ML16168A358

4 to Updated Safety Analysis Report, Section 11, Plant Power Conversion System

ML16168A358
Person / Time
Site:	Prairie Island
Issue date:	06/03/2016
From:	Northern States Power Co, Xcel Energy
To:	Office of Nuclear Reactor Regulation
Shared Package
ML16168A332	List: L-PI-16-049, 4 to Updated Safety Analysis Report, Appendix L, Requirement of Renewed Operating Licenses ML16168A330 ML16168A342 ML16168A344 ML16168A345 ML16168A346 ML16168A347 ML16168A348 ML16168A349 ML16168A350 ML16168A351 ML16168A352 ML16168A358 ML16168A360 ML16168A361 ML16168A362 ML16168A363 ML16168A364 ML16168A374 ML16168A375 ML16168A376 ML16168A377 ML16168A378 ML16168A379
References
L-PI-16-049
Download: ML16168A358 (93)

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{{#Wiki_filter:PRAIRIE ISLAND UPDATED SAFETY ANALYSIS REPORT USAR Section 11 Revision 34 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 34 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 34 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 34 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 34 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 34 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. 01183316 01183316 01183316

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. 01193402

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. 01183316

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. 01406854

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. 01406854 01406854 01406854

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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. 01284959

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.] 01491637 01491637

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. 01427085

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. 01429750

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 hours/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

A B c D E F G H Ul ~ (IJ 1 2 3 4 5 6 I TE-13114 f- -1 r-1 TE-13131 I VENT TO ATMOSPHERE THRU ROOF i4 TE-13113 I !TE-13132 ~~ ,-----------------------------------~TC~~~---------------------------------------1 1-1 ll I I I I ,-- - -jTE 13080 ,----jTE-13075 ,--- ITE 13073 ,-- -jTE 13074 I

I !TE-13078 II 1 I riTE -1312188 IlL

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I I I I I I I ~CONT I I' --- -'1'- --~ REFERENCE DRAWINGS: NF -39215 CR SYS FLOW OIA. UNIT 1&2 NF -39222 - AF SYS FLOW DIA. UNIT 1 NF -39224 - BL SYS FLOW OIA. UNIT 1 NF -39226 - HD SYS FLOW DIA. UNIT 1 lli=!Eill : NF -3923~ - AR SYS FLOW OIA. UNIT 1&2 NF -39233 - TO SYS FLOW DIA. UNIT 1 NF-39244 - SA SYS FLOW OIA. UNIT 1&2 NF-39247 - CG SYS FLOW DIA. UNIT 1&2 NF-39605 HS SYS FLOW OIA. UNIT 1&2 XH-248-1 SM SYS FLOW DIA. UNIT 1&2 I I NF-39233 I C-1~

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NF -39605-1 F-2 1 c='"""""""'l I TD-13-6 ~ I I ~ NF-39233 C-12 PRAIRIE ISLAND C2 NSR tB I m LEGEND CLASS BREAK OA TYPE Cl - SAFETY-RELATED; IS! CLASS I C2 - SAFETY-RELATED; IS! CLASS 2 C3 - SAFETY-RELATED; IS! CLASS 3 SR - SAFETY-RELATED FLUID BOUNDARY: NON-CODE CLASS NSR - NON-SAFETY-RELATED IA,IB,IC.IIA,IIB & III DENOTES PIPING OA TYPES. NOTES: I. FOR VALVE POSITIONS SEE OPS MANUAL C PROCEDURE CHECKLIST.

2. UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS le.g.. PIPE. CAPS, ETC.I CLASSED AS NON-SAFETY-RELATED.

3. +- DENOTES CATEGORY I VENTILATION ZONE

4.

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

5. Ill DENOTES EQUIPMENT OA TYPE/

DESIGN CLASS.

6. SHELL SIDE C2, TUBE SIDE C!.

7. CS4304S DELETED. E/P DISCONNECTED

& ABANDONED IN PLACE. CV-31~93 MANUALLY OPERATED ONLY. B. *DENOTES FURNISHED WITH EQUIPMENT.

9. 0THRU@ DENOTES CONDENSER TERMINAL CONNECTION NUMBER.

lt?l. 0 DENOTES CONTAINMENT PENETRATION NUMBER

11. SR/NSR BOUNDARY 0 !NSTR. VLV. MANIFOLD.

SIGNIFIQlNTNO FLOW DIAGRAM MAIN AUXILIARY STEAM & STEAM DUMP PLANT NF-39218 IIF-3'l218.DGN IMSRf GENERATION CADI 12 c D E F H FIGURE 11.1-1 REV. 34 CAD FILE: U11101.DGN

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6" ~* lfl~G'RUPTURE 't- 'cJhc *-' DISC ~ NSRtiiA 1 NF-39234 E-11 NF-39244 D-9 10'1 ,--~ _!_:1-~Z':'M~5-:;c5'.Cl ___ ~ _:::,~----------:ji"J r110-,2M~i--7, CJ NSR THR~T VLV ~~~ffi4~~~~~~n -65 22 2-2M~ 1 p ~, NF-39223 TO AFWP REGULATOR G-9 1111/1) 'L' GLAND l 245-201 \\ ' co** DRAIN r 11* -* **-- "' 1.,--.._ 72' _, IIO. V /. I NF-100034 I r .....1-"" I I \\

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~ ~'\\ I / CJ fit £..';_'.._), Y.,-:2MS;-.n47-,'-. 1, .~ J\\ ~ STM RING DRAIN NF-~~ 23 I ~' c I \\_CASING DRAIN G-9 5 XH-248-1 I SS-210 C-3 I 1255-2-l 6 f--12-2MS-3 I 5-71'-' 2~*2MS ~ 20' EOLZG ---l-t-~<I-___,C?.,(2-;?:)Pll XH-248-1 ~~~~~ 1 & BYPASS LN ~ L--~-~-.~~~~---Y~ ~ 1: 7 5~~~11 ~ l t30-2MS-4 -i I I ~ CONT + t 1 8 9 1 10 1 2B CONDENSER ())]/3) v LP TURBINE <III/3) CONT 1-en ~ !'o! l-30.. 11 I 12 REFERENCE DWGS XH-248-1 SM SYS ~,1 ~~ DIA. UNIT 1&2 NF -3g2J5 CR SYS c, un DlA. UNIT 1&2 NF -3g223 - AF SYS ~LI \\-: DIA. UNIT 2 NF -39225 - 8L SYS FLOW DIA. UNIT 2 NF -3g227 - HD SYS FLOW DlA. UNIT 2 NF-39230 - AR SYS FLOW DIA. UNIT 1&2 NF-39234 - TO SYS FLOW DIA. UNIT 2 NF-39244 - SA SYS FLOW DIA. UNIT 1&2 NF-3g247 - CG SYS FLOW DIA. UNIT 1&2 NF-3%~5 HS SYS FLOW DIA. UNIT 1&2 C2 NSR is I ni LEGEND CLASS BREAK OA TYPE Cl - SAFETY-RELATED; lSI CLASS I C2 - SAFETY-RELATED; lSI CLASS 2 C3 - SAFETY-RELATED; lSI CLASS 3 SA - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS NSR - NON-SAFETY-RELATED lA, IB, IC, IIA, liB, Ill DENOTES PIPING QA TYPES. NOTES:

1.

FOR VALVE POSITIONS SEE OPS MANUAL C PROCEDURE CHECKLIST.

2.

UNLESS OTHERWISE SHOWN,CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS !e.g., PIPE, CAPS, ETC.l CLASSED AS NON-SAFETY-RELATED.

3. +- DENOTES CATEGORY I VENTILATION ZONE 4,

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

5. Ill DENOTES EQUIPMENT QA TYPE/

DESIGN CLASS.

6. SHELL SIDE C2, TUBE SIDE Cl.

7, CS-"'13600 DELETED. E/P DISCONNECTED & ABANDONED IN PLACE.CV-31502 MANUALLY OPERATED ONLY.

8.

• DENOTES FURNISHED WITH EQUIPMENT 9, (Z)THRU@ DENOTES CONDENSER TERMINAL CONNECTION NUMBER 10.~ DENOTES CONT PENETRATION NUMBER A

B E 1-- F t--

11. SR/NSR BOUNDARY 0 IN5TR. VLV. MANIFOLD. t--

12. OPI 1756"'1 IS DISCONNECTED FROM GAGE LINES AND CAPPED.

• • ~

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£ ---,---------------lz_r_o-_ll,-",r~r<" I --~----_j::~~~~~ilM~AilN;:A:U:X:lL:l:A:R~Y~L~s~;~TE~A~ 2 M~&~S~T~E:A~M~D~U~M~P TO ) ~~ I - NONE I ~ 88 C-11 NF-39234 PRAIRIE ISlAND " ON.., PlANT N F 3 9 21 9 ' ~ 7 8 9 1 0 "*'*W,'."f7.t\\~~~~if!iim:::illl"" ,...,..,.oo;l2 """""' '"' 1 1 5 6 2 3 4 H FIGURE 11.1-2 REV. 34 CAD FlLE: U11102.DGN

0)

I' m CD... 10... 0

1 I 2 I A BUILDING WALL "8~ ELECT. HEAT TRACED ELECT. HEAT TRACED 3 I cow LEVEL 471111119 4 HIGH LE\\IH 47elfJ'l 051!11 I 5 I 6 ~~LA-1-1 liB ~. 4 131 /.A LA-2-9 I ~ ";;- I'. ~ LA-1-3 lA ~I'-.. z* ~/_,.1 LA-2-7'11 IB CONDENSER 1111/31 I~ /

{

__/ CONDENSER <111131

~1:.-----. !!- \\~ I D r-- CA-4-1 I ~ 1: ........ -----~~-~'=A=-*=-1=0~51 J-~ CONTROL ""i LA-4-3 I

• GAGE CLASS~-----..!-~~

I-

,.,.., (-k "'=' BUILDING WALL rl>-'1"'!.\\'--' ---4-- SEE CONT. ON NF-39222 ~ =L- --~ ~- ~ ............. ~) lA-4-4 I ~It liB --, I LA-4-1061 CCNTROL. PMP. TRIP 7 L1 41223 01 I_~ CONTROL

~;,~ ---y I

8 I 9 I LEGEND Il/3 - DENOTES EQUIPMENT O.A. TYPE/DESIGN CLASS @ - DENOTES FURNISHED BY WESTINGHOUSE

• - DENOTES FURNISHED WITH EQUIPMENT

@ - DENOTES CONDENSER TERMINAL CONNECTION IC-liB-III - DENOTES ... +.. DENOTES 0- DENOTES THE PIPING Q.A. TYPES LIMITS OF O.A. TYPES TIE-IN TO EXISTING SYSTEM DENOTES DISSIMILAR METAL 10 I 11 REFERENCE PlPlNG DWG. NO'S. CONDENSATE SYSTEM TURBINE BLDG. NF-39271-1, NF-39271-2 &. NF-39271-3 LEVEL TROL &. ALARM GAGE GLASS PIPING NF-39312-1, NF-39312-2 &. NF-39312-3 (' 16-CD-11!1 ts* 14" HEATER DRAIN PUMP DISCH. SEE DWG.NF-3922& 14" I 12 REVISIONS ~FOR CONSTRUCTION I:ELETED CONTROL SWITCH 4G.IJqJ, 8. 4G.IJQJG OWN, LFP CHK'D1 OPP PROJ 1 o '1!11L221 REV'D: jOf'P'D & CEAT1 WJJ UH3-'l2 PE'" 20013 AS BUlL T-INCORPORATED AlE'S REV. 'AY' PER ~R PI-'94-160 CERTIFIED REV. 'AY' TRANSFERRED TO RECORD TRACING OWN; WHS CHK'D1 PAS 11/11/'9.11 MOD*: 9111L221 FILMED1 11-23*94 ~

• . AS BUILT A

/ BREAKDOWN ORIFICE,r'" NITROGEN BLANK'T f r suPPLY SEE VENT. NF-3G247 11'81 B 1.-c-c-= 39-=_3*~ J4* .r-~ %" N2 BLANKETING ~ 1r ~ SEE NF-3CJ247 3' RECYCLE LINE ~~_1__....-.----- 2 ~t ~ "'eA 4 2 I I ----1 ~* ~-~- ~

---

"~==='-----'

~* INST. TEST ~ CONN. SEE DWG. I C-7 -2 __1--,.,--,--------+__j'-----------1 '\\~;-. ts* IIIL '.._jr"'TE,--"t54'""'35"1 REVISED DWG. TO REFLECT AoS FOUND COND. ADDED OWG. REF. NUMBER. B c D E F G H 6" NF-3q23'l /" I' G' 3" ,---,.L...'---jH r _____.:...__., ___ t--'<<L.-(11-- FROM DEMINERALIZER ~-CD-32 1 JIIB ~T !LIB SEE NF-3CJ24t-8 CONDENSER LEVEL CONTROL & ALARM PlPlNG 6'

• O't'ERFLOW -......

6" S*DE-58-........ I I I 6" 3" RECYCLE DE-613*2

• 11 CONDENS~TE MAKE-UP STORAGE TANK (III/31 471!11!1"!

"171!110 PUMP [$] 3-llE-53 061113 liJ10S CONT * ')"' LOW LOW-LOW LEVEL LEVEL I I I 4' MAKE -UP FROM I GRAB SAMPLE 1~;; DEMINERALIZER _.....,......_ SINK OCATED 'hu\\ l I SEE NF-392411-8 L ~ WEST OF RMU I STORAGE TANKS ~ ~ -I\\ ~_f; j 2' MAKE-UP TO *121 HEATING ~ 1....., ~ SYSTEM MAKE-UP PUMP+ SEE NF-! 57545 PI SEE NF-39605-1 1108'! SPARGER ~* TUBING J 2' r 8 - }--+-,-.J@""",~ 1 C~D~-<~O~-~IL 1_j---jj~;;~y---;,:t-1~_j LOW PRESS'u'R_E_T_U/R,BINE tiii/3l ~t=NO=Z=Z=L*=--....===t=~~~~~;;;;t;t~~i~l/i:-1 A ~ ~ ~* ~ ~ vlf'V'MJ TO

,f~

/2 12-0~~~:-547 CD-44-1 I A~l!lvl!l~ I c:~:~:ll..h <F ESXP~~~SST~ 1'-----'---------;:::==::', ~ OE*110*1VENT ATM. v ?' I .1: r.l. I C-27-1 ~ N2 ~~~~:;:RA\\ DE-10~-1 31~~~ ~; ~ ~ 6't-----l C-2'!*1 I 12'FLEXIBLE HOSE N tt=-3"1247J T CD-61!1-1 ~ CD-2-.o\\-7 l\\'. \\- \\ ~r-------" I C-23-1 ---..._.,~ 1Y.z' ~ ~ I cD-61-1 ~-, ~ r 7 . L1 c-311J-1 I ~ ~rt-~~~:H.w<li*<:H:"'~~~'"**"'Irl;+/-:(ii),:--------' ~ TO CONDENSATE MAKE-UP 2' C0-52-1 , \\ 'I""-' 4-DE-54 '-.o\\-DE-55 ORAIIN TO GRADE N2 SPARGER-C0-45-21'L ~"71~~ -~ 1-...:.-' STORAGE TANK "21 < ~ \\ ~ CD-45-1 I ft!!* / II!*CD*II SEE NF-39221 CD-5111-2 u 1 ( 1%' wDE-6 ~-DE-63 CONDENSATE TRANSFER TO *11 & *12 GLAND SEAL TO CDNI:ENSIITE ~ REACTOR MAKE -UP WTR. l.. I C-23-2 I ~-CD-23 16-CD-7 PUMPS, SEE DWG. NF-3"123C! ~ '\\ STR. TK'S. SEE DWG. NF-39242 _j CONT.'n/'-/f-lf,( TC 2-DE ~ ~ CD*3'l-1-'ll

• 13A F.W. HEATER CIII/3>

I TE-1543fJ I I I ~ C-6-1 r--' J.lol" "'!" 16' ":-t __I C-JC!-6 12' 20" /211l-CD-7 -t2-CD*7 ~-CD-28 _...-"'j 12" "-f C-5-1 I ~/ 16" I TE-15433 I I I ~ 1---r C-6-2 16" *:I r"""F ~ 11451 LOW PRESSURE TURBINE (111/3) ~EXHAUST~ rl C-37-1 I 1} ~r SPRAYS

---

~

CONTROL A~~~~ ~/ _i_f @) ill" ~........ C-37-2 I ";r- '---<-11\\------<,-Q'r!:lll~. t' lel-M,tll"~s B j,..IL-~t-- 1681111 1\\I*CD*II--< t%-\\ I 1%'

• • CD-27 16-CD-7 I C-37-3 C0-3~-11 I_
• 138 F.W. HEATER Clll/3>

TT 17311lC! I TE-15434 h 20' ~ I ss-*-sV 14" S~MPLE CI:I'I!N. 55-13 SEE OWG. X-HIAW-248-1 16-CD-7~ "14A F.W. HEATER C[JI/3l II~C.___j C-7-1 I Jt .G"6* L

• • r12-CD-7

..... ""/16" L 16-CD-7 C*B-2 I 12" r: 2-C0*7 7 12-C0-11!1 12* { 12-CD-10 '-r C-8-1 I ) ts* r -~-- j TE-15436 I r 16-CD-10 II~H C-7-* I R *!48 F.W. HEATER 1111/3) ll;r:~ ~ICV '---;:::=lc-=7-=3~-, ) 26311Jl 3' STEAM, SEE f--- 1-IJE *57 L ~-DE -63 .I__.......... I TE.o\\37 ~- - CONDENSATE TO UNIT 2, DWG. NF-3961115*1~ + / IL 2 CO 11

• • CD-22

-+ 3l* 3l*....

• -CIJ-26

§ : ~ SEE DWG. NF-39221 I C-3-'1*4 ~ I 1 I" 1 CD-46-6 2' Zn*DE-57 ---- 1 CD-39-7 t-1--- ~ 1 ~_.; .... ~ 1.....!!!.

---

~ CD-3'!-10 1 p

IS' c IS" 2Y.z' ' \\ 2~-DE-577 I CD-51-1 h ~ 2¥.!' co.o\\6 4 2Y.z' 2Y.z" r /- i 21023 <4- -- --- --- -- --- -- -~- - -*~~:===~ /"1~~.;l2~t~c~:~NO l~.-;;M;-u~~f~,3t.Jl I~c~o~-4~6~-5~~---<~~?,,~c'\\...!.~:::;:::;::;-~ I TE-15429 1- ---~ ~- -- -i TE-15432 I r-;J1 ~ r ::;;:-:::o-:-1 I STOR. TNk. FRZ. ~ 26912 C-34*5 f---: 2%" 16-CD-6' _I __.;~~I ~ --........._ -'16-C0-9 ~----;:=:==:;--_,t-----'-T-AR_T_C_ON_D_E_N-SA_T_E-~=-~=-~~~l-

• 21 CDNOENSIHE RECYCLE &.

CD-46"3 h PROT. WTR. HTR. 2". / 21£, I A C0-72-1 TRANSFER PUMP CIII/31 I 72../~ Tol I.J;---2\\-i:-OE-12 12022 PUMP v I 2\\0" 2'<'/ -m'=L II ,. ~2 ~~ C-42-1 I l n/ I I _2,.. I CD*39-6 1-h...hl liB liB ~.r' ~-1 CD*39-9 I TO cw t-'1' coNe. TO STANO-r=_;=;-:;;-] I ~* ~ 1 \\co 67 1 I 4-CD-42~RETURN PIPE,NF*J~2l6-21 1 f./ I ,_1 C0-46-7 CONDENSATE RECYCLE TO !6" 16* I CD "6 I CD-46"2 V ou' STEAM GEN. I %-DE-63 IIMINERALIZERS, SEE DWG. Vl-C0-70-1 I CD "2 2 6 2' IL 2,_::,. I BLDWODWN 1 u ..., -*I Jll="-39241

• 12A F.W. HEATER (Ill/31

~-CD-21 l.G-CD-2

• 12B F.W. HEATER (Ill/31

\\"" NF-BB740 <C-71 / 2-CD-12 1 2n' I c-J.o\\-3 h "11 CONDENSATE RECYCLE & 4-CD-34 2-cD-.o\\:.L.,P; TR~NSFER PPUIMP CIII/31 "IIA F.W. HEATER (JI!/31 l2" "'liB F.W. HEATER UII/31 r!S*CD-34 -'--t:l'f...-+ I I L----;:-;:;;:-:;-;-------t...L.JI I L.L]~:::;~3~C0~34i:7~5=====:!_+l*-<le~>t.'C~0~5~7_:2,_1, I+ 'r,211' ICD-66-2' "'- 4"x2" REO. w/ /:)_ 2**DE*Ei~ C-33*1 1-. 11112 ~ 3-CD-34 1 ~~ y . I \\'"i CD-71-1 I REST.OR!F. I 'I ~CONDENSATE MAKE-UP ~ ~ ~ ~ ~ ~ ~ ~ ~ :-CD-34 5-CD-34*~*- J:i:(; *Lt ~~G::~/ J r--f\\L----it= lco-.o\\5-41 /.-:..~,l~l....--t--~~2~;-J 1 ~ 2*'- I¥.!' 1.-12-0E-54 @I I \\___-@ 4~ q.~ EXCH~N:jER*t2 ~" ~ _, f--1 1 1 m 1 m1131 1/\\,. liB ~., 1 1 I -, *' IIB I.-- 2\\4' TO BACKWASH WTR. M-U PUMP i4' VENT co-57" 1 l'j u I 1 ~, L.J 1 CD 65 2 I T 74 1/

.On. SEE owG. NF-3'1253 D LDC. c-n 16' H co J'l 12 I

, o co-s6-1 174-co 36 o / ~f-11..:::::*:::::*= 16-CO-B CD-65-3 B, '1-DRAIN-2 11 ' r::::c=::::; \\. ...L o n -1 TE 15-'128 1 \\ F 16-CIJ-35 ~ '"16-CD-36 --::t !, / ("r VENT 1\\ t-T r;I\\ WATER HAKE-UP PUMP I ~ /16-CD-5 T, 2~-DE =Jti* VENT-:/ f-- 2~*[)E*56

• • C0-24

~6-C0-12 /1 TE-15431 I / 16' """[;_ gJt I C-3-.o\\-2 r' I C-41!1-3 -h I~ C-3<1-1 I gJt ~ t ,-------'~--+-----'l-------1~------+-.::"=-"------+--__j IS" 16' 3".¢ 2~* 7 ~3" H c-32-1 1 tz- ~ts* TE~sr FL.ow co-J'l-s I f.- 12.c0*4 TE~ST FLOw UN[l 2 CONDENSATE 1 ~SPOOL PIECE ~ PI 16-CD-4"1 ~ ~ SYSTEM, SEE DWG. J. 2

• 11586

+ 1 3 liB

• UA DRAIN liB 1

r a-CD--'1 l /"" ~-CD-20 Cf

• UB DRAIN NF-3G2211**

T I c-41*2~ 3*DE*56-B' 2 !.\\"1 T ~ ---,I COOLER IHI/31 r --+-~------"'"-. ---,----+--------1

~r&

~,. 4 COOLER 1111/31 ~ ..,/ ~- _____ l_y-IH "'-._I \\ B' !2" C\\ij_ ~. 'II II~ 6-CE -56 I 4-DE *56 ~I ~ l 6-0E-56 Tl ~----'\\_/'\\..__ f-f-"16,.. t--'T--<1------'::Bc." -.-----+-----.--'--.----~'::Be." -+""O""C ________ _,._:Ic::B",-{:>--,/-.J'--'16"'+-'--.1+--i f---"---1:~-+-'J n/'\\._ 1 4' 1 4' 1 4' 1 4'

• "VEN~2* H oE-2~-5 12 1t.162

[t8-cc-4.J TO *IA & *1s MOIST.SEPS.....__ l/r-;.~,,L-'---"----...L_j '----11211164 I I 1 "\\. W' 1c 1 \\ f

• ' INSTR, TEST ""'

~ ~ 1 t 1 / 16* 1 "\\. \\: n I C-12-1 s 2*CD-4 18'

a. REHEATER DRAIN T~NKS ~

C~TROL cv CD 1 I 4 C-13-1 I IDE-3-'1_6"' ---2-DE-54 DIGITAL SICV '--;=':=::'-" lir==:~:J~:E;~~~~-.---=---l-'--IJ~~J==lF SEE DWG.NF-3'!226 a 3u187 f--~*VENT TO *22 TO *12 TO *21 Tbo A;uf> COUNTER -60q- -,1 C-24-3 1---... I A~ C-26-1 I I c 24 5T

t.

2' DRAIN I rlS-CD-10 212l-CD-10___.... {6-C0-34 r~'VENT 20' 20' 20' Jf-3':f2~ ~f-3~2~

f-3~~ NF-3~222 r----1~*~"~1N~S~T~R.~T~E~S:T:C:IN~E~~S~;2V~

'i'Bi.C~O~*:~~j~~S~*C~D~*;*~ '~~ ~~C~I~I:I~= lj;~ 1 ~C:* 3 ~ 9 ~. 2 ~r~~~=IG:*~~=~~~~~~~~=~~~~i=j~;2:0*~;:: H-7 H-s H-3 G-2 FROM ADT MONITOR ~~~ I TE-15-'1271 c ,,c,v22 '!J: c-26-2 I TO *15A & *15B HP HTR'S. *'I' - J \\. s* TANK P Mps "V I \\ SEE OWG. NF-3'l226 I 8" 8' u r-- ~ ~+§ CONTROL r RECIRCULATING

a. NF-3'J22-'I

\\. c-q-J I 6" I SS 7 H SEE DWG.NF-39236 12' ~ 48114 ,.. A BREAKDOWN ORIFICE LINE -'1-CD-4 \\ 6' -.J ~ "\\. 16' C-ll-2 r s* lS' ~*'SAMPLE CONN.SS-14 ~ a*.\\:

• a*

,(......, 1111* ~ N"' e-co-4 --L ~ 6~ ~- t1Wx2'RELIEF VALVE [__........._,'j,r-::c_-:9,.,_2::-, SEE OWG.,.;-HIAW-2-.o\\B-1 -..t CONDENSATE EMERG. F FE s-co-4 -r-Wr ~ ~ ~)'~ ~*VENT c-II!I-1 I 6-co-II!I -c...£...1 .... ""'\\. J I sET AT 551!1 P.s.I.o. --Is-co-11!1 4ffi1- -1 SUPPLY & MAKE-UP--- 23011 2JI1J2q 6 6' 6' I TO &. FROM COND./ ~ I ~~ C-28-1 SPRAY PIPES C-21!1-1 r-C-15-1 I 16" I C0-39-151 6-CD-Ifil....../ 16' I POLISHING SYS. 7-l r4-DE-S4 4 CONTROL *.... ¢ 118 0 HEATER DRAIN TANK /; 2-CD-10 ~ . @-* '" ~"'7 I TE-154261 13 -'1-DE-5 4 4' ~-CD UMP SUB COOLING w ~ C-25-1 I I c 25 2 I-._ FE

• • • • OON CDNTROL.r- _ -. _,

I" 1 , 2*

• • ~*'1-

= = 1 r;, SEE CWO. NF-3'J226 .:f. C 3til 2

• -(§ ~
• REMOVABLE SPOOL PIECE !TYf>ICALJ Z71!JI!l3 231!107 IN PLA;~E F

FE 1 ~~*CONN. FOR CHEM. COND MAKE u* ~ v SEE coNDENSER 'EVE'

• 1

) ~ PER ORR: PI-q4-lq6 DWN1 M.R.H. 1111/16/q5 CHK'D: MOD:,......._ FILMED: ~ AS BUll T* REV 'D. DWG. CONT. TO READ NF-39216-2. PER ORR PI-"l5-123 OWIII; DB CHI<'D: MOO*:_. FILMED: ~ AS BUlL T-ADDEO COLOR COOED t-EAT TRACINGS. PEA ORR PI-97-120 DWN1 JOS 11*5*'97 CHK'Oo poe 112'9/98 MOD**~ FILMED: 2/'J8 .§Qj AS BUILT-CORRECTED COORDINATES A2 WAS H\\111 AND CS WAS Fl. PER ORR PI-~8-127 OWN1 BMS 2-B-99 CHK'D1 PAS 2-12-'l'l MDD*1 ~ FILMED 2-9<;1 ~-AS BUILT-SHOW NORMAL POSITION OF VALVE CD-72*1 AS CLOSED. REDRAW COSR SPRAY PIPING TO ACCOr.tOOATE ADDITION CF EXISTING VALVES. MJYED LEGEND AND REFERENCES. PER ORR PI-00-220 OWN: BMS 2-\\-'1-01 CHI<'C: CMR 3/8101 MOO*:,......_.. FILMED 3111Jl ~-AS BUILT-CD*.o\\5-4 8t CD-711!1-1 REVISED TO REFLECT tciRMALL Y OPEN. PER OAR PI*IU*12!:i OWNz GPL 'l-5*1113 CHK'D: CMR 'l-10-03 M00*1...--#---' FILMED 'l/1113 ~ AS BUILT* ADO OWG CONTS 8t GRID COOROIIIIATES, IIIEW BORDER DEL REF MOTOR VALVES B4NS15 PER ORR PH'JB-11180 OWN1 Jl< 10-2111-08 CHI<'O: DB B-21-IZI'l MOO*: EC-132~1 FILMED <J-11Jq 2ZJ AS BUlL T-REYISEO TYP NOTE AT GRID F-11 PERTAINING TO REMOVABLE SPOOL PIECES. PER ORR PI-10-175 OWN1 KJF 11-4-10 CHK'D: JLK 11-11-1111 APP'D1 CMR 11-17-1111 Z§J AS BUlL T-ADDEO ISOLATION VALVE FDA PS-168~6 & RELOCATED VALVE CD-59-2. PER ORR PI-12-126 OWN: JEK 6-28-12 CHK'01 RTC 7-2-12 MOO*: EC-21111!122 APP'D1 CMR 7-~*12 c D E F .-/ ~ 238IZI~ 271iH3 1 FEED INJECTION, I CD 3'1 4 v:T 18:./ IB-GD-4........_ 18' £~.-.......,_,__ C-31!1-3 I @I-: CONTROL a. ALARM PIPING 11043 Z-CD-11!1 CONTRDU- ~ I I SEE NF-39241t'J-l "M' c 35 1 ~ CTHIS DWG.J 16-C0-11!1-1"""1 S*CD-Z 1 116 liB liB liB 2 PS @~ t CONTROL T , *. 1

• I " ~

li-CD-'" ~ r CDNTROC ~- !SOl. ~--- . ~ '-.;; ,-t--.,_-+-,,/,.1~~=~~~.1 to?"' Tl' '")II II"*- '\\.~ F2'g ~ :~*DE-5<"~~~=';::::0J.._..!i::r_L __ -,_~-,-~-,:-==-------,-__j '----,----------,-__j ~c ~~~~~;~~~:tN<m.> ~~;~2<-tl ~- 4" iiid J4* SAMPLE CONN. SS-34 / 8"11 AIR EJECTOR 1111/31 PT c-*-2 I-'

• u GLANO STEAM I *;,:

to !B n n ~-~ 18' SEE DWG. X-HI~W-248-1 TT PT 11 1712lll 18-CD-3 CONDENSER CIII/3) 4 C-4-1 I IIB CONDENSER (III/3l CONDENSER HII/3) ,J...L-_LL, I .-!1 / 4' Lj SS-4-261 17303 170Hl /1-CD-H 12026 !DISCHIIRGE VENTS .-6-CC-13 ....... ~------' I ND-'l-1 I Fl tM J [ ]::[ P= ~ AS BUILT-CORRECTED DRAWING CONTINUATION FROM rt="-39241 TO NF-392-'11-6. PER ORR PI-13-fJ21 OWNz JEK 1*28-13 CHK'D: JCH 1*36-13 MOD*1 EC-2011122 APP'D: CMR 1*3l!l-13 CD-73-1 I ! I C-1'H II C0-3'!-13 1' \\' II/. s* ~2 ~ ~';;:;zt"'==~==~~ 1B-CD ~TO GLAND SEAL PIPING 1" I \\" 61 I CD 62 I CD 54 1 I @t b SEE DWG. NF-39239 / 3' 3' 3'

• 2*

~\\ 2* _.. 2-CD-18 ')-*24'CROSS OVER r H ND-9-4 I 1-CD-15J 1-CD-16~ I / n c-31-1 1 3 3' I~'J~~~co=-] 53 ~-t' ~nr__,_~~Jt~~1~~==r::_ _ _j~~L--,;;;rj CONTROl!---- >5 24"MANWA~l 3" \\ \\ 3" ~ /(3) 3 ~~ -::-J4*~ ~~ ~2) ,[,'21 ~? ~ 118* 1/ t rH c-~~-1 J) rH C-22-2 I I c-24-<l--J 3-CD-13 ~ \\_sum:: VENTS

• Art 30-Lo ~4r ~.

\\ ~~18 ~ /. - ~

~20rc;;;:oc;-5o;;3-o-2Cl lcD-47-t~'{'

• cu'? ~ **1~2§srQ I'V2' 48*

te-co-2 1 / 48* 2-co-!71 ~.~~1'-. 118 liB\\\\ 2.1\\\\\\\\\\ \\\\:\\"\\ 30\\_\\ ~~CD-62-2 DRAIN . ~ 2 ...J ~ I I .<1-CD-1 /\\ ).( ~- SAMPLE CDIIIIII. SS-50 nYP.J 1-co-2 'I co-75-1 1-co-2 c-1-2 I 2-co-2 ~ C-1-3 I \\ SAMPLE coNN. ss-12

• 11 FEEOWATER PUMP UII/31 DWG. X-HIAW-248-1 188'!6 1 co-5"1-s_.r--.......:

]4-co 5 co 481~ lc-22* 1 ~ I' ls-ca-2.-' ~*l I"_J. c-2-21 3111-co 2'--!\\. c-2-3 t*a-co-tl-3.-co-t i:I 1 TE-to4231 ~4"DRAIN'L 30 ~~~~~ \\~,>~~\\LSAMPLECDNN.SS-48} I MD-B-4 4' 3111-CO*I- ....1 MD-B-5 I.A CIJ-75-2 I .....1 MD-B-6 I ....I CIJ-75-3 I'

I TE-1542

-'1 I lJ-I \\ \\_ j;'--:_,_ ~:=~~~ ~g~~: ~~=;~ SEE l eo l'l 3 L....... 18' ?----- 1' Rr I MD 7 4 8' I' nr / I MD 7 5 18'~VJ ,. r-r~ / I MD 7 6 I 30" liTE 154251 y SS-4-5 I / SAMPLE CDNN.SS-.o\\7 I J1 J1 A / SAMPLE: COlliN. SS-.o\\6 Y r r" !j> ss-.o\\-4 t ~ ~* 3' 30' t - on* 3" 30' tr-3"

• s p CD-58-1 N CD-59-1 I CHEM. INJECTION I

cc--',_-,' 0 '!1a* T. ~T.r. c 1-'1 2 I fil--W TEsT coNN. FDA MD-'!-2 168~6 ~~=~ C 14 I I 16' LJ~' TO FLR. JL MANOMETER <TYP.J ~ '" 1 1 no I. 'no-y 1 no \\, no '1' DANS '1' no SS-4-3 I....-jCD 59 !BI 18-CD-2 __.,....... ~ ~ '( ~ ~ \\ -=-=--+- (TVP.i- ~ ~Z::-L C-14*3 I y L. (TYP.l c c::Jf' J"\\ I SS-4-2 ADDITIONAL ~ ~~-~- ~fof;j~ ~

r.~BLE S>DDl,IECE WITH

~ ~::::~ I 1 ss

• 36; 8~rf+~k

~rc=o-c_ 5 =,-c_ 3, I r=-=-,-, rJco-5 q.JJI ~ TEM,ORARY STRAINER nv*.t MD-7-3 I I SS-4-35 r I ./CD-56-tl !6-CD-34 I C0-55-21 L__ L__ cc-4q_1 I"""" EXPANSION JOINT ITVP.J MD 7 2 ,_J"'---,----.._--f'(.J------'------.._--j~l---'-----r----jrF-,I-----j;l<if-' 1111 1112 1113 B*CD-34__....-1" L-r ~ f ~-CD-3~ CONDENSATE PUMP CONDENSATE PUMP CONDENSATE PUMP MC-J-1 I CD-':5':5-1 f-l nii/31 ~ (1[1/31 ~ (1[1/31

l CD-74*1 I MD-B-3 CD-5'!"2 CD-69-1 I

~ SEE NF-392-'Ifil-1 2" J~-{co-68-t 1 DRAIN CC-47-2 I CD-47-3 I

• 11 CONDENSER CD-59-4 MD-8-2 I SPRAY PUMP

~ C0-48-2 I ~ CD-46-3 I I 2-CD MC B 1 1 I 2 I 3 I 4 I 5 I 6 t 7 I 8 I 9 I 10

• 12 FEEOWATER PUMP (111/3)

~0co-5*-*l ~ AS BUILT-ADO'O NITROGEN BLArt<ETING EL!M.BELL ALARM AND ASSOCIATED WIRING. PER ORR PI-15-134 OWN1 MEA 10*21-15 CHK'01 RLM 11'/J-23-\\!:i MOO*: EC-24671 tSl N N ()' "'-fco-5'!-61 c"'::_:__:0:_'.::"::_Jw'---_:1::0 -_:2::8_:-1::5_----j M J ~ lhilmBI'I<ioanrtilataDIIDIIIIiotem~~;,tlw poriaiiiiBIICIIdlhoi" jabo. Yaurp!AIIrllll_,.,.ill ~I<!VideOfcr loy..slr~g~...-.""'""""""'8ro:l"lllprnenl*--... 11181y-hgprog-..... r1U81s..... SPNI.'&. SIGNIFic;ANTNO. OIIOUP NORTHERN 5fATE5 POWER COMPANY ~ """'""- I B63fJ 1 4111111 1 1 ~ 1 17401!1 FLOW DIAGRAM CONDENSATE SYSTEM UNIT 1 NONE PRAIRIE ISLAND NUCLEAR GENERATING PLANT NF 39220 REDWINQ, Mf!NESOTA I'""*'*W,'.'t=Xt\\~~~~iT!im::ill" I NF -:39221!l.OCN I I@ fiEN{RATIQN CNJ I 12 H FIGURE 11.1-3 REV. 34 CAD FILE: U11103.DGN

0)

I'

0) co...

II)... 0

A B c D E F G H 1 I 2 TAOGEN BLANKETING---\\~ SUPPLY 5EE NF-3"!247 CEIU ~ "BIZ!"~ I "BIZ!"

• OVERFLOW 6'

G-2DE-13-....., ~ 11 22 CONDENSATE MAKE*UP STORAGE TANK SPARGER NOZZLE' 6.! f-l_____ ~ DRAIN TO GRADE BLOO. WALL I VE~2C0-46-2I f =Jt4* 3-2DE-6/ Tl 1-*-~---J<c-{ 12367 2C0-54-1 SAMPLE SEE NF-157545 3 I 4 3' ~12-2DE-7 v2C0-44-1I IZCD*46*6; 7,---[:>----=+-SEE CONT. ON ELECT. BLDG. ~~* NF-39223 HEAT WALL TRACED 3' ~* 3' RECYCLE LINE I LOW LEVEL 4751!1"! IIJ605 VE~~ 2CD*3'1*3I ELECT.HEAT VE~2C0*4G*II '~* _ 3-2DE*7 liB liB

• 6"VENT
• ~

f--- FROM DEMINERALIZER ~=)4* SEE NF-39241 sj r ~* ORI\\~ZC0-46-71 ZOE 60 21 2CO 511 .~ ~6-2C0-12 I

• 21 CONDENSATE MAKE-UP STORAGE TANK CIII/3l 2'

I2C055~ 4750q 9G03 475111l 0101 RECYCLE am PUMP 2LI L~e~L L~~v~~ CONT. 724 'l"' 2L T ~ I I 724

• 0\\'ERFLOW.............

6' I2CD-55-I r-TE TC @__< ~ \\§)I~ SPARGER NOZZLE"'-. r~ I2CD-27-I I I 2" I I 2LT }--------j 723 ~12-ZDE-7 'l r 12' '~I I I ~* ~ ~ \\ 2CD*46*~ ,i.J-.,'----+12' FLEXIBLE ELECT.HT. TRACED 6' t---_ cr:;:;:c:;:-:--, 1(,*

• ~/P HOSE BLDG, WALL r ~

ZC0-2"!-11 SAMPLE 3!5300 SEE NF-157545 TT DRAIN TO IJRADE v ELECT. I-IEAT TRACED 17313 r=:::-:::-::1V.ENT r1 _....j2CD-3CJ-14I BLDG. WALL -~~~2~,o~*~*~~~~~~~~1 ~,2C="=-~**~-~2~~*~,.~j(~ ~Y~-r~E~-~2~------J FROM WTR.HTR. _j'\\. 'V';II --Z-20E-12 FOR CONT, SEE '2-0E-63--l I2C0-46-3 !(* G-2DE-111l-....., 6'

• • \\_~

'--j 2CO-J0-11 4-2DE*7 12' 4' MAKE UP FROM DEMINE:RALIZER SEE NF-3'l241 J** '~ \\. 4*2DE-8 owG. NF-3<J220 I I 2* 2 2* 1 ~! IZC0-24-7 1 2* f-- ~-2DE-12 L.,;,l OE 63' ____, u """"'- r DRAIN 74- ~4* '-j 2C0-52-1I OLANO SEAL TO CONDENSATE PUMPS, SEE DWG.NF*3't24e CONDENSATE TRI\\NSFER TO *21 &. *22 REACTOR MAKE*UP WATER STORAGE TANKS. 2\\1,'

• ----------------~--~<

~DENSATE TO UNIT I, SEE OWG.NF-3922~ + I I 2w 11--1-20E-"l

2~'

I c-34 _6 h "21 CONDENSATE RECYCLE & 1 TRANSFER PUMP !III/3l SEE Djt£-'J'l242 r ~~*2DE*q ---- - 1 2%" 12" HIGH LEVEL 4751!1<t 0505 5 I 6 ~ liB 2LA 4 1311 A 2LA-2-'l I ~ ~* /A 2LA-I-3 ~~'-.,_ 2 //..,ri2LA-2-7ql CONDENSER 2A h / r:.:: / - CONDENSER 2B ~~=---* .Lfr 2LA-<-11 ~ ~~~::l-~~~~t1JT-- K~a*-<-1051 ......, 2LA-4-3 I CONDENSER LEVEL CONTROL & ALARM PlPlNG 7 CONTROL CONTROL. PMP. TRIP I LI 416')8 01 I_ -1 CONTROL 8

1~ ---y I

9 I LEGEND DENOTES FURNISHED BY WESTINGHOUSE CORP. DENOTES FURNISHED WITH EQUIPMENT DENOTES CONDENSER TERMINAL CONNECTION

• +..

DENOTES L!M[TS OF Q,A. TYPES IC-liB-III - DENOTES THE PIPING Q.A. TYPES (11/3) - DENOTES EQUIPMENT O.A. TYPE/DESIGN CLASS 10 I 11 REFERENCE PlPlNG DWG. NO'S. CONDENSATE SYSTEM TURBINE BLDG. NF-39272-1. NF-39272-2 & NF-39272-3 LEVEL TROL &. ALARM GAGE GLASS PIPING NF-39313-1, NF-39313-2 8. NF-39313-3 CHEM FEED - NF -39241tH d TE-155G51 I 14" HEATER DRAIN PUMP DISCH. SEE DWG.NF-39227 (' 16-2CO-le 16' I 2CD-7-2~,---1--------t>-_L_----------1 ~ ~ ' 16' II~ I I TE-15564 h 20" l r-1124A F.W. HEATER !lli/3l ~~~-____j 2C0-7-1 I Jt

• ~6' L

) v-20-ZCD-10 20' ~~URETU~ A IZC0-23-3 h I ~EXHAUST~ A~~~~ CONTR(L ~r SPRAYS ~~ 1.,. @ t l ""',1. I I2C0-23-1 n ' 1 181 ~ t 1%" I' 1\\1,"110 \\ -_. "{] t\\1,' / I%' 1\\I,-2CO-Ilj ~ I2CD-23-2I

• -2CD-25 16*2CD*7 20'

/211l-2CD-7 -t2*2C0*7 f---- 2-ZCD-22 2'N

• ~f-l-lll,'-2~~2co~-5-1 I

~--~~ "2"'CD'---"-"'--'-6::J;I 16-ZCQ-,-* 12' 16" 16' PI 11452 I TE*I5562 I I I ~ 2CD-6-1~ J_}'l' ""'[ 16'-:-, I TE*15563 I I I ~ 1---r 2CD-6-2 16' *.:J r"F LOW PRESSURE TURBINE (III/3) ~EXHAUST~ rJZCD-37-11 1} ~r SPRAYS

---

~

CONTROL A~~~~ ~/ ~ ¥ L~@*?\\:--- 3 1 1\\1,-~+--J;:f'ri~~.<--D~I"J~<:J--tl.__,-\\1,~'~2C0~~-2~

• -2C0-28 16-2CD*7 B j,..IL-~t--

16803 I I\\I,-2C0-11-' 1%'\\ IZC0-37-3 L-(~==="=2=3=A=F=*=*=*=HE=A=T=E~R~<I~II~/~31~~~~-~~:2fC0~-~3ql-~8 "'2rC0~-:3ql-~ll~~~~=r~*2~3~B~F~.W=*=H=E=A=TE=R==<I=II=/=3=1====~ 1G' 1&' ~-ZCD-24 -+ *' ~-2CD-27 I2CO-J0-7!-- ~ 1,' 1 ~

---

j2C0-30-IOI

/ 12ss-4-sV ~* SAMPLE CONN. SS-213 SEE OWG. X-HIAW-248-1 IG-ZCD-7____.

• -r 12-2CD-7 (16'

~16-ZCD-7 12* { 12-2C0-19 \\...r 2C0-8-1 I 12 ---A zco*a*z 1 r: 2*ZCD*7 1-'---... zH,_~~ 12-2CD-IIIJ 16' r -~-- j TE*I556G I IG' r 16*2CD*10 II~ H 2C0-7-< I R '24B F.W. HEATER (111/31 ) nr J t 1G'. 12co-1-~ 12' 1 TE -15567 r __ §:~ ~ ~ .----;=:=::=::::;----+-----*-T_*R_T_'_o*_o_E_N_s._T_E_, _________ l ___ Ps\\_____ I PUMP ~ \\ CO-:::~~ GEN. I TE-15560 1- ---~ ~- -- --i TE-15561 I 16-2C0-6-~ (..,!~j I (..,!~~8 ~ -.....___16-2CO-'l ~~ v-s-:?j I2CD*3't*6f--1---: ~liB liB~~ --i 2C[)*3't*'ll ,---------===---t-;; ~*' ~**- -2*2CD*II 1 j' 16' IG" t 21ll-2C0-\\0~ SLOWDOWN NF-3<J250 <E-81 I L ~-2CD-23

• -2C0-26 ~

2'

• 22A F.W. I-EATER (III/3) 8 228 F.W. HEATER (III/3)

11-t I

+--l:li 2\\1,' I<' ~~'218 F.W. HEATER (Ill/31 r 5*2CD*41!1 =::-=--:oJ ~~'21A F.W. HEATER (Ill/31 12" 32C0407 20' 12 REVISIONS ~FOR CONSTRUCTION DELETED CONTROL SWITCH 465S5 &. 46781 OWIII: LFP CHK'D: DPP PROJ': qfi!1L221 REV'D1 APP'D l CERT: WJJ 10-13-qz PE* 20roJ13 AS BUlL T-INCORPORATED AlE'S REV. 'AV' PER CRR Pl-"14-160 CERTIFIED REV. 'AV' TRANSFERRED TO RECORO TRACING OWN1 WHS CHK'O: PAS 11-3-"14 11/]1/q<l MOD*1 9111L221 FILMED: 11123/"14 ~-AS BUILT REVISED OWG. TO REFLECT AS FOUND COND. ADDED REF. DWG. NUMBER. PER ORR: PI-'94-1'96 OWN: M.R.H. ~1/16/95 CHK'O: MOD:,...__. FILMED: ~-AS BUILT-AEV'Q, OWG. CONT. TO REI\\0 NF-3q217-1 PER ORR PI-<J5*123 OWN* DB CHK'D: MOD**____.. FILMED! ~-AS BUll T-ADDEO COLOR CODED HEI\\T TRI\\CINGS. PER ORR PI-'t7-12e OWN! JDS 11-5-q7 CHK'D: pes 1/Z'l/'lB MOD*:~ FILMED* 2/<J8 ~-AS BUILT* SHOW NORMAL POSITION IF VALVE 2CD*72-I AS CLOSE C. PER ORR Pl-fl0-22111 OWN: BMS 2-15-01 CHK'D: CMR 3/B/~1 MOO*:..-- FILMED 3/liJI. ~ AS BUILT-ADD O'lr/G CDfHS &. GRID COORDINATES, NEW BORDER DEL REF MOTOR VALVES 04NS15 PER ORR PI-1!18*08111 OWN: JK 1fl-20-fiB CHK'O: DB 8-21-rt'I<J MOO*: EC*132CJ1 FILMED 't-0'l 2ZJ AS BUlL T-REVISED TYP NOTE AT GRID F-ll PERTAINING TO REMOVABLE SPOOL PIECES. PER ORR PI-1111-176 OWN: KJF 11-4-10 A B c D CHK'D1 JLK 11-11-1111 ~ MOD*: EC-16,"10 APP'D1 CMR 11-17-U'I ,J, 2CO 60 21 'r I I2C0-66-2I ~ - J:i:(; r-::!J. [hili-~~.::~;-' -tuft ---it: r:==-, EXCHANGER *22 ~ 5-2CD-411J! rG-2C0-41!1 11]1 CONDENSATE RECYCLE &. t 2**2DE*~ ~ 2CD*33*1 R} TRANSFER PUMP !III/3) 1 b~ 1~*2DE*'l 1\\1,' 2\\1,' 1 2\\1,' .1 IW I '3*2CD*40 ~CONDENSATE MAKE-UP ~'VENT \\_q --...-ll__.-._!--:"".... 1--r--1 ~ / '~-- 1 I I-... I ~z~* TO BACKWASH WATER 1, -+ ) liB * I I -, *' IIB 1/ MAKE-UP PUMP *11, SEE ,J.. DWG. NF -39253 Cl LDC. A-ll 'I-,... DRAIN--, l2W 2~'6 f- ~*2DE*q ~* RECIRC. LINE FROM ___!_~ I PMP.I' TE-15558 I r 16-2CD-5 r: !;l I VENT1 I m PI I IS" 16' Lt :~CD-30-12 ~ I \\ ~-2CD*21 f.- 12*2C0*4 ~ 16-2CD-8 1-m j Ull/31 I\\. 12co-so-1 M ~ 12COG52I I* 6 0 I2CO SG II *-ZCO-JG D 12CD-S5-3 u F IG-2CD-35 ~ \\._ 16-2C0-3G /1 TE-155591 / ~6*2C0-12 11342 t ,----------'--+-----')--------i~'--------+--=--------+-------' 3I - r r VEN: 2'g+ ____ :~: ~- ,. H 2C0-32-1 I 12" 16' TEST FLOW ~ UN[l 1 CONDENSATE I I -~* I PI ~ 16*2CD*4l ~ (' 18~~0 i'~co-3q-51 SYSTEM, SEE DWG. J. I 1 2u. 11341 v .A.

v.

5

• 2!A DRAIN

v 3l r a-2co-"'

NF-39220Z8* T L_L_-'j'--*~-----------, 3-20:~7 2~:-r +74 ~ COOLER (11'\\_1/3) rll8 74 74-2CD-34 I ..,._ ----.l __ ------,---- -r-~--- ----,--- -- 1 -~---B-- 16*2co*5- ..........._ I _.._-f\\--------"-+-,8c-.----+--..L------i12" .....j2CD-72*1 l 6-ZOE-7 Tl I\\/' %f'----Co~-'----')------j111 16 \\ 18 .J V I 4' I 4' I 4' I 4' 12216 !S' 1 f 18-2CD-4 24't COOL WTR. RETURN + + + + I2CD-12-I 2-2C0-11---" IB' SEE '1:~ 2 E~!~OC.A-G TO *11 ra *21 TO *12 TO *22 °c 1 o 0u 1 NTTAELR _§~~---, 2C0-2'-31f--..__ ~~-~~=:z~~~~~o~-f-~1~'~-~==--1-'----@ I*~E~=t*~ 4-2C0-42~. TO AFWP MD AF~P MD AFWP TO AFWP 48817 I 2"

• I 12C0-24-5 T'*

"""-1 ....-1 2C0-71!1-tl NF-~~222 NF-~-~:22J NF-~~22 NF*~-~223 I ~ '!!!ZCD-26_2 1 r_ L \\2-2DE 10 1 TE-155571 rf3~; 5\\ PI 16' 18' / 18-2CD-< ~~r~~~ -4 C;~t~RD~~~~3l 118:;.---'~ 12co,. 15~ IB' /1~11~ T ~ _ 11 /'--- V f--t6*2CD*a ~~ ~~~T~, ~~~TMcif~f.SEPS.",..fl & 111 , 1 / *(--;:;~16:_,':::CCIL--'I\\.-----"---_j_j ------{121!17 &. REHEATER DRAIN TANK;*~, C~TROL CV 2CD-65-I ~ Lj 2C0-13-I I SEE OWG. r.F-3q227 8 311!188 ~*'VENT I2C0*3'l-16...

• -2CD-31' t
• ' INSTA, TEST LINE

~j -d 2CO 11 1 I "'f 'i 2CD*3CJ-21 IS' r IS-2CD-l0 TO *25A & *25B HP HTR'S. *' J '\\. G" 2' DRAIN 20' I2CD-3't-!J---,r1r *'VENT 20-ZCD-10

• _/ ~- 2CD*J2

\\ 20' I 2SS-4-7 H,..__ !(-2C0-30 ,/_,2~;~~~:~ CONDENSATE 12" ~-,~~F*~ FE C~r_,:J---- B* \\t§. *. r;;,. ~**CONTROL 18701 r ~~~~RCULATINO BREAKDOWN ~~+1~~~ EMERG.SUPPLY ~ 'S?o:4-L-G'

• Wr. ~ ~ ~)'~

SEE DWG. ~-3q225 8-2C0-41 8" 8" &. NF-3"!227 \\. f_ G' 4-zco-4 \\ s* "I 1 1s* zco-q-1 I L s-2co-4 -~= 2

'

0 =- 1~ 1 -~ 2~r s* 16* L a-2co-4 s* r-- -r-:::::-::-::; 4' 1Wx2" RELIEF VALVE L-- "' ZCO-'l-2 ~ *' SAMPLE CONN. SS-214 SEE OWG. X-HIAW-248-1 "-!ZLll-71-1 I ORIFICE ~ 132 2311l12 27026

• 6-1 -

/r: I TO & FROM Cc::t.IO,/ & MAKE-LP-2C0-28-I SPRAY PIPES 6' i2CD-45-4I TO GLAND SEAL I@ POLISHING SYS. 7.l4-2DE-7i-4 CONTROL.~ liB 6-2CD-10J

• ~NC[)-1111-1 I 6-2CD--4

~ SET AT 55111 P.S.I.G. 7 6-2CD-JI1l.l r.2:::,0;:-_.,20::-_:-11 ~J> 2CD-15-t 1 16 16' PIPING SEE I ..!f.!! 4CONTROL SEE DWG. NF-39253 ~ 4' ~ 4' FE F ABANDON DWG. NF*3924e I 866 - -l TE-155561 112-2DE Ill 12' 14'~-;o- :i!*"l. .£.:>.1 t:O 270~4 231!108 IN PLACE 4 F I ......,---.... _ I' ZCD 2 2711114 A FEED INJECTION 2DE 7 2CD 35 1 SEE CONDENSER LEVEL. CONTROL &. ALARM PIPING CTHIS DWG.I I2C0-31-1 I 2311Jll!l FE ~~ .---------~*coNN.FOR CHEM. 2CD-39-4 v r1 lBj 1B-2CD-4, 18' £3.............. 2C0-311J-3I CONO.MME-UP @lv 18-2CD-4......... 0-* ~ r-:;~:2~;:,0-1:-3~~~-* /..I* 1 B* if::i1 ~ k l4-2CD-~~* h ~.. ~~.*~ F/9 ~~!B~** 1 12* 2 -.~. :~*'----.-----==*=--------.----' I 6 4* s*/ tl4,~ N2~~Low NOZZLE ~, 112,1 AIR EJECTOR 1111~~31 @T \\ / 2co-4-:'p

• 21 GLAND STEAM I '/{:~~:~~_JI

~ 2* - 2C0-33 ~* SAI'f'LE CONN. SS*234 PT TT s-2C[)-14 Tl 1711128 ) v 18-2C0-3 CONDENSER CIII/3) 4 liB aB CONDENSER (III/3) 2B 2CD-11-4 ~-~'

~

4-;;~~~- 2 SE~ ow~.X-HIAW-248-1 17027 17314 1" I ri-ZC0-15 12215 !DISCHARGE \\'ENTS. r6-2CO-l3 _:;;_ ....... r-----~~ 2MQ-q-1 I ~l4-2CD-12

• L*2C03S

~\\ 1 t~J G" ~ 1"*2=c=-o-"'53'"""-1"*1'el 2CD-1<t-ll 18 I' \\ I 1" I. I I 2C0-73-1I ~,.r1B-2CD-2 3' I-2CO-IG~ I ~. 3' 3' 3' 12<~::~~~ ~ 2/ 2-2CO-IB

?-*24'CR05S OVER

~---~@r 2-2co-1, j,H'*o+*l 3' \\ \\

• ~~~Ol 1

{f. 3>Gl ~ 3 A~~~"Jt~-~::-1*~**~ tr==t:~~~Ol~~ 2~~-_-,-;;;!C 2.,J 1 =;;-;;;;--;;-, [1Lf 2111125 GAGE 24"MA~~AY7 H2CO 22 2 2C0-24-4f- \\ 3' I *' 31il" 311J' ts-' ""4'~ r\\1: ~* - ~ .L ....-IZCD-33-2 14 / 2' 3-2CD-13_3. \\.__SUCTION VENTS OLA5S c /.,' lr ~ I I 2' 48' 18-2CD-2\\ 48" 2-2CD-17_/ CONDENSER CIII/3) TO HEATER DRAIN TANK PUMP SUB COOLING SEE OWG.NF-3"!227 PI 1111151 I2CD252 CONTROL~- PS 16012'--- CONTROL<-~~ T ""'-- *REMOVABLE SPOOL PIECE ITYPlCALl ~ ~'---1\\I,-2CD-10 16-2C0-1111 ~L 2C0-24-2 ~;-- 2" DRAIN CTYP.I jt 2-2C0-2q ,-1--l---'--'----, J 1121 FEEOWATER PUMP <III/3l P1 18899 I2CD-61-B___r-......: ~-2C0-40_____.; 16-2C0-10~ ~2CD-24-II n l '-- 2~2CD-31!1 [ 5 ]::[ 0=

• 22 FEEOWATER PUMP CIII/3)

~02c0-61-*I b-------1 zm AS BUILT-ADDED ISOLATION VALVE FOR PS-IS8q7 & RELOCATED VALVE 2CD-6I-2. PER ORR PI-12-128 OWN1 JEK 6-28-12 CHK'O: RTC 7-2-12 MOD** EC-211lli!l22 APP'O; CMR 7-'t-12 ~ AS BUILT-DELETED DUPLICATE LINE NO.IB-2C0-2 Ill LOC F -3. PER ORR PI-13-1!110 OWN: 08 1-10-13 CHK'01 SF l-1fl-13 MOO*: EC-1"1S05 APP'D* CMR 1-14-13 ~ AS BUILT-AIJO'O NITROGEN BLAJI<<ETIN ELIM.BELL ALARM AND ASSOCIATED WIRING. PER ORR PI-15-134 OWNz MEA llil-21-15 CHK'O! ALlot 10-23-15 MOO*z EC-24671 APP'O: KJW 10-28-15 E F ~ N N ()' M 18' ll.! 1 ') 18' \\ '1<8-2C0-1 ~,___ CTYP.I} I*2Co-Jql 2CD-ZZ-1 ft 3*2co.13 _

• ' l 2CD-2-2 I 3~-2co-!~

2,.,.,. 2CD-2-3 1--3~-zco-1 ~: .* __,_c_D-- 1 ---, 2~0-1 ~ SAMPLE CONN.SS-248} "=-"'=--"' I~ -:!"' 3-2C0-13 ~ I I A* ORA1N '\\ SAMPLE CONN. 55-250 ~I 'i2cD-75-I 2-2co-3s ':7 zco-1-2 I

• *--;:zco-35

~ zco-1-3 I 4B*2CD*I \\ SAMPLE coNN.ss-212 lzco-48-tl 1 2Mo-8-4 4* 31!1-2ca _...12MD*B*5I _A2co-75-21 _...12MD*8*S 1 _.,i2C0-75-3I' I TE-15571 I: '"25;;;5

--_-;-4

\\ \\_ \\-~\\- ~:=~~~ ~g~~:~~:~;~ SEE I2CO 1<t 3 h IB" 0 1

• Rr A 2MD 7 4 8'

1' nr / A 2MD 7 5 18'"~ 1 1' r-r~ / A 2MD 7 6 I 3111 I TE 15572 1 1

---

4 2

C0-\\ 7-ll ~'- / =-\\ ~:=~~~ ~g~~:~~=~:~ DWG.NF-39236 N ZCD-61-1 I CHEM. INJECTION "-r 2CD-G1-6 I f-- 2-2CD-4111 J ~ -2 2CD 40 1

__, 7 t r

t r" t 2ss-4 I zca-z-10'---1B' ~: 3' 30' . ~: 3' 30' r T 3' Ps 2CO 14 I I IB' J L 2CD 14 2 I w L.!!. TO FLA. J L ZM0-"1-2 ~ 168'l7 2ca-1-l ~ -v- \\c ITR

• ~*

DRAIN

• ~*

TTR 2ss-4-3 18 _2co-~ / ~ ~ ~ ~ \\ CTYP.I- ~ t,-l_2C0-14-3I 7 /l2C0-61-18I c cit> ~(o I 255-4-2 ADDITIONAL v - ~~;::_ ~fofjl~ ~ ~~ ~:::::::I / 8~rf+~~- ~ r ~ [REMOVABLE SPOOL PIECE WITH ~ ~ 2 2 5 5 5 3 3 5~ c=c-c=-Cl TEMPORARY STRAINER CTYP.1 2M0-7-3I I' ~I / .f2C0-58-ll r6-2CD-411l lzcD-57-2h I2C0-47-3 L---=======~--~~~~-,..J----,-----------l_---;~----------i_ ________ _j __ -t~----_l------~----1-- '\\ ~ =~~~:l EXPANSION JOINT !TYP.I 2MO 7 2 I F I ...1_ SEE NF-3924e-l _f ZC0-5"!-1 I 2" j{_2C0-61-3I ~2C0-61-7I rJ2CD-G\\-1111I 2C0-6't-1 PUMP CONDENSATE PUMP CONDENSATE PUMP 1,..,-v-v.l \\_) LL_._f-:;;:;;:;:;-:::;'1 I 2C0-~ 7 -I~ ~ "21 CONDENSATE (IJI/3) 1122 2CD-64-2 f-

• 23 21ot0 -7_1 II!I-2CD-4fJ __....... ~\\

l ~ f ~-2C0-4~ ~ (III/3l (IJI/31 I2CD-45-~-

l2CD-74-1I 2MD-B-3

--, 2CD*61*21 2c0_47_2 1 8 21 CONDENSER IZCD-61-4 , 2C0-4<t-1 I 2M0-8-2 I SPRAY PUMP ~ ~ ~ 2CD-4B-21 I2CD-48-3 f---. 2-2CD-"111l ~ 2' 2MD81 OR~2CD-68-II I 2 I 3 I 4 I 5 I 6 t 7 I 8 I 9 I 10 fi 2CD-61-5I 1 lhilmBI'IdoanrtisataDIIDIIIIiotem~~;,tlw poriaiiiiBIICIIdlhoi" jabo. Yaurp!A1111111_,.,.ill pi<!VideOfcr loy..slr~g~,......_,F<"""""""'aro:loqlllprnenl*--..,11181ytranhgprog..,..,moriU8lsonOSPNI.'&. SIGNIFic;ANTNO. OIIOUP NORTHERN 5fATE5 POWER COMPANY ~ """'""- 1 8630 1 40111 1 2 ~ 1 1741110 FLOW DIAGRAM CONDENSATE SYSTEM UNIT 2 NONE PRAIRIE ISlAND NUCLEAR GENERATING PlANT NF 39221 REDWINQ, Mf!NESOTA r.F -3'l22\\.DGN I NiP fiEN{RATIQN CNJ I 12 l'"",*,w.~.'t'Xt\\~~~~iT!im::ill" I H FIGURE 11.1-4 REV. 34 CAD FILE: U11104.DGN

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1.

FOR VALVE POSITIONS SEE OPS MANUAL C PROCEDURE CHECKLIST.

2. UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.)

CLASSED AS NON-SAFETY-RELATED.

3. +- DENOTES CATEGORY I VENTILATION ZONE

4. FOR SYMBOLS SEE XH-1-1~5, NF-39214.

5. 111 DENOTES EQUIPMENT OA TYPE/

DESIGN CLASS.

6. 0 DENOTES CONTAINMENT PENTETRATION NUMBERS.

7. ~ DENOTES CONDENSER CONNECTION NUMBER.

B. SHELL SIDE CLASS BOUNDARY SR.

9. C3/NSR BOUNDARY FOR Tl-12046/12047 IS AT ITS THERMDWELL.

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ITYPI AOOEO NEW RECIRClLATION r-- 21 STEAM GENERATOR 22 STEAM GENERATOR ([/!) 234-012

• -"n"*ol v~-.-o '----

"-N I.~ "" ~ LINES 3-250-1& 3-250-2 3-2AF trll '~ ~ uo-.::::r-w-.:::: ~0 ASSOCIATED VALVES CONT 1*. 2A CONDENSER J, 2SG-I-t> 2s0 _,_2, I ',- l j l , I r - -~~-I~T=E~-~~3~0=9=4~1 ;:=;;;:::::;-1 !TYPJ I~ 2FW-26-1 HII/3) !TE-13eJB7 ~ -,- I

...J I

PI PER ORR PI-1-4-1336 r---.='.*,*....... r I~. y- _/I --@)PERFORATED PI 1---..., I lt3! -17 t 3l 11135 ~~:o~~~L 'i.-~',. ~ u Q PIPE WITHlN 11130 --74-<rW.., 1 'J<I-2FW-18~ 78 l:f), __ 41~~4 MOD*oEC-16B07 FI -@,! CONDENSER 'J!i'lli", 'Y' IIA 'Y 1 ,.,,.,, CMR 2-5-14 4 ~ 6 2 91 '\\ Lf',_ I 2FW-25-2 ( I 41~~3 -~ L 1 0 /~I 01 ~AS BUILT-y~v_\\ "1 ~ 1 A~-lj ./ F-===-="r:m==:o ADDEO PERFORMANCE TEST L ~ 2FW-l-: l-2 I I 2FW-145-2 INSTR LiliES l-2SG-1 &. 2 '~ AND ASSDC VLVS 2SG-2-I. 48~7. r--- 21 22 b=C,--tJ= 250*3-1, 2S0*2-2,3, SC BRK. FROM ...... ~.... K b=C FW PUMP p [ FW PUMP PER ORR PI-14-1!165 245-261 245-262 CHK'D: RWR 4-25-1-4 D ([/!) Ill C2, NSfl 234-011 f@. 18 REACTOR BUILDING UNIT 2 AUX BLDG i r--------- ~~-~ TURB BLDG+ CHEM FD SYS

• ~

~*, (III/31 <III/31 OWN: DB 4-25-1-4 NF-39240-1 r-~~~~~~~;-w: SEE :J:l-~~~~~~~~t-;jbkd=~==d MOO*oEC-16B12 HT-9 Gr9 ,.~~~~~~~~J = 1 NF-39223-1 j~-

'~sc

:IL;~25-14

~ -2FW-5 I ~ l"iAi='-31-21-: 1-i 2AF-31-II C~@EQ_ 2FW-22-31 '" "' AOOED v*LVE *F-47-2 """ -~ ~~~ ~ BLIND FLANGE FOR FLEX

%=2'oc -<,.......

-26 r---------1 r I r------1 I 2FW-23-4 I EQUIPMENT TIE-IN. '14*

• lR~AK_ DOWN "'

....,~ IJA...,. n1r n.c. CTYPl M PER ORR PI-15-151 1!5R Ill 3-2AF-10 ~ I 1-2AF-9 0 FROM ~~---~ 1-2!!!: AF'~

• --r-:-;;-:;:-;;:-"lt-=-:~;~~-=-;1'--f------,1-~
• 21 0

0 OWN1 JEK 10-2'H5 REFERENCE DWGS ~* DRAIN CTYP) CHK'D: MP 11-3-15 ':~",:~; ~==---~---- ".. ~~ 1:~~ A : :*.I A Fff~' ~ ~- D MOD*1 EC-23532 FEEDWATER NF-39216 CL SYSTEM FLOW DIA. UNIT 1 "D' KJW IH-15 NF-39217 CL SYSTEM FLOW OIA. UNIT 2 ~AS BUlLT-AUX FEEDWATER NF-39219 - MS SYSTEM FLOW DIA. UNIT 2 REV'O VL.V AF-35-2 FROM I NF-3922~ - CD SYSTEM FLOW O!A. UNIT 1

• NC GLOBE VLV TO.

I2AF-33-tr NF -39221 - CD SYSTEM FLOW OIA. UNIT 2 NF -39222 - AF SYSTEM FLOW O!A. UNIT 1 CJ-.:-IC:---A(- '-Tr ---'=-- 'r .~ c---- ~ 18 Ill ,---------_IYl'"~-~ 24 -...,. ~ !lSR. CJ_ ) ! ~

.t_

~ NSR~II I ~T801 ':d 1 ~~~~111 IC AF 1 @~E[] CJ IC 1 '""<:, r.;.,..,....,=,., NF -39222 AF L/0 SYSTEM FLOW DIA. UNIT 1 & 2 NF -39240 CF SYSTEM FLOW OIA. UNIT 1 & 2 ~ ' 12AF*2~1 C3

• NS[l II~~***~ ~~~

~~~--~--~~~~~~~~~~~~~--~~~t~~~~~~~~~J ,,,lc~l~~'~2~31 C~TRL ,.., I ""~-......__FLEX TIE-IN TO CONO f1-U STG TNK '21 ~ ""'~""" (~;~~~1-+::::::::i

a_::c~=:::J~B~I~~

'l" \\. ~ ~ L.""'.!. CONNECTION _R,~CIRC LINE l,...-------- NF-39221 L,._ L, !S X {'"""" PI 41692 01 21~~L/OSYS I ~~~~~~~~~,~~ 72~~~~~~-~~~~~~~~~~~ ~===~:~::~;;;-~~~-~-~~~~j B4 22~WPL/O~ ~ I' [/ ~--/ ~ NF-39222-2 ~ I ~SR CJ_ N6_-~92~~~2 / ~ ~ ~~ f::.. ~ -_jTE-! 30931 !Y.,-r2-AF_*_2_4--c~~~ AF':j~E~ 8C-~fR:3~ ~~~L:_:IN~EJ_....,.._j k C;!c~~9-:.::C*~-1L0-~~?' ~~11::_ AA.) _L---I_~~~-1,~-ffil* A/S ~~~~~tj ~*_j;TE;_;13;.0;9;5~ ~ ~~-:L= 2AF'=

• • I3~--~

llll~*z i - NF-;~222 !JI,-2AF-2~21 IAF-28-411: IC SEE NOTE 71 1' I (~::~ -~~~it* .CJ,t i12_ I2AF-32-3r 1-21~F-<!~:..]J'I.:. ~Ill rv LLi/IDAFC; L~ I" dl( IAF-17-31 2 . 6 -~~ l~~~

-41=~9-;lf--e i-c>-~;

::=~~~

• iiA~FF~-21~
  • 7:j

--4~-T~?; . ~~-+r

---

~ :,~

TES=--" TL,INE I L8C~..!..:i.l ~ 1 IC I y ~ " 2AF 22.l- ~ 7 ~~.. ~ ~ -+= 22 AFWP J@ 1 ~SR! C3 .':""n SEE NOTE 7 NSR CJ r-------, 1 y '-J, "'" , _32_41 ~719~ I L/0 CLR a Ill> I rr. ~~~~

== V--Jlu'EID '-~ '"" """""""".,"' - '* -2AF -29 18 IC Jl: C31ffiC ~ .. ~

• ~ "'

~ iY IIB IC 'r J4* IC II..- nT.,, / ~ w 12AF-2~-~3 *_,-@K§J IIAF-36-6 I I r ~ l<.-<Ac-<~- L, eD ll...f"\\[:JB[J ooo<} ~ 1-2AF-25------<:J-1 lll, ~ ~ LB!:.. :.U.. :.!£ NSR Ill " ~ ...""'.J..CJ r' '-' 12AF-145-3 14:* \\18281 ~ !I~ ~ 'c ~ I.- 3-2AF-3 ~ ,~~Fl I~ R I~ -141 J= I2AF-18-13 '- rl-ZAF-54 1__.- LJ==:~==:..:!.=!Z.=~

• !~~;-]

N~~.*.~ Ca';;IIB) Moll;~,wP r ' ~* r::3w ~~ ----.. * -i-~ 219 "J> NsR cJ sR -~w IAF-25_3, "---./ 245-331 \\-V1 o.teD t_BASE PLATE ORN 1'1,'/ I -....._,_/ c 22 0 ~ ,._..,1---i.--'l-----'2~-2"'-A"-F-'-7_._ __ --.-_jil:r---=~ NSRe CJ - ~ ITYP 2> C3 SR o ~_fJ_ _i TDI!,rlwP ~'--- 111 1 ~ ~~i iC~I_ C _~=~--'--(~ 11~~~~ '-\\ f 'I

• III I IC*

Ill 2AF-133-UfctfE-l(( rr-NSR ~Ill i Jt.* 245-201 3-;!j v-- IAF-27-31 TEST LINE-' 72 I II* --...,:~ I *~ PS 1-2AF oo' CJ IC ~ " \\ ' \\>719o n --oo ~ I J"~'...':' 11:2= ~'A= F 0 -~ I3d 3-~6~ l =--@ CJ.. ~~; "(7 I-I2AF-133-5I 17779 t-72 1"'"" i 1... 12AF-281-l4-2AF-18 CJtNSR ~ %-2AF-I ,_OAF-" Ql NS[! ~ y 0 C2 C3 IB lie LEGEND CLASS BREAK OA TYPE t<<: BALL VL V II L.OC G-B. PER ORR PI-15-175 OWN: DB ll-12-15 CHK'D: JS 11-16-15 MOD*: EC-16B311l APP'D: KJW 11-16-15 Cl - SAFETY-RELATED; lSI CLASS I C2 - SAFETY-RELATED; ISI CLASS 2 C3 - SAFETY-RELATED; lSI CLASS 3 SR - SAFETY-RELATED FLUID BOUNDARY; NON-CODE CLASS NSR - NON-SAFETY-RELATED lA, IB, IC, IIA, liB, Ill DENOTES PIPING OA TYPES NOTES:

1.

FOR VALVE POSITIONS SEE OPS MANUAL C PROCEDURE CHECKLIST.

2. UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS lo.g., PIPE, CAPS, ETC.I CLASSED AS NON-SAFETY-RELATED.

+- DENOTES CATEGORY I

3.

VENTILATION ZONE

4. Ill DENOTES EQUIPMENT OA TYPE/

DESIGN CLASS.

5. 0 DENOTES CONTAINMENT PEN '

E F r--- (Y) N N o-(Y) I LL z lt'~'l4 \\ ~~).:~ IC -liB* 6 2-CL-112--..._ ~ -"89" 74~" IC ' Ill IC rlu:> i 174 c.;;._, "-...__./ IAF-2l-3f-J 0 1-2AF-2 !:'ill (\\112200445~i/tr1'-'2=:A.::.F_-,_ l _______ ~ -l ~ 281 21 ~~ 0 ""'....,.,"""'~/- J

• CJtNS~

y A~ 1"'-"'-*r '-..._/ (l~INTERNALS REMOVED I2AF-133*41 ~ INTERNALS REMOVED - 'sl AF 28-7 IC Ill F~ I

6. DENOTES CONDENSER CONNECTION NUMBER. t-

~ PT

7. SHELL SIDE CLASS BOUNDARY SR.

u 1 ~ Y.,* PT j ~- *' !)1,-0E -SB r--~~=j~=--;::;;;;:::::;:;~fAF=-~1 4~-~5~ 1 -il=;:--;--:::;:-:;--------~;:;~l~:;;;----\\t7168 0 4-0E -56 10 r~ l.. ~n 1'-- 4 2AF 2 I2AF-133*3I .-<Hc-,.\\ '-J l"'::>n

8. FOR SYMBOLS SEE XH-1-llll5, NF-3~214.

1-- N !111~+-=I*A::F::::-3::7:::::-3~~ !w ~ ~~:~ ~~* l2c,=~1~:l~ * ~"~ - I,Cf.,l

• ,;*:;~ : 4(:" I'

  .:t ~:~;~~~~6

~~~~~go IAF-14-71 l4-2AF-!5 lJ IC llf

.;::.:;:::.:::;.--:,::;::;-... ::::=:::;:=-,.;:;:::,::;::.;;;:.~

0 L '-4-0E-56 NSR CJ ~ 1J, C3 NSR V TO WST {~ I NIISIR r~~~~M~**~~~~~~~~*-~*~- 0~ 7 =t~~~**~*~*"~~~.,~~~~~~a~63~o~~~~;~*~*~*+/- ~~2~~ fwo-1~ 44~1*g;~+/- ~~7~,.~, I J MV D NF-39217-1...... ---, , !/ CHECKED OIIQUP ~ ~ 4 0 ~;~. e FROM Ill IC 202 IC Ill FROM G-4 I ~~

9. C3/NSR BOUNDARY FOR TI-12045/12~50 ITS THERMDWELL.

IS AT CONO STG TNKS TO WST FROM Ul CL SPLY CONO STG TNKS ~ NSR Ill: 0 FLOW DIAGRAM TO UIAFW PM~ !~~~~----~~~~---~N~F~ 3 3 9 ~ 2 2 ~~--~~~-:w~-l3~~~1~6~-2~--~N~F~-~~~2~1~~~2~~~-------- W-~ 2~ ~~~~~~~] ~- 4 2 ~-l FEEDWATER & AUX FEEDWATER 1 7-CI -117 B-3 °- 0 E-2 ~ CJ [C, L-Io-41 RECIRC RTRN LN-n-* ~q~ 1 UNIT z NF-39222 TO U2 CL RTRN HDA FROM U2 CL SPLY '-- "-2CL-140 R..IIB) NORTHBlNSTATe3POWERCOMPANV H5 1 - WAL.ENONE NF-39217-1 NF-39217-1 ~-- -v ll_,-.,.. I~ 89 1 2 3 4 5 6 B -1 G-3 PRAlRIE ISLAND NUCLEAR GENERATING PLANT 7 8 9 10 REDWINe, Mr<INESCTA $$$$$$SYT I hiE*ftUff::;t.E,.:*~SYOATE 1!$$$$ $$$$$$$$$l>£SHiN IL $$$$$$ NF-39223 NF*J~223.0GN i.ysRP GENERATION CADI 12 H FIGURE 11.1-6 REV. 34 CAD FILE: U11106oOGN

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...... T..,. r aL... I.D PIPio..ll~. ~.~,..~.2Go*-t ur-w.*..r.*<l-'2. ..,._Ta..,; HI!... T&I'I: "l&.loiT PIPit.ICit "'r-~'"T~-t WF**~"'."I'S-'11. ~T1l!04* ':~~~~*Giatali: L.£~END ~:::~s::::.:~~=:'T-MI-. ~~N-~T\\0~ \\ii=.. *Nodr.* f'U"J*IISI44o~..,.. W*ST"'t.o!GMOIIM ~RI'I. 'D*NoT*a fiLIRNI.... ~........... Q,UI,.M.N"'; @T>I*o.&9D-~.. c.oMO---~*MI-\\- C..ON"..C..'TION~. -+- gr,MGTU I.IJ41T. CP qA TY'U

I'A1DNIII U-OI.MOTU Tlie,.,.,...

ClA. TT'e ~~~:...~ =:~: ~~,.J./11111~11 w.u

A B c D E F G H 1 j2HD*2**5~ INSTR TEST CONN ""' SE.C DWC 1..1'<39240*~ [I" Vl'-'-'T"" {TyF) -**~--~

---

~

SHELl START-UP VEI>-ITCTYP) 1::115H LEVEL CONTROL\\ _.'l.IA 'Z.HV-l-~1

~t'l\\B 2HV-1*3S I CHANNEL 11E~T m:

][B 1 2 2 3 4 5 18-Z.BL-2 [5 t' r--.---i:<l--l"-.i--,L-<_ .. _,;--T.o l-~E-!\\.Tir-...16 "":;>TG-A !v'l "".:>."-sT ~;"' ~E:-E DYVG~ WJ:"""- 3'3cSOS-~ i; N'F-59'Z'2.4 j 24-ZBL-2 z.b-' 2 2Hb-"-i-3 , I 2 2.( I(.' 16" JIB 11 2.1A 'ZHD-2.6*30 m C::,.";~:;-, "'218 ~HD-'2.&~.}1 , __../ / 'o/~ 1 (\\-l~N.NO:::L ORP.IN / / 1'1 ;,~~LL- 'DR~.JN 'TYPICAl.- VENT FOI< ZIA ij... Zll> To ~uJ ....,--,p f De'AIN PIPING F-W. HE::ATE.02S 3 4 6-258-38 li' WARM-UP BV*P"-55 Ll;;.,.e,_T'£-IZ'" DRA..~~..J P! ?o'-'~" SE-E-DWG. N~- 3~1..27 (TYPi FROM SGB FLASH TANK STEAM LINE NF-3CJ25121 <071 "78"

3., E'::'.c<;U AL 1 Z 1 h.! G I T-IP l

-5Hi;LL OUTLH 2.1 B DRAIN COOLER (ID /3) 2~-2HD-81 12>L-EEO F='1PII'>..JQ;. 1--l F- "' "' *z:r o - ' N F* ':>'3'2 /0* '2 HE.A.,~R VE.WT PIP11--lC>-. Wf::.;'~ :0'3'260-*1 i'JF-e:\\S\\'280-'Z o"' \\..iiVE1,.:Tt~'Cll_ 1 ALAR tv! t ~A.-~~ GjlA.S'S PlPING, NF*.!I3 :.1;:;- 'Z. 5 6 2TB-2-l 2TB-1-2 2TB-l-l z" 41." 6 7 8 9 2MS-43-4 2MS-43-5 ZMS-44-5 ZMS-44-2 2MS-44-6 2MS-44-t 2TB-1-3 2MS-43-6 (11! /3) 2lh-2H0-83 LS6E~W DE"I'-!GH'-S EXI5Til'-!6 5YSTEIY'* TIE-IN 11'>- 1 REHEAT!: +{. DR.. fN

n::A TANK (m: /3) 2'!12-2HD-82 Tt-.-lR:'l) (1~ Dt=WC)T~'S TUR,elf....._\\F:-

Te-~lv'\\1!-....IAL C.C.Jf....Jt:-Jt--~T\\C>I'-...\\"":l. DE-;..JoTE-::. t=lJR"J-.J!"::::lW&-D BY \\NE--"':'.;Tit--.JG \\-lOU'"':~G C.:::..*I?P. DEWOTE-'5 FUR"t--...!!~1--lE.-D VVi1 i--1 SQUlPME.NT + DEr40T~~5" L!iVI 1T5 OF"" ().A TYP~-.5 JIA,If.8$TI! Df:t.J.(Y"::_'~ ':J('" p!::.Jk.<,'; q i;,, T'{PE.S lf"3 DEi'\\jO-;*e__:i T:-iE EQ!J!PN1f.:r*JT Q r-.... TYPE/DE..-':;;I~$1\\l CL.At>S ~~::t;'ENOTES CATEGORY I VENTILI<TION ZONE 7 8 9 zl.. z 10 2TB-1-4 2TB-3-1 ZA RE.HEATE Ol:cA\\N. 'TA..NK (lll /s) 2 '/2." 2Y.!-2HD-84 11 F-()R_ C.OI0T St-1:::- t:>WG. f-lor:*0:.<>.1~1,1) 12 REVISIONS Rj AS 5l...1i\\-T* REMO\\IED ORIFICE. REPLACED W:TH or:;:IF'ICE cor..,ITROL 'lALilE. PER. DRR PI.- 9'2.- 2...87 'DW/'J. P<;n J/8/53 GHKD: :::Z:.:.S 1-!.Z-*?_:; MOO#: 8~1.;1 ~~ 5 FILMED: /f5!;i/75f S AS BUlL T-ADD MSR RELIEF SEALING STEAM VALVES. PER ORR PI-01!1-147 OWN: MPP 8/31100 CHK'D: MOD*: ME-0420 FILMED T AS BUlL T-CHANGED WORDING FROM SUCTION TO CASING AT COORD.C-8 PER ORR PI-04-052 OWN: DB 7-2-04 CHK'D: CMR 7-7-IH FILMED B-04 76 AS BUlL T-REMOVE GAGE GLASS SHOWN AT E-4. PER ORR PHI9-041 OWN: JLB 5-6-09 CHK'D: NWM 5-1CJ-0CJ MOD": EC-13412 FILMED: 6/0CJ 77 AS BUlL T-CORRECTED & ADDED LINE NO.'s PER EC-13861. OWN: LAB 3-12-1111 CHK'O: BCS 5-6-10 AS BUlL T-CORRECTED FOR CONT,REF. DRAWING NO. PER EC-11S87. PER ORR PI-09-105 OWN1 LAB 3-12-1111 CHK'O: JMC 4-29-10 MOD": EC-11687 APP'O: CMR 5-6-1111 78 AS BUILT-CORRECTED LINE CONTINUATION AT GRID C-4, PER ORR PI-15-163 OWN: JEK 11-9-15 CHK'D: KB 11-9-15 MOD": EC-26020 APP'O: KJW 11-9-15 ___-- SAM PL.-E. CONN. 55-223 SEE DWG. X-H\\AW-248-~ 10 CHECKED PR()JEGT~ APP'D l CERT. IN"\\"~RLOC.K I..OG\\C. br-:t.Q..\\Nlt-ib No. NI='-~O,'=>S A.CCOUN,- NO. 45~t:.D-Z.-I'Z (6!.-e.E.D S>iE;AM} <!-5 c.~O-? -llc>(HIS!\\T\\0.-~ ve-r-.TS.) TOi* m&p/ dcrumonl is ~ tl:lcl tD """is! ""'Picyees in tno f'I"'Drm*= Dlthoir Jcbo. Your P"'""'"ll*llloty i* pll>>'idod mr by "'i'lg &afety prac:ticM, P<JCI'durtr; and ""'prrwot.., do&crib<oj i'l &afety traini>g P"l""""* manueloll'ld SPAR'&. SIGNIFIC.O.NTNO. BLEED STEAM E.U. CLAESON & HEATER VENTS FLOW DIAGRAM 5-27-71 PE *8626 NOR.THERN STATES POWER COMPANY (l keiE""'W PRAIRIE ISLAND NUCLEAR GENERATING PLANT RED WING, MINNESOTA $$U5ERNAME$$ $$$$$$SYT I ME$$$$$t$$$$$$SYOA TE$$$$$$ $$$$$$$$$DES IGNF I L$$$$$$$$$ SCAL.E NONE RC'V 78 NF-39225 NF -39225.DGN I NSP GfllfR4TIOH CAQ I 12 A B c D E F lO N N (J' M J_ z H FIGURE 11.1-8 REV. 34 CAD FILE: U11108.DGN

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3 4 A B c D E '( tf" F G H 2 3 4 5 6 7 8 9 10 11 ~ 12 u.lf.oll66*17*1'1 tH<llltoKie&-n*n ilS 9JILT* ~OVAlY'ESIORDEATE tJ!AIHTN<<STNilPIFES I'EIIEC*I~ ~LitBG-17-8"1 O<<"'ON:.c6*21*11 PEII CHl Pl*l"*ll'l (Mf.ol.AB6-17-rt 0<<111 HOC &-n-n KD*1EC*Il"l6a F!Lt£0. 7*11 i£HQY[O '1\\.Y"'ile RD£ATE11 tf'.AIHINICSI~B.28& AOOEONJTE2FCAVAl.VE Dll'S.D'IIG.C(ffl)~T PEACHlPH1*141 (Mf.oi(.Jf *-21*11 Ot("DDOC 11*7-11 H:ll*,Et*JU(" ti>Plll~ li*IHI @ nRJ@ OEMJTES CO<<kSER J[FI(lllo!C.. CCH£CTICJ6 -[£1(11£SLIMIT5<FO.A.T'tl'i:S. 11*.118 [£lf)1ESTt£PIPIIGOATYPES. 1113 tElf)lES THE EOOIPK.IH o.A.tYPESn:ESJ(i( tl.A$. [EII(IlESf\\A(!Stmllrr>>EOJ1Pt£KT. c D E F FIGURE 11.1-9 REV. 32 CAD FILE* Ulll09,0GN (X) C\\1 an (I),.. 0

FIGURE 11.1-10 REV. 32 CAD FILE; Ulll HIJ.DGN

A B c D E F G H 1 2 3 4 5 6 7 8 9 10 11 VENT LOOP SEALS PT 21072 PT 21273 PT 21275 PT 21073 PT 21274 PT 21276 FROM AIR EJECTOR lst STAGE SUCTION RELIEF VALVES FROM HOGGING JET 112' DRAIN FROM HOGGING JET 1/2' DRAIN FROM 8" & 12' VENT STACK DRAINS PT 21075 PT 21283 PT 21285 PT 21076 PT 21284 PT 21286 ,., ) 'I I"'A R~-711"'5,---4,--{ I AR-115-6 I I AR-115-3 I AR-115-5 I lA CONDENSER IB CONDENSER TO ATMOSPHERE ~ EXHAUST SILENCER\\ ~ ~=J (TYPIC AU Yz' ~ SCREWED CAP WITH \\1,' DRILLED HOLE --. n n rr--- .1 I' ~ SCREWED CAP WITH n Ys' DRILLED HOLE I2AR-115-3I ~ ) 2A CONDENSER ) 'I '-2;-;;Ac;o;R--;-1:;-;15~--;4-{ I 2AR-115-5I 28 CONDENSER EXHAUST SILENCE 2AR-115-6 TO ~OS~/ I 4" 4' 8' IT'.----- w DRAIN III 8' 12' ROOF\\ y,RAIN TO TURBINE BUILDING SUMP AT EL. 712'-0' ~~ 'J4' DRAIN ----' (!! ROOF 7 SEE !--III (4-AR-16 I 2\\lz' '11 AIR EJECTOR 1" STAGE

>1L~....1~~1f--.....J.:._ ____

_!4::." -~P~l~TC~H~;...-_, SUCTION RELIEF VALVES ~I !!:.., SEE OWG. NF-3g218 ~--*fj I~~ --~ ~~

• f, I -l 4, zy 2\\lz-AR-16 ~ ---"

/ <-FLEXIBLE CONNECTOR / 3-AR-16 4t,: I 3' 4" '11 EJECTOR STEAM SUPPLY 0' :, ~ RELIEF VALVE SEE DWG 3g218

u.

Yz" DRAIN TO TUB~IN.=E:__, BLDG SUMP - ~* _.J.__ 72 1' DRAIN TO 8 AR 16 4'

---

11--- f 8-AR-16

/ __ 4-AR-4 4' 8' 12' 7 I'- A 47!1108 0504 PS TURB. BLDG \\ 7 8" 16165 SUMP 8' PITCH, \\ r-'-L..,;: __ ""....Jt--....J I ~ ~ 6-AR-16~~- Yz-AR-16 1-DRAIN TO TURBINE BLDG SUMP (SEE VENT LOOP SEAL DETAIU THIS DWG. i_@s )----1'-----, AR-14-3 6~, SAMPLE 16166/ ,~i:i:ol ./ III '-----,(]( IAR-11-3I~l'liAR-3-II ~ AR-14-4 ~

• • • I "

130-011@ @ 130-012 ~..§ J I \\ ~~-- ~ cs~ 1' DRAIN TO--' i7CSl- /'----"' '----"' + 'J4" 463g0 TURB. BLDG. CONDENSATE SYSi:\\.=~ AR-14-2 AR-12-1 SUMP SEE DWG NF -39220 £TYPE AIR EJECTOR) ~ -~ --....,.,_____./"".......- AR-14-1 12-AR-7 'J4" AR-12-2 4' B' ~ FLEXIBLE CONNECTOR TO ATMOSPHERE 4' \\_ ~~ @) ~ 4"TJ ](]~ - Yz* DRAIN TO TURBINE ROOM SUMP (TYP) TURBINE CYLINDER HEATING STEAM RELIEF VALVES, FOR UNIT I SEE DWG 'X-HIAW-2-16A UNIT 2 SEE DWG 'X-HIAW

~ TO 121 AUX BLDG SPECIAL EXH NF-3%00 CD D-8 36014 TO 11 AUX BLDG.

GENERAL EXH FAN NF-3%00 D-8 TURB BLDG WALL 'G' LINE III 12' ¥,12' r 4-2AR-I6 8" 8' 4"

• 911..!:

4'

• 21 AIR EJECTOR ls1 STAGE

~- ~ 2' ~; SUCTION RELIEF VALVES i

• ' ~},, 1
• 2 2AR 16 4'

PITCH ~2-2AR-7 4' SEE DWG. NF-3g21g 1,-

• :-/

2 ;><..,

---

'-~ L.:: ">

FLEXIBLE CONNECTOR I Yz' 3'

• 21 AIR EJECTOR STEAM i1 4'

SUPPLY RELIEF VALVE SEE II 7 f 1' DWG. NF-3g21g If. - I Yz' DRAIN TO TURBINE BLDG----- 12' SEE NF-3g21g ----~---he-,+-~ 3-2AR-16_j v SUMP 4" ,---..::3_" ---'f-11 8" 4" 4' ',:\\<., 'J4' ~ ~EE DWG I2AR-20-5I / I PI SBaPI NF-3%05-1 11091 21074 41~~g 1-E Yz" DRAIN TO TURBINE-r---I"'B_'_""TJ'---' I"ATOs11lcr~~\\~~DG. BLDG.SUMP _.r-~*-~-- 6" r-t 8' PITCH B-2AR-16_~ NF-3%00 1' DRAIN TO TURB. A PS '-6-2AR-(6 6_2AR-I 6-l'l,_ B-2AR-16,< 7 l' DRAIN TO c-g BLDG. SUMP 4 7508 16168 t:------ 1'- Y.,-2AR-I6 / TURB BLDG 6 0504 '-._ 7 -r-----, 6' 1\\ Y.!' SAMPLE SUMP 2AR 14 3 lii lii ~ 2AR-ll-3 ~--, ~ @ 23*-*" ~ J I ~ 2AR-14-4 6' 230-012 @ \\._~- ~lias*~ _ ZAR-14-1 _____ __. ZAR-12-1 I ;-t-_~;--"'~~;-;:,~"~2~A~R~-1~4~-§2~l) L_ CONDENSATE SYS ~ SEE DWG. NF-39221

• 21 GLANDSTEAM CONDENSER t ~* D (TYP c AIR EJECTDRl 2AR-11-2

'\\ r--.r.o..-LD I I I I a:a:o:::a: <r <I <I .J STEAM SEAL@ 8' B" I'/ (SEE VENT LOOP 2\\lz' pJTCf-1 AR-10-2 I~ I ~l'* I I '*~T, I' lqJJs** Yz'DRAIN *8' RELIEF VALVE SEAL DRAI.~N~) =-----:-~~~::::--:--"r---="=-=---'

_.fA

' L ~URSINE s-r'E:AM -SEAL SUPPLY III DRAIN TO TURBINE @UNIT 2 ~UNIT 1 j A AR 12 3 SEE DWG X-HIAW-2-16 r Ill BLDG SUMP M M / 14'VENT 4' ~ 1 18504 1851213 4' -+-- / --I-- -II' ~ '11 HOGGING JET '12 HOGGING JET (((l/3) 4.. 4*

a:n AIR EJECTOR'

/ ~~~ III 118 4.. LOOP SEAL SEE (JJI/3)_.1 k_ uNIT 1 UNIT 2 ~~--i.-t'-1--*... --f ((]l/3) ]= L oio 1-1: 1 X-HIAW-6-34 ---+ ~ ~ +..._-- lr.iE A @S ~S 1 - "'-;;,.-o-";-r""~~

• r *i -*~,.J'lls..

1.~~ l'i lr-1~" -1v;~AR-1g ~~ ., 1--:---___..... r- - STM SUPPLY SEE 47007 4750'--160gs 160g7 I IUNIT II I' " liB . II~ _,__, 5V-3334I ) 1108B -~ ~ DRAIN:k DWG NF -3g21B 0304 AR-14-5 PI 3 1 f ~ ( i R_._ III -~ Is r --=-" (SEE vENT

• =-

nYP) tillS =_,1_:.;~1-1 , liSt~ I r~ B LDOPSEA~B L!iJ-, PI ~-------~ 2AR-!4-51, '/ F j"7 I

y.;*

~ CS CS 1 (IB DRAIN) liB \\ CS Il155 '11 GENERATOR 6 <UN(T 21 S. PI 110B7 . (. 2-A~-3 _/I I I",( 8 12" I:-- Yz-AR-20 230 12' lJO ~ !(LB ~;~~::II :~. 1

• ~,~-~~;j

_\\4_::A!::_I~I7CSl M r: ~~~~o v I AR-5-2 463gg ~.,'\\_I ~R-g-3 I I ~ 205 2\\lz' v B-AR-8 2' II* 2'

• 11 & 21

---

t-B-AR-8 234 234 8-AR-9 M

M 72 1 GENERATOR ~" t 8-AR-g 2-AR-1g~ r!r BEARING ](] Yz-AR-1g---:-----., '-, 1 234 ~,, FILL CAP W/\\1," SEAL Q(L Yz* LOCAL SAMPLE CONN ~/ I / 12.. 4-AR-10 __; ~ 4' VACUP~~rJtEAKER 2Yz" HOLE FOR Ex¥~~~~oR ~ ~ ,1 r 12" VENT tTYP) --------- J\\(([1131 2" TRAP WITH GAGE I AR-g-1*~~ Cz' 2' ~ OJ~ 1 GLASS* ------...___ T liB 7 A AR 1 3 Yz' ORIFICE ----...____ ...___liB / (TYP) 2-AR-1g I 2' B' , / 1:1-"' ~\\ ]*:1 ~ ~- -~~~8B (DB'-11 ~. ~*f'r* 1' r* TO TURB BLDG SUMP -*2' ) 8' B' 1" ~ 4 lA IB ~h-:;M--' ~ / CONDENSER CONDENSER ~ Y ~ I (III/3) (III/3) AR-1-4 I I 3* B-AR-8 ~ ,-,-------+-"-----.---~<l--+f@ B-AR-g 1' 6' 4" PITCH 3' 3-AR UNIT 1 6' 6' I' r I' I" GAGE-GLASS

• 3'-INTERCDNDENSER LOOP SEAL P!P(NG

\\ / liB II VALVE LOCKED OPEN ---' ~ DURING NORMAL ~~~.1 OPERATION CLOSE AR-6-1 r WHEN PURGING 1 MD-!-! I I 2MD-1-1I UNIT 2 TO EMERGENCY TURBINE OIL SUMP CONT'D ON DWG NF -39231 1-AR-1 ~J:r=--:-L~~IJ + AR-10-I I REFERENCE PIPING DWG NO'S SYSTEM AIR REMOVAL PIPING UNIT 1 NF -3g307-1 6' 6 6' DEMISTER l (((!) ~,{ ,-'.. c~ I "-......~P~IT-'=CH=-<1 r~ r--"G---' 'i 2" 2AR-8-1 METER 18224)'2-RE ~ 2AR-11-5 8' \\8'-2AR-6 PITCH-8' STEAM SUPPLY SEE IN-LINE ~15 llf _ OWG NF-39219 tTYP) \\ MOISTURE ~-; 2AR-11-6 H1l' 'Hl-2AR-? \\ SEPARATOR 29~25 V 1 j I t249-011) L .1_ FLEXIBLE / / I I' U '-.."< 4' CONNECTOR I I 4-2AR*2 2AR-115-2 1.. ¥ y SAFETY@ ,-B-2AR-6 ~~tl

• r)\\ l J V,;!l J ::::::::; ~ ~

~HEAD STEAM SEAL ¥f

• ~!.*I l-;* 1 *r t w

f

~ 1* T ~~l---~~~r~- RE~~:A:~7LVE DRAIN T~ ~URSINE ~ ZAR-tt-4 TURBINE STEAM a* B' ~ BLDG. SUMP / 2AR-12-l <':J 4' ~~.!*....- SEAL SUPPLY -+--f-""1---' '-.. l4'YENT..-- _.J'- ~ r.;;-;:"- -L21 HOGGING JET (((l/3) j'-*22 HOGGING JET (((l/3) e ' / ~ ~ 4.1~B~* 4-2AR-4 --'--.:0-,._ __.1':'-._STM SUPPLY SEE p( ~I '21 AIR EJECTOR'v (!11131 /liB III ~ ~4' ~~~~IA~~~~~ 6~~E -, ll,fl:j~ ~DWG NF-3g21g li0g2 110g3,ti'D I

• il *;l *"'I' __ j[IB I '

.rMU ~t-- r, PI (TYP) 6' --=t'-r-- I I

• ~'

467g0 liB liB I / PITCH-12' ____1: liB \\ r ~ ~'lf,-~~IB;\\"111 -~ ~' PI ~~M ,';:,1-B-1(lR-B j8';~f--@--l 11156 ~::-:----'~~~~t-== o -'() -\\~I' ) 118 I Y\\. s ~* 11094 cs ,y J

~

I F E (8 E I I r It t) I /s* 'IMl tr£ll, ~\\.__ { ,~'" 12" Yz' DRAINS I ~s L X L ZAR-ll?l-2 8' I lla, 1-2AR-3 'I l:~.t2AR-'19:S"" -SV-33342)/32.312 12 31-3 ~ 46791 ~--CD~~~~[OR 1' DRAIN r!~ 8-2AR-9-/... 1 ~B-2 AR-9 I 8-2AR-9 12* ~ ru~~~~~E 2~IL liB B' I B'/ . J ~ Yz:2AR-20 '--r2-2AR-g 1" 1" I" 1' 1' I" 0 '4" f I" I" I' RESERVO(R VAPOR 8-2AR-B /

Jl~ ~

1 12' '--12-2AR-B ~ EXTRACTOR B-2AR-g:.J CS CS 1 ~S CS <III13l 46796 46795 4680121 ~r--- -~- 46784 zo5 W~TII ~ AR-14-6 2AR-5-11 2AR-5-21 v -A---;-2AR-I ~ 2' M M L!!J L{2AR-14-6 235 ~~ f--12-2AR-8 235 l ~ IUNIT 21 l..f::o,__-4' VACUUM BREAKER !UNIT }) CUNIT Zl 14 7~0BI 4 7~0B 3' ~-0405ul 0405 7 -@@y -@@ '--'85" I 2AR-11-1 I"- I2AR-g-3l 4-2AR-10 liB """~=P=I=P=IN=G=_i,4*-2AR-11 Yz' LOCAL SAMPLE CONN- ::--, 12 / p!B, 1/2-2AR-1g ~ / /) ~ r,_1 j4f.\\' I2AR-g-1 ~ 2' TRAP WITH GAGE ~ ~: liB~ GLASS* 8' 8, 2AR g 2 2 ' , 1" -==-G 2-2AR-1g I~ TO TURB. BLDG, SUMP--- =2.. (;(:8

• 0_! 2A CONDENSER 12"

!UNIT 1) <UNIT 2l

• 3'-INTERCONDENSER: 7 I 2AR I I B 2AR-B (IIl/3)

LOOP SEAL PIPING I 2AR-1-2 II2AR-1-3 I 11 11 &. 21 TURBINE OIL RESERVOIR CNF-39231-11 CNF-39231-2) GAGE./ :..._ GLASS L 3-2AR-1 I-2AR-1 -~::::JL-~~--~~2;-;;Ac;o;R--;-Ic;;0c--1;-,l VI' DRA(N LEGEND I 2AR-6-I ("' [~ UNIT 2 AIR REMOVAL SYSTEM NF-3g307-2 HYDROGEN & TURBINE OIL VENTS DENOTES FURNISHED WITH EQUIPMENT 12 REVISIONS !Z§J AS BUlL T-ADDED MANUAL DAMPERS AND CHECK DAMPERS CD-36Bl3 THRU CD-36016 ON LlNE GOING TO AUX BLDG SPECIAL EXH & AUX BLDG GENERAL EXH PER ORR PH1l6-B70 OWN; WLI 8*4*1il6 CHK'D: WJS 8-H~HIB MOD*: EC-546 FILMED 9-1116 1771 ISSUED FOR r--:--' CONSTRUCTION A INCORPORATE VENDOR DWG.2~806496,SHT.3 CHANGES.ADD VACUUM TRANSMITTERS. DWN:AAH/AMF 5-4-07 CHK'D: JSM 5-4-B? MOD111 EC-346 REVIEWED1 N/A APP'D & CERT: RICHARD C. LINDBERG 5-8-07 PE* 44886 ISSUED FOR CONSTRUCTION ADDED UNIT 2 VACUUM TRANSMITTERS. OWN: LAB 5-9-08 CHK'D: PH 7-23-1!18 MQOM: EC-8647 REVIEWED: JM 7-23-08 B APP'D & CERT; RICHARD C. LINDBERG 7-23-08 PE" 44896 AS BUlL T-INCORPORATED AlE'" REV. 77 PER ORR Pl-!119-013 CERTIFIED REIJ. 77, TRANSFERRED TO RECORD TRACING. OWN: DMN 3-2-09 CHK'O; PH 4-29-!119 MOD": EC-8647 FILMED1 5-0"1 ~-AS BUILT-ADDED MOISTURE SEPARATOR REPLACED AIR EJECTOR FLOW XMTR FI-1B224 AND REMOVED S/CV 35132. PER ORR PI-!119-!1161 OWN; LAB 7-22-!119 CHK'D1 HBW 7-24-1!)9 MOO"; EC-13122 FILMED: 8-!119 ~AS BUILT-REV CD-36!1113, 14, 15 & 16 TO BE DOTTED. ADD GRID REF'S TO NF-396!11!11. 04NS15 PER ORR PI-!118-!1181 OWN; JEK 12-16-!118 CHK'O; DB 11-9-09 MOD": EC-13296 APP'O; CMR 11-9-!119 ~-AS BUILT-ADDED MOISTURE SEPARATOR REPLACED AIR EJECTOR FLOW XMTR FI-18223 AND REMOVED S/CV 35131. PER DAR Pl-09-219 OWN; LAB 3-8-10 CHK'O; HBW 4-8-10 MOD"; EC-14635 APP'D; CMR 4-8-111.1 ~ AS BUILT-ADDED CATEGORY I VENTILATION SYMBOL TO LEGEND. PER ORR PI-!119-1!115 OWN; LAB 3-12-11!) CHK'O; JMC 4-29-10 MOO"; EC-11687 APP'O; CMR 4-2H0 ~ AS BUILT-CHANGED AND/OR ADDED AR-14-t THRU AR-14-6 II. 2AR-14-1 THRU 2AR-t4-6 TO BUTTERFLY VALVES. c D E CORRECTED PRESS. SWITCH CONFIGURATION AT t!A, UB CDSR AIR EXHAUSTER. REV'D CONTROL SW DESIGNATION FROM ES TO CS. ADDED 11 & 21 TURBINE OIL RESERVOIR EXTRACTOR SUCTION LINE AND INSTRUMENTATION. PER ORR PI-11-11155 OWN: LAB 4-26-11 CHK'O; SRB 4-28-ll MOO"; EC-13991 APP'D1 CMR 4-28-11 ~AS BUILT-CORRECTED TYPO'S ON VALVE !D'S, AR-11-1 TO AR-11-2 &. 2-2AR-ll-1 TO 2AR-ll-1. PER ORR PI-11-218 OWN: JEK 11-16-11 CHK'O; SMF 12-7-11 MOO*; EC-18795 F APP'D: CMR 12-12-11 ~AS BUILT-CHANGED 2' LINES FROM 1111 - AIR EJCTR 1ST STG SUCT RLF VLVS TO 2Y.!' & LINE NO. TO 2~-AR-16. PER ORR PI-13-029 OWN; JEK 2-B-13 CHK'O; RTC 2-12-13 MOD"; EC-20!1179 lSI ~A~P~P'~Oo~C~M_R~2~-=12~-1=3----~r1 ~AS BUILT- ~ PRESSURE SWITCH NO. ("') CHANGED FROM 16174 TO I 16177 (UNIT 21. LL PER ORR PI-15-133 DWN1 MEA 1!11-21-15 CHK'O; RLM 1!11-13-15 MOO*; EC-25881 APP'O; KJW 10-28-15 3_ I' DRAIN SYSTEM AIR REMOVAL PIPING UNIT 2 NF -3g308-1 (TYPICAL FOR UNIT 1 AND UNIT 2) (jj; DENOTES FURNISHED BY WESTINGHOUSE CORP. 0 THRU @ DENOTES CONDENSER TERMINAL CONNECTIONS -+- DENOTES LIMITS OF Q A TYPES TOi* m&p/ dcrumonl is ~mol m """is! ""'Picyees in tno f'I"'Drm*= Dlthoir Jcbo. Your P"'"""ai *a~oty i* prt>o'idod mr by L>!ilg &afety prac:ticM, p-oc:edurtr; and ""'f!IYWII*' doolcrib<oj il &afety lraini>g Prntl1811'10, manuelo Md SPAR'&. UNIT I AIR REMOVAL SYSTEM 1 2 3 NF-3g308-2 SYSTEM HYD. VENTS & MISC. EXHAUST PIPING UNIT 1 NF -3g285-1 SYSTEM HYD. VENTS & MISC.. EXHAUST PIPING UNIT 2 NF -3g2B6-1 I 4 I 5 I 6 t 7 I 8 IIB & III DENOTES THE PIPING Q A TYPES {Il/3l&CIII/3l DENOTES THE EQUIPMENT Q A TYPE/DESIGN CLASS + I DENOTES CATEGORY I VENTILATION ZONE 9 I 10 DWN ASJ DATE 2/"1/EJeJ SIGNIFIC.O.NTNO. CHECKED I 863B I 400 11B0 ~ 1 I 733!11 5 CL 8 PR()JEGT~ APP'D l CERT. elL~.. to FLOW DIAGRAM AIR REMOVAL SYSTEM 8-27-69 PE *8626 NORTHERN STATES POWER COMPANY (l keiE""'W PRAIRIE ISLAND NUCLEAR GENERATING PLANT RED WING. MINNESOTA $$$$$$SYT I ~E$$$$$t$$$$$$SYOA TE$$$$$$ $$$$$$$$$DES IGNF I L$$$!11$$$$$ I I $$U5ERNAME$$ I SCAJ.E NONE I RC'V 85 NF-39230 NF -3923~.DGN I NSP GfllfR4TIOH CAQ I 12 H FIGURE 11.1-11 REV. 34 CAD FILE: UllllLDGN

0)

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CD 10 0

A B c 1 2 3 4 5 6 7 8 9 10 11 T'URP.>IWE coww. t-.Je %.1 J....E GE l'V'D FOR 5-T C: Atyr ~ IPINC£1 DRAIN COI'.JI\\:lE C:.TlOtvS DE SCRIPT'I0"-1 DR: AI"-> ~ROM ST'~AM IN~" o Plf'7E ~ DRAit-J FROM FIR~,-

,TA~E C.Of.ll

>E"lSER C..O ~ }V.tvS

~4 4"AUX STEAM FOR OEAERATOR-- STEAM TO CONDENSER SEE NF -39218 F-7 ~*FROM HTG SYS CALTERNATE LY TO HOGGING JETS SEE NF *39218 D-7 I D-8 STEAM DEAERATOR STEAM TO CONDENSER SEE NF-39218 H-9 LEAKOFF FROM PILOT ON STOP VALVE SEE XH-2-15 c-MAIN STEAM DRAINS SEE NF -39218 H-6 2' 2"

0:.4

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!>0 44 75 z.c;..

70 bR.Ail0 OWIE:R C:.Y\\...1>-)I::>ER t::>RAIN FROM <',I..AI-.)1':;, ST"EAM :;IJPPI-Y VAl-VE HEAt:>ER bRAI~ 'F'~OM C.ROSS U~'DER t='1PE: DRAI~ FROM G.LA>.:l~ C010't::.El0~E~ STEAM LEAK OF<= FROM Pll.. <>,- VAl-VE. ON ST'OI" VAI..VE' (R.H.) .5,-t=A.M 1-.E.AKOFF FROM PILO,- VA.\\_.VE. Olo.l STOP VAl-VE (1-,H.) SLOP DRAIN (WASTE OIL & WATER!- CAPPED ,SPARE:~ S,-EAIV1 TRAP CR.AlW AIR E..JE.C.T"OR .ST'EAM TRAP I:>RAI"-' MAll>) ~TEAM .5IEAM TRAP 'ORAl'-' AWX.. 5TE.AM .5TEAMTRAP CRAIN ~1-C.C:D.ST'EAM C.Ol()DEI05A.T"E. RE"'i'""URW 'F~OM HEA"("""I~C, SY;5. DRA\\N 1=RO" CI"<OSS uNOE:R PIPE: MOlSTURE. '5"-?ARt>.TO R ROTOR L""--"tLA00 '=:,TE-AM ~P\\LLOVER.. D Rt>. I >J 1= ROM C. 'f LJ '-.! D ~ R \\-l E. A.. T I 1-> Gj.., \\ E t>. \\VI ""'1.:> P P<-'t DR..A1~ FRoM c_---rur-.....;DE.R \\--\\~A."(J't--)-~ ~~~P..rv\\ 5UPPl....--{ 34

34 3S 34 37

>."T 38 3-

:l 40 41 4.Z.

4?. 44 11 HOGGING JET -------, 12 HOGGING JET------, AUX STEAM TO HOGGING JET-AUXILIARY STEAM SEE NF -3g2J8 E-6 LP TURBINE (IJI/31 L.P. TURBI""I:(m/5) SEE NF-39218 BLEED STEAM TO GLAND STEAM PRESS-- REGULATING STATION SEE NF -39218 E-6 SEE NF-39224 'I ~ ? H.P. HEATERS 6'!f ~ ~ """Il ---1"' I~ SEE XH-2-15 liB~ TO 15A;ui5B ~0 14A & 14B I .1~ 3' _r*:J-I*:H><l-Cl D-4 E-~ ....... 4'1 / ~ ~ """ I I STEAM DRAIN & GLAND ASSY SV-33026 *-... A'lTl 16" 24' 11 a* 30" ~*..."37 _Jkl- _ --cJ

,_,_..liB t r-1_.

- -,-. s* I 4" _. 12*,./-' \\2~ 12' ~- I' 2' ' 34 ~ 6"1 1' I 6'1 1"1

• • ~- Jl ~ -"

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• ,~

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~

~,0~~"' 2*

• 34 !

SUPP~:G::~~~~~~s SEE\\ / ITDII1f 6

• 1.-zl P(sv-33024)-----

I ro-o-d I V I ~10'78 2' "34 II.P...:tJ;I.41 I £;1l' -c,

~

~ ~ lTD<, 7 f~~ I/ --:"FREE i. ~ .. ~ (sv-33025) --** *1 : 8_4 8_6 I" I" I" 1* iTDII*61 LJ.2+/-t1 ITt>=,r!DI i ITD~~pw / 1 fTI>joBI lTD* II*'" I ITD-6*131 !,1 2' '3<

L +, + -1 1- + 7 +.J

~ l1o -;;-s ; ' 1 TD*~<*2t -... ' i

ITD*II*HI r+'-

--'-'-; ;rm-10'71 ;' ITD-11201 IITD*o;**l4. ;; L_ __ =~"%~:::-:=.. c!;. ~*~lei~~. .":::;,_t:(~s~v-~33~0:=.,,::,:)-=-1., 2" _ 115'5'51 .. **~><)'- D II. r---c- \\, - i ..1_,I r c---- 1* .* ~ D' o 5TE.A,M "5 --- - ~ l / l.j I i 0 ITD-5-61 TRAP, ~J I" I" f 1'1 t" r [ ~~.. ~-** ~ , I** 1** f' t~ l" w ~ 2'

• 34 (TYI'>) "IBA ;?"

)

19A ~~' 2 li l~ I IZ \\l]N_,. Q"2' :=.... liB~ 8-2 1-.::..c:_ TURBINE SLOP DRAINS SEE XH-2-16 (TYP.)

1175 L.:..J 8-4 "38 C-9'-J

" 38 [-¢-Jrl\\1:," TURBINE GLAND STEAM\\ SUPPLY STRAINERS SEE DWG. XH-2-16 I" I 8-2 B-4 I 1-k-!--1 1-t-?t-.J ~

• ~ 2-X

~ TD*Sa )'- ~ ~ ,-----__j TURBINE GLAND STEAM - SPILL DYER REGULATING STATION SEE XH-2-16 C-5 AUX STEAM TD CONDENSER WATER BOX EJECTOR SEE NF -3g218 F-8 MAIN STEAM BY/"ASS SEE NF *3921B y ~~: 11 AIR EJECTOR, STEAM AUX STEAM TO *11 AFWP F - 3 ~f 1 SEE NF-39218 ~EE NF*392IB STEAM RING I E-ll H-~ 2 A DRAIN ? CV CV REGULATOR --1 f-l I>..J-~I:>M_9-I>::J-: 31998 31059 1: I 1' 1 ... __ l_J i"' I 1--- --- I ~ 1 I T ? TO*I3*6fi( I' ~~ L-T~:oJ::)---'1 I 3' / }f )j T /----l t ~ ~---l :,J ::J--l~ ?- T' I ~I 1' 1125 11 7121 01 I ,.!__ ):-! 1' 12' I ~ HTD-6-40 HTD-6-44 1 ~ 1------- _j r ~ ____ 1 SEE :;39218 ",~-::t 1' I I ~H HTD-13*4 IC ~ H TD-13*1 -I~T"D'I"0'1"'21 IIATNSR 32 "" IT~-o-411- ---,_f--

• i01 r--

I~ I' """"',~ I ""'"-., ~" ¥.!' w $ D 'z_ 3 Y,* ~ 14 Y,* I" 6" I' "'., 'f' D ~ -1TD-6-32I TD-1~-13H HTD-10-14 I" 8 12 REVISIONS ~AS BUILT-ADD SAFETY CLASS FLAGS LEGEND & NOTES, REF DWGS & GRID REFS TO DWG CONT A & MISC LN NOS. IZI4NS15 PER ORR PI-Ii19-!il6121 OWN: DB 7-24-11l9 CHK'O; JEK 9-24-09 MOD": EC-\\4376 APP'D1 CMR 1-12-1121 ~ AS BUILT-CORRECTED DUPLICATE YALVE !0 AT GRlD D-10 FROM TD-6-35 TO TD-6-33 PER ORR PI-10-156 OWN: DMN 9-29-10 CHK'O: MC 9-30-UZl MOD*: EC-16067 APP'O: CMR 9-30-Hil ~ AS BUILT-CORRECTED PIPING AT DRAWING LOCATION B-9. PER ORR PI-09-163 OWN: KJF 4-29-10 CHK'D: JBS 10-12-10 MOD": EC-14472 APP'D: CMR 10-18-10 ~ AS BUILT-CORRECTED VALVE 10 FROM TD*12-1 TO TD*2l-1 AT LOCATION G/9, PER ORR PI-11-157 OWN: LAB 8-19-11 CHK'D1 CMR 8-23-11 MOD111 EC-18206 APP'D: CMR 8-23-11 ~ AS BUILT-CORRECTED PIPING AT DRAWING LOCATION F-1

• '&I' CHANGED TO 1.5'.

REROUTE PIPE TO CAP. PER ORR PI-15-108 OWN: MEA 9-8-15 CHK'O: RLM 9-30-15 MOD": EC-24467 APP'O: KJW 10-28-15 B c 2 ~\\* / r1-Ul Jll:;;c, 9-'-#~** (sv 33020)

• f ~

2, 1 ITD<>-41 186 l 19B 2 20 ~* Zl t zz ~*

f.

~~-~6J: ~ 7 23 ~* 24 ~- B~~ L------::i:--=:::::~J~~!'C~:r-:!~~2'~:-*_,314 : L_ __ =._--1~-------, D l l ' I. l

I'

I L

~~tl .HI ) l ~'"! 1'3C. /J rlt ( !'I / A' lt~ i. ,1* l* ~~ o ~ . *-,sv-3311127 nuRBINE Aux 2' 2' TD*G '3 ~ ('f'l:8!)) 1 "'--- ~ Z! - 2 2, , 34 ~ROLLERl I" r-- i-I _ji\\ ! c---- 1\\ ', _j\\ r.- 'i'D61~ = '27 2' 2" ITO*!&*~, ll/_1IB ::r~! 5TEAM ~* IIA 0* TRAP --;~"'"""" (T"I'P.) ITD*20 I~~ II~ ~ _:r: __ li.' ORIFICE

r:

OLD TRAP '12 HTD-6-34 1\\!,' HTD-10*1~ D E F G H r-llp_lljj lTD IH21 ~ \\ : '~~~': llPJM ITD*II*211 L__L __ --I~---..:.1"----CY-TD_=*_ 6

• _I~~-' -"1"::.~....,}-<~:]-.. --"11>"-" _',3::e5'-l

!Y,." CONTROL VALVES I !*I 1 f., I' iffi-=11.*-18.~ *-....- '-~ ]" '42 (TYP) I" I" 1' I" I" lfD*IH5f ' Iii ITD*IIIB} ' li LJ.1 _______ --I~---------="""=--"--'D"'e::J~f---l~-'----"'-" ITD*I03i- j I\\>" ITD*I0 '* -~ ::1 I\\>" "411 ITD-18*8 f- --. - -l~ ITD*ID*41 _j v ': ITD-13-rf- -- I\\>" llDIO'Kj. **- I 1\\!," "411 IT0-22-,3 L -- ~ I" ITD*IInf !\\!," '41 I IT0-22*41- -- \\' ""' ' 'rL'I--cf-l-'_1:..:\\!,c." -----------------------I~---I-'-Y,=-*---'I=TD=*'='D=IIl'-*--_,-....,l:;e.--i:::II---1.,_-"I\\!,cc"_'_:<-'-'jtl ITD-22*1 1-v ': I j., I" TD*6*l7f.. _.,_ f. 1" '43 lTD-n-;af-L\\-1'-.J-.L_i ---------------------------------.. ----'---===---f)a:l-'-.. o---'---'-"'j __j_ ~ I" iTD*B-@-*.. _v ~ I I" '431 ,j\\ II ul.A~>JO 51<' AWl <:ON!:>t'!'-l$E 1<: (m / :3) t t (~ T~) '84' ~~~~ ~f1ATER DRN MO~STURE SEPARATOR RELIEF v I - J SEE NF -39224 '\\' ~~L VE HEADER SEE NF-3922~ 7 11~-;-IIB TURBINE CYLINDER HEATING SYSTEM B-7 \\ "~3~ _.8 _7 ~--~_10 liB DRAINS SEE XH*2-!6A l <:_ __ __ __ 4 TO HEATER DRN 8-3 t T-*11 ,...-A--.,,3f~B-~ *.,; I:-~ TO 5 10 :[f"!SIG; GAGE~~* ~ TD*o* 11 SEE ~:.-J9224 = I T0-7*3" I SS+I I r v TD*1'*2~ IB CONDENSER ([))/31 TO TURBINE BLDG SUMP '41 I" . )TI>**;ffi 1\\>" I lls-t-IIA liB j /f-.0.5* 1i.5'"'f'-~ -- -t-" / '"5" -l>( .. -~- ~ g:I,;0-7-~3; lv* 1-;rp;~ \\!,~,74-'--- L~ v _ ~-' ~ FROM SAMPLE RECOVERY SYSTEM ' 38 OAIF;tc JT~* ~'-, ~~~ 'J 'J'* 'J'~~ 'J'~r 'J -j TD-7*291 liB-SEE LEEDS-NORTHRUP XH-248-1 jto l*2QY t.~:( ~6 ~ e~ ~7 -' ~ f~~~'(:{(;:;=Jr;* ~" ~- ~ ~* ~ilD*7*3ii/ITD*b-2'11 Tlni(y::"lf/'~ / L "c}. I/ llD*7.25f-' TD-7-27

1 I'

I ..I*~===;~:rrr:s~~~f.,~IAP ~0~ Fll-1.. ~; ~:le -tf" E ZZ. F\\..00~

---

---"+"--LtcJ-*--

MOIST SEP REEHEATER TEL.!.- TAJ.-E SUPPLY LINE 2" ~SEE NF -39218 / ~*;-~ ~G.... ~ 10" ~ -"-" I" I" 9 2" ~ 1\\1o"J~ !\\!," ~ [toc5:2: *

3.

ITDc5c'J / '-----<~:J----... ---------------------"----1~---------, !l STEA~ T~AP 3~ -(TYPICAL) !\\!,' ~ I \\1.' (TD*'dj SEE NF -3961215-1 E-3 \\ UNIT 2 BLEED STEAM TO HEATING SYSTEM 1--- ~.,.-----------~r---1 ~ IT0+14f---~ IIBi I 1 BL-10_1 1 11ei I rn IT1o-7-BI nit nit lro-7*41-T:'-7 51 y ITD-7*71-o 26 lro 7 sf-j "--I TD-27*1 I 1 NF-3%05-1 D-5 HAS-4-g 27 TO 7 9t- ~* 2 b -1 m-21-2 1 I I Yz' L NIT I BLEED STEAM TO HEATING SYSTEM SEE NF-3%05-1 E-2 I-

---

1

---i TD-7-15 I liB~* I TD-7*11 I I III 1 m-7*1* 1-28 I TD-7-12 ~ 3 I TO OEAERATOR MANIFOLD SEE NF -39605-1 F-9 4 NF -3g2J8 NF-3g224 NF-39226 3" "" 1' 1' REFERENCE DWGS: MS STM SYS FLOW DIA UNIT I BLD STM & HTR VNTS SYS FLOW DIA Ul FW HTR, MOIS SEP & RHTR DRNS SYS FLOW DIA Ul NF-3%05-1 HTG STM SYS FLOW D!A UNIT I &2 NF-88741?1 SGB SYS FLOW DIA UNIT 1 &2 XH-2-15 STM DRN & GLAND SYS FLOW DIA U1 XH-2-16 STM DRN & GLAND SYS FLOW DIA Ul XH-2-16A XH-248*1 I STM DRN & GLAND SYS FLOW DIA Ul HOT LAB GRAB SMPL PNL, SURVEY PNL FLOW DIA Ul 5 I 6 NOTES: I. FOR VALVE POSITIONS SEE OPS MANUAL C PROCEDURE CHECKLIST. rD-14-'

2.

UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.l CLASSED AS NON-SAFETY-RELATED.

3. t-DENOTES CATEGORY I VENTILATION ZONE t

7 I I" !A CONDENSER (][1/3) FROM WATER HEATER *121 SEE NF-39605-1 E-5 HS -b'J-J To WA5-TE. liB IIA 7 I\\>" *-,' IIA 1"1,\\ TD-18-1 ltD-~IO.JOl -n$ 71 s:.... HEATER DRN TNK VNT SEE NF -39226 FROM '11 AUX STEAM 1 -1 m-*a-31 lD-b-51 II I H-8 1" I" TD AUX FW PUMP TURBINE a.39 __ ATD*.-t-2:] SEE NF -39218 6" G*! 11- ~ 2" & 3. *- T"'jj8,------1------"---------.---"-~J L-1 //r---/ A FROM '12 AUX. STEAM TO TD-15*4 'J'*: IRS-15*21 L '!"_ 1_ 1//r---t A.F.W. PUMP TURBINE _J._ l I I RS-!5_11 SEE NF -39218 J.' F *3 C3J..!£...: TD-15*2 '-1TD*!5*71 T0-15*5 IC+CJ MAIN STEAM DRAINS NSR CZ NSR'fiiA ,0 NSR C2 IIAfNSR SEE NF -39218 \\!, ~,lA IB ~ MV GEN. SEE NF-39218 <X> "'T"'D"*I"'5-,_6, RS-~g-z MV [ FROM 1112 STEAM GEN. ~li!I 9 B G-5 ] ~ TD 15 3 Fl 31099 SEE NF-39218 RS-19-1

---

,~1

'(""" 3121' I ,...., T,...., 31' F-5

---

~~- ~-(~1 ~ I,...,, 1 1~ -5

%-MS-57A ~~ ~--,------- 1..... ( 1...-i<.....r----- -r--s r r 1"-.... w I // 12": TO LOW SIDE I{!Yz"~ll \\!," !\\1." 1 TO LOW SIDE-,_'2~- ~~ ~~ ~ l/ 1 DP1-1 7652 1 ! T0-24-41 I DPI-17651 I~ 1

i\\

.J SEE NF-1 3921(¥ 1 1 lj. I SEE NF-39218 1 1 ~RS-22-1I E-3 1 / : T0-24-3 I l .1. ~ L!J I(;; I TO 4 1 E-2 7 ~ l~ " l L!J ~ 1--iT0-24-21 ""r RS-22"2 IB!C2 TO 11 50 ITD-10-26f- , '-i TD-24*11 ~ I*MS*56A i" IIA;NSR,--....,;:

o-I*MS*53A

/ ...,..._l 1-MS-54A IMS-132*111~1-371 i1 T0-6*54 ITD*!0*2Bf- \\ TO*IH3

1. *.

TD-10*22 '1/ ITD-10*271, \\ \\- TD-11*4 ~ 'f r;W~ 1\\!,' I" I' 1\\!," 1\\!," ~Jl\\!,"- TO SAFETY 1\\!,' 1\\!,' I" I' --iTO*IH41 0 b _r I ' A_ RELlEF VENTS _i Uw 5 I T0-10-181 wr4l TO t1 36 2 r 31 SEE NB~-439218 2' 2 !h' 1 1' TO SAFETY <r . ~~ ~*1 1 I J::::'~ RELIEF VENTS ISl L ~ 'I TD-10-21 1 ~- SEE NF-39218 $--J 1\\!,' !£ I' HTD-11*38 1\\!," HTO 10 23 ,~ _jiiB ~ ~ B*! p ~ 1 fJIA,', =- 17~1[1[~ n ~ 1* 4-1m-1a-61 c-j TO 7 331 I t--'l"\\1,';' :;,;J~~TD*I 7 *~ciT0-7*321 j 74'~0 I T0-11-391 7\\. 1' -iTD-11-471 -1 TO 11 401 T0-10*24 ~ W j I -j T0-17*11 TD-10*25 I' ~C2 liAfNSR fiiB fllA I TD+3 I 2" I TO TURBINE SUMP_"-J... -'-1 L-im 1a *I b-iro 17 21 ~ I" -ITD*IH61 L 2-MS-62 . I 2" 1\\!," T ~ L__~:~-~~--~~--~~-.. ~:--=~--=~--~~~2"-"~:_*' ~-~;,-~'Lc'_,"'~>~-~M-S--6-2A _______ T_IIf '-{~::>' _t,_* ____ I_JI ~ I' I -ITD-28*11 I' 2\\!,' I z* IT0638~---....... T0-10-16 1 m-9-1 r 1-1 T0-21-1 -..., _____i!IA "39 f-t-LL__._.J-'-::-"6=_.=_=_=-.,.-1---~~IB l 'liB LEGEND CLASS BREAK

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

C2 NSR is I ui DA TYPE I his map /documertis " tooiiil assst=ploy= in tile f'<"lormanc:e oftnoir jobs. Yoor p!7Sonalsclecy is proWled for !:'! lRling safo:y r<ar::i<:ao, proo<<Jures r>1d O"QJP<nent.. d"""Ot.rd in Ml8ty lrM1~g prqJrnme. ml'rlill; and SPAA'e

5. Ill DENOTES EDUIPMENT DA TYPE/

DESIGN CLASS.

6. ~

DENOTES STEAM TRAP

7. 0 DENOTES TIE-IN TO EXISTING SYSTEM Cl

• SAFETY* RELATED; lSI CLASS I C2 - SAFETY-RELATED; lSI CLASS 2 C3
• SAFETY-RELATED; lSI CLASS 3 SR - SAFETY-RELATED FLUID NON-CODE CLASS BOUNDARY; NSR
• NON-SAFETY-RELATED IA,IB,IC,IIA,l!B & III DENOTES PIPING QA TYPES.

CHECKE~ PROJECT NO. APP'D & CERT. SIC!NIFIGANT NO. 1 863111 111110 mrnlt 5343 FLOW DIAGRAM TURBINE BUILDING TRAPS AND DRAINS UNIT 1 NOR.THERN STATES POWER COMPANY (l keiE""/' sCAJ..E NONE I AE'V 84 PRAIRIE ISUAND NUCLEAR GENERATING PUANT RED WING. MINNESOTA NF-39233 E F M M N () M J_

3.

H I $$$$$$SYT I ~E$$$$$.$$$$111SYOA TE$$$$$$ $$$$$$$$$DES IGNF I L$$$!11$$$$$ I I $$USERNAME$$ I NF-3'3233.DGNI NSP GENER~TIOH CAD I 8 9 10 12 FIGURE 11.1-12 REV. 34 CAD FILE: Ullll2oOGN

0)

0)

CD 'I"' 10 'I"' 0

A B c D E 1 2 4"AUX STEAM FOR DEAERATOR STEAM TO CONDENSER ------------------0 SEE DWG NF-39219 F-7 )4* FROM HTG SYST <ALTERNATE SUPPLY TO HOGGING JETS! CONT SEE NF-39219 0-7 "'21 HOGGING JETS -

• • 22 HOGGING JETS -

3 4 5 CV-31363 A-6 STEAM LEAKDFF FROM PILOT VALVE ON STOP VALVE SEE OWG ------, I )I.," TURB STOP XH-HZIQJ2-43 \\ til~ VALVE DRAINS DEAERATOR STEAM TO CONDENSER SEE DWG NF -3g21<:1 H-g MAIN STEAM DRAINS EE OWG NF -39219 H-6 AUXILIARY STEAM EE DWG I 9219 E-6 CV-31362 A-5 SEE NF-3g21 g II0At ~F-7 '4"1 / 24 / \\ I ~~p TURBINE --~ (111/3) ~ "1' I2Ttl-rd IL"to-S-41 ~ I I I

• • ~~,~~

TO TURBINE BUILDIN~ \\ IU f<: ~ a.J E CO'I-.)'1'...). W.2 Z.l zz Z3 zs "il.7 30 44 4'5 75 I GLAND STEAM PRESS AUX STEAM TO HOGGING JETS REGULATING STATION SUMP \\ TURB GLD STM SUPPLY STRAINERS SEE OWG XH-1002-45 IIA 2'1~~ B-3 SEE DWG NF-39219 0-7 ____,, ""\\ ~ I \\ SEE OWG NF-3921/ BLEED STEAM TO I E - 7 // SEE 0~~ ~~~j~~~5 E-4 \\

• • r 1<.

B'\\ 3" ~~H46 t '-------------l--=:2--. "~::.71 f L..-------------J----'0....*-=.!j liB TO *25A & *2~ l TO *24A & *24911..1:'1 "'.. 1...,. \\ 1 r 11 f/=l'f+--tl. fl-.] ~a~l .. -.114 /_c."--':-4Y" "_***~+-j-IZY" 4~L_~7 l\\_~7.*3;t,k..- --<J-w i'" STEAM DRAIN & GLAND ASSY ~=-== SEE DWG XH-1002-45 l ~ L(,V-?.30a<:,) c I,,...._ IIA r o~r37T

"'zs -.. "2

5

~ ,~.. i' ~34 t ~"JB ~ ~--,;,~,, :::'"J~~l4~"~~~.. '14~*~* ~ ~ I~A < ~*- !~:D.*,*l*l--! I' IIA II/ \\' i [z~ !T"D-b:!QI TP-25-:t. TD~I-1/ zro-11-s z-ro*1; zro**<J*I lt.ro-lo*sl z:ro (,*n l?m-~-~z* I I" I" I2TD-*-*~-" - I" i20T0-2S-3) I I" ~~ r r IZT0-.:0-? t I' ~lz]"ro[-~*C:*Bi>J;f'2" ~ 13C<" I' .. 1<11T£D3<.0::*9!!}1 o---- I" 1" 1-r---r.-.~ ..f'"" l1TD-2t~ ..../'- 210*22-1 IZro-22-2~ "21 GLAND STEAM CONDENSER (IJI/31 L

---

t-t--MOISTURE SEPARATOR REHEATER SUPPLY LINE 10" l."TC>-\\1-14 r~

I" I" \\. l.z. 11." v~l I" (" I" MOISTURE SEPARATOR I RELIEF VALVE HEADERS \\ TURBINE CYLINDER HEATING SYSTEM SEE DWG NF-39225 DRAINS SEE DWG XH-1002-45 ~~e '-r &;** ~o-~_1~ 2' TO HTR DRN TNK B-7 B-4 B-4 f : lf "21 FOR CONT SEE t ~, )-,. ~ I "'310 B-7 B 10

~

liB - -[JsDoWG NF 392:!5 - liB ~.. i SIGHT GAGE 2" "--l?T'D-'5-111 I~" I" -'35 6 7 8 J...EG,E::'I0t> FOFt STEAM PIP liVe; DRAIIV COI010EC"rl0t05 DE.SCR\\PitON DRA\\1-.> FROM STEAM llo..H.. ET PiPES DJ<:AIW FROM F \\~loST STAc;,P-r->R.AIN OW\\ER CYi...ltv>:>ER DR AI"-' !"ROM G,i...AI0D 5TE.A.M SUPPLY VAO..VE HEADER DRAtt--.:};;;: ~OM LRO S5 J..Jt-.JbE::R 'F'lPE: r.>RAI\\V FI'-DM G,LA.._,l":> COWDENSER COt-.lbE..,5r:R co~~~ :tV2 ':>-4 ~4 34 3S 34 9 10 11 STEAM >..EAKOFF FR.OM PII..OT" VALVE OIV STO"" VAl..VEO (R-1-1) SIEAM l..EAKOFF FROMPilOIVAi...VE -~\\-:~SlOP VAi...VE(\\...1-\\.) 37 37 ,5PAR.E'S STEAM 1"RAP DRAII'l AIR e.JE CTOR. STEAM TRAP DR.A\\1-.) MAl"" STEAM

ST E' AM 1"1'< AP PRA\\1--l Aux. STEAM 5TEAM1"RAP 'DR.Al~ ~I-EEI:> ::>TEA-M HEATER DRAIN TANK VENT ORA.lN I=I<OM CI<O"'SLlNDEil. PIP£. "TO MO 5TuRE R0"1'0R Gs'-~NO S'"rE.;:..M SEAL SPILLOVER DR:"-IN I=ROM C.'!L\\ND\\0."--

HEA"TING, !;"'rE.I'I\\'1'1 SUI"I"L~ Dl<:;o.\\N FROM C.~L\\NI:lEP:. 1-\\E;o,-;\\NC, !:l"TEF\\IY\\ !:>UF'P\\...'1 3~ 40 4( 4.Z. 43 44 70 -~ /- ./ TURBINE GLAND STEAM SPILLOVER REGULATING STATION SEE DWG XH-1002-44 C-4 r-- AUX STEAM TO "'22 AFW PUMP SEE DWG. NF-39219 H-2 LP TURBINE (1!1/3) LP TURBINE (1!1/31 .x liB TURBINE GLAND STEAM SUPPLY STRAINERS SEE ,t'" '""~:*1 I 2TD-5-7 2TD-5-8 I y a** ~** X 4~ ~ L h-if-t ~t 7 t _j ,---"'-+... ----' 2. 2.." TO TURBINE BUILDING SUMP 2." AUX STEAM TO CONDENSER WATER BOX EJECTOR SEE DWG NF-39219 E-8 "21 AIR EJECTOR STEAM SEE DWG NF -392!9 E -11 (r' ~ I>::J--1:>~:::)--1>..., I I I r-, I I 1~1 I ""F/'.,:. --lh-- l.t..'. "25 .f?0 liB IIA liB 2T0-6-44 I' I' \\-1 29 \\-1' -,,1 ~ rl]O~N:

--1' ~~,i ~"'N. ~)

i2TD 16 3~ W n l[; ~ STEAM 1 15 \\-1" TRAP 13 \\-1' ~4 \\-1' ITYPJ 7

=

t::C'N: I' lzTD-16-4~ !~.!' N N I' liB IIA ~..!!!!_ 1--- L......l...- '4~* ly., ~ 1\\r lliAir.._. 2TD-IB-I 6' HEATER DRAIN TANK VENT I*B Ill OWG NF-39227 H-B I" I" 6" 6" MAIN STEAM BYPASS FOR CONT SEE OWG. NF-392!9 H-3 SEE DWG. NF-39219 G-11 bTE~:AJ ~ING ~-hlo 13; rj I l" I" rr r' I. r' )}11 112" ~~-._ __._~ ~ ~\\~ : T-i<~ zro 13 s

---

i

.-!...-~.. ::c ~ r IC ~ -1 2TD-13-> I IIA / l\\-1" IIAfNSR ZTD-1121-12 I2TD-6-33f-I" _,I2TD-6-32I I" I2TD-1111-13 r- _I_,...__ Ye* ORIFICE

r::

OLD TRAP "12 I" ' I2TD-6-34I I" I2TD-1B-3f-l 1\\-1" I" lzTD-10-141 .,.---/ ]~' 1~' ,E-- 1" B 1\\-1" 2TD-HH5 I' !~" 6' 6' '? 0 r~I~IB~r~~~~~~~~~~~~~~::::~~~~~----------~~~-_j~~ FROM *21 AUX STEAM I2TD-t-21 2' 2' TO AFW PUMP TURBINE G-1 7 .l ~ .l _I2M_ s;; -:? --2_1 3_. _ 74-2MS-44L\\ T 3, FROM 1122 AUX STEAM I I ~--\\..-

---

--?.,...____ TO AFW 2TD-lS-5 r-- _j PUMP TURBINE F -3 MAIN STEAM DRAINS L---- -~

1210 15 n- ~~ ~~Cl [C ~ SEE DWG NF-39219 7.;;-2M5_45~ I -- 'z.. NSR llA NS,llg FROM 2B NSR c2 3;1~6 FROM 2A 2TD-15*4 .. --;job I lA IB STM GEN ~ STM GEN ~ '14* ~* 7 31 ~* F -4 1 F -2 IC CJ --"o := '%_,TD-15-6 3.!"5-19-*~ ~ F l~ l,. ,.. n, ~~ J,:.IA NSR J4* 30 : 2" 12 REVISIONS ~-AS BUILT-SLOP DRAINS REMOVED & CAPPED AND DELETED DESCRIPTION FOR TURB CONN NO. 75 PER ORR PI-IZIS-103 OWN: VLS 136/14/05 CHK'D: CMR 06/15/05 MOD": 05TB01 FILMED1 07/05 ~ AS BUILT-CORRECTED PENET NUMBERS TO 28 CDSR PER ORR PI-07-017 OWN: WLI 2-28-07 CHK'O: JMD 2-28-07 MOD": EC-\\0043 FILMED: 3-07 ~-AS BUILT-CORRECTED DESC & DWG REF FROM COND RETURN FROM HEATING STEAM TO HEATER DRAIN TANK VENT AT CDSR CONN N0.44 AND D-9 PER ORR PI-Iil8-lil35 DWNz DMN 5*211l-08 CHK'O; BS 6-2-11l8 MOD": EC-10792 FILMED: 6-liiS I 781 ISSUED FOR ~ CONSTRUCTION A B REPLACED CONTROL SWITCH _____ ES-468(2]4 WITH TURBINE CONTROLLER 48515 AND DELETED LOW VAG TRIP LINE,CONN.28 &. CAPPED CONN.',. 36. OWN: LAB 6-16-08 CHK'D1 PH 7-23-08 MOD111 EC-B647 REVIEWEDl JM APP'O &. CERTl RICHARD C. LINDBERG 7-24-08 PE" 44886 AS BUlL T-INCORPORATED A/E',. REV. 78 PER ORR PH21'H!I34 CERTIFIED REV. 78, TRANSFERRED TO RECORD TRACING. OWNl OMN 4-15-09 CHK'O: PH 4-24-1119 MOD": EC-8647 FILMED: 5-09 ~-*AS BUlL T-REMOVE GAGE GLASS SHOWN AT C-1. PER ORR PI-09-041 OWN: JLB 5-12-09 CHK'O: NWM 5-19-09 MOO*: EC-13412 FILMED: 6/09 ~ AS BUILT-ADD SAFETY CLASS FLAGS LEGEND & NOTES, REF OWGS &. GRID REFS TO DWG CONT &. MISC LN NOS. 04NS15 PER ORR PI-09-060 OWN: JEK 7-211Hl9 CHK'O: DB 9-23-09 c D MOD": EC-14376 ~ ~*~P~e-~o*~'~"~"~~~-~~2~-1~*~----1~ ~ AS BUILT-REVISE LINE DIMENSIONS TO REFLECT PLANT CONFIGURATION PER ORR PI-10-075 OWN: DMN 4-29-10 CHK'O: BWK 5-10-Hll MOD": EC-154CJCJ APP'O: CMR 5-10-10 ~-AS BUILT-CORRECTED PIPING AT ORAWlNG LOCATION B-9. ADDED TURBINE STOP VLV. DRAINS. & CONTINUATION. E '~ bSEE OWG NF-39219 F-6 f v 2TD-4-2 / r-- IIA I /'T.. ft.5" Tt.5' y'83" - - -+ -' A k'

4)

L.... r* / 1,4" 3 ~* ~~ 3~ ~- y.y 3 ~ 2B CONDENSER (111/3) I" 2A CONDENSER ([!I/3)

• -*------,/~ 1/ ~..j""-----,---t
• --------]/ ~,).J"" -I 1

12,11 lj lW IJIL* 1~. 1 TO LOW SIDE , I \\- l%" 11!1.!" ~ I

T-,

I " I DPI-17653 12 I IRS-22-31 1 - L

=

IRs 22 41 L 1 SEE NF-39219 1 1 1 1 N ~- - -r.u : 1-/ 2T~~;~~~\\\\~ I E;3 ~;'t~" ~

,_;-1 2TD-24-IN~:r:~A ~~o PER ORR PI-09-163 OWN: KJF 10-4-ll'l CHK'O: JBS H11-12-H'l MOO*: EC-\\4472 F

G H I ..... __ / ~'- !.5J CAP FOR FILL liB --* ~30 _/ ~-MEZZ FLOOR ~-TELLTALE -~0l~+--3........,f-

r. (aa~~~~aR

. 1'z xl'?. , F-\\.____, ~ 2" FLOAT TRAP ~ 1 1,------{::)., ~ ~.. r------------'- liB 4 ' ORIFICE ~ ~ 4 4 4 4 4 4

~1Cf j;.~ r;-0 1

37A r;l'l L ~ )4*- L::;J r 1:'.~ ~1'01*211 <If(Jhl5! v.~AAPM 3

• 3 **

""'--f" ~ * ~* ~ izio=J-:*~; J1 2 2 DYPJ_ ...... ; j..-: I" 4 4 c..-, I r <2TD

• 721 V"" I y

, d.__ ! tm U5t I" '-I" ] I", ~. 4 2~ I' ~5' 91 i ~* 9 f--GAGE GLASS t'i' f / 3" 3" 2TD-S*I ~L_--~C}--------~~------------------------------------------------~.~----------------0 C:To ~*z 1 ~* I' HEATING SYSTEM SEE OWG NF-3g605-1 ~ F-H'l ~; ~ ~ \\ 1~2. I" I" / ),. ?5.. ~6-LJ, I\\, REFERENCE DWGS: "} 1210 6 312ll 3" ~*,. :------- 1 NF-39219 NF-39225 NF-39227 NF-39250 NF -39605-1 XH-1002-43 XH-1002-44 XH-1002-45 2 MS SYSTEM FLOW DIA UNIT 2 BLD STM & HTR VENTS SYSTEM FLOW OIA UNIT 2 FW HTR, MDIS SEP & RHTR DRNS SYSTEM FLOW OIA UNIT 2 SGB SYSTEM FLOW DIA UNIT 1&2 HTG STM SYSTEM FLOW DIA UNIT 1&2 STM DRN & GLAND SYS FLOW DIA UNIT 2 STM DRN & GLAND SYS FLOW DIA UNIT 2 STM DRN & GLAND SYS FLOW DIA UNIT 2 3 I 4 ""';_ \\ IIA f ~ liB

'r I I f

~ 6"/~ 1 ~ ZTD-6-29 I I 5 r..* 1139 ~ L_ ____________________ ~ I. NOTES: FOR VALVE POSITIONS SEE DPS MANUAL C PROCEDURE CHECKLIST.

2. UNLESS OTHERWISE SHOWN, CLASS BOUNDARIES STOP AT VENT AND DRAIN VALVES WITH DOWNSTREAM ITEMS (e.g., PIPE, CAPS, ETC.>

CLASSED AS NON-SAFETY-RELATED.

3. +-

I DENOTES CATEGORY I VENTILATION ZONE 6 t 2' ~ / I "75 ~ L_ ____________________ ~

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

5. 1/1 DENOTES EQUIPMENT DA TYPE/

DESIGN CLASS.

6. ~

DENOTES STEAM TRAP 7, 0 DENOTES EXISTING SYSTEM TIE-IN 7 I 8 I 1!1.!' IZTD-24-4r-C2 18 2'

i ~

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• n77 PRAIRIEISlAND~~~EAATltlGPLANT NF-39240 FIGURE 11.1-15 REV. 32 CAD FILE: U!1!15.DGN o;:t (X) I' N

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.--STEAM SUPPLY ,I SEE OWG. NF-3"1219 "21 CONDENSER WATER BOX EJECTOR (III/3) B" 8" STEAM SUPPLy ~ M0 6 I SEE DWG. NF-39218- !J;.' G*AR*l4 > ~C~ONr,R00. 1 L.......:J~~------1 ~~~~*j*l~~_zc;:~R4i-"~*~--- ~ 1- .~.1-I t ~ -4" 4' 4~AIZ-17./ 'PI ~ ~ I' .. 1\\C.OI.\\0101.\\SER ~~11588~. 1_... i 'NIIo..\\tR ~a)( \\-_............. ".)EC.,.O~(i!l./',) _L \\\\ 'TO 'TURol"'"- \\!>LOC.. :.u.... ? I I r "II VACUUM TANK ())1/31 \\'------,---/)---0 I-----GAGE GLASS <TYP.l 12 REVISIONS 1771 ISSUED FOR t-'-'-' CONSTRUCTION REV'D UNIT 2 COND. TUBE CLEANING PIPING. REMOVED OPI-18410 & DPI-18411 02CR01 AS BUlL T-INCORPORATED AlE's REV. '77' PER ORR Pl-07-013 CERTIFIED REV. '77', TRANSFERRED TO RECORD TRACING. OWN: WLI 2-26-07 CHK'O; RBW 3-13-07 MOD11 : EC-34q FILMED: 4-07 ~-AS BUILT-CORRECTED CONFIGURATION OF TRVLG SCAN BUBBLER TUBES PER ORR PI-08-002 OWN1 DMN 1-22-1118 CHK'D; EJH 4-29-09 MOO*; EC-1211213 FILMED; 5-1219 ~ AS BUILT-CORRECTED VALVE NUMBER FROM 2CW-40-1 TO 2CW-91?l-1. PER ORR PI-12-208 OWN: JEK 11-9-12 CHK'D; SMF 12-19-12 MOD"; EC-19491 APP'D1 CMR 12-19-12 ~AS BUILT-REMOVED & PLUG TT-17366 & TT-17367 11:1 LOC D-4. PER ORR PI-13-11119 OWN: DB 2-6-\\3 CHK'D; SLW 6-19-13 MOD"; EC-21194 APP'D: CMR 6-19-13 ~ AS BUILT-CORRECTED VALVE NUMBER FROM CTC-2-7 TO 2TC-2-7. PER ORR PI-1*4-IaBS OWN: JEK 5-29-14 CHK'O: BAW 5-29-14 MOD": EC-23535 APP'D; CMR 5-29-14 ~~ \\t-:2_"' ----+--'-*' -----,; 12.. IMD-4'7 l~/ 1'. CONOENSER I DW-9-2 I y "( TO TJP.blNE: RM ""*UMP >-II ~V~~IIUM DRAIN TANK WATER 50)( VEN i <; DRI'.IN P\\P\\Nb l'O BE. QA. \\"'<~E "Jl EQ,U\\P\\'fll:~\\ 1C BE QA. \\YPE 1It-/ DE.'~\\G~ C\\..t>..SS 3 lC*!ll~- IIl (I/' \\(n/;'fpr_/;) l-EC.Ek!D Dt:~oTES LIMIT"":l 01=" Q.A...TYPE'S DoNOTE.5 Tl-IE PIPII-J"' GiA T'! PES DEWOTE!;t THC \\O.QUIPI-/l.E 'o..lT ~.A._ TYP~'S jDE~I""'f.J CLJ\\'S5 21h' "IB 2~*

• 116 RECIRC.

~-------c IFC67 Pra1rie Island #2 Ex1sbng HP Turbtne, MUR upgrade, VWO Heat Flow D1agram No -- WB-12784 Orlando, 2013-Feb-15 SIEMENSAG Recommended pnnbng format 11x17 FIGURE 11.2-2 REV. 33 CAD FILE; U!1212J2.0GN It) CD CD 0 'I"" 0

USAR SECTION 11 FIGURE 11.2-3 Revision 33  FIGURE 11.2-3 DELETED 

G 8 0 865 0 1197 4 3611227 7 527 3 77380ibml~ Slowdown 920 0 343 5 3618965 7 369 6 Not Guranteed 8650 11974 3602503 527 3 187 8 1143 3 1421489 376 6 Water 350 5 7393 8 3771 1822 11041 1495427 3741 376565 4 lbmlh 838 9 1197 4 3225937 9 523 7 357 0 lbmlh CJ-----1 Water 294 7 5261081 3240 8643 10930 3073077 317 4 234853 4 lbmlh 0-- 444 7 2572080 6 8283 11974 376565 522 2 -~- 285923 6 lbm;Q 284 9 Btu/Ibm I 1193 8 308 4 1117 4 1849 1095 8 1626 1073 3 1384 81 67 1093 0 234853 4 313 5 283 6 313 4 Water 6310 9 Water 96245 Water 131467 Water 15980 4 0786 1057585 4 L_~----~-----4----r---QD 285923 6 lbmlh 284 9 Btu/Ibm Heat Rate= (3611227 y+ (1197 4-343 5) + 7738 0 * (503 1-343 5)) I (296 614

• 1000) = 10400 Btu/kWh 9195 31bmlh 1---->(U Scaveng1ng Steam TID=21 0 "F 12820 501 2 76 72 1282 0 1276150 500 9 10733 1384 10480 105 7 15980 41bmlh(ZJ Condenser#1 0 786 61 8 10816729 938 7 947 1018 6 122851 1 182 6 76 72 1282 0 2552300 500 9 Water 13146 7 Water 15980 4 2634 7332 12676141364

-->CD Water 104 3 396994 1 136 4 ffi '"'""w l il '~'M" G 5354 8 lbm/0. I 210 2 Btullb1 ps1a I Blu/lbm lbmlh "F (X) all pressures are absolute pressure ps1a temperature oF enthalpy Btu/Ibm mass flow lbmlh atmosphenc hum1d1ty % fuel sensible heat Included F~rst Stage Pressure = 264 2 ps1a Mechamcal Loss = 1 982 MW Electncal Loss = 3 697 MW MSR Effectiveness = 99 0 % TEP = 1026 4 Btullbm PF = 0 900 Heat Rate = 10400 Btu/kWh 357 0 lbmlh 5401 7 lbmlh 1197j;tullbm ~ ______ 11653Jltullbm

• ~DDDDl~
• © Water/Steam Property Functions H2032Bit(2012-05-25) --> IFC67 Pra1ne Island #2 Ex1st1ng HP Turbine, MUR upgrade, 50% Load Heat Flow D1agram No -- WB-12785 Orlando, 2013-Feb-15 SIEMENSAG Reccmmended pnntlng format 11x17 FIGURE 11.2-4 REV. 33 CAD FILE; U!1212J4.0GN It)

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A I i ........... i B c D FIGURE 11.2-5 UNIT 1-TURBINE GENERATOR HEAT BALANCE -100o/o POWER-VALVES WIDE OPEN AT 1.60 IN HGA CONDENSER VACUUM 2 .ER* -... ate. ~** M4lW IFPPOWUI

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• RATE 7147478' 1199.196
• 411.496) 583722 MOISTURE SEPARATOR DRAIN TANK 4

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A B c D FIGURE 11.2-6 UNIT 1-TURBINE GENERATOR HEAT BALANCE-MAXIMUM STEAM FLOW WITH VALVES WIDE OPEN AT 1.60 IN HGA CONDENSER VACUUM .E.P.* P.= ...... H 986.7 H ELEC.LOSS* BFP P<)lhER = 2 7457 kW 1035 kW Qi.LOSS=1982 kW CONTROLVALVES~Jh: 8.8 % ARST STAGE PRESSURE "' 583.9 PSIA. ~---.~~---, (!) 4431 w I -------, 1147.4 H I I I I I 4170945 W I r--------....1 I 998.7 H I I I 1~.1 H 1024.9 H 2:<1 p I I I I I I I I I I .,.,_ w I Sl8.8 HI 320B4 w I --~-!.~J 1087.4 H 1053.4 H 545 p 60048w SIEIIENS WES1WGHOUSE PROPRIETARY I Uoo... """"'"""_..... _ Given. Do nol ~.Reproduce,<< u.. 133.9 H 256565 w 1088.8 H 1Dn.6 H 102 p ..... w 162.4 H 35188 w 1088.6 H 3 1107.7 H 1089.8 H 170 p I I 44081 w I 187.7 H I Z13IMO w I 1107,7 H I 18.15 p I I I I I I 1180.2 H.... I 374158 w 1 1180.2 H I 52.8 p l I I I I + 4 160.8 p 5382712 w i-1287-:2-H-l llv@ RSV~ I I I I 5382712 wl 11!12.41 p 1 489.1 T I 1267.18 HI ID* 21.6 F 5 6 U11206 r-------------c@(B) + cv lV ,~5f cr-w REGULATOR 501150~ 749.1 P 1 11119.2 H I _____ J ~----~~~- ~~~-~--~----*~-~~-~ ~ 1199.2 H '<Y 782.3 p T 781.3 p I 1199.2 H 4 1199.2 H I 515.5 T l 712.3 p E 0.1 M + 1181.4 H 1160.3 H 413.2 p I I I I I I '----J+L----------'+~------j I I L_ _______________.: I I I r----~~-~-~~ I 1104.3 H ~ I 337W I ,-------- N I I 1104.3 H ~R-EH_EA TE_R-+----------~~F I I I I I I I 181l4 P I 1198.0 H I MOISTURE ~--.JL~L---~~~.--------------~-f-. _______ j SEPARATOR 1104 3 HI ~------------, DRAIN TANK 647422 w 342.SH 172.5 p I I r------J 594154 w 1 10433 w 1 1104.3 H I 427.8 H I 168.1 p 1 885932 w 1 1 1181.4 H I I 405.4 P I t ~ W-FLOW l.BWH C?-.7447 w I..... H I 13103 w I 1199.2 H / / / 442.7T 422.3 H 7883714 w DJBB!rt;- fiiNERAIOR Olfllniwbe \\WhOut Willen eoo-d d NET HEAT RATE 7893714 ( 1199.196 - 422.341 ) P-PRESSURE PSIA 578935kW ---~ 9646.865 Btu/kWh 635675 SIEMENS WESTINGHOUSE POWER CORPORATION 635675 kW NET LOAD H-ENTHALPY BT\\JI'LBM T-TEMPERAT\\.RE DEG F 720 PSlA 1108.83 H 2.00 IN HgA 'TC4F -47 in 050000KVA ENG:WSM DATE:2004.03.01 WB-09927 8 100Y. POWER MAXIMUM GUARANTEED A B c .--.------------t-=====;==:;==;==;-==;o=;::;:::=----J ~ D =c:.. UNIT 1 - TURBINE GENERATOR HEAT BALANCE ~;~ MAXTMUM STEAM FLOW WITH VALVES WIDE §~ ~~==~~~~~~O:.P~E;.N;.A~T~l.~60~1N~H~G~A~C~O~NO~E~N~S~ER~V~A~CU~U~M~--~::::~:~ NORTHERNti==: COW' NoN ..w 30 PAAIRIEISLAND~~~ERATINGPLANT FIGURE 11.2-6 REV. 30 2 3 4 5 6 7 0...... co co 0...... 0 co I C\\1

USAR Section 11 Revision 31 Figure 11.2-7 PRAIRIE ISLAND UNIT 1 HBD-MUR   ),*85(  FILE :.IPI. 1.curr.rtr.2007.03.12 T.E.P.= ELEP. = 997.5 H 990.9 H ELEC. LOSS = BFP POWER= 8196 kVI/ 6489 kW MECH. LOSS= 1982 kW CONTROL VALVES ~ = 5.5 % FIRST STAGE PRESSURE= 546.6 PSIA t;:::\\ ____ 2_02_8~~----1 '2./ 1 ~4~~ ~ l (:;:\\*-------, I \\..!._) 1151.8 H f I I I I I 3917093 W ~---------* 1 997.8 H I I I 1042.9 H 1026.0 H 2.19 p 71927 w 97.4 H SIEMENS PROPRlETARYINFORMATION Use this Document solely for the Purpose Given, Do not Disclose, Reproduce, or Use 1068.1 H 1054.3 H 5.19 p 83434 w 1 131.8 H I 234833 w : 1068.1 H 1 4.93 P I 1089.6 H 1078.9 H 9.7 p 50569 w [ 159,9 H t 32964 W I 1089.6 H ! NOT GUARANTEED FOR INFORMATION ONLY

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@ (HJ t CV TV 1ooo w t t 5017 w 1108.8 H 1100.9 H 16.1 p 3~3881 w 184.9 H 25'1580 w 1108.8 H 15.31 p 11822 H 53.2 p I I I I I I I I I I I I I I I I I I I I I I I I I '----~ I 345132 w l 11822 H I 50.5 p l I I I I t 150.4 p 5031749 w ,------1 I 1267.1 H I ! IV RSV~ A I I I I 5031749 w l 151.9 P 1 486.7 T I 1267.1 HI r~-R-E_G_U_LAL_T_O_R--.,1 tf\\'*---'!..5!...'!!~- fC>. * ~::~:_::::: __ l_ ___ l,--~~~~::: L. -----,.., -,;----'* ~ 1200.3 H ~ ~ 739.0 P I 762.0 P (';::\\ -- I 1200.3 H I 1200.3 H ~~-- l 698.4 p 6 5~~~ ~ "::.::.r-----~ r---... t \\.SJ. f7;;\\__ __,£S.§:L\\:Y. __ _, ~ 1104.7H 1 ~ 337W I \\.£V - -1i04.7-HJ J I I 1160.4 H 1159.3 H 378.5 p 1104.7 H 165.4 p I I I I '---~+, __________.+, _______ j I I I I I I ~----tel!ol.YJ __,.. ~M I 1104.7H ~ !116 3.0-~-----@ 7738 w 503.1 H TO= 21 F 527759~ 7251.1 P 1 1200.3 H 1 ~-----------------..-: I I I I _____.J I I I I I I ~----+-----------~F I I I I I I I I 5645 WI 254.0 H T 158.3 p 1194.9 H MOISTURE SEPARATOR DRAIN TANK 591179W 336.7 H 161.3 p I I I I I I ___.162,~E. ___ _2§_22J<'!__!Y-.-------------~-t~------j 1104.7 H I I I I I

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I I ,------l 545716 w 1 9757 w : 1104.7 H I 418.2 H 1 156.3 P I 555033 W I I 1160.4 H l I AH 3.0 BTUJLB 367*3 p I t t LEGEND (j) / .14872W I 495.4 H I 128a7 w I 1200.3 H / / / 431.8 T 410.4 H 7281149 w TURBINE-GENERATOR Otherwise Without Written Consent of Siemens Power Generation NET HEAT RATE 7273408 ( 1:<00.3 - 410.4 ) + 7738 ( 503.1 410.4 ) 9691.2 Btu/kWh W-FLOW ?-PRESSURE H-ENTHALPY LBM/H PSIA BTU/LBM 578935 kW 592917 SIEMENS POWER GENERATION, Inc. 592917 kW NET LOAD T-TEMPERATURE M-MOISTURE Prairie Island Unit 1 - For Information Only - Existing HP Turbine - MUR Uprate DEGF no PSIA 1199.63 H 2.00 IN HgA TC4F-47in ENG:WSM DATE:2007.03.12 659000 KVA WB-10995

G £0 E E £ £ D co D D C) ~ 7620112003 7274037 4/ 512 6 684 000 MW 7738 0 lbm/h c[T"~- 920 0/410 5 7281775 4/ 431 9 I II 0 L.----i~= I "'-1 Not Guranteed 762 ol 1200 3 7267723 E1b512 6 3787111601 555910 0/ 439 3 Water /419 0 9818 4/439 9 367 5/1147 2 565728 4/ 436 4 527574 81bm/h 512 6Jtu/lbm F C) C) 7390112003 6740148 81 509 2 357 o lbm/h c~-----1 729711200 3 52757 4 s,l, 5077 1 2882 7 lbmlh 1------,!o{U Scavenging Steam TID= 21 0 OF 1653111047 1637111047 r-- ----1562111949-- -r-l 1519/12671 1469/12671 6168386 9J.366 2 _5_6_2_2"'39"'3'-'\\+'1,32'65,_4'---, 5031072 7*362 7 1 i'J 5031072 74,486 7 5031072 74,4861 ~+-~~--~--H 1 Ms__ ~~~~--~----------~--~ R_ehe_a_te_r#_1 'J 545993 8 lbm/h 720215126 _11+----{u 591320 5 Ibm~ 336 7 Btu/Ibm@ 527574815063 ~ 1489/12671 ~-~-------------2-5_1_55_3_s_~~*4_s_s_1 ____________________________ ~ ~~~1 c-~v~ 111~ i]il ~~~~~~ ~~~ i)jl~~~~~ I~L.::~*w ~~;~~~~===R=======17=2=;~=;=~==l~~=~=~=2==============~~ LPrflfe# 1 ~~====p::~~~~1~72~~~~3~2~~~~,~~~~~~~~~2~~~~~~~~~~~~~~:~::rrrLrPrrrLU~lre#Z 1610/11088 Water/1881 1610/11088 Water/1881 s~----1-25_6_4_5~~:2_1_6_s ________ zo_1_27~o*~:z_1_9_8 __ ~H-~L---~ o~----1-25_6_4_5~~:2_1_s_s ________ 2o_1_2_7~o*~2_1_9_8 __ ~H-rr~--~ 9700/10696 Water/1618 9700/10896 Water/1618 16480~1918 255231*1937 16480~1918 255231j,1937 I 5190/10681 Waterl1336 I 5190/10681 Water/1336 r 117589 1,~ 163 8 32079 9* 165 6 1175891* 163 8 32079 9* 165 6 J~~---~~-------~---4~-----~ A~-Z-----~--------~----1~-------J 1968/10429 Water /974 1968/10429 Water /974 v~--1_5_o4_2_5~j,12_s_s ____ s_s_o7_2_0~j,x_=_o_o_oo._--+-'------~ ~---1_so_4_2~5j,~1_2_5_5 ____ 3s_o_72~0j,L1_2_9_4 __ 1_~-----~ 0 786/ 997 9 0 786/997 9 1957<153 3/ 93 8 J D-t- __:~o72 o lbm/h @ ~ p 1 60 HG I ' p = 1 60 In HG 21: 1 n I ~36072 o lbm/h(\\i) 07861618 l*-_-1_o3_4_o_os_5_1_b_m-(/hg) L_C_o_n_d_e_ns_e_~_1 __ ~ _______ 2_o_o8_58 3_7*~9_3_s __________ ~~~----------------~ndense~2 19574533/938 H 545993 8] 361 7 156211104 7 344846 51 296 6 1531/9817 5050111822 493017929 291544 5/2141 383344 51 161 6 li-D N II 0 II 1-E----,:---{Y C) C) 5624 3lbm/~ 250 8 Btu/lbml II II 5313 81bmlh 1 1200 \\}3tu/lbm First Stage Pressure ; 546 9 ps1a Mechanical Loss= 1 982 MW Electncal Loss = 8 204 MW MSR Effectiveness = 99 4 % TEP = 997 7 Btullbm PF = 0 900 Heat Rate ; 9686 BtulkWh 357 o lbm/h 5533 o lbm/h 12003_.Btu/lbm ~- _____ ~ 11513)ltu/lblsJ © .!Dl~~~lil.,, 444 7161 8 -oc5o"'sc:1-715;-;8'-'ool-:'g::':z-:;6'-----c~ 11510 Btu/lb 12003 Btu/Ibm 920 ol336 1 444 7j3331 444 ?j332 4 § 444 7L246 5 0 -~ <( (.) 0 444 7_1 178 2 5533 0 Ibm/, 1000 0 lbm~G g 444 7/63 0 ~ 444 7/63 0 444 7/61 9 I ~. __ 7_z_s_1_77_5_'\\t~*-3_62 __ 6 ___ E"'~-72_8_1_7_75_*~~:3_6_o_3 ________ s_o_s1_1_5_s~o*£-35_9_7 ____ -4l~, 50511580*2766 I Heater#5 Delta h ;:::: 3 0 Btu/Ibm -r-Hea1er#4 Waterf345 9 1093303 1/ 372 6 '--..,--/A----~ 2230617 41bm/h 334 7 Btu/Ibm k Water 1334 0

• ~ 1639296 9 361 6 591320 5 lbmlh 336 7 Btu/Ibm 5051158 04,2091 Heater#3 50511580*938 1 ""-

5o511sso4,933 I r( 5051158o~s27 r J Condensare Cooler L:i_, ~ Gland Condensor ~'1-: .S-JA_E ______ _ L Water /250 8 J Water 1179 8 _I Water I 503 0 J 5624312816 1 5533012116 -1 1000015126 il 103400651bmlh ..L_ ___________ "'-----~~-------------------L---------> Waterf/18 10218492/1038 lbm/h I Diu/Ibm °F (X) all pressures are absolute pressure ps1a temperature °F Water/Steam Property Functions H2032Bit(2012-05-25) --> IFC67 Pra1ne Island #2 Ex1st1ng HP Turbine, MUR upgrade, 1684MWt Heat Rate= (7274037 4 * (1200 3-410 5) + 7738 0 * (503 1 -410 5)) I (593 228 *1000) = 9686 Btu/kWh 773801bm/1 503 1 Btu/Ibm enthalpy Btu/Ibm ~ mass flow lbm/h atmosphenc hum1d1ty % fuel sensible heat Included Heat Flow D1agram No -- WB-12783 Orlando, 2013-Feb-15 SIEMENSAG Recommended pnnt1ng format 11x17 FIGURE 11.2-8 REV. 33 CAD FILE; U!1212J8.0GN It) CD CD 0 'I'"' 0

L. BORCHARDT 6-23-89 Ul1901.0GN AUXILIARY FEEDWA TER PUMP CHARACTERISTIC CURVES NORTHERN STATES POWER Cot.f'ANV PRAIRIE ISLAND NUCLEAR GENERATING PLANT RED WING WIESOTA FIGURE 11.8*1 REV. 18

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u.. 0.1 0 8 ~ - 6 1-u 4: e: ~ 2 .m ~--~~~~~~~~----..J---L-~~~LLL---~---L~~~~u 1.0 2 ~ OWN L. BORCHARDT DATE 6-23-99 ECI<ED CAD FILE U11904A.OGN 6 8 10 2 ~ 6 8 100 TIME <SECONDS) DECAY HEAT CURVE I TO 1000 SECONDS NORTHERN STATES POWER COMPANY PRAIRIE ISLAND NUCLEAR GENERATING PLANT RED IIHl WHSOTA 2 ~ 6 8 1000 SCALEa NONE FIGURE 11.9*4A REV. 18

ffi 0.1 8 6 ~ 2 0.. ...J ~ LL .01 0 8 ~ 1-u ~ 6 2 .001 ~-------~~~L-~~~~-------~-----~~~~~~-------~-----~~~~~u 1,000 2 1.000.000 WN L. BORCHARDT DATE 6-23-99 CHECKED CAD FILE U11904B.DGN 6 8 10.000 2 6 8 100.000 2 6 8 1.000.000 10.000.000 TIME CSECONDS) DECAY HEAT CURVE GREATER THAN 1000 SECONDS NORTHERN STATES POWER CO~PANY PRAIRIE ISLAND NUCLEAR GENERATING PLANT liED WING YNIESOTA SCALE* NOt£ FIGURE 11.9-4B REV. 18}}