DEL REF MOTOR VALVES 04NS15 REMOVABLE SPOOL PIECE (TYPICAL)

DWN: KJF 11-4-10 CHKD: JLK 11-11-10 AS BUILT-77 MOD#: EC-16990 REVISED TYP NOTE AT GRID F-11 PERTAINING TO REMOVABLE SPOOL PIECES.

PER DRR PI-10-175 APPD: CMR 11-17-10 16897 PS 2CD-61-18 OMITTED DETAILS SEAL ADDITIONAL DWN: JEK 6-28-12 CHKD: RTC 7-2-12 AS BUILT-78 MOD#: EC-20022 ADDED ISOLATION VALVE FOR PS-16897 & RELOCATED VALVE 2CD-61-2.

PER DRR PI-12-128 APPD: CMR 7-9-12 HOSE 12" FLEXIBLE COOLER (III/3)

1. 21A DRAIN

1. 22A F.W. HEATER (III/3)

1. 21A F.W. HEATER (III/3)

CONDENSER (III/3)

1. 21 GLAND STEAM

1. 21 AIR EJECTOR (III/3)

(III/3)

CONDENSATE PUMP

1. 21 (III/3)

CONDENSATE PUMP

1. 22 (III/3)

CONDENSATE PUMP

1. 23 2CD-73-1 2-2CD-11 2-2DE-9 2"

16-2CD-6 2CD-39-6 17378 TT 3-2CD-40 16" 16-2CD-5 2"

2CD-39-5

-2CD-34 27015 FE TEST FLOW 18" 8"

16" 18" TRANSFER PUMP (III/3)

1. 11 CONDENSATE RECYCLE &

SEE DWG. NF-39220 CONDENSATE TO UNIT 1, 2CD-72-1 2CD-71-1 2CD-70-1 2CD-45-4 C-34-6 C-40-4 2CD-39-4 TRANSFER PUMP (III/3)

1. 21 CONDENSATE RECYCLE &

NF-39220 SYSTEM, SEE DWG.

UNIT 1 CONDENSATE 2"

2" 2"

2-2DE-9 1"

2" 12" 1-2DE-9 11113 PI 2"

2" 1"

DRAIN VENT VENT 2"

2" 2"

3" 3-2DE-7 11342 PI 11341 PI 2"

1" DRAIN 8"

3" 4-2CD-42 2-2CD-42 2-2CD-12 8"

4" 4"

4" 4"

8-2DE-7 8"

12" 2"

IIB IIB IIB IIB 12" CONDENSATE MAKE-UP 2SS-4-26 2CD-47-1 2CD-48-1 2CD-19-3 2CD-75-1 2CD-75-2 2CD-49-1 2CD-47-2 2CD-48-2 2CD-47-3 2CD-48-3 2CD-75-3 2CD-74-1 TEMPORARY STRAINER (TYP.)

REMOVABLE SPOOL PIECE WITH EXPANSION JOINT (TYP.)

(TYP.)

DRAIN TO FLR.

SUCTION VENTS DISCHARGE VENTS 27004 FE 23008 F

IN PLACE ABANDON 2CD-45-3 CONTROL 23010 F

12032 TI 16088 PS 21025 P

23012 F

01 41696 PI CONTROL 27014 FE 31126 CV 02 41697 FI 6"

6-2CD-12 6-2CD-12 18-2CD-2 6"

6" 4"

10-2CD-2 18" 18" 4"

1" 18" 18" (TYP.)

DRAIN 18" 4"

24" MANWAY GLASS GAGE 1"

30" 30-2CD-1 3"

18" 1"

18" 3"

30" 2"

FLOW NOZZLE SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-234 18-2CD-2 30-2CD-1 18" 1"

2" 18-2CD-2 48" 3"

3" 18" 3"

30" 30-2CD-1 48-2CD-1 48" 2-2CD-17 3-2CD-13 IIB IIB IIB IIB IIB IIB IIB IIB IIB TE-15570 TE-15571 TE-15572 1"

3" 3"

3" 1"

1" 1-2CD-14 1-2CD-15 1-2CD-16 1"

1" 2CD-62-1 2CD-56-1 46 11 11 11 12 61 50 3

3 30-2CD-1 4" DRAIN 48" 30" 30" 2"

3" 3"

3" 6"

6-2CD-13 IIB IIB IIB IIB 1"

1" 1"

12" 12-2DE-7 12215 TI 17028 PT 18-2CD-3

-2CD-20 18-2CD-4 24" 18" 18" 18" 12" 18" IIB IIB IIB IIB 24" 18" 17314 TT 17027 PT TE-15556 48669 T/U CONTROL SEE NF-39240-1 FEED INJECTION,

" CONN. FOR CHEM.

SEE DWG. NF-39253 POLISHING SYS.

TO & FROM COND./

48613 TE-15558 IIB IIB TE-15557 2"

16" 16-2CD-4 8"

8" 6"

6" 3"

4" 4"

3" 4"

4-2DE-7 12" 18" 31125 CV 31124 CV 32042 MV 12" 3-2DE-7 46562 ES 4"

9 13 IIB CONTROL 10" CONTROL 17375 TT 16" 11455 PI 12216 TI 48817 S/CV 48614 27028 FE 42590 FR 48520 FI COUNTER DIGITAL 16-2CD-5 2CD-12-1 2"

2-2CD-40 2CD-24-3 2-2CD-11 18700 PI 6-2CD-4 18701 PI 2CD-26-1 2CD-26-2 2CD-28-1 18-2CD-4 2CD-4-1 2CD-4-2 2CD-3-1 V

& MAKE-UP EMERG. SUPPLY CONDENSATE 4-2CD-2 6-2CD-2 2CD-11-3 2CD-36-1 2CD-31-1 DWG. NF-39240 PIPING SEE TO GLAND SEAL 2CD-39-13

-2CD-33 4-2CD-2 2CD-19-1 4-2CD-12 2CD-11-4 2"

4" ORIFICE BREAKDOWN SEE NF-39217-1 @ LOC. A-6 24"o COOL WTR. RETURN 2CD-22-1 2CD-2-1 2MD-8-4 1-2CD-19 2CD-1-1 18-2CD-2 1-2CD-14 2MD-8-1 2MD-8-3 2MD-8-2 2MD-8-6 2MD-8-5 2CD-22-2 2-2CD-36 2CD-2-2 2CD-1-2 2CD-24-4 2-2CD-35 2CD-64-2 2CD-2-3 2CD-1-3

-2CD-38 2CD-14-1 2-2CD-1 2CD-14-2 2CD-14-3 4-2CD-1 2CD-17-1 2SS-4-5 2SS-4-4 2MD-9-2 2SS-4-3 2SS-4-2 2SS-4-1 2MD-9-3 2MD-7-3 2MD-7-2 2MD-7-1 2-2CD-1 2CD-61-11 2MD-9-4 2MD-7-6 2MD-7-5 2MD-7-4 BACKWASH WTR. MAKE-UP PMP.

" RECIRC. LINE FROM DWG. NF-39253 @ LOC. A-11 MAKE-UP PUMP #11, SEE 2" TO BACKWASH WATER 2CD-32-1 2CD-33-1 1-2DE-9

-2DE-9 12-2DE-7 2CD-35-1 2CD-30-3 2CD-30-2 12-2DE-7 2"

18" G-2 NF-39222 TD AFWP TO #11 2SS-4-36 2SS-4-35 2CD-61-2 6-2CD-40

-2CD-40 2CD-61-3 2CD-58-1 2CD-57-1 2CD-61-7 10-2CD-40 50 61 2"

4" 2"

2" 2CD-33-2 2CD-62-2 2CD-53-1 10 50 52 2-2CD-18 24-2CD-1 30" 24" 4"

2" IIB IIB

• 24" CROSS OVER 2MD-9-1 S

CONDENSER (III/3) 2A CONDENSER (III/3) 2B (III/3)

EXCHANGER #22 SGB HEAT COOLER (III/3)

1. 21B DRAIN (III/3)

1. 21 FEEDWATER PUMP (III/3)

1. 22 FEEDWATER PUMP 2" DRAIN 16" 18-2CD-4 18" 12"

-2CD-21 12-2CD-4 16"

" VENT 17379 TT 6-2CD-40 20" 2CD-66-2 2CD-65-2 2CD-66-1 2CD-60-1 2CD-65-3 2CD-65-1 SEE DWG. NF-39227

& REHEATER DRAIN TANKS TO #1A & #1B MOIST. SEPS.

" INSTR. TEST LINE

& NF-39227 SEE DWG. NF-39225 TO #25A & #25B HP HTRS.

" INSTR. TEST LINE SEE DWG. NF-39227 PUMP SUB COOLING TO HEATER DRAIN TANK TE-15559 31088 CV 11456 PI 12217 TI 16013 PS 11052 PI 27016 FE CONTROL 16012 PS 11051 PI CONTROL TEST FLOW CONTROL SET AT 550 P.S.I.G.

1"x2" RELIEF VALVE (THIS DWG.)

CONTROL & ALARM PIPING SEE CONDENSER LEVEL 2" DRAIN (TYP.)

5-2CD-40

-2CD-36 16-2CD-4 16-2CD-8 6-2CD-10 6-2CD-10

-2CD-35 18" 16" 16" 16" 16" 16" 16" 16" 16" 16" 20" 8"

8" 6"

8" 4"

6" 6"

6" 6"

2"

" VENT

" VENT

" VENT D

D 75 76 77 IIB III IIB III IIB IIB IIB IIB 10 LINE RECIRCULATING SPRAY PIPES COND. MAKE-UP 18899 PI 18897 PI

-2CD-40 2CD-61-8 2CD-61-9 2CD-24-1 2-2CD-30 16-2CD-10 1-2CD-10 2CD-25-2 2CD-9-2 20-2CD-10 16-2CD-10 2CD-11-2 6-2CD-4 2CD-24-2 1-2CD-10 2-2CD-29 16-2CD-10 2CD-25-1 2CD-9-1 6-2CD-4 8-2CD-4 2CD-10-1 2CD-15-1 4-2CD-4 2CD-20-1 8-2CD-4 2CD-39-2

-2CD-31 2CD-39-1

-2CD-32 2SS-4-7

-2CD-39 SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-214 2CD-39-12 2CD-24-5 18-2CD-4 2CD-39-15 2CD-39-16 2CD-13-1 16-2CD-35 16-2CD-36 16-2CD-8 2CD-11-1 6"

8-2CD-4 DRAIN 18898 PI 2-2CD-40 SEE NF-39240-1 CHEM. INJECTION 2"

2CD-61-4 2CD-59-1 2CD-57-2 2CD-68-1 2CD-69-1 2CD-61-5 2CD-61-6 2CD-61-1 2-2CD-40 1"

2CD-61-10 LOW PRESSURE TURBINE (III/3)

LOW PRESSURE TURBINE (III/3)

1. 23B F.W. HEATER (III/3)

1. 23A F.W. HEATER (III/3)

1. 24B F.W. HEATER (III/3)

1. 22B F.W. HEATER (III/3)

1. 21B F.W. HEATER (III/3)

CONTROL 1"

1" 1"

1" 1"

1" 11090 PI 8

73 SPRAYS EXHAUST IIB IIB SPRAYS EXHAUST 1"

73 8

TE-15562 TE-15563 12039 TI 12218 TI 16" 12" 16" 16" 16" 16-2CD-7

-2CD-25 16" 16" "

-2CD-28 16-2CD-7

-2CD-24 16" IIB TE-15560 12037 TI 2CD-39-7 16" IIB

-2CD-23 3-2CD-40 12" 12038 TI 2CD-39-9

-2CD-26 IIB 16" 16-2CD-9 TE-15561 IIB

-2CD-27 16" 1"

1" 1"

1" 1"

11452 PI 16803 FS 31004 CV CONTROL 20" 12-2CD-7 16" 16" 12" 16" 16-2CD-7 12040 TI 16048 PS TE-15566 TE-15567 IIB IIB 21026 P

42583 PR 41695 PI PUMP START CONDENSATE 2CD-67-1 NF-39250 (E-8)

BLOWDOWN STEAM GEN.

2CD-60-2 5-2CD-40 2"

4" 20-2CD-10 16-2CD-10 12-2CD-10 2CD-7-4 2CD-7-3 SEE DWG. X-HIAW-248-1

" SAMPLE CONN. SS-213 2CD-8-2 12-2CD-4 16-2CD-7 2CD-6-1 2CD-6-2 2CD-39-11 2CD-39-8 2CD-39-10 1-2CD-11 2CD-37-1 2CD-37-3 2CD-37-2 1-2CD-11 2CD-23-2 2CD-23-3 16" MOD#: 90L221 AS BUILT-DRR PI-94-160 TRANSFERRED TO RECORD TRACING REV. "AV" PER REVD:

APPD & CERT:

10-13-92 AV AW AS BUILT REVISED DWG. TO FILMED: 11/23/94 MOD#:

CHKD:

AS BUILT-FILMED:

PER DRR PI-95-123 AX MOD#:

AS BUILT-FILMED: 2/98 PER DRR PI-97-120 AY 2"

IIB 2"

2LA-2-11 2LA-2-81 10 10 IIB 2LA-2-79 16603 LA CONTROL 16914 LA CONTROL PMP. TRIP CONTROL 48819 S/CV 01 41698 LI 24005 L

NF-39240 CONN. SEE DWG.

" INST. TEST 2LA-2-10 2LA-2-80 2LA-3-34 CONDENSER LEVEL CONTROL & ALARM PIPING CONDENSER 2B 2LA-4-131 2LA-1-1 2LA-2-9 2LA-1-3 2LA-4-1 2LA-4-3 2LA-4-105 2LA-1-4 2LA-4-4 2LA-4-2 2LA-4-106 LEGEND

- DENOTES EQUIPMENT Q.A. TYPE/DESIGN CLASS

• - DENOTES FURNISHED WITH EQUIPMENT 10

- DENOTES CONDENSER TERMINAL CONNECTION

- DENOTES THE PIPING Q.A. TYPES

- DENOTES LIMITS OF Q.A. TYPES IC-IIB-III REFERENCE PIPING DWG. NOS.

CHEM FEED - NF-39240-1 NF-39313-1, NF-39313-2 & NF-39313-3 LEVEL TROL & ALARM GAGE GLASS PIPING NF-39272-1, NF-39272-2 & NF-39272-3 CONDENSATE SYSTEM TURBINE BLDG.

- DENOTES FURNISHED BY WESTINGHOUSE CORP.

(II/3)

1. 24A F.W. HEATER (III/3) 12" 12-2CD-7 20-2CD-7 2-2CD-22 20" 2CD-24-6 DWG. NF-39227 PUMP DISCH. SEE 14" HEATER DRAIN 14" 20" 16" 16" 20" 12" 16" 16" 12-2CD-7 16-2CD-7 TE-15564 IIB IIB 2SS-4-6 12-2CD-10 2CD-8-1 2CD-7-1 20-2CD-10 16-2CD-10 TE-15565 2CD-7-2 12" 2CD-5-1 2"

4" 4"

4-2DE-7 4-2DE-8 2CD-30-1 PUMPS, SEE DWG. NF-39240 GLAND SEAL TO CONDENSATE 2-2DE-12 BLDG. WALL 6"

DRAIN TO GRADE

-2DE-12 2CD-45-1 DWG. NF-39220 FOR CONT. SEE FROM WTR. HTR.

2" 2"

2" 2"

2CD-52-1 2CD-24-7 2CD-45-2 2-DE-63

-DE-63 DRAIN VENT 2CD-39-14 2CD-46-3

-2DE-12 16913 LA 6"

III 6-2DE-10 6"

6" VENT IIB IIB 6" VENT 3"

TRACED 1"

NOZZLE SPARGER II B 6"

3" 3-2DE-6 0603 47509 A

0101 47510 A

CONT.

PUMP RECYCLE LEVEL LOW LEVEL LOW-LOW 723 2LI 724 2LI 723 2LT 724 2LT NF-39223 SEE CONT. ON SEE NF-39241 FROM DEMINERALIZER 3" RECYCLE LINE 12-2DE-7

-2CD-37 2DE-60-2 2DE-59-3

• OVERFLOW 6-2CD-12 WALL BLDG.

TRACED ELECT. HEAT (III/3)

STORAGE TANK MAKE-UP

1. 21 CONDENSATE 2CD-39-3 DRAIN 2CD-51-1 31957 CV 2CD-29-1 VENT 2CD-46-1 2CD-46-6 DRAIN 2CD-46-7 2CD-27-1 723 2LC 724 2LC 35300 I/P WALL BLDG.

HEAT ELECT.

6" III 6-2DE-13 6"

DRAIN TO GRADE NOZZLE SPARGER 3-2DE-6 2-2DE-12 12-2DE-7

• OVERFLOW 2CD-54-2 VENT 2CD-46-2 6" VENT STORAGE TANK MAKE-UP

1. 22 CONDENSATE 3"

2CD-44-1 2"

2" 2CD-55-2 2CD-55-1 14298 TE 26300 TC 12367 TI X

X X

2" 12" SEE NF-157545 SAMPLE 2CD-46-4 II B SEE NF-157545 SAMPLE 2CD-46-5 2CD-54-1 HOSE FLEXIBLE 12" 12" 17313 TT ELECT. HEAT TRACED ELECT. HT. TRACED BLDG. WALL DWN: DB 1-10-13 CHKD: SF 1-10-13 AS BUILT-79 MOD#: EC-19605 DELETED DUPLICATE LINE NO. 18-2CD-2 @

LOC F-3.

PER DRR PI-13-010 APPD: CMR 1-14-13 NF-39247 (E11)

SUPPLY SEE NITROGEN BLANKETING NF-39247 (E11)

SUPPLY SEE NITROGEN BLANKETING DWN: MEA 10-21-15 CHKD: RLM 10-23-15 AS BUILT-80 MOD#: EC-24671 ADDD NITROGEN BLANKETIN ELIM. BELL ALARM AND ASSOCIATED WIRING.

PER DRR PI-15-134 APPD: KJW 10-28-15 16946 PS 16945 PS REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 2

400 5

6 4410 7400 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 81 39221 NF-39221 NF-by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSP GENERATION CAD NF-39221.DGN FLOW DIAGRAM CONDENSATE SYSTEM UNIT 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 DWN: JEK 11-22-17 CHKD: MJL 11-27-17 AS BUILT-81 MOD#: 6MOD00027409 ADDED PRESSURE SWITCHES 16945 AND 16946.

PER DRR PI-17-161 APPD: DB 11-27-17 "81" "81" LEVEL LOW LEVEL HIGH 16602 LA 0605 47509 A

0505 47509 A

16802 FS 2LA-2-82 2LA-2-12

• GAGE GLASS CONDENSER 2A 2LA-4-5 2LA-4-107 2LA-4-108 2LA-4-6 2LA-1-2 2LA-3-1 SEE NF-39241 DEMINERALIZER 4" MAKE-UP FROM 31003 CV SPRAY PUMP

1. 21 CONDENSER 2CD-23-1 SAMPLE CONN. SS-246 SAMPLE CONN. SS-247 SAMPLE CONN. SS-245 SAMPLE CONN. SS-251 SAMPLE CONN. SS-212 SAMPLE CONN. SS-250 SAMPLE CONN. SS-248 SEE DWG. NF-39242 REACTOR MAKE-UP WATER STORAGE TANKS.

CONDENSATE TRANSFER TO #21 & #22

603000001331 CAD FILE:

FIGURE 11.1-5 REV. 35 U11105.DGN M

M 23022 27008 23023 27007 23021 4206301 4114102 4114101 M

M 4114201 4114203 23024 4206501 S

1"

-FW-17 1"

AF-18-14 AF-15-10 AF-18-2 AF-17-2 AF-13-1 PT AF-133-1 1"

AF-19-5 AF-15-9 AF-13-3 AF-18-1 AF-17-1 AF-29-1 M

1-AF-9 AF-15-1 M

AF-15-2 M

AF-15-4 M

AF-15-3 AF-18-15 48128 M

M 4"

4" 46B 46A

-FW-18 1"

SHIELD BUILDING WALL 16-FW-15 1-FW-22 12" 16-FW-9 4-FW-8 1-FW-8 16-FW-10 4-FW-10 4-FW-8 1-FW-8 1FE 476 16-FW-8 16" 1FE 466 1FR 465A 467 466 495 22-FW-8 ABANDON IN PLACE 14-FW-3 1-FW-3 20-FW-3 16-FW-3 16-FW-8 14-FW-8 1-FW-3 48098 T/U 48185 FI FE T/U 26600 27005 48097 48183 2-FW-3 1-FW-5 16-FW-2 6-FW-2

-FW-5 6-FW-2 16-FW-1 2-FW-3 1-FW-4

-FW-7

-FW-6 476 497 477 1FR 475A 1-FW-20 1-FW-19 10-FW-6 10-FW-7 LO 75 75

-AF-23 AF-18-3 1-AF-10 1-AF-23 AF-32-1 AF-32-2 1-AF-24

-AF-24 AF-32-3 AF-28-1 1-AF-5 AF-25-1 AF-26-5 AF-27-1 2" TEST 1-AF-3

-AF-27 2-AF-4 S

A/S SV-33285 2-CL-111 AF-34-1

-AF-27

-AF-19 AF-36-3 AF-36-2 AF-36-1 PI 11355 4-DE-56 AF-25-5 2-CL-111 32333 ES 46420 2-CL-111 AF-33-2 AF-28-2 FE FI 27194 18279 1-AF-8 AF-26-6 A/S SV-33286 1-FW-8 AF-195-1 AF-195-2 16-FW-13 1-FW-23 V

V 16-FW-13 1-FW-16 1-FW-21 16-FW-12 1"

D 1"

D 14-FW-3 16-FW-3 V

D 3-AF-10 3-AF-9 3-AF-10 1-AF-10 1-AF-9 3-AF-3 D

AF-123-7 AF-123-8 AF-123-5 AF-123-6 3-AF-9 1-AF-3 D

2-AF-3 AF-123-2 AF-123-1 AF-133-5 1-AF-1 17166 AF-133-3 AF-37-1 D

D 3-AF-6 3-AF-6 2AF-13-1 RECIRC LINE TURB BLDG 1-AF-6 2-AF-6 3-AF-6 1-AF-22 M

M AF-133-2 AF-28-6 4-DE-56 D

AF-133-6 1-AF-2 17167 AF-133-4 AF-29-2 4-AF-2 AF-37-2 TE-14039 4-AF-1 AF-123-3 AF-123-4 2-AF-7 2" TEST CL-115-4 REACTOR BUILDING UNIT 1

-AF-13

-AF-14

-AF-20 4"

4" 2-AF-4

-AF-25 1-AF-21

-AF-16 32242 MV 32243 MV 46319 ES 46318 ES AF-30-1 AF-30-2 AF-16-1 AF-12-1 AF-16-2 SG-2-1 SG-2-2 SG-3-1 AF-12-2 31153 CV AF-18-13 AF-14-1 AF-21-1 46422 ES 32335 MV AF-21-2 AF-14-3 3"

SG-2-3 SG-2-4 SG-3-2 AF-35-1 AF-26-7 AF-25-7 AF-19-6 AF-145-3 AF-145-1 AF-33-1 FEEDWATER AUX FEEDWATER 32027 MV 46434 ES 1-AF-7 1-DE-56 48127 1-AF-7 32025 MV 1-AF-4 1-AF-17

-AF-3 46433 ES 15A FW HEATER 15B FW HEATER 1FI 1FI 1FI 1FI 1FI 1FI 4-FW-9 AUX BLDG 3-SG-1 SG-1-1 7A 7B 32023 MV P

21031 32024 MV P

21032 FW-145-8 FW-145-7 1TT 498 1TE-499 1TT 499 CONT CONT F-22-8 FW-125-2 FW-125-1 FW-125-4 FW-125-3 HI LO TE-15255 CONT 1PT 501 1PT 500 CONT 1FT 466 1FT 495 1FT 467 HI LO CONT 1-FW-8 F-22-7 FW-125-8 1FT 477 FW-125-7 FW-125-6 1FT 476 1FT 497 HI LO FW-125-5 CONT CONT CONT CONT AUX TURB F-3-1 F-11-1 TE-13148 SS-3-1 F-4-1 F-4-2 F-3-2 TE-14071 TE-13149 F-11-2 F-23-5 F

23112 FW-145-10 FW-145-11 HI LO CONT CONT CONT FE 27006 FI 26601 F

23113 FW-145-12 FW-145-13 HI LO F-22-2 F-24-2 32324 MV F-23-2 F-1-2 TE-13076 P

21030 PI 11104 F-9-2 F-22-4 F-23-4 CONT F-9-1 P

21029 TE-13069 PI 11103 FW-145-2 FW-145-1 F-1-1 F-22-1 32323 MV CONT F-23-1 F-24-1 (III/3)

PUMP 12 FW F-22-3 F-23-3 D

F-23-9 V

F-23-8 V

31874 CV D

LO HI

-FW-4 V

V 16" D

SG-1-2 CONT 6"

6" 31875 CV 1 WARM UP LINE (TYP)

F-22-5 F-22-6 AF-18-4 AF-18-12 CONT 1-AF-7 32382 MV PT AF-13-4 S

1" S

M 1"

MV TEST TEST 145-261 145-262 136-018 136-017 20" (III/3)

(III/3) 1" (III/3)

PUMP 11 FW CF-1-3 CF-1-5 F-6-3 F-26-2 F-26-1 F-22-9 F-22-10 F-6-4 F-20-6 F-5-1 F-6-1 F-6-2 F-5-2 F-5-4 F-20-5 F-5-3 F-20-1 F-20-2 F-20-4 F-8-2 F-8-1 F-20-3 AF-31-2 AF-31-1 M

CL-115-3

}

(TYP 4)

CONTROL D

REMOVED INTERNALS D

BASE PLATE DRAIN REMOVED INTERNALS D

BASE PLATE DRAIN RECIRC LINE

-AF-26

-CL-139

-CL-140 145-201 (I/1)

TD AFWP 11 145-331 (I/1)

MD AFWP 12 (III/3)

CONDENSER 1A 6 RECIRC LINE 6 RECIRC LINE AF-281-4 AF-281-3 AF-25-2 AF-27-2 AF-32-4 AF-25-6 NF-39222-1 SEE NF-39240 CF SYSTEM FLOW DIA UNIT 1 & 2 NF-39223 - AF SYSTEM FLOW DIA. UNIT 2 NF-39216 CL SYSTEM FLOW DIA. UNIT 1 NF-39217 CL SYSTEM FLOW DIA. UNIT 2 NF-39220 - CD SYSTEM FLOW DIA. UNIT 1 NF-39218 - MS SYSTEM FLOW DIA. UNIT 1 REFERENCE DWGS:

G-3 NF-39218 F-6 NF-39223 NOTES:

3.

DENOTES CATEGORY I LEGEND VENTILATION ZONE

4. FOR SYMBOLS SEE XH-1-105, NF-39214.

DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

C2 CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

MAW 5-4-07 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1

400 5

6 4410 7400 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 86 NF-39222 NF-39222 by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSRP GENERATION CAD NF-39222.DGN FLOW DIAGRAM FEEDWATER & AUX FEEDWATER UNIT 1 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 DENOTES CONTAINMENT PENTETRATION NUMBERS.

6.

17700 PS 4-AF-1 12046 TI AF-28-5 17057 PT 11054 PI 17704 PS 3"

12047 TI 17059 PT 17776 PS 11055 PI 4-AF-2 16-FW-11 16-FW-14 01 41231 F1 D

20-FW-3 20" 14-FW-8 A-4 SS-38 XH-248-1 1FCV-481 1FCV-476 1FCV-466 1FCV-480 FLOW NOZZLE LO D

D 4114202 (2 PLCS)

FITTNG FLUE 8"x3" TE-13077 TE-13079 1"

1" 1"

1" FI FE 18278 27193 AF-281-2 AF-281-1 3-AF-11 C-4 C-5 G-5 G-4 NF-39222 AF L/O SYSTEM FLOW DIA. UNIT 1 & 2 L/O CLR 11 AFWP 1-SG-1 CONN TEST 18038 FI CL-113-5 NSR NSR C3 NSR C3 C3 NSR NSR C3 C3 NSR C3 C3 NSR NSR C3 NSR C3 NSR C3 NSR D

C2 NSR B-4 NF-39220 STG TNK #11 TO COND M-U H-4 NF-39240-1 CHEM FD SYS FROM G-4 NF-39240-1 CHEM FD SYS FROM H-2 NF-39240-1 CHEM FD SYS FROM NF-39222-2 12 AFWP L/O SYS E-3 NF-39220 STG TNKS FROM COND B-4 NF-39216-2 CL SPLY FROM U1 C-1 NF-39216-2 TO U1 CL RTRN HDR B-4 NF-39216-2 TO WST H-1 NF-39223 FROM 21 AFWP RECIRC LN H-1 NF-39223 RECIRC RTRN LN TO U2 AFW PMPS E-2 NF-39220 FROM COND STG TNKS G-2 NF-39217-1 TO WST G-2 NF-39217-1 FROM U2 CL SPLY IB IC C3 CLASS BREAK QA TYPE

7. DENOTES CONDENSER CONNECTION NUMBER.

75 IA, IB IC, IIA, IIB, III DENOTES PIPING QA TYPES IC III NSR C3 IC IIB III IC III IC IIB IC III IC IIB IC III IC IIB IC III IC III IIB IC IC III III IC III IC IIB IC IC III IIB IC III IC III IC III IB 18036 FI 23122 F

02 41227 FI III IB C2 NSR III IB III IC IIB IC 1-DE-56 III IIB IIA IIA IIA IIA IIA IB NSR C2 III IC IC IIB IIA D

IIB III IIB III

8. SHELL SIDE CLASS BOUNDARY SR.

02 41231 F1 504A 504B 504C 504D 504E 504F 504G 504H 504J 504K 504L 504M 504N 504P 504Q 504R 504 1FM 1FT 505A 505B 505C 505D 505E 505F 505G 505H 505J 505K 505L 505N 505P 505Q PLANE A PLANE B PLANE A PLANE B 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1TE-507B 1TE-507A 1TE-506B 1TE-506A 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT 1FT TO ERCS 505M 1FT F-1 NF-39240-1 D

D 46414 ES 41224 P1 6-FW-6 6-FW-7 CONT CONT WITHIN CDSR PERFORATED PIPE F-3 NF-39240-1 505R 1FT NOZZLE FLOW NOZZLE FLOW 12" 16-FW-8 16-FW-8 16-FW-8 1FE 505 1FE 504 16-FW-8 11336 PI 17060 PT 01 41228 PI 01 41227 PI 46314 ES 32238 MV 32239 MV 32381 MV 27147 FE 23127 F

02 41228 FI D

18032 FI 27100 FE AF-145-2 AF-145-4

-AF-12

-AF-11 3-AF-12 1-SG-2 27145 FE 41225 P1

-AF-17 17777 PS 18034 FI 27105 FE 11334 PI 21034 P

21033 P

46317 ES 46316 ES 46315 ES 17058 PT CONN TEST 134-011 (I/1)

GENERATOR STEAM 11 134-012 (I/1)

GENERATOR STEAM 12 NSR C2 IB III 8

NOTE SEE IB IC 3-SG-2 D

D D

D D

D D

IC III IC IIB NSR 31154 CV 31369 CV 31127 CV 31128 CV 31370 CV C2 C3 46413 ES IIA IIA IIA 1TE-498 5.

C3 IC IC SR C3 IC IC SR C3 IC IC SR C3 IC SR IC

9. C3/NSR BOUNDARY FOR TI-12046/12047 IS AT ITS THERMOWELL.

NSR III 1-AF-53 1-AF-54 1-AF-55 27616 FE AF-143-2 AF-143-1 AF-282-1 AF-282-2 AF-282-3 18616 FI DWN: LAB 6-6-11 CHKD: PMB 6-8-11 AS BUILT-80 MOD#: EC-17465 ADDED FE-27616 & ASSOC.

INSTRUMENTATION TO 11 AFWP L/O COOLER PIPING.

PER DRR PI-11-109 APPD: CMR 6-8-11 NF-39222-2 L/O SYS 11 AFWP NSR III NSR III IC C3

-AF-2 NSR III

-AF-5

-AF-4

-AF-6 3-AF-3

-AF-1 "86" 27617 FE 18617 FI III IC C3 NSR DWN: LAB 1-10-13 CHKD: PMB 1-11-13 AS BUILT-82 MOD#: EC-18349 ADDED FI-18617, FE-27617, ROOT VLVS AF-143-3, 4, AF-282-4, 5, 6, CAPPED CONN. & SAFETY CLASS BRK.

PER DRR PI-13-003 APPD: CMR 1-11-13 AF-143-4 AF-143-3 AF-282-5 AF-282-6 AF-282-4 L/O CLR 12 AFWP NOTE 8 REDRAWN PER SYSTEM WALKDOWN, INCORPORATED 04NS15 AS BUILT-PER DRR PI-08-080 MOD#: EC-13291/14091 DWN: MAW 5-4-07 CHKD: DB 8-21-09 FILMED: 9-09 REVIEWED: WJI 8-24-09 78 DESIGNATIONS SAFETY CLASS DWN: DB 7-26-10 CHKD: JEK 7-27-10 AS BUILT-79 MOD#: EC-16528 REVD LOC OF SAFETY CLASS FLAG. ADDED SAFETY CLASS FLAG, LINE NOS 1-AF-53, 54, 55 04NS15 PER DRR PI-10-119 APPD: CMR 7-28-10 DWN: DB 7-23-12 CHKD: DC 8-18-12 AS BUILT-81 MOD#: EC-19906 REVD MISC LINE SIZES, LINE NOS. & SAFETY CLASS DESIGNATIONS. ADDED GOV LOC @ LOCATION G-2,3.

PER DRR PI-12-131 APPD: CMR 9-11-12 DWN: LAB 9-30-13 CHKD: CMR 10-1-13 AS BUILT-83 MOD#: EC-22144 VALVE F-24-1 INCORRECTLY SHOWN AS A GLOBE VALVE.

REVISED TO CHANGE IT TO A GATE VALVE. (LOC C-10).

PER DRR PI-13-159 APPD: CMR 10-1-13 DWN: DB 1-21-16 CHKD: MP 1-25-16 AS BUILT-84 MOD#: EC-23531 ADDED BLIND FLNG CONN INCLUDING VLV AF-47-1 &

LINE NUMBER 3-AF-7

@ LOC F-8.

PER DRR PI-16-014 APPD: KJW 1-27-16 DWN: MEA 6-7-16 CHKD: MP 6-7-16 AS BUILT-85 MOD#: EC-16823 DELETD BLIND FLNG CONN INCLUDING VLV AF-47-1 &

LINE NUMBER 3-AF-7

@ LOC F-8.

PER DRR PI-16-161 APPD: DB 6-7-16 DWN: JEK 10-11-16 CHKD: MP 10-11-16 AS BUILT-86 MOD#: EC-23531, 27594 ADDED BLIND FLNG CONN INCLUDING VLV AF-47-1 &

LINE NUMBER 3-AF-7

@ LOC F-8.

PER DRR PI-16-218 APPD: DB 10-11-16 AF-47-1 3-AF-7 S

FEEDWATER AUX FEEDWATER 16-FW-16 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C3 NSR C2 1-AF-15 NSR C3 NSR C3 NSR C3

603000001331 CAD FILE:

FIGURE 11.1-6 REV. 35 U11106.DGN 3-2AF-9 3-2AF-10 M

M M

M AF-18-8 3-2AF-10 3-2AF-3 AF-15-5 AF-15-7 1-2AF-10

-2AF-27 1-2AF-27 2AF-32-2 AF-18-9 3-2AF-6 AF-18-10 1-2AF-9 AF-15-8 AF-15-6 AF-18-11 1-2AF-23 1"

3-2AF-3 AF-13-6 AF-15-12 AF-18-6 AF-17-4 1-2AF-3 2-2AF-3

-2AF-16 3-2AF-3 1-2AF-17 1"

1" 3-2AF-3 A/S AF-27-4 2-2AF-4 SV-33493 CONTROL S

A/S AF-34-2 AF-36-6 AF-36-5 AF-36-4 2AF-18-14 AF-25-7 AF-25-6 M

D 2AF-133-1 2AF-133-5 AF-21-3 AF-28-7 2AF-133-3 AF-14-5 46766 ES AF-37-3 2AF-29-1 PT 17168 17061 PT M

2AF-18-13 1"

2AF-33-2 AF-28-4 2AF-32-4 AF-28-3 2AF-33-1 2AF-32-3 27195 FE 18280 FI AF-25-3 AF-27-3 AF-17-3 D

AF-19-7 AF-13-5 AF-15-11 AF-26-9 17778 PS 2AF-195-1 12050 TI 11056 PI 17779 PS 11335 PI P

21044 31418 CV SV-33492 AF-18-5 2AF-13-1 2AF-145-3 2AF-145-1 2AF-32-1 2AF-31-1 32383 MV 32384 MV 32246 MV 32247 MV 2AF-31-2 2AF-123-1 2AF-123-2 2AF-123-3 2AF-123-4 31419 CV D

M PT 2AF-29-2 4-DE-56 1-DE-56 D

17169 AF-28-8 AF-21-4 AF-37-4 D

AF-14-7

-2AF-13

-2AF-15 2AF-133-4 4-2AF-1 4-2AF-1 2AF-195-2 2CL-113-3 STEAM GENERATOR (I/1)

STEAM GENERATOR (I/1) 4" 4"

M 2FW-8-2 2FW-8-1 V

2FW-20-3 32249 MV 32248 MV 46844 ES M

46845 ES 2AF-30-2 2AF-30-1 2FW-20-4 FEEDWATER AUX FEEDWATER FEEDWATER AUX FEEDWATER REACTOR BUILDING UNIT 2 AF-18-7 D

2AF-281-1 2AF-281-2 2CL-115-4 1-2AF-1 2AF-145-2 2AF-281-4 3"

3" 1-2AF-10 RECIRC LINE 1-2AF-9 2AF-133-6 32030 48628 48627 2AF-123-7 2AF-123-8 2AF-123-5 2AF-123-6 32026 MV 46767 ES 1-2AF-24 1-2AF-22 1-2AF-19 SHIELD BLDG WALL TURB BLDG AUX BLDG V

M M

ABANDON IN PLACE V

1" 10" 10" 6"

PERFORATED PIPE WITHIN CONDENSER PIPING 21 22 16-2FW-12 16-2FW-11 16-2FW-9 16-2FW-8 1-2FW-31 4-2FW-8 16-2FW-14 465A 2FR 467 2FI 32028 MV 32029 MV D

1-2FW-26 2FW-20-1 16-2FW-15 2FW-20-2 1-2FW-26 2FW-145-8 CONT 4250401 2FW-5-2 2FW-6-2 4173402 2FT 467 23026 2FT 466 23025 466 2FI 4173401 4173403 2FT 495 495 2FI CONT 2FW-5-4 2FW-6-4 4-2FW-10 16-2FW-10 1-2FW-25 16-2FW-8 1-2FW-24

-2FW-8 2FR 475A 477 2FI 2FW-5-1 CONT CONT CONT 2FW-6-1 2FW-20-6 CONT CONT D

2FW-5-3 2FW-20-5 4-2FW-8

-2FW-8 2FW-6-3 2FW-22-7 2FW-22-8 D

D 1-2FW-30 V

V 16-2FW-8 2FT 477 2FT 476 27012 27011 4173702 23028 23027 4251001 4173701 CONT 2FI 476 2FI 497 CONT 16-2FW-8 2PT 500 2PT 501 2SS-3-2 2FW-3-2

-2FW-8 22-2FW-8 20-2FW-8 14-2FW-8 16-2FW-8 20-2FW-3 14-2FW-3 1-2FW-20 2FW-22-12 2FW-4-2 2FW-22-6 14-2FW-8 14-2FW-3

-2FW-19 20-2FW-8 20-2FW-3 2FW-4-1 2FW-23-5 V

16" 2FW-3-1 2FW-11-1 F

23115 CONT 1-2FW-3 1-2FW-5 2-2FW-3 16-2FW-2 1-2FW-5

-2FW-18 10-2FW-7 2FW-22-2 2FW-24-2 4173703 CONT 10-2FW-7 1-2FW-23 1" DRAIN (TYP) 1-2FW-22

-2FW-21 10-2FW-6

-2FW-7 10-2FW-6 2FW-23-9 2FW-23-8 2FW-22-10 2FW-22-9 V

2FW-26-1 2FW-26-2 LO (III/3) 81 81 2FW-23-3 1-2FW-4 2FW-22-1 16-2FW-1

-2FW-17 10-2FW-6 1-2FW-3 2-2FW-3 CONT 2FW-24-1 2FW-23-1 2FW-25-1 2FW-1-1 2FW-22-3

-2FW-4 10-2FW-7 2FW-23-2 2FW-25-2 PI 11135

-2FW-5 2FW-22-4 2FW-23-4

" DRAIN (TYP) 2FW-145-9 CONT 4-2FW-9 31371 CV 31135 CV 31136 CV 31372 CV 12" 12" (TYP 2) 1" DRAINS HI LO 2FW-125-1 2FW-125-2 2FW-125-3 2FW-125-4 LO HI 2CF-1-3 2CF-1-5 2FW-125-7 2FW-125-8 HI LO LO HI 16-2FW-8 D

1" D

16-2FW-3 48600 48679 T/U HI LO CONT 48599 48678 T/U 2FW-145-10 2FW-145-11 HI LO 16-2FW-3 2FW-145-1 D

2FW-145-2 1" WARM UP LINE (TYP)

V 2FT 497 D

D AUX TURB AF-13-1

-2AF-28 D

P 21097 S

2TT 499 P

21098 2TT 498 1-2AF-24 RECIRC LINE TEST LINE 17062 PT S

32336 MV 2CL-115-3 2AF-281-3 AF-25-4 AF-26-10 AF-35-2

-2AF-30 TEST LINE AF-26-8 32345 MV AF-19-8 2AF-145-4 (TYP) 1" DRAIN 234-011 234-012 M

V V

AF-12-3 AF-16-3 AF-12-4 AF-16-4 1" WARM UP LINE (TYP)

P 21041 (TYP 4)

CONTROL S

2AF-133-2 S

INTERNALS REMOVED INTERNALS REMOVED

-2AF-29

-2CL-139

-2CL-140 6"

D 245-331 (I/1)

MD AFWP 21 D

(TYP)

CONT NOTES:

3.

DENOTES CATEGORY I LEGEND VENTILATION ZONE DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

4.

C2 CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 2A CONDENSER NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS 10" RECIRC LINE 10" RECIRC LINE NF-39222 - AF SYSTEM FLOW DIA. UNIT 1 NF-39221 - CD SYSTEM FLOW DIA. UNIT 2 NF-39240 CF SYSTEM FLOW DIA. UNIT 1 & 2 NF-39216 CL SYSTEM FLOW DIA. UNIT 1 NF-39217 CL SYSTEM FLOW DIA. UNIT 2 NF-39219 - MS SYSTEM FLOW DIA. UNIT 2 F-6 NF-39222 F-10 NF-39240-1 F-11 NF-39240-1 G-4 NF-39219 1-2AF-24 1-2AF-24 2FW-22-5 26602 FI 245-261 (III/3)

FW PUMP 21 245-262 (III/3)

FW PUMP 22 PENETRATION (TYP)

(III/3) 236-017 25A FW HEATER (III/3) 236-018 25B FW HEATER 16-2FW-3 27009 FE 26603 FI 27010 FE 2FW-145-12 2FW-145-13 FLOW NOZZLE 2FW-11-2 REFERENCE DWGS 7D 7C 46C 46D

5. DENOTES CONTAINMENT PEN #

A-6

" SAMPLE CONN SS-238 XH-248-1-2 1"

2FW-1-2 C-9 C-10 G-9 G-10 NF-39222 AF L/O SYSTEM FLOW DIA. UNIT 1 & 2 L/O CLR 21 AFWP L/O CLR 22 AFWP NSR C2 IIB IC NSR C3 NSR C3 4-DE-56 NSR C3 C3 NSR NSR C2 18037 FI 23128 F

NSR C3 NSR C3 IIB IC IC III C3 NSR IC III NSR C3 NSR C3 NSR 18035 FI G-10 NF-39240-1 CHEM FD SYS FROM NF-39222-2 21 AFWP L/O SYS NF-39222-2 22 AFWP L/O SYS B-4 NF-39221 TO COND M-U STG TNK #21 H-5 NF-39222 RECIRC RTRN LN TO U1 AFW PMPS E-2 NF-39220 COND STG TNKS FROM B-3 NF-39216-2 TO WST B-3 NF-39216-2 FROM U1 CL SPLY B-1 NF-39217-1 TO U2 CL RTRN HDR E-2 NF-39220 COND STG TNKS FROM G-3 NF-39217-1 FROM U2 CL SPLY G-4 NF-39217-1 TO WST NF-39220 - CD SYSTEM FLOW DIA. UNIT 1 NSR C3 III IC NSR C3 III IC NSR C3 IC III IIB IC III IC III IC III IB IIA IIB IIA IIA ORIFICE (TYP)

BREAK DOWN IIA IIA IIA IIA IIA III IC 17064 PT IIB IC IC IIB 17705 PS C3 NSR C3 III IC C3 IC IIB III IC C3 NSR III IC III 17701 PS IC III III IC IB IC C3 CLASS BREAK QA TYPE IC III IIB IC 3-2AF-12 3-2AF-11 III IB

6.

81 DENOTES CONDENSER CONNECTION NUMBER.

IA, IB, IC, IIA, IIB, III DENOTES PIPING QA TYPES III IIB IC III

7. SHELL SIDE CLASS BOUNDARY SR.

8. FOR SYMBOLS SEE XH-1-105, NF-39214.

SEE NOTE 7 SEE NOTE 7 16-2FW-13 (TYP 2)

FITTINGS 8"x3" FLUE 2CF-1-1 504A 2FT 504 2FE 504B 2FT 504C 2FT 504D 2FT 504H 2FT 504G 2FT 504F 2FT 504E 2FT 504N 2FT 504P 2FT 504Q 2FT 504R 2FT 504J 2FT 504K 2FT 504L 2FT 504M 2FT 504 2FM 505A 2FT 505 2FE 505B 2FT 505C 2FT 505D 2FT 505H 2FT 505G 2FT 505F 2FT 505E 2FT 505N 2FT 505P 2FT 505Q 2FT 505R 2FT 505J 2FT 505K 2FT 505L 2FT 505M 2FT 2TE-507A 2TE-506A 2TE-507B 2TE-506B TO ERCS PLANE A PLANE A PLANE B PLANE B 2FCV-480 2FCV-466 2FCV-476 2FCV-481 NOZZLE FLOW 2FW-125-6 2FW-125-5 V

CONT

-2AF-18 1-2AF-2 27107 FE 1-2AF-5 3-2AF-6 D

D 3-2AF-3 46843 ES 46842 ES 46841 ES 46840 ES IB III IB IC C3 C2 IC III IC IIB IC IIB NSR C3 NSR C3 III IC III IIB III IIB C3 NSR NSR NSR C3 G-9 H-9 NF-39240-1 CHEM FD SYS FROM

-2AF-26 1-2AF-26 C2 IB C3 NSR D

TE-13095 TE-13093 TE-13094 TE-13087 TE-13151 TE-14072 TE-13150 TE-15311 TE-14056 2TE-498 2TE-499 31877 CV 31876 CV 32325 MV 32326 MV 01 41692 PI 02 41733 FI 01 41733 FI 01 41694 PI 01 41693 PI 02 41691 FI 02 41692 FI 46774 ES 46775 ES 46768 ES 46883 ES NSR III IB IIA C2 NSR C2 NSR NSR C3 NSR C3 NSR NSR NSR C3 NSR C3 NSR D

D D

D D

D D

D D

1" 1"

1" 1"

10-2FW-2 10-2FW-1 IC IC C3 SR IC C3 SR IC IC C3 IC SR IC IC C3 SR 1-2AF-53

9. C3/NSR BOUNDARY FOR TI-12045/12050 IS AT ITS THERMOWELL.

1-2AF-8 NSR III NSR III 1-2AF-54 C3 NSR

-2AF-2

-2AF-4

-2AF-6 245-201 (I/1)

TD AFWP 22 11356 PI

-AF-5

-AF-3

-2AF-1 NF-39223-1 SEE DWN: DB 7-25-12 CHKD: DC 9-11-12 AS BUILT-82 MOD#: EC-19906 REVD MISC LINE SIZES, LINE NOS., & SAFETY CLASS DESIGNATIONS. ADDED GOV LOC @ LOCATION G-8,9.

PER DRR PI-12-131 APPD: CMR 9-11-12 27619 FE DWN: DB 11-14-12 CHKD: PMB 11-27-12 AS BUILT-83 MOD#: EC-18347 ADDED PI-18619, FE-27619, ROOT VLVS 2AF-143-3, 4, 2AF-282-4, 5, 6, CAPPED CONN. & SAFETY CLASS BRK PER DRR PI-12-216 APPD: CMR 11-30-12 18619 FI 2AF-143-4 2AF-282-5 2AF-282-4 2AF-282-6 2AF-143-3 III IC C3 NSR DWN: KJF 9-6-13 CHKD: DHJ 9-10-13 AS BUILT-84 MOD#: EC-22530 CHANGED PI 18619 TO FI 18619 AT DWG COORD E8.

PER DRR PI-13-123 APPD: CMR 9-11-13 27618 FE 18618 FI 2AF-143-2 2AF-282-1 2AF-282-3 2AF-143-1 III IC C3 NSR 2AF-282-2 2-2AF-7 1-2AF-24 CNTRL 1-2AF-6

-2AF-19 1-2AF-21 DWN: DB 10-25-13 CHKD: PMB 10-30-13 AS BUILT-85 MOD#: EC-18350 ADDED PI-18618, FE-27618, ROOT VLVS 2AF-143-1, 2, 2AF-282-1, 2, 3, CAPPED CONN. & SAFETY CLASS BRK PER DRR PI-13-197 APPD: CMR 10-30-13 11337 PI 21040 P

27196 FE 4-2AF-2 1-2AF-25 2-CL-112 2-CL-112 2-CL-112 2-2AF-6

-2AF-22 3-2AF-6 1-DE-56 18033 FI 27106 FE 1-2AF-25 11081 PI 17063 PT 12045 TI 18281 FI 16-2FW-13 1-2FW-27 3-2AF-12 3-2AF-11

-2AF-11

-2AF-12 16-2FW-16 1-2FW-29 18039 FI 27148 FE 27146 FE 23129 F

11130 PI (TYP 2) 1" VENT 01 41691 PI 2SG-1-2 3-2SG-2 2SG-1-1 3-2SG-1 DWN: LAB 2-5-14 CHKD: TLL 2-5-14 AS BUILT-86 MOD#: EC-16807 ADDED NEW RECIRCULATION LINES 3-2SG-1 & 3-2SG-2 AND ASSOCIATED VALVES 2SG-1-1 & 2SG-1-2.

PER DRR PI-14-036 APPD: CMR 2-5-14 III IB C2 NSR 2SG-2-1 1-2SG-1 IB NSR C2 III 2SG-2-2 1-2SG-2 IB NSR C2 III CONN MCO TEST CONN MCO TEST 2SG-3-2 2SG-3-1 DWN: DB 4-25-14 CHKD: RWR 4-25-14 AS BUILT-87 MOD#: EC-16812 ADDED PERFORMANCE TEST INSTR LINES 1-2SG-1 & 2 AND ASSOC VLVS 2SG-2-1, 2SG-3-1, 2SG-2-2,3, SC BRK.

PER DRR PI-14-065 APPD: CMR 4-25-14 3-2AF-7 C2 IC NSR III AF-47-2 CONNECTION FLEX TIE-IN DWN: JEK 10-29-15 CHKD: MP 11-3-15 AS BUILT-88 MOD#: EC-23532 ADDED VALVE AF-47-2 AND BLIND FLANGE FOR FLEX EQUIPMENT TIE-IN.

PER DRR PI-15-151 APPD: KJW 11-4-15 "90" DWN: DB 11-12-15 CHKD: JS 11-16-15 AS BUILT-89 MOD#: EC-16830 REVD VLV AF-35-2 FROM A NC GLOBE VLV TO A NC BALL VLV @ LOC G-8.

PER DRR PI-15-175 APPD: KJW 11-16-15 1-2AF-55 DWN: JEK 10-20-16 CHKD: BJS 10-21-16 AS BUILT-90 MOD#: EC-17065 ADDED LINE NO. 1-2AF-55 AT LOC G-10.

PER DRR PI-16-229 APPD: DB 10-21-16 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

MAW 5-8-07 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 2

400 5

6 4410 7400 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 90 39223 NF-39223 NF-NSP GENERATION CAD NF-39223.DGN FLOW DIAGRAM FEEDWATER & AUX FEEDWATER UNIT 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

M M

466 2FE 476 2FE P

21042 F

23114

01516979 CAD FILE:

FIGURE 11.1-8 REV. 34 U11108.DGN NF-39250 (D7)

TANK STEAM LINE FROM SGB FLASH 6-2SB-38 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 2

5 6

4410 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT E.U. CLAESON NORTHERN STATES POWER COMPANY 78 39225 NF-39225 NF-by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSP GENERATION CAD NF-39225.DGN 5-27-71 PE #8626 BLEED STEAM

& HEATER VENTS FLOW DIAGRAM A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 DWN: JLB 5-6-09 CHKD: NWM 5-19-09 AS BUILT-FILMED: 6/09 76 MOD#: EC-13412 REMOVE GAGE GLASS SHOWN AT E-4.

PER DRR PI-09-041 "78" AS BUILT-77 PER DRR PI-09-105 CHKD: BCS 5-6-10 DWN: LAB 3-12-10 NO.s PER EC-13861.

CORRECTED & ADDED LINE AS BUILT-APPD: CMR 5-6-10 MOD#: EC-11687 CHKD: JMC 4-29-10 DWN: LAB 3-12-10 DRAWING NO. PER EC-11687.

CORRECTED FOR CONT. REF.

DWN: JEK 11-9-15 CHKD: KB 11-9-15 AS BUILT-78 MOD#: EC-26020 CORRECTED LINE CONTINUATION AT GRID C-4.

PER DRR PI-15-163 APPD: KJW 11-9-15 PUMP CASING VENTS 1A 2A 3A 3B 2B 1B 2MS-44-3 2MS-44-2 2MS-44-1 2MS-43-2 2MS-43-1 2MS-43-3 GLAND SEAL STEAM SEE DWG. NF-39219 2TB-1-3 2TB-1-4 2TB-3-1 2MS-44-4 2MS-44-5 2MS-44-6 2MS-43-5 2MS-43-6 2MS-43-4 2TB-2-1 2TB-1-2 2TB-1-1 MOD#: ME-0420 DWN: MPP 8/31/00 CHKD:

AS BUILT-ADD MSR RELIEF SEALING STEAM VALVES.

PER DRR PI-00-147 FILMED S

DWN: DB 7-2-04 CHKD: CMR 7-7-04 AS BUILT-PER DRR PI-04-052 FILMED 8-04 T

MOD#:

CHANGED WORDING FROM SUCTION TO CASING AT COORD. C-8 SEE DWG. NF-39221 INSTR. TEST CONN.

10-2BL-1 2-2HD-81 2-2HD-83 2-2HD-82 2-2HD-84

603000001331 CAD FILE:

FIGURE 11.1-10 REV. 35 U11110.DGN APPD & CERT:

FOR CONSTRUCTION.

ALARM 47502-0103. ISSUED TURBINE TRIP TO ANNUN.

16872 THRU 16877 FROM CHANGED LEVEL SWITCHES 0103 47502 A

0103 47502 A

LEVEL HI-HI 0103 47502 A

LEVEL HI-HI LEVEL HI-HI S

AS BUILT DWN: LAB 6-8-00 ISSUED FOR AS-BUILT.

VLV. PER ECR NO. 00HD01-1.

REPLACED WITH NEW GATE GLOBE VALVE 2LA-3-23 WITH NEW GATE VALVES.

THRU 2LA-2-96 REPLACED GLOBE VALVES 2LA-2-85 CHKD: D.G. 5/26/00 MOD. No. 00HD01 G. SUNDBERG P.E.# 11840 5/26/00 PER DRR PI-00-118 AS BUILT -

DWN: TF 7/6/00 CHKD: CMR 7/00 MOD#: 00HD01 FILMED 8/00 4-2HD-87 1-2HD-47 4-2HD-89 4-2HD-88 MOD#: 98HD01 DWN: BMS 1-11-01 CHKD: CMR 1-24-01 AS BUILT-ADDED LINE NO. TO HEAT-ER DRAIN PUMP RELIEF VA. DUMPS AS SHOWN.

PER DRR PI-00-201 FILMED 3-01 T

SEE NF-39225 (TYP.)

1" DISCHARGE VENTS (TYP.)

2" 20" 20" 12" 12" DRAIN (TYP) 2HD-1-3 2HD-5-3 2HD-5-2 2HD-1-2 2HD-1-1 2HD-5-1 DWN: DB 7-6-04 CHKD: CMR 7-7-04 AS BUILT-PER DRR PI-04-052 FILMED 8-04 U

MOD#:

ADDED " VENTS 2HD-5-1 THRU 2HD-5-3. REV. CONT.

DESCRIPTIONS AT COORDS.

B-8 AND B6.

2" 1"

12" 20" 2" CASING VENT TO 20" 2-2HD-36 2HD-3-2 2HD-2-2 20-2HD

-32 2-2HD-46 2HD-3-3 2HD-2-3 SEE NF-39225 2-2HD-85 EXPANSION JOINT (TYP.)

TO 21/22/23 HD PMPS PRESS RELIEF VLVS DRN TNK

1. 21 HTR DRN TNK TEMP STRAINER (TYP.)

TO #21 HTR DRN TNK DWN: JLB 11-11-08 CHKD: MC 11-17-08 AS BUILT-FILMED: 12/08 76 MOD#: EC-13174 ADDED CAPS TO CDSR HTR DRN PIPING DRN VALVES.

PER DRR PI-08-102 TE-13160 8"

2" 2"

8" 8"

2HV-5-26 2HD-34-3 2LA-5-10 (III/3)

TANK DRAIN REHEATER 1B 8-2HD-15 8-2HD-16 2"

2" IIB (III/3)

TANK DRAIN REHEATER 2B 11494 PI 12094 TI 27184 FE 23175 F

11493 PI 12093 TI 17386 TT 8-2HD-3

(@ CO-ORD B-1)

TO DPS 17943 1-2HD-65 V

-2HD-64 2LA-5-9 6"

6" 6"

6" 8"

8-2HD-7 16736 LA 0507 47504 A

LEVEL HIGH DRAIN TANK DUMP TO HEATER 2LA-2-70 2LA-3-31 2LA-2-68 8"

8" TE-13158 8"

2" 2"

2HV-5-25 2HD-34-1 2LA-5-2 8-2HD-13 8-2HD-14 11495 PI 12095 TI 17384 TT 8-2HD-1

(@ CO-ORD A-1)

TO DPS 17941 1-2HD-69

-2HD-68 2LA-5-1 6"

6" 6"

6" 8"

8-2HD-5 2LA-3-27 2LA-2-58 2LA-2-56 8"

8" (III/3)

TANK DRAIN REHEATER 1A 1" V 12087 TI 17392 TT TE-13138 2LA-4-84 27181 FE 23172 F

48601 8-2HD-14 8-2HD-13 2HV-5-24 1-2HD-67 1" V

(@ CO-ORD B-1)

TO DPS 17942 48604 2LA-5-13 2LA-5-14 8"

8" TE-13159 8"

2" 2"

IIB (III/3)

TANK DRAIN REHEATER 2A 11496 PI 12096 TI

-2HD-70 27182 FE 23173 F

17385 TT ADDITION (TYP.)

" FOR CHEM.

2HV-5-23 1-2HD-71 1" V

(@ CO-ORD A-1)

TO DPS 17940 8-2HD-6 2HD-34-2 48602 2LA-5-5 2LA-5-6 TE-13161 2HD-34-4 17387 TT

-2HD-66 SEE X-HIAW-248-1 SAMPLE CONN. SS-244 2SS-4-33 8-2HD-8 SEE X-HIAW-248-1 SAMPLE CONN. SS-243 2SS-4-32 SEE X-HIAW-248-1 SAMPLE CONN. SS-241 2SS-4-30 SEE X-HIAW-248-1 SAMPLE CONN. SS-242 2SS-4-31 2LA-6-45 2LA-6-46 2LA-6-41 2LA-6-47 2LA-6-48 2LA-6-42 2LA-6-43 2LA-6-44 2LA-6-39 2LA-6-40 2LA-6-36 16873 LA 2LA-6-31 2LA-6-32 2LA-6-29 2LA-6-30 2LA-2-43 2LA-6-37 2LA-6-38 AS BUILT-ADDED VALVES TO REHEATER DRAIN TANK STAND PIPES PER EC-13965.

DWN: LAB 6-17-09 CHKD: MGC 6-22-09 DWN: LAB 6-17-09 CHKD: MGC 6-22-09 DWN: LAB 6-17-09 CHKD: MGC 6-22-09 AS BUILT-FILMED: 7-09 77 MOD#: EC-13965 ADDED VALVES TO FEED WATER HEATERS GAUGE GLASS PER EC-14292.

PER DRR PI-09-039 2LA-4-120 2LA-2-32 2LA-2-34 16728 LA

1. 23A FW HEATER (III/3) 2LA-1-14 2LA-1-12 2LA-3-14 2LA-1-23 2LA-4-63 2LA-4-46 2LA-4-42 2LA-3-16 2LA-4-65 2LA-4-60 2LA-1-25 2LA-4-61 2LA-3-20 16872 LA 2LA-3-17 2LA-2-20 2LA-4-14 2LA-4-18 2LA-4-16 2LA-3-11 2HD-35-2 2LA-3-37 SEE DWG. NF-39225 HEATER VENT PIPING CONTD AT CO-ORD. A-4 2LA-3-38 16875 LA 0103 47502 A

LEVEL HI-HI 8-2HD-23 2LA-3-15 2LA-1-16 2LA-4-67 2LA-1-27 2LA-3-22 2LA-4-68 2LA-2-38 2LA-1-18 2LA-4-52 2LA-2-36 2LA-4-122 2LA-2-94 16877 LA

1. 23B FW HEATER (III/3)

(III/3)

1. 22A FW HEATER (III/3)

1. 21A FW HEATER 2LA-2-88 2LA-2-87 2LA-2-46 2LA-6-33 2LA-6-34 2LA-2-45 2LA-4-111 (III/3)

1. 22B FW HEATER (III/3)

1. 21B FW HEATER 2LA-1-29 2LA-4-72 2LA-4-70 2LA-2-47 2LA-6-35 2LA-4-113 2LA-2-49 2LA-2-85 2LA-2-51 2LA-1-33 2LA-4-117 2LA-2-89 SEE NF-39240 TEST CONN.

" INSTR.

2" 8"

12" SEE NOTE 2 2) 1)

REFER TO NF-39313-2 FOR VALVE & PIPING DETAILS.

PIPING & VALVE DETAILS NOT INCLUDED.

CONDENSER DUMP TO CONTROL DETAILS FOR VALVE SEE NOTE 1 HIGH LEVEL LEVEL LOW LEVEL LOW HIGH LEVEL 16744 LA 0503 47504 A

24134 L

03 41761 LI 24205 L

16745 LA 0603 47504 A

CONDENSER DUMP TO CONTROL DETAILS FOR VALVE SEE NOTE 1 HIGH LEVEL LEVEL LOW LEVEL LOW HIGH LEVEL CONTROL HIGH LEVEL LEVEL LOW LEVEL LOW HIGH LEVEL DETAILS FOR VALVE SEE NOTE 1 CONDENSER DUMP TO CONTROL HIGH LEVEL LEVEL LOW LEVEL LOW HIGH LEVEL CONDENSER DUMP TO DETAILS FOR VALVE SEE NOTE 1 16746 LA 0504 47504 A

24135 L

04 41761 LI 24206 L

16747 LA 0604 47504 A

16749 LA 0601 47504 A

24207 L

01 41761 LI 24136 L

0501 47504 A

16748 LA 16750 LA 0502 47504 A

24208 L

24137 L

02 41761 LI 16751 LA 0602 47504 A

DWN: KJF 9-17-10 CHKD: DC 10-7-10 AS BUILT-78 MOD#: EC-14849 REMOVED VLVS @ REHEATER DRAIN TANKS 1A,2A,1B,2B &

ADDED NOTE 1 FOR VALVE DTLS & DWG. CONTINUATION.

PER DRR PI-10-141 APPD: CMR 10-11-10 2"

2" 2"

1" 2"

1" 2LA-1-9 2LA-1-10 CONTROL 24015 L

24016 L

41764 LI REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

LAB 5-25-00 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 2

5 6

4410 7400 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 79 39227 NF-39227 NF-by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSP GENERATION CAD NF-39227.DGN FLOW DIAGRAM FEEDWATER HEATER, MOISTURE SEPARATOR

& REHEATER DRAIN SYSTEM - UNIT 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 2LA-1-52 2LA-1-53 2LA-1-57 2LA-1-56 2LA-1-50 2LA-1-51 2LA-1-55 2LA-1-54 CONSTRUCTION ISSUED FOR REPLACE / ADD LEVEL TXMITTERS & ASSOC. PIPI 21 HDT AND REMOVE SIGHT DUE TO AS-FOUND CONDITI N/A PE#

MOD#: EC-20403 79 REVIEWED: RLW 8-3-16 AS BUILT-MOD#: EC-20403 DWN: MEA 12-4-17 CHKD: SJR 12-7-17 DWN: JEH 2-24-15 CHKD: RL 8-2-16 RECORD TRACING.

TRANSFERRED TO CERTIFIED REV. 79, DRR PI-17-154 REV. 79 PER INCORPORATED A/Es PE CERT:

APPD: DB 12-11-17 APPD: RLW 8-3-16 "79" IIB IIB 2-2HD-30 2"

2LA-2-92 2LA-2-91 2LA-2-96 2LA-2-95 2LA-2-93 2LA-2-86 2LA-2-90 2LA-3-23

01516979 CAD FILE: U11111.DGN FIGURE 11.1-11 REV. 34 VFD-64 VFD-63

" DRAIN ROOF 4"

4" 12" 8"

8" 12-2AR-7 DRAIN TO TURBINE BLDG SUMP PS 16168 47508 0505 A

8-2AR-16 8"

6" 8-2AR-6 1"

4" VACUUM BREAKER PIPING IIB IIB 4-2AR-11 14 14 8"

8" 8"

4 4

IIB 8-2AR-9 4

4 8

2AR-1-4 2AR-1-3 8"

8" 8-2AR-8 3"

IIB 4

4 8"

8" 2AR-1-1 2AR-1-2 2AR-6-1 33 III IIB IIB III IIB 1"

III IIB 8"

LOOP SEAL SEE X-HIAW-1006-8 2AR-2-1 8-2AR-9

-2AR-19

-2AR-20 12-2AR-8 2"

2-2AR-19 12" IIB 8-2AR-9

" DRAINS IIB 12" 12-2AR-8 4-2AR-10 2AR-9-3 12" 2AR-9-1 1/2-2AR-19 2"

2" 2"

2" 2AR-9-2 IIB 12" 12" 12-2AR-9 III IIB IIB 8"

8" 8"

8" (III/3)

IIB 2"

1-2AR-3 8-2AR-9 IIB 8"

8-2AR-8 8-2AR-9 2AR-5-1 2AR-5-2

" LOCAL SAMPLE CONN HYDROGEN & TURBINE OIL VENTS (TYPICAL FOR UNIT 1 AND UNIT 2) 1" DRAIN UNIT 1 AIR REMOVAL SYSTEM 1-AR-1 AR-10-1 7-0" MIN 3-AR-1 3"

TO TURB BLDG SUMP 8"

8" 8"

2" 2"

2" 2"

3" 4"

4" M

M 8"

M M

8" 12" 6"

M M

S (TYPICAL) 1" ST 4-2AR-16 4"

2-2AR-16 FLEXIBLE CONNECTOR 2"

2" 2"

4" 4"

47508 0504 A

3-2AR-16 3"

4" 1"

4" 4"

4" 8"

12" 3"

8" 1-E PITCH 4"

4" 8"

12" 12-2AR-7 12-2AR-6 12-2AR-4 12-2AR-5

" D III

1. 22 HOGGING JET (III/3) 8-2AR-8 2-2AR-19 TO TURB. BLDG. SUMP 3-2AR-1 1" DRAIN 1-2AR-1 UNIT 2 AIR REMOVAL SYSTEM 7-0" MIN.

3" 3-2AR-1 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

" III 6"

6" 6"

6" 1"

1" 1"

6" 6"

6" 1"

4" 4"

4" 6"

2" III III 1"D 3"

1. 21 AIR EJECTOR TO ATMOSPHERE 4"

4" FLEXIBLE CONNECTOR 4"

4" SEE NF-39219 ROOF VENTS TO ATMOSPHERE 2"

6" 4"

4" 2"

UNIT 2 UNIT 1 TO ATMOSPHERE 4"

8" 8"

III 12" DRAIN ROOF 8-AR-16 4-AR-4 4"

4" 8"

8" 12" 12" 1"

8-AR-16 6-AR-16 6"

" SAMPLE III 6"

8" 12-AR-7 1"

III (TYP) 1" DRAIN III 8" DRAIN IIB IIB IIB III 1"

III 8"

10" 10" SAFETY HEAD 4-AR-4 PITCH 8"

PITCH 4"

8-AR-6 10-AR-7 12" 8-AR-7 8-AR-6 8"

8" 4"

1. 11 & 21 1"

1. 12 HOGGING JET (III/3)

III

" DRAIN (SEE VENT LOOPSEAL DRAIN) IIB 8"

IIB 12" 8"

12" 12" 12-AR-9 III UNIT 1 UNIT 2 2"

2" III 2"

12" IIB 8"

8" 1"

1" 8"

8" 1"

8-AR-9 IIB 12" 2"

12-AR-8 4-AR-10 IIB IIB 12" IIB 8-AR-8 2-AR-19 III 3"

2-AR-19

" LOCAL SAMPLE CONN 8-AR-9 8-AR-8 8-AR-8 8-AR-9 IIB 2-AR-3 1-AR-3 8"

8" 8"

8" IIB IIB 12" 12" 8"

M M

M 4-AR-11 M

(III/3)

1. 11 HOGGING JET III M

M S

3/4-AR-19 1"

2" 8"

CONTROL 29024 AR-11-5 1/2" AR-11-4 6"

SEE NG-39218 3-AR-16 3" 4" 6-AR-16 1" DRAIN TO TURB. BLDG SUMP 47008 A

0505 FLEXIBLE CONNECTOR 4-AR-16 III ST 4"

4" VENT LOOP SEALS

1. 21 HOGGING JET (III/3) 2AR-10-1 T

T 2AR-11-5 III III 2AR-20-5 AR-8-1 AR-8-2 4"

8" 12" AR-12-2 AR-11-3 MS-20-5 PITCH AR-9-3 AR-9-1 AR-9-2 AR-1-1 AR-11-1 AR-1-2 AR-6-1 AR-1-4 AR-1-3 AR-5-2 AR-5-1 SV-33341 SV-33342 PITCH PITCH PITCH III PITCH AR-10-2 PITCH III REFERENCE PIPING DWG NOS SYSTEM AIR REMOVAL PIPING UNIT 1 NF-39307-1 NF-39307-2 SYSTEM AIR REMOVAL PIPING UNIT 2 NF-39308-1 NF-39308-2 NF-39285-1 SYSTEM HYD. VENTS & MISC. EXHAUST PIPING UNIT 2 SYSTEM HYD. VENTS & MISC. EXHAUST PIPING UNIT 1 NF-39286-1 MD-1-1 2MD-1-1 UNIT 1 UNIT 2 T

T 4

8" 33 4

8" 4

4 14 14 DWN: WLI 8-4-06 CHKD: WJS 8-10-06 AS BUILT-PER DRR PI-06-070 FILMED 9-06 76 MOD#: EC-546 SPECIAL EXH & AUX BLDG GENERAL EXH CHECK DAMPERS CD-36013 ADDED MANUAL DAMPERS AND THRU CD-36016 ON LINE GOING TO AUX BLDG SILENCER EXHAUST 11156 PI "G" LINE TURB BLDG WALL 16046 PS 16169 PS 11091 PI SUMP TURB BLDG 1" DRAIN TO 01 41709 PI BLDG. SUMP DRAIN TO TURBINE 11094 PI NF-39231 CONTD ON DWG TURBINE OIL SUMP TO EMERGENCY WHEN PURGING OPERATION CLOSE DURING NORMAL VALVE LOCKED OPEN GLASS GAGE LOOP SEAL PIPING 3"-INTERCONDENSER PIPING 4" VACUUM BREAKER 32350 MV 32053 MV 32312 MV 32313 MV 32352 MV 32353 MV JET 1/2" DRAIN FROM HOGGING DRILLED HOLE SCREWED CAP WITH "

JET 1/2" DRAIN FROM HOGGING STACK DRAINS FROM 8" & 12 VENT

" DRILLED HOLE SCREWED CAP WITH AT EL. 712-0" BUILDING SUMP DRAIN TO TURBINE SEE DWG. NF-39219 SUCTION RELIEF VALVES

1. 21 AIR EJECTOR 1 STAGE DWG. NF-39219 SUPPLY RELIEF VALVE SEE

1. 21 AIR EJECTOR STEAM BLDG. SUMP

" DRAIN TO TURBINE BLDG. SUMP 1" DRAIN TO TURB.

NF-39605-1 SEE DWG (III/3)

1. 21 GLANDSTEAM CONDENSER (TYP)

DWG NF-39219 STM SUPPLY SEE (III/3)

CONDENSER 2B (III/3)

CONDENSER 2A GLASS 2" TRAP WITH GAGE LOOP SEAL PIPING 3"-INTERCONDENSER 11134 PI 11092 PI 11093 PI UNIT 2 SEE DWG #X-HIAW UNIT 1 SEE DWG #X-HIAW-2-16A STEAM RELIEF VALVES, FOR TURBINE CYLINDER HEATING 6" LOOP SEAL DRAIN TO TB SUMP DWG NF-39219 (TYP)

STEAM SUPPLY SEE (III)

DEMISTER SUMP TURB. BLDG.

1" DRAIN TO THIS DWG.

SEAL DETAIL)

(SEE VENT LOOP BLDG SUMP DRAIN TO TURBINE (III/3) 11 GLAND STEAM CONDENSER (TYPE AIR EJECTOR)

SEE DWG NF-39220 CONDENSATE SYS DWG NF-39218 STEAM SUPPLY SEE X-HIAW-6-34 4" LOOP SEAL SEE CONNECTOR FLEXIBLE SEAL 6" LOOP TB SUMP DRAIN TO (III/3)

SEAL TANK GENERATOR OIL LOOP SEAL DRAIN)

(SEE VENT LOOP BLDG SUMP DRAIN TO TURBINE (TYP)

DWG NF-39218 STM SUPPLY SEE 18503 M

18504 M

16097 PS 16098 PS 0304 47007 A

0304 47507 A

(III/3)

1. 11 GENERATOR VENT (TYP)

HOLE FOR FILL CAP W/"

(TYP)

" ORIFICE (III/3)

CONDENSER 1B (III/3)

CONDENSER 1A GLASS 2" TRAP WITH GAGE 32052 MV 32349 MV 32309 MV 32308 MV 32346 MV 32347 MV (III/3)

1. 11 AIR EJECTOR RELIEF VALVE STEAM SEAL SEE DWG X-HIAW-2-16 TURBINE STEAM SEAL SUPPLY BLDG SUMP

" DRAIN TO TUBINE RELIEF VALVE SEE DWG 39218

1. 11 EJECTOR STEAM SUPPLY 16045 PS 11085 PI SEE DWG. NF-39218 SUCTION RELIEF VALVES

1. 11 AIR EJECTOR 1 STAGE 01 41219 PI ATMOSPHERE TO SEAL SUPPLY TURBINE STEAM 0504 47008 A

16165 PS 16166 PS 11155 PI 11086 PI 11088 PI 11087 PI 11118 PI 21074 P

21071 PI 15 1-RE 2B CONDENSER 2A CONDENSER 2AR-115-3 2AR-115-5 2AR-115-4 2AR-115-6 21075 PT 21283 PT 21285 PT 21076 PT 21284 PT 21286 PT RELIEF VALVES 1st STAGE SUCTION FROM AIR EJECTOR 8-0" 8-0" 8-0" SILENCE EXHAUST REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

ASJ 2/9/00 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 100 400 5

6 4500 7330 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 85 39230 NF-39230 NF-by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSP GENERATION CAD NF-39230.DGN 8-27-69 PE #8626 FLOW DIAGRAM AIR REMOVAL SYSTEM A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 1B CONDENSER 1A CONDENSER 21072 PT 21273 PT 21275 PT 21073 PT 21274 PT 21276 PT AR-115-3 AR-115-5 AR-115-4 AR-115-6 CONSTRUCTION ISSUED FOR ADDED UNIT 2 VACUUM TRANSMITTERS.

APPD & CERT:

RICHARD C. LINDBERG 7-23-08 PE# 44886 DWN: LAB 5-9-08 CHKD: PH 7-23-08 REVIEWED: JM 7-23-08 MOD#: EC-8647 CONSTRUCTION ISSUED FOR INCORPORATE VENDOR DWG. 208D6496, SHT. 3 CHANGES. ADD VACUUM TRANSMITTERS.

APPD & CERT:

RICHARD C. LINDBERG 5-8-07 PE# 44886 MOD#: EC-346 77 REVIEWED: N/A AS BUILT-MOD#: EC-8647 DWN: DMN 3-2-09 CHKD: PH 4-29-09 FILMED: 5-09 DWN: AAH/AMF 5-4-07 CHKD: JSM 5-4-07 RECORD TRACING.

TRANSFERRED TO CERTIFIED REV. 77, DRR PI-09-013 REV. 77 PER INCORPORATED A/Es 2AR-12-1

" VENT 4-2AR-2 4"

41700 FI III 15 2-RE CONTROL 2AR-11-4 8"

8" CONNECTOR FLEXIBLE 4-2AR-4 29025 4"

1" 2-2AR-3 4"

1 1/2-2AR-19 4"

4" 2AR-115-7 2AR-115-1 2AR-11-6 HEAD SAFETY RELIEF VALVE STEAM SEAL 8"

8" 8-2AR-7 III III

" DRN 4"

8" 10" 10-2AR-7 8"-2AR-6 4-2AR-4 PITCH PITCH 12" 8"

-2AR-18

-2AR-15

" SAMPLE 2AR-11-2 18224 FI (249-011)

SEPARATOR MOISTURE IN-LINE 2AR-115-2 1"

LEGEND DENOTES FURNISHED WITH EQUIPMENT DENOTES FURNISHED BY WESTINGHOUSE CORP.

DENOTES CONDENSER TERMINAL CONNECTIONS DENOTES LIMITS OF Q A TYPES DENOTES THE PIPING Q A TYPES DENOTES THE EQUIPMENT Q A TYPE/DESIGN CLASS (II/3)&(III/3)

IIB & III 4

THRU 33 DWN: LAB 7-22-09 CHKD: HBW 7-24-09 AS BUILT-FILMED: 8-09 78 MOD#: EC-13122 ADDED MOISTURE SEPARATOR, REPLACED AIR EJECTOR FLOW XMTR FI-18224 AND REMOVED S/CV 35132.

PER DRR PI-09-061 METER LEAKAGE AIR C-9 NF-39600 SPECIAL EXH TO 122 AUX BLDG.

C-9 FAN NF-39600 GENERAL EXH TO 21 AUX BLDG.

D-8 NF-39600 SPECIAL EXH TO 121 AUX BLDG D-8 FAN NF-39600 GENERAL EXH TO 11 AUX BLDG.

DWN: JEK 12-16-08 CHKD: DB 11-9-09 AS BUILT-79 MOD#: EC-13296 REV CD-36013, 14, 15 & 16 TO BE DOTTED. ADD GRID REFS TO NF-39600.

04NS15 PER DRR PI-08-081 APPD: CMR 11-9-09 36014 CD 36016 CD 36015 CD 36013 CD ROOM SUMP (TYP)

" DRAIN TO TURBINE 4"

III 1"

18223 FI (149-011)

SEPARATOR MOISTURE IN-LINE 1"

METER LEAKAGE AIR AR-115-7 AR-115-2 41230 FI AR-115-1 4-AR-2 AR-12-3

" VENT AR-11-6

" SAMPLE

-AR-18 AR-2-1 4"

4" IIB III III IIB DWN: LAB 3-8-10 CHKD: HBW 4-8-10 AS BUILT-APPD: CMR 4-8-10 80 MOD#: EC-14635 ADDED MOISTURE SEPARATOR, REPLACED AIR EJECTOR FLOW XMTR FI-18223 AND REMOVED S/CV 35131.

PER DRR PI-09-219 DENOTES CATEGORY I VENTILATION ZONE DWN: LAB 3-12-10 CHKD: JMC 4-29-10 AS BUILT-81 MOD#: EC-11687 ADDED CATEGORY I VENTILATION SYMBOL TO LEGEND.

PER DRR PI-09-105 APPD: CMR 4-29-10 11B 11A AR-14-2 AR-14-1 130-012 130-011 AR-3-1 46390 CS AR-12-1 46391 CS AR-14-4 AR-14-3 46394 CS 46397 CS 46393 CS 46403 CS 46398 CS 46399 CS 2AR-14-1 2AR-14-2 230-011 230-012 2AR-14-3 2AR-14-4 46807 CS 46808 CS 2AR-8-2 2AR-8-1 (TYP @ AIR EJECTOR)

SEE DWG. NF-39221 CONDENSATE SYS 4"

2AR-12-1 2AR-12-2 21B 2AR-11-3 21A 6"

III III 6"

6-2AR-16 6-2AR-16

-2AR-16 8-2AR-16

" SAMPLE

-AR-16 1-AR-19

-AR-18

-AR-20

-AR-19 46796 CS 46795 CS 46800 CS 46790 CS 46784 CS 46791 CS 2AR-14-5 6"

(TYP)

CONNECTOR FLEXIBLE 2AR-10-2 1" DRAIN AR-14-5 (UNIT 2)

(UNIT 1) 6" (III/3)

EXTRACTOR VAPOR SEAL OIL BEARING GENERATOR

1. 11 & 21 (III/3)

EXTRACTOR RESERVOIR VAPOR TURBINE OIL

1. 11 & 21 GLASS GAGE 2AR-14-6 AR-14-6 (UNIT 2)

(UNIT 1)

(NF-39231-2)

(NF-39231-1)

RESERVOIR TURBINE OIL

1. 11 & 21 16173 PS 18501 TAP 0405 47008 A

18502 TAP 0405 47508 A

(UNIT 2)

(UNIT 1)

DWN: LAB 4-26-11 CHKD: SRB 4-28-11 AS BUILT-82 MOD#: EC-13991 CHANGED AND/OR ADDED AR-14-1 THRU AR-14-6 &

2AR-14-1 THRU 2AR-14-6 TO AND INSTRUMENTATION.

EXTRACTOR SUCTION LINE 21 TURBINE OIL RESERVOIR FROM ES TO CS. ADDED 11 &

CONTROL SW DESIGNATION CDSR AIR EXHAUSTER. REVD CONFIGURATION AT 11A, 11B CORRECTED PRESS. SWITCH BUTTERFLY VALVES.

PER DRR PI-11-055 APPD: CMR 4-28-11 (UNIT 2)

(UNIT 1)

DWN: JEK 11-16-11 CHKD: SMF 12-7-11 AS BUILT-83 MOD#: EC-18795 CORRECTED TYPOS ON VALVE IDS, AR-11-1 TO AR-11-2 & 2-2AR-11-1 TO 2AR-11-1.

PER DRR PI-11-218 APPD: CMR 12-12-11 AR-11-2 2AR-11-1 "85" 2"

2-AR-16 DWN: JEK 2-8-13 CHKD: RTC 2-12-13 AS BUILT-84 MOD#: EC-20079 CHANGED 2" LINES FROM #11 AIR EJCTR 1ST STG SUCT RLF VLVS TO 2" & LINE NO. TO 2-AR-16.

PER DRR PI-13-029 APPD: CMR 2-12-13 16177 PS DWN: MEA 10-21-15 CHKD: RLM 10-13-15 AS BUILT-85 MOD#: EC-25881 PRESSURE SWITCH NO.

CHANGED FROM 16174 TO 16177 (UNIT 2).

PER DRR PI-15-133 APPD: KJW 10-28-15

01516979 CAD FILE:

FIGURE 11.1-12 REV. 34 U11112.DGN D

D D

4. FOR SYMBOLS SEE XH-1-105, NF-39214.

DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

5.

6.

7.

}

}

IA,IB,IC,IIA,IIB & III DENOTES PIPING QA TYPES.

1. 25

1. 25

1. 37

1. 26

1. 26 SV-33027 SV-33020 SV-33022 SV-33025 SV-33024 SV-33023 SV-33021 M

M M

1. 38

1. 38 75 SLOP DRAIN (WASTE OIL & WATER) - CAPPED 38 1"

1. 38

1. 38 1"

TURBINE GLAND STEAM SUPPLY STRAINERS SEE

1. 75

1. 75 SEE NF-39218 MAIN STEAM DRAINS 30" 31" 12" 1"

12" 30" 31" 1"

TD-11-49 1"

1" 1"

2" 1"

1" NOTES:

3.

DENOTES CATEGORY I VENTILATION ZONE

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

C2 NSR CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS DENOTES STEAM TRAP DENOTES TIE-IN TO EXISTING SYSTEM 25 1"

1" 1"

1" 1"1" TD-17-4 1"

TD-7-32 TD-17-3 1"

1" 1"

1" 1"

1" 1"

1" 2"

1" 1

2 3

4 5

1" 1"

1" 1" 1" 1"

2" 1" 2" 1"

2" 2"

TD-10-25 TD-10-24 1"

33 NF-39226 3"

34 TD-10-23 TD-28-1 1"

1" TD-15-2 TD-15-4 TD-15-3 RS-22-1 TD-24-2 TD-24-1 TD-18-6 TD-11-47 TD-18-5 TD-11-46 TD-11-45 TD-11-44 RS-15-2 RS-15-1 TD-15-7 TD-15-5 TD-11-50 3"

RS-19-1 31098 MV TD-15-6 D

TD-10-29 TD-10-26 TD-10-27 TD-10-28 TD-11-43 TD-17-2 TD-6-54 TD-4-1 31099 MV RS-19-2 NSR C2 TD-24-3 TD-24-4 TD-10-22 TD-11-37 TD-11-36 TD-11-38 TD-10-18 D

TD-18-4 TD-17-1 TD-9-1 TD-6-38 TD-28-2 TD-7-33 TD-10-20 IIB IIA IIB REFERENCE DWGS:

IB III QA TYPE LEGEND CLASS BREAK 1"

6" 2"

1" TD-18-3 TD-6-34 1"

TD-6-33 TD-6-32 TD-13-1 3"

31998 CV 31059 CV REGULATOR TD-13-6 TD-13-5 1"

1" 12" 6"

1" 1"

1" 1"

1" 1"

1" 1"

1" 6"

TD-6-47 TD-6-45 TD-6-42 TD-6-43

" ORIFICE OLD TRAP #12 TD-10-14 TD-10-15 TD-10-13 8

TD-10-12 IIA MS-132-1 IIA IC 13 14 15 TD-10-16 TD-21-1 TD-9-3 TO TURBINE SUMP 2"

6"

1. 39

1. 39 TD-10-17

-MS-46A NSR C3 IC IIA IB IIA NSR C2 IB IIA NSR C3 IC IIA G-1 SEE NF-39218 TO AUX FW PUMP TURBINE FROM #11 AUX STEAM TO 14A & 14B 24" 4"

6" 6"

6" 1"

1" 1"

1" 1"

1" 1"

6" 4"

4" 1"

16" TO 15A & 15B 11 HOGGING JET 12 HOGGING JET 3"

30" 12" 12" 8"

8" 12" 6"

30" SEE XH-2-15 STEAM DRAIN & GLAND ASSY (III/3)

HP TURBINE RH LH 2" 2" 2"

2"

1. 37

1. 37 STRAINERS SEE XH-2-16A TURB GLD STM SUPPLY TO TURBINE BLDG SUMP LP TURBINE (III/3) 2" 2"

1. 44

1. 24

1. 24

1. 45 SEE XH-2-15 ON STOP VALVE STEAM LEAKOFF FROM PILOT VALVE 1"

1. 25 1"

1. 70 IIB

1. 75

1. 75 IIB IIA IIB SV-33026 IIB IIB 2"

2" 2"

2" 2" 2" 2" IIB IIB IIA IIB IIB 2"

2" 30" VALVE HEADER SEE NF-39224 MOISTURE SEPARATOR RELIEF 30" 2"

1. 74 1"

1" 2"

SEE NF-39224 TANK #11 2" TO HEATER DRN

1. 38

1. 36

1. 36 DRAINS SEE XH-2-16A TURBINE CYLINDER HEATING SYSTEM 1"

1" 1"

1" 1"

1" 1"

1"

1. 27

1. 34

1. 34

1. 34

1. 34

1. 34

1. 34

1. 34

1. 34

1. 35

1. 42

1. 41

1. 41

1. 41

1. 41

1. 43

1. 43 1"

1" 1"

2" 2"

2" 2"

2" 2"

2" 2"

1" 1"

1" 1"

1" 1"

1. 41 1"

IIA IIB 1"

3" "

1" 1"

6" 1"

1" 1"

3" AS-4-9 TD-7-9 TD-7-5 1"

F-9 SEE NF-39605-1 MANIFOLD TO DEAERATOR D-5 NF-39605-1 E-2 SEE NF-39605-1 HEATING SYSTEM UNIT 1 BLEED STEAM TO E-3 SEE NF-39605-1 HEATING SYSTEM UNIT 2 BLEED STEAM TO 28 26 27 IIB IIA III IIB III IIB III IIB IIB IIB 1"

1"

1. 43

1. 43 1"

1" IIA IIA IIB IIB 2"

2" IIB

1. 39 III IIB IIA IIB

1. 44

1. 40 TD-6-46 TD-18-1 TD-18-9 IIA IIB 1"

32 TD-6-44 IIB IIB IIA IIA IIB TD-6-40 TD-13-4 B-2 B-4 2"

2" TURBINE GLAND STEAM SUPPLY STRAINERS SEE DWG. XH-2-16 DWG. XH-2-16 DRAIN STEAM RING H-2 SEE NF-39218 AUX STEAM TO #11 AFWP F-3 SEE NF-39218 MAIN STEAM BYPASS SUMP TO TURBINE BLDG (III/3)

CONDENSER IB (III/3)

CONDENSER IA SEE LEEDS-NORTHRUP XH-248-1 FROM SAMPLE RECOVERY SYSTEM 1"

1" 37 37A 36 36A IIB IIB IIA 10" 10" SEE NF-39218 SUPPLY LINE MOIST SEP REEHEATER 1"

1" 1"

1" 1"

30 2"

3" 3"

2" 2"

2" 2"

9 1"

IIA 1"

1" IIB IIA IIB 1"

1" 1"

1" IIB 1"

B-6 B-4 F-7 SEE NF-39218 STEAM TO CONDENSER 4" AUX STEAM FOR DEAERATOR SEE NF-39224 H.P. HEATERS BLEED STEAM TO E-6 SEE NF-39218 AUXILIARY STEAM F-6

1. 35A TRAP TRAP

1. 35 TD-6-50 1"

1" 1"

1" 1"

1" 1"

1" B-3 B-4 B-4 B-7 B-10 B-7 SS-6-1 SEE NF-39224 TANK #11 TO HEATER DRN B-10 SIGHT GAGE TD-5-10 TD-7-22 TD-7-29 TD-7-30 TD-7-23 TD-7-27 C-7 C-4 F-7 SEE NF-39218 VALVE DRAINS 1" TURB STOP H-9 SEE NF-39218 TO CONDENSER DEAERATOR STEAM H-6 SEE NF-39218 MAIN STEAM DRAINS D-4 E-4 E-6 SEE NF-39218 REGULATING STATION GLAND STEAM PRESS A-5 A-4 D-4 E-5 SEE NF-39605-1 HEATER #121 FROM WATER F-8 SEE NF-39218 WATER BOX EJECTOR AUX STEAM TO CONDENSER C-5 SEE XH-2-16 SPILL OVER REGULATING STATION TURBINE GLAND STEAM (TYP.)

SEE XH-2-16 TURBINE SLOP DRAINS B-2 B-4 B-4 B-6 (TYP. 4) 1" SEE NF-39218 AUX STEAM TO HOGGING JET 1-MS-58A 1-MS-56A 1-MS-55A 2-MS-62 1-MS-62A 1-MS-54A 1-MS-53A

-MS-57A TD-7-15 TD-10-21 TD-10-19 TD-11-40 TD-11-39 C3 NSR H-8 SEE NF-39226 HEATER DRN TNK VNT HD-13-17 IIA IIB IIA IIB IIA IIB IIB IIB IB IIA NSR C2 RS-22-2 IB IIA NSR C2 H-3 SEE NF-39218 TD-7-13 TD-27-1 TD-7-4 TD-7-6 TD-7-14 TD-7-7 TD-7-8 TD-27-2 BL-10-1 TD-7-11 TD-7-10 TD-7-12 TD-27-3 XH-2-15 STM DRN & GLAND SYS FLOW DIA U1 NF-39224 BLD STM & HTR VNTS SYS FLOW DIA U1 FLOW DIA U1 NF-39226 FW HTR, MOIS SEP & RHTR DRNS SYS NF-88740 SGB SYS FLOW DIA UNIT 1 &2 NF-39605-1 HTG STM SYS FLOW DIA UNIT 1 &2 NF-39218 MS STM SYS FLOW DIA UNIT 1 XH-2-16 STM DRN & GLAND SYS FLOW DIA U1 XH-2-16A STM DRN & GLAND SYS FLOW DIA U1 FLOW DIA U1 XH-248-1 HOT LAB GRAB SMPL PNL, SURVEY PNL (TYP) 1" CONTROL VALVES 48015 CONTROLLER)

(TURBINE AUX DWN: DB 7-24-09 CHKD: JEK 9-24-09 AS BUILT-PER DRR PI-09-060 APPD: CMR 1-12-10 80 MOD#: EC-14376 ADD SAFETY CLASS FLAGS LEGEND & NOTES, REF DWGS

& GRID REFS TO DWG CONTS

& MISC LN NOS. 04NS15 DWN: DMN 9-29-10 CHKD: MC 9-30-10 AS BUILT-81 MOD#: EC-16067 CORRECTED DUPLICATE VALVE ID AT GRID D-10 FROM TD-6-35 TO TD-6-33 PER DRR PI-10-156 APPD: CMR 9-30-10 "84" DWN: KJF 4-29-10 CHKD: JBS 10-12-10 AS BUILT-82 MOD#: EC-14472 CORRECTED PIPING AT DRAWING LOCATION B-9.

PER DRR PI-09-163 APPD: CMR 10-18-10 DWN: LAB 8-19-11 CHKD: CMR 8-23-11 AS BUILT-83 MOD#: EC-18206 CORRECTED VALVE ID FROM TD-12-1 TO TD-21-1 AT LOCATION G/9.

PER DRR PI-11-157 APPD: CMR 8-23-11 D-7 / D-8 SEE NF-39218 SUPPLY TO HOGGING JETS

" FROM HTG SYS CALTERNATE 1.5" 1.5" 1.5" DWN: MEA 9-8-15 CHKD: RLM 9-30-15 AS BUILT-84 MOD#: EC-24467 CORRECTED PIPING AT DRAWING LOCATION F-1

" &1" CHANGED TO 1.5".

REROUTE PIPE TO CAP.

PER DRR PI-15-108 APPD: KJW 10-28-15 REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 100 5

6 4410 5343 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 84 39233 NF-39233 NF-NSP GENERATION CAD NF-39233.DGN FLOW DIAGRAM TURBINE BUILDING TRAPS AND DRAINS UNIT 1 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

E-11 SEE NF-39218

1. 11 AIR EJECTOR, STEAM F-5 SEE NF-39218 FROM #12 STEAM GEN.

E-2 SEE NF-39218 DPI-17651 TO LOW SIDE F-3 SEE NF-39218 A.F.W. PUMP TURBINE FROM #12 AUX. STEAM TO B-6 NF-88740 B-5 NF-88740 F-4 SEE NF-39218 E-3 SEE NF-39218 DP1-17652 TO LOW SIDE B-4 SEE NF-39218 RELIEF VENTS 1" - TO SAFETY B-1 SEE NF-39218 RELIEF VENTS 1" TO SAFETY G-5 GEN. SEE NF-39218 FROM #11 STEAM

603000001331 CAD FILE:

FIGURE 11.1-13 REV. 35 U11113.DGN

2TD-6-29 2TD-7-3 11 3"

75 M

M M

43 43 43 41 35 42 DWN: VLS 06/14/05 CHKD: CMR 06/15/05 AS BUILT-FILMED: 07/05 AE MOD#: 05TB01 SLOP DRAINS REMOVED

& CAPPED AND DELETED DESCRIPTION FOR TURB CONN NO. 75 PER DRR PI-05-103 CONSTRUCTION ISSUED FOR REPLACED CONTROL SWITCH ES-46804 WITH TURBINE CONTROLLER 48515 AND CONN.s 36.

APPD & CERT:

RICHARD C. LINDBERG 7-24-08 PE# 44886 MOD#: EC-8647 78 REVIEWED: JM AS BUILT-MOD#: EC-8647 DWN: DMN 4-15-09 CHKD: PH 4-24-09 FILMED: 5-09 DWN: LAB 6-16-08 CHKD: PH 7-23-08 DWN: WLI 2-28-07 CHKD: JMD 2-28-07 AS BUILT-FILMED: 3-07 76 MOD#: EC-10043 CORRECTED PENET NUMBERS TO 2B CDSR PER DRR PI-07-017 DWN: DMN 5-20-08 CHKD: BS 6-2-08 AS BUILT-FILMED: 6-08 77 MOD#: EC-10792 CORRECTED DESC & DWG REF FROM COND RETURN FROM HEATING STEAM TO HEATER DRAIN TANK VENT PER DRR PI-08-035 AT CDSR CONN NO. 44 AND D-9 DELETED LOW VAC TRIP LINE, CONN. 28 & CAPPED RECORD TRACING.

TRANSFERRED TO CERTIFIED REV. 78, DRR PI-09-034 REV. 78 PER INCORPORATED A/Es DWN: JLB 5-12-09 CHKD: NWM 5-19-09 AS BUILT-FILMED: 6/09 79 MOD#: EC-13412 REMOVE GAGE GLASS SHOWN AT C-1.

PER DRR PI-09-041 2TD-15-4 2TD-11-50 2TD-10-18 2TD-10-19 2TD-10-20 2TD-28-2 2TD-17-1 2TD-10-17 2TD-15-6 2TD-15-5 2TD-15-7 2TD-4-1 2TD-24-4 2TD-15-2 2TD-15-3 2TD-24-2 2TD-24-1 2TD-11-49 2TD-11-45 2TD-11-47 2TD-6-53 TD-11-41 TD-11-42 2TD-11-46 2TD-18-6 2TD-28-1 2TD-9-3 2TD-9-1 2TD-21-1 2TD-6-38 2TD-10-16 2TD-7-32 2TD-18-5 2TD-17-3 2TD-17-2 2TD-10-25 2TD-10-24 2TD-17-4 2TD-5-8 2TD-5-7 2TD-5-6 2TD-5-5 1"

2" 2"

2" 1"

31 3"

1" 1"

1" IIA IB 1"

1" 30" 12" 2TD-7-33 2"

12" 5

4 3

2 1

2TD-11-38 2TD-11-39 2TD-11-40 2TD-18-4 1"

1" 1"

1" 1"

2" 2"

2" 2"

2" 2"

2" 2"

2" 1"

TD-11-35 TD-11-34 2TD-10-23 2TD-24-3 2" TO TURBINE BLDG SUMP IIB IIA 1

2TD-10-22 2TD-10-21 2TD-6-54 1"

30" 31" 31" 12" IIA IIB 1"

1" 1"

1" 1"

1" IIA IB E-3 SEE NF-39219 DPI-17653 TO LOW SIDE 2TD-10-29 2TD-10-28 2TD-10-27 2TD-10-26 2"

SEE DWG NF-39219 MAIN STEAM DRAINS 1"

1" IIA IB IIA IIB IIA IC IIA IC 30 2TD-18-3 2TD-10-30 2TD-1-2 2TD-6-34 2TD-6-32 2TD-6-33 2TD-13-1 2TD-10-15 2TD-10-13 2TD-10-14 2TD-10-12 2TD-13-5 2TD-13-6 OLD TRAP #12

" ORIFICE 3"

1 1

1 1

1 1

1 1

12" 1"

1" 1"

1" 1"

8 29 2TD-6-44 2TD-13-4 2TD-13-3 2TD-6-41 2TD-6-42 2TD-6-45 2TD-6-46 2TD-6-47 2TD-6-43 2TD-18-1 2TD-18-9 2TD-20-1 2TD-16-4 2TD-16-3 2TD-16-2 2TD-16-1 2TD-13-2 2"

2" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

1" 1"

6" 6"

6"

1. 44

1. 40 6"

6"

1. 70

1. 25

1. 70 IIA IIB IIB III IIA IC IIB IIB IIA IIA IIB 15 14 13 IIA IIB IIA IIB D

D RS-22-4 RS-22-3 IIB IIB IIB D-7 SEE DWG NF-39250 STEAM LINE FROM FLASH TANK IIB IIB IIB IIB IIB IIA IIB IIB IIA IIB IIB IIA SUMP TO TURBINE BUILDING IIB IIB IIB IIB IIB IIB IIB IIB IIA IIA IIB IIB IIB IIA IIA E-3 SEE NF-39219 DPI-17654 TO LOW SIDE (TYP)

TRAP STEAM (TYP)

TRAP STEAM D-6 SEE DWG NF-39250 STEAM LINE FROM FLASH TANK (III/3)

CONDENSER 2A (III/3)

CONDENSER 2B IIB IIA IIA IIB SUMP TO TURBINE BUILDING XH-1002-43 ON STOP VALVE SEE DWG STEAM LEAKOFF FROM PILOT VALVE

1. 21 HOGGING JETS

1. 22 HOGGING JETS TO #25A & #25B TO #24A & #24B (TYP)

TRAP STEAM E-7 SEE DWG NF-39219 REGULATING STATION GLAND STEAM PRESS SEE DWG XH-1002-45 STEAM DRAIN & GLAND ASSY (TYP) 1" CONTROL VALVES (III/3)

LP TURBINE (III/3)

LP TURBINE (III/3)

1. 21 GLAND STEAM CONDENSER DRAINS SEE DWG XH-1002-45 TURBINE CYLINDER HEATING SYSTEM SEE DWG NF-39225 RELIEF VALVE HEADERS MOISTURE SEPARATOR DWG NF-39225

1. 21 FOR CONT SEE 2" TO HTR DRN TNK ORIFICE SIGHT GAGE GAGE GLASS TELLTALE DRAIN TO FLOOR MEZZ FLOOR CAP FOR FILL C3 NSR C3 NSR NSR C3 NSR C2 C2 NSR 1-2MS-56A

-2MS-44A

-2MS-45

-2MS-44 1-2MS-58A

-2MS-45A 1-2MS-54A 1-2MS-53A 1-2MS-56 2-2MS-62 2-2MS-54 1-2MS-55A 1-2MS-62 2-2MS-54 1-2MS-53A

-2MS-45A 2"

1" NOTES:

3.

DENOTES CATEGORY I LEGEND VENTILATION ZONE

4. FOR SYMBOLS SEE XH-1-105, NF-39214.

DESIGN CLASS.

I/1 DENOTES EQUIPMENT QA TYPE/

2.

MANUAL C PROCEDURE CHECKLIST.

FOR VALVE POSITIONS SEE OPS 1.

5.

C2 NSR CLASSED AS NON-SAFETY-RELATED.

DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

STOP AT VENT AND DRAIN VALVES WITH UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES C1 - SAFETY-RELATED; ISI CLASS 1 C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; ISI CLASS 3 NSR - NON-SAFETY-RELATED SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS IB III CLASS BREAK QA TYPE 6.

7.

25 DENOTES STEAM TRAP DENOTES EXISTING SYSTEM TIE-IN FOR CONT SEE NF-39219 D-7 SUPPLY TO HOGGING JETS)

" FROM HTG SYST (ALTERNATE 2MS-15-1 2MS-15-2 RS-19-3 31116 CV RS-19-4 31117 CV PUMP TURBINE F-3 TO AFW FROM #22 AUX STEAM PUMP TURBINE G-1 TO AFW FROM #21 AUX STEAM F-2 STM GEN FROM 2A F-4 STM GEN FROM 2B SEE DWG NF-39219 F-7 STEAM TO CONDENSER 4" AUX STEAM FOR DEAERATOR SEE DWG NF-39219 D-7 AUX STEAM TO HOGGING JETS SEE DWG NF-39219 F-6 REHEATER SUPPLY LINE MOISTURE SEPARATOR SEE DWG NF-39219 H-9 TO CONDENSER DEAERATOR STEAM SEE DWG NF-39219 H-6 MAIN STEAM DRAINS NF-39219 E-6 SEE DWG AUXILIARY STEAM SEE DWG NF-39219 E-8 WATER BOX EJECTOR AUX STEAM TO CONDENSER SEE DWG NF-39219 E-11

1. 21 AIR EJECTOR STEAM PUMP SEE DWG. NF-39219 H-2 AUX STEAM TO #22 AFW SEE DWG. NF-39219 G-11 MAIN STEAM BYPASS DWG. NF-39219 H-3 FOR CONT SEE NF-39219 A-4 VENTS, SEE DWG 1 " TO SAFETY RELIEF NF-39219 B-1 VENTS, SEE DWG 1" TO SAFETY RELIEF B-7 B-10 SEE DWG NF-39225 E-4 HP HEATERS BLEED STEAM TO D-3 SEE DWG NF-39227 TANK TO HEATER DRAIN REFERENCE DWGS:

NF-39219 MS SYSTEM FLOW DIA UNIT 2 NF-39250 SGB SYSTEM FLOW DIA UNIT 1&2 NF-39605-1 HTG STM SYSTEM FLOW DIA UNIT 1&2 FLOW DIA UNIT 2 NF-39225 BLD STM & HTR VENTS SYSTEM DRNS SYSTEM FLOW DIA UNIT 2 NF-39227 FW HTR, MOIS SEP & RHTR XH-1002-43 STM DRN & GLAND SYS FLOW DIA UNIT 2 XH-1002-44 STM DRN & GLAND SYS FLOW DIA UNIT 2 XH-1002-45 STM DRN & GLAND SYS FLOW DIA UNIT 2 2TD-6-30 F-10 SEE DWG NF-39605-1 HEATING SYSTEM IIB CV-31363 A-6 CV-31362 A-5 SEE DWG XH-1002-44 C-4 SPILLOVER REGULATING STATION TURBINE GLAND STEAM B-4 B-6 B-2 B-4 DWG XH-1002-44 SUPPLY STRAINERS SEE TURBINE GLAND STEAM DWG XH-1002-44 SUPPLY STRAINERS SEE TURBINE GLAND STEAM B-7 B-4 B-4 B-3 SEE DWG XH-1002-45 TURB GLD STM SUPPLY STRAINERS 31060 CV 31999 CV DRAIN STEAM RING IIB H-8 DWG NF-39227 TANK VENT HEATER DRAIN D

D IIA IB NSR C2 NSR C2 1"

IA,IB,IC,IIA,IIB,& III DENOTES PIPING QA TYPES DWN: JEK 7-20-09 CHKD: DB 9-23-09 AS BUILT-PER DRR PI-09-060 APPD: CMR 1-12-10 80 MOD#: EC-14376 ADD SAFETY CLASS FLAGS LEGEND & NOTES, REF DWGS

& GRID REFS TO DWG CONTS

& MISC LN NOS. 04NS15 (TYP)

TRAP STEAM 2" FLOAT TRAP 1"

DWN: DMN 4-29-10 CHKD: BWK 5-10-10 AS BUILT-PER DRR PI-10-075 APPD: CMR 5-10-10 81 MOD#: EC-15499 REVISE LINE DIMENSIONS TO REFLECT PLANT CONFIGURATION "84" (III/3)

HP TURBINE

1. 24

1. 24 IIA 1"

1" F-7 SEE NF-39219 VALVE DRAINS 1" TURB STOP DWN: KJF 10-4-10 CHKD: JBS 10-12-10 AS BUILT-PER DRR PI-09-163 APPD: CMR 10-18-10 82 MOD#: EC-14472 CORRECTED PIPING AT DRAWING LOCATION B-9.

ADDED TURBINE STOP VLV.

DRAINS, & CONTINUATION.

48515 ES CONTROLLER TURBINE AUX HEATER DRAIN TANK VENT 1.5" 1.5" 1.5" DWN: MEA 9-8-15 CHKD: RLM 9-30-15 AS BUILT-PER DRR PI-15-108 APPD: KJW 10-28-15 83 MOD#: EC-24467 CORRECTED PIPING AT DRAWING LOCATION F-1.

" & 1" CHANGED TO.

1.5" DIAMETER.

DWN: MEA 12-8-16 CHKD: TEO 12-8-16 AS BUILT-PER DRR PI-16-270 APPD: DB 12-8-16 84 MOD#: EC-25491 SWAPPED VALVES FROM GATE TO GLOBE &

CHANGED GATE TO GLOBE REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 2

5 6

4410 5343 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 84 39234 NF-39234 NF-NSP GENERATION CAD NF-39234.DGN FLOW DIAGRAM TURBINE BUILDING TRAPS AND DRAINS UNIT 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

603000001331 CAD FILE:

FIGURE 11.1-14 REV. 35 U11114.DGN MOD#:

DWN: MRH 01/18/95 CHKD:

AS BUILT-DELETED CHEMICAL FEED PIPING AND REF. DWG.

PER DRR PI-94-196 FILMED AL MOD#: 93A279 DWN: JMM 2-18-98 CHKD: PAS 2-26-98 AS BUILT-ADDED FLANGES AND REDUCERS AS SHOWN PER DRR PI-97-182 FILMED 3-98 AM MOD#: 00GS01 DWN: TF 3-14-01 CHKD: CMR 3-29-01 AS BUILT-DELETED DRAINS GS-8-15

& 16 FROM 11 & 12 FEED WATER PUMPS. ADDED EQUIP.

NOS. TO TRAPS AS SHOWN.

PER DRR PI-01-025 FILMED 4-01 AN GS-14-1 "76" MOD#:

DWN: WLI 1-12-05 CHKD: CMR 1-12-05 AS BUILT-ADDED VALVE GS-14-1 PER DRR PI-05-013 FILMED 2-05 AP REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1

400 5

6 4400 7402 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 76 39239 NF-39239 NF-NSP GENERATION CAD NF-39239.DGN FLOW DIAGRAM UNIT 1 FEED WATER PUMP INJECTION & GLAND SEAL PIPING A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

16B 16A 17B 17A GS-113-3 GS-113-2 11500 DPI DWN: JEK 5-8-13 CHKD: RTC 5-14-13 AS BUILT-76 MOD#: EC-21987 CHANGED PI-11500 TO DPI-11500. ADDED VLVS GS-113-2

& GS-113-3 & LN BETWEEN DPI-11500 & PI-11501.

PER DRR PI-13-087 APPD: CMR 5-15-13

603000001331 CAD FILE:

FIGURE 11.1-16 REV. 35 U11116.DGN REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

SAB 8-18-95 NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 100 400 5

6 4420 7700 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 82 39215-1 NF-39215-1 NF-by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for NSP GENERATION CAD NF-39215-1.DGN CIRCULATING WATER UNIT 1 & 2 FLOW DIAGRAM A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 DIFF HIGH DIFF HIGH NF-39217-1 30" STAND PIPE, SEE DWG.

(TYPICAL)

CLEANING BALL TRAPS CONDENSER TUBE (TYP.)

EXPANSION JOINT IN PLACE ABANDON IN PLACE ABANDON SUMP PUMPS HOUSE SCREEN PANEL CONTROL HEAD DIFF.

NF-39228 SOLENOID VALVES TO SCREEN WASH DIFF HIGH DIFF HIGH (16 PLACES TYP.)

FLAT PERFORATED STRAINERS IB CONDENSER (III/3)

(4 PLACES TYP.)

CONE STRAINERS ROOM SUMP (TYP.)

DRAIN TO TURBINE SEE DWG. NF-39218 STEAM SUPPLY SEE DWG. NF-39219 STEAM SUPPLY EJECTOR (III/3)

1. 21 CONDENSER WATER BOX S

S DISCH.

OUTER PASS CONDENSER 155-021 UNIT 1A

1. 11 TRAP PUMP 145-013

1. 11B RECIRC.

PUMP 145-011

1. 11A RECIRC.

DISCH.

INNER PASS CONDENSER 155-022 UNIT 1A

1. 12 TRAP PUMP 145-014

1. 12B RECIRC.

PUMP 145-012

1. 12A RECIRC.

S S

SOUTH LOOKING INLET INNER PASS CONDENSER

1. 1B SOUTH LOOKING INLET OUTER PASS CONDENSER

1. 1B 155-011 UNIT CATCHING

1. 11 BALL 155-012 UNIT CATCHING

1. 12 BALL (NF-39241-1) (F-7)

DOMESTIC WATER TIE-IN TO EXISTING DW-128-1 SET TO 15 PSI OUTLET PRESS.

PRESS. REG.

CONN.

TEST PREVENTER BACKFLOW DW-127-1 DW-130-1 DW-130-2 DW-129-1 S

S 255-012 UNIT CATCHING

1. 22 BALL DISCH.

OUTER PASS CONDENSER 255-022 UNIT 2A

1. 22 TRAP PUMP 245-014

1. 22B RECIRC.

PUMP 245-012

1. 22A RECIRC.

DISCH.

INNER PASS CONDENSER 255-021 UNIT 2A

1. 21 TRAP PUMP 245-013

1. 21B RECIRC.

PUMP 245-011

1. 21A RECIRC.

S S

SOUTH LOOKING INLET INNER PASS CONDENSER

1. 2B SOUTH LOOKING INLET OUTER PASS CONDENSER

1. 2B 255-011 UNIT CATCHING

1. 21 BALL PREVENTER BACKFLOW (NF-39241-1) (C-7)

DOMESTIC WATER TIE-IN TO EXISTING DW-130-3 DW-130-4 DW-127-2 DW-128-2 SET TO 15 PSI OUTLET PRESS.

PRESS. REG.

CONN.

TEST DW-130-5 DW-129-2 "82" CONSTRUCTION ISSUED FOR REVD UNIT 2 COND. TUBE CLEANING PIPING. REMOVED APPD & CERT:

PHC 77 AS BUILT-MOD#: EC-349 AS BUILT-MOD#: EC-349 CHKD: RBW 3-13-07 DWN: LAB 8-1-06 CHKD: RBW 8-1-06 DWN: WLI 2-26-07 RECORD TRACING.

TRANSFERRED TO CERTIFIED REV. "77",

DRR PI-07-013 REV. "77" PER INCORPORATED A/Es PE# 42848 FOR UNIT 2; ADD DP21290-7-25-05 FILMED: 4-07

1. 12 PER EC-8149, 8240, 8913 &

WTR SPLY LINE VALVES 9632.

-DP21293 IDS. ADDED DOM REVIEWED: FJD/TFM 7-25-05 MOD#: EC-349 CHKD: RW 7-25-05 DWN: VP 7-25-05 02CR01 DPI-18410 & DPI-18411 DWN: DMN 1-22-08 CHKD: EJH 4-29-09 AS BUILT-FILMED: 5-09 78 MOD#: EC-12103 CORRECTED CONFIGURATION OF TRVLG SCRN BUBBLER TUBES PER DRR PI-08-002 2CW-90-1 DWN: JEK 11-9-12 CHKD: SMF 12-19-12 AS BUILT-79 MOD#: EC-19491 CORRECTED VALVE NUMBER FROM 2CW-40-1 TO 2CW-90-1.

PER DRR PI-12-208 APPD: CMR 12-19-12 PLUG PLUG PLUG DWN: DB 2-6-13 CHKD: SLW 6-19-13 AS BUILT-80 MOD#: EC-21194 REMOVED & PLUG TT-17366

& TT-17367 @ LOC D-4.

PER DRR PI-13-019 APPD: CMR 6-19-13 2TC-2-7 DWN: JEK 5-29-14 CHKD: BAW 5-29-14 AS BUILT-81 MOD#: EC-23535 CORRECTED VALVE NUMBER FROM CTC-2-7 TO 2TC-2-7.

PER DRR PI-14-086 APPD: CMR 5-29-14 18666 DP 18667 DP "82" DWN: MEA 4-20-16 CHKD: DC 4-20-16 AS BUILT-82 MOD#: EC-24001 INSTALLED DIFF. PRESSURE INDICATORS DP 18666 & DP 18667 PER DRR PI-16-112 APPD: DB 4-25-16 A

A 47501 47501 0403 0402 LI 41773 02 CR-3-1 2CW-90-3 NOTE 1 90 90 NOTE 1 PR 42611 03 TE 15506 NOTE 1 CR-4-2 2CW-90-2 84 84 84 84 MV 32005 LA PI P

ES 11002 21090 16706 46465 MV TT TI 32002 17367 12002 84 (III/3) 84 CR-1-1 CR-2-1 CONTROL CR-3-5 CR-3-6 MV 32009 MV 32004 CR-3-2 TT TT 17369 17368 22 12 121 3

30 CR-5-2 ES 46879 30 30 CR-3-3 CR-5-1 ES 46468 6

6 8

STOPLOG GUIDE (TYP.)

ES 46467 TRASH RACKS A

47001 0403 A

47001 0404 4

4 2MD-10-9 2MD-10-2 2MD-10-1 MD-3-25 2MD-3-6 MD-3-6 MD-3-26 MD-3-3 MD-4-1 MD-4-2 VENT TO ATMOS.

DRAIN TO ROOF (TYP.)

8-AR-14 8

8 6-AR-14 4-AR-14 36" RECIRCULATING LINE NF-39216-2 ROOF EL. 732-2" 8-2AR-14 6-2AR-14 SUMP 2

2 CR-1-2 CR-2-2

1. 122

1. 121 CR-3-7 MV 32003 MV 32001 CR-3-8 4" DRAIN (TYP.)

4 102 102 24" MANWAY 84 84 36 CR-3-4 CW-90-2 CW-90-1 CR-4-1 NOTE 1 NOTE 1 NOTE 1 CW-90-3 102 102 2

1. 21 VACUUM TANK (III/3)

NF-39216-1 NF-39216-1 PI 11589 3"

3" 3"

3" CTC-2-2 CTC-2-3 3"

3" 3"

CTC-2-7 CTC-2-8 3"

3" 1"

1" 4"

4" DW-89-2 3"

3" 3"

3" CTC-2-5 3"

3" 3"

CTC-2-9 CTC-2-10 3"

3" 1" DRAIN 1"

1" CTC-2-4 TC-6-1 1" VENT 1" DRAIN 4"

4" TC-6-2 TC-5-2 TC-3-2 TC-4-2 TC-5-1 TC-3-1 TC-4-1 1" VENT DW-126-4 DW-126-2 SV-37243 SV-37245 SV-37244 SV-37242 DW-126-1 DW-126-3 DW-9-2 2"

TO DRAIN 1"

1" 3"

3" 3"

3" 2TC-2-4 2TC-2-5 3"

3" 3"

2TC-2-9 2TC-2-10 3"

3" 4"

1" VENT 1" DRAIN 1"

1" 2"

3" 3"

2" 2"

2TC-1-1 2TC-1-3 2TC-1-4 4"

DW-84-1 3"

3" 3"

3" 2TC-2-3 3"

3" 3"

2TC-2-8 3"

3" 4"

1" 1"

2TC-2-2 2"

3" 3"

2" 2"

2" 2TC-1-5 2TC-1-8 2TC-1-7 2"

2TC-1-2 2TC-1-6 PIPING TO BE Q.A. TYPE III, EQUIPMENT TO BE Q.A. TYPE (III) DESIGN CLASS 3 CONDENSER TUBE CLEANING PIPING 2TC-5-2 2TC-4-2 2TC-3-2 1" VENT 2TC-4-1 2TC-3-1 2TC-5-1 4"

2" 2"

2" 2"

2" 2"

2" 2"

2TC-6-1 DW-126-6 DW-126-8 2TC-6-2 TO DRAIN 1"

SV-37248 SV-37246 1"

DW-126-7 DW-126-5 SV-37247 SV-37249 21293 DP 21292 DP 21290 DP 21291 DP 4"

MD-10-2 MD-10-9 MD-3-1 MD-3-2 MD-3-4

1. 11 VACUUM TANK (III/3) 2 GAGE GLASS (TYP.)

MD-13-1 MD-4-6 PI 11588 2"

3" 3"

2" 2"

CTC-1-2 CTC-1-5 CTC-1-6 2"

3" 2"

CTC-1-3 2"

CTC-1-1 CTC-1-4 2"

2" 2"

2" 2"

2" 4"

1. TO CORROSION MONITORING EQUIPMENT.

3" 2"

2" CTC-1-8 CTC-1-7 2"

2"

603000001331 CAD FILE:

FIGURE 11.1-17 REV. 35 U11117.DGN MOD#:

DWN: AJG 10-02-02 CHKD: CMR 10/9/02 AS BUILT-1" WAS "

PER DRR PI-02-124 FILMED 10/02 AK CONTROL FS 16690 PUMP DEWATERING

1. 121 (III/3)

ES 19212 CT-79-2 CT-100-2 CT-101-1 CT-75-1 45-27-1-43 UNIT#1 45-27-2-43 UNIT#2 INTAKE SCREENHOUSE NF-92764-14 SEE DWG 91732 a

b a

c e

b d

f 91733 ERCS CMPR ROOM NF-92764-28-1 UNIT 1 UNIT 2 c

d f

e 91718 TT OF RIVER TEMPERATURE MONITORING SYSTEM.

SEE NF-92764 FOR OVERALL BLOCK DIAGRAM TE-91513 36 36 SCREENHOUSE, SEE DWG. NF-39215-1 QA I QA I QA I 36 ES ES 49014 49013 PM PM PM PM 28103 28102 28101 28100

1. 124

1. 123

1. 122

1. 121 RECYCLE CANAL 3

36 APPROACH CANAL CIRCULATING WATER ES ES PM PM PM PM 49018 49017 28107 28106 28105 28104 TE-91522 TE-91523 TE-91524 TE-91525 WATER INTAKE EMERGENCY COOLING TE-91526 TE-91527 TE-91528 TE-91529 TT 91719 RE 29018 RE-21 DISCHARGE CANAL FLOW 1

1 1

12 PMI PMI PMI PMI PMI PMI PMI PMI 18422 18423 18424 18425 18426 18427 18431 18430

1. 123

1. 124 3

CONTROL GATES DISCHARGE BYPASS DISTRIBUTION BASIN PMI PMI 18429 18428

1. 121

1. 122 PMI PMI 18421 18420 VENT

1. 122

1. 123

1. 124 CT-10-7 CT-13-1 CT-10-5 CT-56-2 CT-72-1 CT-73-1 CT-77-1 ES 19167 HOSE CONN. (TYP.)

SERVICE WATER AIR CHAMBER (TYP.)

VALVE (TYP.)

PRESS. REDUCING DISCHARGE BASIN CONTROL FS FS FS FS FS FS FS FS 16882 16973 16974 16975 16976 16883 16884 16885 PI 11829 1

PI 11827 1

CT-35-4 CT-12-4 CT-36-4 CT-37-4 CT-38-4 CT-39-4 CT-40-4 CT-10-4 CT-41-4 FI 18833

-0303 47501 LA LA 16818 16707 LA 16817 1

CONTROL 2

CT-104-1 CT-7-1 CT-43-1 CT-43-2 CT-42-1 1

8 5

5 3

1. 122

1. 121 FI 18829 18832 FI CT-107-4 CT-107-6 CT-106-4 CT-106-6 4

4 4

3

1 CT-106-5 CT-106-3 CT-107-3 CT-37-3 CT-36-2 CT-39-2 CT-40-2 FI FI PI 11828 18828 18831 8

8 5

5 CT-106-7 2

4 FI FI 18830 18827 4

CT-37-2 CT-38-2 2

CT-5-5 CT-35-1

TI TS 12403 17642 CT-106-1 CT-107-1 FI 18826 CT-60-1 8

5 NO(WINTER)

NC(SUMMER)

NO(SUMMER)

NC(WINTER) 2 2

1

1 2

1 1

1

1. 121

1. 121 1

CT-58-1 CT-103-1 1

CT-68-1 CT-59-1 CT-59-2 CT-52-2 CT-69-1 PI PI PS 11648 11681 16438 DPS 16444 COOLING TOWER LUBE COOLING WATER HEAT EXCHANGER CT-52-1 PI PI 11987 11988 PM PM PM PM 28108 ES ES ES ES 19217 19219 19221 19223 12 28109 28110 28111 TT 91721 TE-91510 TE-91506 TE-91507 TE-91508 TE-91509 TE-91511 TE-91512 SLUICE GATES DISCHARGE STRUCTURE 1

ES-49060 TE-91514 TE-91515 TE-91516 TE-91517 TE-91518 TE-91519 TE-91520 TE-91521 TT 91722 ES-49061 FLOW TO RIVER 60 72 84 96 FLOW RIVER 8

8 8

6 SEE DWG. NF-39241 FROM WELL WATER OVERFLOW SEE DWG. NF-39241 FROM DEMINERALIZER HEAD TANK SEE DWG. NF-39249 FROM AUX. BLDG. STAND PIPE CT-70-1 CT-71-1 CT-71-2 CT-51-1 CT-9-2 CT-8-2 CT-49-1 ES 18204 PS PI 11647 17736 MV 32365 CONTROL CT-6-2 CT-6-1 CT-38-1 TO GUTTER DRAIN 1

1 2

2 2

2 1

1. 122 2

CT-107-5 4

4 4

5 5

1. 121 72 2

CT-51-2 CT-5-1 MV 32013 ES 19187 ES 19188 CT-2-1 CT-74-1 3

1 1

2 2

1 (III/S)

WATER PUMPS LUBE COOLIING COOLING TOWER

1. 121 3

3 3

CT-54-2 CT-2-2 5

3 2

8 MV 32014 ES ES 19189 19190

1. 122 72 CT-2-5 CT-5-2 5

2 72

1. 123 ES ES 19191 19192 CT-5-3 MV 32015 4

4 CT-2-3 ES ES 19208 19209 MV 32310 3

2 2 72

1. 124 ES ES 19193 19194 CT-2-4 8

6 6

4 1

CT-5-4 MV 32039 CT-100-1 CT-79-1 PI PS 18737 17737 CONTROL 4

4 ES ES 19210 19211 MV 32311 CT-54-4 CT-102-1 3

3 3

72 3

8 8

CT-14-4 CT-54-3 CT-1-3 CT-1-4 CT-14-3 72 4

3 4

4 CT-55-1 72 CT-14-2 2

CT-55-4 3

3 84 8

84 2

CT-55-3 CT-54-1 CT-55-5 CT-1-1 CT-1-2 4

8 8

2 CT-14-1 84 84 84

1. 122

1. 121 3

CT-55-2 72 4

4 3

CONTROL PS 17735 PI 11646 MODEL 143C (TYP.)

CLOW F-3066 AIR RELEASE VALVE CT-57-1 CT-8-1 CT-9-1 TE-91532 TE-91533 TE-91534 FLOW FLOW CONTROL WEIR CANAL DIKE TO DISCHARGE 54 54 54 54 6

1. 122

1. 121 TE-15411 TE-15410 TE-15413 TE-15414 54 54 54 TE-15419 TE-15420 TE-15416 TE-15417

1. 123 FLOW RETURN CANAL COOLING TOWER 84 84

1. 124

1. 123 54

1. 124 84 8

2 (SUBMERSIBLE WELL PUMP)

COOLING WATER PUMP 123 C.T. PUMP LUBE MANHOLE (TYP.)

24 MANWAY (TYP.)

MANHOLE SUMP PUMPS (III/3)

ES ES ES ES 46496 SELECTOR)

(4 POINT 46497 SELECTOR)

(12 POINT 49026 46498 (STOP-START)

(FORWARD-REVERSE)

NOTE 1: THIS VALVE IS NORMALLY OPEN BETWEEN OCTOBER 15 AND APRIL 15 NOTE: ALL PIPING TO BE Q.A. TYPE III UNLESS OTHERWISE NOTED.

CT-50-1

CONSTRUCTION ISSUED FOR ADDED NEW EQUIPMENT PER RIVER TEMPERATURE MONITORING SYSTEM REPLACEMENT.

D.D. HOLLMANN 11-19-11 PE# 49267 MOD#: EC-17799 76 REVIEWED: SLW 11-19-11 AS BUILT-MOD#: EC-17799 DWN: DB 9-6-12 CHKD: PWM 9-18-12 DWN: DB 11-17-11 CHKD: ELH 11-18-11 RECORD TRACING.

TRANSFERRED TO CERTIFIED REV. 76,

DRR PI-12-163 REV. 76 PER INCORPORATED A/Es PE CERT:

APPD: CMR 9-18-12 APPD: JAL 11-22-11 "77" REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 100 5

6 4410 7700 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 77 39215-2 NF-39215-2 NF-NSP GENERATION CAD NF-39215-2.DGN EXTERNAL CIRCULATING WATER FLOW DIAGRAM A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

DWN: MEA 12-14-16 CHKD: WDG 12-19-16 AS BUILT-77 MOD#: EC-23750 ADDED BRANCH CONNECTIONS AND FLOW TAP VALVES CT-67-5 THRU CT-67-20.

PER DRR PI-16-271 APPD: DB 12-21-16 CT-67-10 CT-67-5 CT-67-6 CT-67-9 CT-67-11 CT-67-12 CT-67-7 CT-67-8 CT-67-13 CT-67-14 CT-67-16 CT-67-15 CT-67-17 CT-67-18 CT-67-19 CT-67-20 "77" "77" "77" SEE DWG NF-92764-3 SEE DWG NF-92764-3 SEE DWG NF-92764-7 SEE DWG NF-92764-2 NOTE 1

603000001331 CAD FILE:

FIGURE 11.1-19 REV. 35 U11119.DGN REVISIONS A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 100 400 5

6 4410 7410 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 76 39253-1 NF-39253-1 NF-NSP GENERATION CAD NF-39253-1.DGN CONDENSATE POLISHING SYSTEM FLOW DIAGRAM - UNITS 1 & 2 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

DWN: DMN 7-20-09 CHKD: BAW 7-28-09 AS BUILT-FILMED: 8-09 76 MOD#: EC-12496 REVISE DWG TO MATCH PLANT CONFIGURATION PER DRR PI-09-107 C-7 C-7 "76" "76" "76" "76" "76" NF-39253-3 A-8 NF-39253-3 H-7 1-CP-66 E-6 E-4 MOD#:

DWN: LCW 5-9-03 CHKD: CMR 5-28-03 AS BUILT-CORRECTED GRID LOCATION CROSS REFERENCE FROM G-2 TO C-7 PER DRR PI-03-66 FILMED 6-7-03 P

01516979 CAD FILE:

FIGURE 11.1-20 REV. 34 U11120.DGN VALVE LEGEND:

-0107 DPA-58901 35040 S/CV-5890015 PDIC DETAIL "A" 39253-2 SEE NF-25024 CE-(X-HIAW-2000-81) (TYP.)

1. C-PID-3700-224 AND L&N DWG 3 PHASE, 60 HZ.

1/3 H.P., 480V, 58901-0304 FAL-CUSTOMER SUPPLIED BY DELAVAL TURBINE INC. DWG# :FD-1000 DW FA-58901-0106 PDAH 30 PDAH 30 PDIC 30 PDY 30 PDCV 30 TU-58903 R/P P

R I/P PDT-5878001 CP-3-3 PLUG VALVE BUTTERFLY VALVE EDUCTOR S/CV 35210 FQI 4A R/P III/3 FQI 4B PDA-58901-0101 PDA-58901-0201 PDA-58901-0301 ZS ZS III/3 FS-18389 FY 41C FQI 4C R/P FAL-58901-0303 1-CP-77 1-CP-76 CP-11-2 CP-11-1 FAL-58901-0108 III/3 III/3 REVISIONS DWN: JMM 8-25-98 CHKD: PAS 9-17-98 AS BUILT-C MOD#:

ADDED MAIN INFLUENT AND EFFLUENT VALVES CP-11-1 & CP-11-2.

PER DRR PI-98-82 FILMED: 9-98 5893702 FAL 4A 5893801 FAL 4B "77" FAL 4C 5893802 A

B C

D E

F H

$$$$$$$$$DESIGNFIL$$$$$$$$$

$$USERNAME$$

$$$$$$SYTIME$$$$$$$$$$$$SYDATE$$$$$$

REV DWN DATE CHECKED PROJECT NO.

APPD & CERT.

NONE FILMED RED WING, MINNESOTA 1

2 3

4 SIGNIFICANT NO.

GROUP 8630 1/2 5

6 9070 M430 7410 CL 1

SCALE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NORTHERN STATES POWER COMPANY 77 2000-9 XH-2000-9 XH-NSP GENERATION CAD XH-2000-9.DGN PIPING & INSTRUMENTATION DIAGRAM CONDENSATE FILTER DEMINERALIZER UNIT #1 A

B C

D E

F H

G 1

2 3

4 5

6 7

8 9

10 11 12 1

2 3

4 5

6 7

8 9

10 12 This map / document is a tool to assist employees in the performance of their jobs. Your personal safety is provided for by using safety practices, procedures and equipment as described in safety training programs, manuals and SPARs.

DWN: LAB 1-27-12 CHKD: AP 1-30-12 AS BUILT-76 MOD#: EC-18952 CORRECTED NOMENCLATURE FOR 11, 12 & 13 F/D ALARM FROM 58904, 58905, 58906 5893802 RESPECTIVELY.

TO 5893702, 5893801 &

PER DRR PI-12-008 APPD: CMR 1-31-12 CP-24-28 CP-135-23 CP-135-24 CP-7-2 CP-24-25 CP-135-18 CP-135-17 CP-135-19 CP-135-20 CP-135-22 CP-24-34 CP-24-24 CP-24-35 CP-135-21 CP-24-29 CP-24-26 CP-24-27 CP-24-4 CP-135-14 CP-135-13 CP-135-15 CP-135-16 CP-135-11 CP-135-12 CP-135-2 CP-135-1 CP-24-32 CP-24-3 CP-24-33 CP-135-9 CP-24-31 CP-24-30 CP-24-22 CP-135-10 CP-135-6 CP-135-5 CP-135-4 CP-135-7 CP-135-8 CP-135-3 "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" "77" DWN: MEA 1-6-16 CHKD: RLM 1-8-16 AS BUILT-77 MOD#: EC-24054 ADDED EQUIPMENT LABELS FOR MV-XX VALVES.

PER DRR PI-15-209 APPD: KJW 1-12-16 "77" "77" "77"

86$56(&7,21

),*85(

5HYLVLRQ

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'(/(7('

01406854

86$56(&7,21

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FIGURE 11.2-7 01214630