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CLOSED FEEDWATER HEATERS
NINTH EDITION
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STANDARDS
TITLE
CLOSED FEEDWATER HEATER TECH SHEETS
Standards for Closed Feedwater Heaters, 9th Edition, 2015
Tech Sheet #106: Specification of Tube Hole Sizes and Tolerances for Support and Baffle Plates
Standards for Shell and Tube Heat Exchangers, 5th Edition, 2013 Standards for Tray Type Deaerators, 9th Edition, 2011 Performance Standards for Liquid Ring Vacuum Pumps, 4th Edition, 2010 Standards for Direct Contact Barometric and Low Level Condensers, 8th Edition, 2010 Standards for Steam Jet Vacuum Systems, 7th Edition, 2012 Standards for Steam Surface Condensers, 11th Edition, 2012 Standards for Air Cooled Condensers, 1st Edition, 2011 Standards for Gasketed Plate Heat Exchangers, 1st Edition, 2014
Tech Sheet #127: Basics of Closed Feedwater Heaters Tech Sheet #128: Typical Feedwater Heater Cold Start-Up Closed Feedwater Heater Specification Sheets English Units and SI Units All closed feedwater heater tech sheets are available for download on the HEI web site: www.heatexchange.org.
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PUBLICATION LIST
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Heat Exchange Institute, Inc.
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NINTH EDITION Copyright 2015 by Heat Exchange Institute 1300 Sumner Avenue Cleveland, Ohio 44115
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Reproduction of any portion of this standard without written permission of the Heat Exchange Institute is strictly forbidden.
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STANDARDS for CLOSED FEEDWATER HEATERS
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HEAT EXCHANGE INSTITUTE, INC.
American Exchanger Services, Inc. Greenfield, WI 53228 Holtec International Marlton, NJ 08053 Hydro Dyne, Inc. Massillon, OH 44646 SPX Heat Transfer, LLC Tulsa, OK 74116 Thermal Engineering International USA, Inc. Santa Fe Springs, CA 90670
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CLOSED FEEDWATER HEATERS
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HEAT EXCHANGE INSTITUTE, INC.
1. DEFINITIONS …………………………………………………………………………………………………………… 1
1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11 1.12 1.13 1.14 1.15 1.16
Closed Feedwater Heater …………………………………………………………………………………… 1 Heater Duty …………………………………………………………………………………………………… 1 Design Maximum Working Pressure ……………………………………………………………………… 1 Operating Pressure …………………………………………………………………………………………… 1 Terminal Temperature Difference (TTD) ………………………………………………………………… 1 Drain Subcooler Approach (DCA) ………………………………………………………………………… 1 Logarithmic Mean Temperature Difference (LMTD)…………………………………………………… 1 Pressure Loss ………………………………………………………………………………………………… 1 Heat Transfer Coefficient …………………………………………………………………………………… 1 Desuperheating Zone (DSH) ………………………………………………………………………………… 1 Condensing Zone ……………………………………………………………………………………………… 1 Drain Subcooling Zone (DC) ………………………………………………………………………………… 1 Drains ………………………………………………………………………………………………………… 1 Total Surface ………………………………………………………………………………………………… 1 Effective Surface ……………………………………………………………………………………………… 1 Integral Flash Chamber……………………………………………………………………………………… 1
2. FEEDWATER HEATER PERFORMANCE…………………………………………………………………………… 2 2.1 Heater Performance ………………………………………………………………………………………… 2 2.1.1 Minimum Data Required to be Supplied by the Purchaser ………………………………… 2 2.2 Thermal Resistance ………………………………………………………………………………………… 2 2.2.1 Tube Wall Resistance …………………………………………………………………………… 2 2.2.2 Fouling Resistance ……………………………………………………………………………… 3 2.3 Terminal Temperature Difference ………………………………………………………………………… 3 2.4 Drains Subcooling Zone Approach ………………………………………………………………………… 3 2.5 Tube Side Velocity …………………………………………………………………………………………… 3 2.6 Shell Side Pressure Loss …………………………………………………………………………………… 3 2.7 Tube Side Pressure Loss …………………………………………………………………………………… 3 2.8 Nozzle Sizes …………………………………………………………………………………………………… 7 2.9 Steam Nozzle Location and Steam Distribution Dome ………………………………………………… 7 2.9.1 Single Nozzle Heaters …………………………………………………………………………… 7 2.9.2 Multi-Nozzle Heaters …………………………………………………………………………… 8 2.10 Drain Nozzle ………………………………………………………………………………………………… 8 2.11 Control of Feedwater Heaters ……………………………………………………………………………… 10 2.11.1 General Control Considerations ………………………………………………………………… 10 2.11.2 Capacitance Requirements for Vertical Heaters ……………………………………………… 10 2.12 Overload and Abnormal Operating Modes ……………………………………………………………… 10 2.13 Vent Off-Take Piping ………………………………………………………………………………………… 10 2.14 Oxygen Content in a Deaerating Heater ………………………………………………………………… 11
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3. MECHANICAL DESIGN STANDARDS……………………………………………………………………………… 11 3.1 Code Requirements …………………………………………………………………………………………… 11 3.1.1 Corrosion Allowance ……………………………………………………………………………… 11 3.2 Design Pressure ……………………………………………………………………………………………… 11 3.3 Design Temperature ………………………………………………………………………………………… 11 3.4 Hydrostatic Test ……………………………………………………………………………………………… 12 3.5 Nil Ductility Temperature …………………………………………………………………………………… 12 3.6 Tubes …………………………………………………………………………………………………………… 12 3.6.1 Tube Metal Temperature ………………………………………………………………………… 12 3.6.2 Tube Joint Temperature ………………………………………………………………………… 12 3.6.3 Tube Wall Thickness Limitations ……………………………………………………………… 12 3.6.4 Tube Length ……………………………………………………………………………………… 12 3.6.5 U-Tubes …………………………………………………………………………………………… 12 3.6.6 Stress Relieving U-Bends ……………………………………………………………………… 13 3.6.7 Tube Plugging …………………………………………………………………………………… 13 3.7 Tube Bundle …………………………………………………………………………………………………… 13 3.7.1 Tube Layout ……………………………………………………………………………………… 13 3.7.2 Baffles and Support Plates ……………………………………………………………………… 13 3.7.2.1 Tube Holes …………………………………………………………………………… 13 3.7.2.2 Spacing and Tube Vibration ……………………………………………………… 13
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Page FOREWORD ………………………………………………………………………………………………………………… vii
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CONTENTS
4. MATERIAL DESIGN STANDARDS…………………………………………………………………………………… 23 4.1 Materials ……………………………………………………………………………………………………… 23 4.2 Quality ………………………………………………………………………………………………………… 23 4.3 Specifications ………………………………………………………………………………………………… 23 5. DESIGN AND SPECIFICATION OF REPLACEMENT HEATERS/BUNDLES………………………………… 24 5.1 Replacement Heaters/Bundles ……………………………………………………………………………… 24 6. FEEDWATER HEATER PROTECTION……………………………………………………………………………… 25 6.1 Safety Requirements ………………………………………………………………………………………… 25 6.1.1 Tube Side Relief Valves ………………………………………………………………………… 25 6.1.2 Shell Side Relief Valves ………………………………………………………………………… 25 6.2 Flashback Protection ………………………………………………………………………………………… 25 6.3 Cleanliness and Corrosion Protection ……………………………………………………………………… 25 6.4 Venting and Draining ………………………………………………………………………………………… 26 7. INSTALLATIONS………………………………………………………………………………………………………… 26 8. CHANNEL TYPES………………………………………………………………………………………………………… 27 8.1 Full Diameter Access Channels …………………………………………………………………………… 27 8.1.1 Low Pressure, Full Access ……………………………………………………………………… 27 8.1.2 High Pressure, Full Access ……………………………………………………………………… 27 8.2 Manway Access Channels …………………………………………………………………………………… 28 8.2.1 Minimum Access Manway Sizes ……………………………………………………………… 28 8.2.1.1 Minimum Manway Sizes ………………………………………………………… 28 8.2.1.2 Pass Partition Cover Design and Type …………………………………………… 28 8.2.2 Low Pressure, Manway Access ………………………………………………………………… 29 8.2.3 High Pressure, Manway Access ………………………………………………………………… 30
APPENDICES Appendix A A1 A2
GUIDELINES FOR INSTALLATION, OPERATION, AND MAINTENANCE OF FEEDWATER HEATERS ……………………………………………………………………………… 41 INSTALLATION OF CLOSED FEEDWATER HEATERS………………………………………… 41 A1.1 General Considerations ……………………………………………………………………… 41 A1.2 Installation Under Freezing Conditions …………………………………………………… 41 A1.3 Pre-Operational Cleaning and Flushing Operation ……………………………………… 41 A1.4 High Level Condensate Dump ……………………………………………………………… 41 A1.5 Accessories …………………………………………………………………………………… 41 CLOSED FEEDWATER HEATER OPERATION ………………………………………………… 42 A2.1 Initial Start-Up Precautions ………………………………………………………………… 42 A2.2 Liquid Level Control ………………………………………………………………………… 42
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9. TYPICAL FEEDWATER HEATER INTERNAL ARRANGEMENTS……………………………………………… 31
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3.7.2.3 Support of U-Bends ………………………………………………………………… 13 3.7.2.4 Thickness …………………………………………………………………………… 13 3.7.2.5 Drain Subcooling Zone End Plate ………………………………………………… 13 3.7.2.6 Shrouds and Longitudinal Baffles ……………………………………………… 13 3.7.2.7 Impingement Baffles ……………………………………………………………… 13 3.8 Tubesheet ……………………………………………………………………………………………………… 13 3.8.1 Tubesheet Corner Radius ……………………………………………………………………… 14 3.8.2 Tube Hole Diameters and Tolerances ………………………………………………………… 14 3.8.3 Ligament Widths and Tolerances ……………………………………………………………… 15 3.9 Channel Covers ……………………………………………………………………………………………… 15 3.10 Heater Supports ……………………………………………………………………………………………… 15 3.11 Condenser Installation ……………………………………………………………………………………… 15 3.12 Welded Joint Construction ………………………………………………………………………………… 16 3.13 Connections-Nozzle Length ………………………………………………………………………………… 16 3.14 Nozzle Loads ………………………………………………………………………………………………… 16 3.14.1 Nomenclature …………………………………………………………………………………… 16 3.14.2 External Forces and Moments ………………………………………………………………… 16 3.14.3 Sample Problem ………………………………………………………………………………… 17 3.15 Tolerances……………………………………………………………………………………………………… 17
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CONTENTS (continued)
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REFERENCE DATA …………………………………………………………………………………… 56 C1 Metric Conversion Factors …………………………………………………………………… 56 C2 Areas of Circular Segments ………………………………………………………………… 60 C3 Modulus Of Elasticity E of Materials For Given Temperatures ………………………… 61 C4 Thermal Conductivity of Materials for Given Temperatures…………………………… 63 C5 Mechanical Characteristics of Tubing ……………………………………………………… 64 C6 Mechanical Characteristics of Steel Tubing ……………………………………………… 66 C7 Chart for Solving LMTD Formula ………………………………………………………… 67 C8.1 Closed Feedwater Heater Specification Sheet - English Units ………………………… 68 C8.2 Closed Feedwater Heater Specification Sheet - SI Units ………………………………… 69 C8.3 Closed Feedwater Heater Specification Sheet - MKH Units …………………………… 70
Appendix D TROUBLESHOOTING GUIDE……………………………………………………………………… 71 FIGURES Fig. No. 1 Fig. No. 2 Fig. No. 3a Fig. No. 3b Fig. No. 4 Fig. No. 5 Fig. No. 6a
Feedwater Specific Volume Ratios …………………………………………………………………… 4 Design Feedwater Velocity at 60°F …………………………………………………………………… 5 Density Correction Factor ……………………………………………………………………………… 6 Loss Correction Factor for Tube Configuration ……………………………………………………… 6 Steam Nozzle Location-Single Inlet …………………………………………………………………… 8 Steam Nozzle Location-Multiple Inlets ……………………………………………………………… 9 Tubesheet Formula Perimeter Calculation ………………………………………………………… 14 v
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Appendix C
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A2.3 Liquid Level Control in Vertical Channel Down Heaters ……………………………… 43 A2.4 False Liquid Level Indication ……………………………………………………………… 44 A2.5 Effect of Low Liquid Levels on External Drain System ………………………………… 44 A2.6 Effect of Load Rejection on Shell Liquid Level …………………………………………… 44 A2.7 Effect of Failed Tubes on Heater Operation………………………………………………… 44 A2.8 Effect of Plugged Tubes……………………………………………………………………… 45 A2.9 Start-Up Limitations………………………………………………………………………… 45 A2.10 Shutdown Limitations………………………………………………………………………… 45 A3 MAINTENANCE OF FEEDWATER HEATERS …………………………………………………… 46 A3.1 In-Plant Cleaning……………………………………………………………………………… 46 A3.2 Chemical Cleaning…………………………………………………………………………… 46 A3.3 Stagnant or Entrapped Areas………………………………………………………………… 46 A3.4 Special Product Warnings (Safety)………………………………………………………… 46 A3.5 Lay-Up Procedure for Non-Operating Heaters…………………………………………… 46 A3.6 Repair Procedures……………………………………………………………………………… 47 A3.6.1 Tube Leak Repairs………………………………………………………………… 47 A3.6.2 Pressure-Boundary Repairs……………………………………………………… 47 A3.7 Spare Parts and Special Tools……………………………………………………………… 47 A3.7.1 Spare Parts…………………………………………………………………………… 47 A3.7.2 Special Tools………………………………………………………………………… 47 A3.8 Inspection……………………………………………………………………………………… 47 A3.9 Alterations or Repairs………………………………………………………………………… 47 Appendix B GENERAL FEEDWATER HEATER INFORMATION …………………………………………… 48 B1 Vertical Feedwater Heaters ………………………………………………………………… 48 B2 Cycling and Off Load Conditions …………………………………………………………… 48 B3 Material Compatibility in Operating Environments …………………………………… 48 B3.1 Compatibility of Tube Materials ………………………………………………… 49 B4 Specific Zone Designs………………………………………………………………………… 50 B4.1 Desuperheating Zone ……………………………………………………………… 50 B4.1.1 Dry Wall Safety Margins at DSZ Outlet…………………………… 50 B4.2 Condensing Zone…………………………………………………………………… 50 B4.3 Subcooling Zone……………………………………………………………………… 50 B5 Heaters Removed from Service……………………………………………………………… 51 B6 Manway Sizes for Hemispherical Heads…………………………………………………… 51 B7 Integral Flash Chamber Considerations …………………………………………………… 51 B8 Floating Pass Partitions ……………………………………………………………………… 52 B9 Emergency Liquid Bypass for Feedwater Heaters ……………………………………… 52 B10 High Pressure Closures: Gasketed vs. Welded Diaphragm ……………………………… 53 B11 Drains and Vents for Heaters………………………………………………………………… 53
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Maximum Tube Side Velocity…………………………………………………………………………… 3 Maximum Metal Temperatures for Tube Materials ………………………………………………… 12 Maximum Temperature of Expanded Tube Joints………………………………………………… 12 Design Minimum Tube Wall Thickness……………………………………………………………… 12 Tube Hole Diameters and Tolerances for Tubesheets……………………………………………… 14 Tubesheet Drilling Tolerances………………………………………………………………………… 15 Steam Flow Multiplier………………………………………………………………………………… 51
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TABLES TABLE I TABLE II TABLE III TABLE IV TABLE V TABLE VI TABLE VII
Wall Thickness/I.D. Ratio for Integral Tubesheets ………………………………………………… 14 Nozzle Load Nomenclature …………………………………………………………………………… 16 Allowable Nozzle Loads (a)……………………………………………………………………………… 18 Allowable Nozzle Loads (()…………………………………………………………………………… 19 Allowable Nozzle Loads (D)…………………………………………………………………………… 20 Standard Tolerances for Nozzles and Support Locations - English Units ……………………… 21 Standard Tolerances for Nozzles and Support Locations - SI Units……………………………… 22 Horizontal Installation ………………………………………………………………………………… 26 Horizontal In Condenser Neck Installation ………………………………………………………… 26 Vertical Channel Up Installation ……………………………………………………………………… 26 Vertical Channel Down Installation ………………………………………………………………… 26 Welded Type Pass Partition Cover Design …………………………………………………………… 27 Gasketed Channel Cover Pass Partition Design …………………………………………………… 27 High Pressure, Full Access Channel ………………………………………………………………… 27 High Pressure, Full Access Channel ………………………………………………………………… 27 Typical Full Access Bolted Pass Partition Cover …………………………………………………… 28 Hemispherical Head Channel Design-LP …………………………………………………………… 29 Elliptical Head Channel Design-LP ………………………………………………………………… 29 Hemispherical Head Channel Design-HP …………………………………………………………… 30 Combination Tubesheet Channel Type Design-HP ………………………………………………… 30 Modified Hemispherical Head Design-HP …………………………………………………………… 30 Straight Condensing Feedwater Heater - Horizontal Mounting…………………………………… 31 2-Zone Feedwater Heater - Horizontal Mounting…………………………………………………… 32 2-Zone Feedwater Heater - Horizontal Mounting…………………………………………………… 33 3-Zone Feedwater Heater - Horizontal Mounting…………………………………………………… 34 Straight Condensing Feedwater Heater - Vertical Channel Down Mounting…………………… 35 2-Zone Feedwater Heater - Vertical Channel Down Mounting …………………………………… 36 3-Zone Feedwater Heater - Vertical Channel Down Mounting …………………………………… 37 Straight Condensing Feedwater Heater -Vertical Channel Up Mounting ……………………… 38 2-Zone Feedwater Heater -Vertical Channel Up Mounting ……………………………………… 39 3-Zone Feedwater Heater -Vertical Channel Up Mounting ……………………………………… 40 Bolt Tightening Sequence ……………………………………………………………………………… 42 Liquid Level Test………………………………………………………………………………………… 43 Liquid Level Controls for Typical Vertical Channel Down Heater………………………………… 43 Liquid Level Controls for Typical Horizontal Heater……………………………………………… 45 Free Surface Area for Shell Liquid Level Control…………………………………………………… 49 Integral Flash Chamber………………………………………………………………………………… 52 Emergency By-pass to Prevent Water Damage……………………………………………………… 53 Recommended Schematic Piping Arrangement for Feedwater Heaters ………………………… 54
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Fig. No. 6b Fig. No. 7 Fig. No. 8 Fig. No. 9 Fig. No. 10 Fig. No. 11a Fig. No. 11b Fig. No. 12 Fig. No. 13 Fig. No. 14 Fig. No. 15 Fig. No. 16 Fig. No. 17 Fig. No. 18a Fig. No. 18b Fig. No. 19 Fig. No. 20 Fig. No. 21 Fig. No. 22 Fig. No. 23 Fig. No. 24 Fig. No. 25 Fig. No. 26 Fig. No. 27 Fig. No. 28 Fig. No. 29 Fig. No. 30 Fig. No. 31 Fig. No. 32 Fig. No. 33 Fig. No. 34 Fig. No. 35 Fig. No. 36 Fig. No. 37 Fig. No. 38 Fig. No. 39 Fig. No. 40 Fig. No. 41 Fig. No. 42
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CONTENTS (continued)
These standards provide practical information on nomenclature, dimensions, testing, and performance. Use of the standards will ensure a minimum of misunderstanding between Manufacturer and Purchaser, and will assist in the proper selection of equipment best suited to the requirements of the application. Some of the new material incorporated into the ninth edition of these standards include new information in Section 2.1, Heater Performance, revisions to Section 2.7, Tube Side Pressure Loss, new information in Section 3, Mechanical Design Standards, and new materials added to Section 4, Material Design Standards, just to name a few. In preparation of this standard, consideration has been given to the work of other organizations, such as the American Society of Mechanical Engineers, the American Society of Testing Materials, the former Feedwater Heater Manufacturers Association, the Tubular Exchanger Manufacturers Association, and others. Credit is herby given to all those whose standards may have been helpful in this work. The publication of the ninth edition of Standards for Closed Feedwater Heaters represents another step in the Heat Exchange Institute’s continuing program to provide standards which reflect the latest technological advancements in the field of heat exchange equipment. The Standards for Closed Feedwater Heaters are continually reviewed by the Technical Committee at scheduled meetings under the direction of the Closed Feedwater Heater Section. Suggestions for improvement of these standards are welcome and should be sent to the Heat Exchange Institute, Inc., 1300 Sumner Ave., Cleveland, Ohio, 44115, or via telephone at 216-241-7333, via fax at 216-241-0105, or email the HEI at
[email protected]. Additional information, such as tech sheets, member company profiles, membership information and a complete listing of all HEI Standards, can be found at www.heatexchange.org
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The ninth edition of these standards has been developed by the Closed Feedwater Heater Section of the Heat Exchange Institute, Inc. The technical information in these standards combines present industry standards, typical Purchaser requirements, and Manufacturer’s experience. In addition, the standards outline the important design criteria for closed feedwater heaters.
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FOREWORD
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ture difference and the lesser temperature difference to the Napierian Logarithm (Natural Log) of the ratio of the greater temperature difference to the lesser temperature difference.
A closed feedwater heater is defined as a shell and tube type unit which heats feedwater or condensate(1) passing through its tubes by means of steam or condensate on the shell side. Closed feedwater heaters are used in a regenerative steam cycle to improve the thermodynamic gain. This is accomplished by extracting steam at various points from the turbine and condensing it using boiler feedwater. The resultant heating of the feedwater aids in avoiding thermal shock to the boiler and reduces the fuel consumption required to convert the feedwater to steam. Since the work lost by extracting the steam is derived from sensible heat, i.e. no change of phase, the much greater latent heat recovered in the feedwater heater by changing phase from steam to water results in a net energy gain. Without a feedwater heater, the latent heat is wasted or thrown out in the main condenser or cooling tower. Therefore, feedwater heaters(1) also help to reduce thermal pollution.
1.8 Pressure Loss
The tube side pressure loss consists of the friction loss through the tubes, including channel losses and turning losses. The total shell side loss is the pressure loss through the zones of the heater. Neither side includes any static losses.
1.9 Heat Transfer Coefficient
The heat transfer coefficient for each zone of the heater is the average rate of heat transfer from steam to feedwater or from condensate to feedwater and is expressed in Btu/hr-ft2-°F.
1.10 Desuperheating Zone (DSH)
The desuperheating zone removes a portion of the sensible heat of the superheated extraction steam to elevate the temperature of the feedwater.
for the purposes of this standard, wherever feedwater is used, it shall also mean condensate passing through its tubes.
(1)
1.11 Condensing Zone
The condensing zone heats the feedwater by condensing steam.
1.12 Drain Subcooling Zone (DC)
1.2 Heater Duty
The drain subcooling zone reduces the temperature of the drains leaving the condensing zone below the saturation temperature by transferring heat to the entering feedwater.
Feedwater heater duty consists of the net heat transferred to the feedwater and is expressed in Btu/hr. The heat duty obtained from feedwater flow and enthalpy parameters shall be calculated for each applicable zone. The sum of individual zone heat duties shall be the overall “heater duty”.
1.13 Drains
Entering drains into a feedwater heater are defined as any liquids which enter the heater from higher pressure stages or sources and combine with the shell side condensate.
1.3 Design Maximum Working Pressure
Design maximum working pressure is the pressure of the tube and shell sides for which the vessel is structurally designed.
1.14 Total Surface
The total outside tube surface in the heater includes: (a) Effective tube surface (b) Tube surface within tubesheet (c) Flooded surface (d) Inactive surface
1.4 Operating Pressure
The shell side operating pressure is the pressure for which the unit is thermally designed and rated. The tube side operating pressure is the normal discharge pressure of either the steam generator feed or condensate pump.
1.15 Effective Surface
1.6 Drain Subcooler Approach (DCA)
1.16 Integral Flash Chamber
The drain subcooler approach is the temperature difference between the drains leaving the shell side of the heater and the entering feedwater on the tube side.
Integral flash chamber is a shell extension beyond the U-bends which provides an area for incoming drains to flash.
1.7 Logarithmic Mean Temperature Difference (LMTD)
Logarithmic mean temperature difference is the ratio of the difference between the greater tempera-
1
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Terminal temperature difference is the difference between saturation temperature corresponding to the entering extraction steam and the outlet feedwater temperature. This value could be either positive or negative.
The effective surface is that portion of the total surface excluding: (a) tube surface within the tubesheet (b) condensing zone surface which is flooded (c) surface not exposed to flowing steam and/or condensate on the shell side (d) tubes that are plugged
1.5 Terminal Temperature Difference (TTD)
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1.1 Closed Feedwater Heater
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1. DEFINITIONS
It is recognized that the performance of a feedwater heater cannot be exactly predicted under each one of a number of possible operating conditions; therefore, the heater should be designed for the one specific condition termed the “design point”. Heater design performance is stated as the capability to heat a given flow of feedwater in terms of TTD and DCA, if applicable, with the following parameters specified: (a) Feedwater inlet and outlet temperatures (b) Drains outlet temperature (c) Steam pressure and enthalpy (d) Feedwater pressure loss (e) Shell side pressure loss, if paragraph 2.6(c) applies The procedures of the ASME Performance Test Code for Feedwater Heaters-PTC 12.1, latest edition, may be followed in evaluating the performance capability of any closed extraction feedwater heater built to these Standards. Note that research has shown that although ASME PTC 12.1 calculations are a reasonable estimate for off-design performance, they are not accurate enough to be used for determination of “design point” performance compliance (including TTD, DCA, and pressure drop); as the cumulative effect of calculation approximations and instrumentation tolerances can vary the results considerably. Considerations shall be given for such in the performance evaluation of feedwater heaters.(2)
Steam Enthalpy– total______________ Btu/lbm Steam Temperature – saturated____________°F
Steam – other sources Source…_________________________________ Flow…____________________________lbm/hr Pressure…___________________________ psia Temperature – total…___________________°F Enthalpy– total…________________ Btu/lbm Drains – in Source…_________________________________ Flow…____________________________lbm/hr Temperature…_________________________°F Enthalpy…______________________ Btu/lbm Note: If there is more than one source for incoming drains, state conditions for each source separately. Drains – out State the downstream pressure to which the outgoing drains are being discharged…_______________________ psia Flow…____________________________lbm/hr Temperature…_________________________°F Enthalpy…______________________ Btu/lbm Drains Subcooler Approach Temperature…_________________________°F Pressure Loss Desuperheater –max. …________________ psi Drains Subcooler – max. …_____________ psi Design Pressure…______________________ psig Design Temperature…____________________°F Minimum Design Metal Temperature…_________________________°F
2.1.1 Minimum Data Required to be Supplied by the Purchaser (a) Item, heater or stage number Installation: (Horizontal, Vertical Channel Down, Vertical Channel Up) Arrangement: (single or multiple stream) Space limitations: (overall length or overall length plus withdrawal clearance)
(e) Overload and Abnormal Conditions State operating conditions other than design which will result in increased steam, drains or feedwater flow rates (See Paragraph 2.12). The following information should be provided: Mode of Operation…________________________ Feedwater Oper. Temp.– in…____________°F Feedwater Oper. Pressure…___________ psia Feedwater Flow Rate…_____________lbm/hr Extraction Steam Temp.…______________°F Extraction Steam Enthalpy…_____ Btu/lbm Extraction Steam Pressure…__________ psia Drains Flow– in…__________________lbm/hr Drains Enthalpy– in…____________ Btu/lbm
Pressure Loss for Overload Operating Point: Desuperheater– max. …______________ psi Drains Subcooler– max. …____________ psi Tube Side– max…___________________ psi (f) Maximum back pressure at shell safety valve outlet connection…_____________________ psig
2.2 Thermal Resistance
(c) Tube Material…____________________________
2.2.1 Tube Wall Resistance The tube wall metal resistance can be calculated
(d) Shell Side Steam Extraction Flow…_____________lbm/hr Steam Pressure________________________ psia Steam Temperature – total________________°F
for the selected tube material using the thermal conductivity from the reference data in Appendix C4 at the average tube wall temperature by the following formulae(1), which applies to plain tubes. 2
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(b) Tube Side Feedwater Flow…____________________lbm/hr Feedwater Terminal Temperature Difference…___________________________°F Feedwater Temperature – in…_____________°F Feedwater Enthalpy– in…__________ Btu/lbm Feedwater Temperature – out…____________°F Feedwater Enthalpy – out…_________ Btu/lbm Feedwater Velocity– maximum…__________ft/sec at___________°F Feedwater Pressure Loss – maximum…___________________________ psi Feedwater Connection Size…_______ ID inches Operating Pressure…___________________ psia Design Pressure…______________________ psig Design Temperature…____________________°F Minimum Design Metal Temperature…_________________________°F
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2.1 Heater Performance
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2. FEEDWATER HEATER PERFORMANCE
)
Feedwater Velocity – Tube Material Vt (ft/sec)
Stainless Steel, 70-30 Nickel Copper Copper Nickel (70-30, 80-20, 90-10) Low Alloy Steel Admiralty and Copper Carbon Steel
where:
d = Outside diameter of tube, in
k = Thermal conductivity, BTU-ft/hr-ft2-°F or (BTU/hr-ft-°F)
t = Tube wall thickness, in
10.0 9.0 9.0 8.5 8.0
The corresponding feedwater velocity at 60 °F can be determined from the following formula: v V60°F = Vt 3 60°F vt where: V60°F = feedwater velocity at 60 °F (ft/sec) Vt = Feedwater velocity at average temperature for design point operation (ft/sec) vt = Specific volume of saturated water at average temperature for design point operation (ft3/lbm) v60°F = specific volume for saturated water at 60 °F (ft3/lbm) Fig. No. 1 shows the relationship of the ratio of specific volumes vs. average operating temperature. When the feedwater velocity for the tube material selected is the maximum per Table I, the design feedwater velocity at 60 °F may be determined directly from Fig. No. 2.
hr 3 ft2 3 °F r w = –––––––––– Btu (1) Tubular Exchanger Manufacturers Association (2) ASME PTC 12.1
2.2.2 Fouling Resistance
It is recommended that a minimum fouling resistance of 0.0002 units be applied to the tube side surface and corrected to the outside effective surface. An additional fouling resistance of 0.0003 units should be applied for the outer tube surfaces in the desuperheating and drains subcooling zones. These minimum values are applicable to all materials.
2.3 Terminal Temperature Difference
It is recommended that heaters without desuperheating zones should not be designed for a Terminal Temperature Difference of less than 2 °F.
2.6 Shell Side Pressure Loss
2.5 Tube Side Velocity
2.7 Tube Side Pressure Loss
2.4 Drains Subcooling Zone Approach
The feedwater velocity through the tubes at average temperature (arithmetic average of the inlet and outlet temperatures) for design point operating conditions should not exceed the values contained in Table I.
Below is a method of determining the tube side pressure losses from and including the channel inlet and outlet nozzles (pressure losses are calculated for friction, nozzles, tube entrance, exit and turn). This method only considers U-tube configurations with tubes projected from the tubesheet (tubes expanded or fillet welded) and tubes welded to the tubesheet
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Performance of an integral subcooling zone is dependent upon many factors such as: heater orientation, feedwater temperature rise, drain cooling range, quantity of drains, and reheating of subcooled condensate. Since experience has determined that the closest approach (temperature of drains minus temperature of entering feedwater) that can be assured is 10 °F, it is recommended that heaters not be designed for less than that temperature approach. A separate drain subcooler should be used for those conditions where a closer approach is required.
For the design operating conditions, the pressure losses through the shell side of the heater should be limited as follows: (a) The overall pressure loss should not exceed 30 percent of the differential pressure between heater stages. (b) The pressure loss within any one zone should not exceed 5 psi. (c) Where line losses and static head are an appreciable portion of the pressure difference between heater stages, it may be necessary for the user to specify lower pressure losses than indicated in (a) and (b) above.
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(
( )
d ln –––– d-2t
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d rw = 24k –––– 3
TABLE I Maximum Tube Side Velocity
DP 5 T
()
w 1.396 3 1027 f C At
2
L d
where: f 5 0.0014 1 0.125 (RE) 2.32 wd RE 5 0.201389 µ At Nozzle Losses DP 5 NI
3.195 3 1029 3 C
DPNO 5
2.034 3 1029 3 C
( ) ( ) w AN
2
w AN
2
Tube Entrance, Exit and Turn Losses DPE 5
()
w 2.896 3 1029 Kt C At
2N
2
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Average Feedwater Operating Temperature (°F) FEEDWATER SPECIFIC VOLUME RATIOS
Fig. No. 1
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Inside Tubes
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with slightly rounded edges. There are numerous specifications providing wall tolerances for their respective tube specifications; therefore, this standard provides a method to determine the nominal ID for use in calculating the tube side pressure loss. The method is only applicable to clean smooth tubes with turbulent flow for the friction factor. Accurate data on friction factors for the different tube materials is not available due to the wide range of tube manufacturing practices. Therefore, the Purchaser must consider that the actual tube side pressure drop can vary from the calculated value. The tube side pressure loss calculation method shown below is a condensed method which is pro vided to give the user/consultant a method to check pressure losses in his evaluation of equipment he plans to purchase. It is to be understood that the final thermal and hydraulic calculations will be based upon the final calculated wall thicknesses. In addition, the Purchaser must consider that tubes with ferrules/ inserts or flow straighteners, etc., will have an effect on tube side pressure loss.
NOTE: CONSTANTS SHOWN INCLUDE A 5% SAFETY FACTOR.
Average Feedwater Operating Temperature (°F) DESIGN FEEDWATER VELOCITY AT 60 °F.
Fig. No. 2
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DESIGN FEEDWATER VELOCITY at 60 °F (Ft/Sec)
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C 5 Density correction factor at average operating temp. (See Fig. No. 3a) f 5 Friction factor AN 5 Feedwater nozzle area, in2 5 Note: For tapered nozzles use mean area. Kt 5 Loss correction factor for tube configuration (See Fig. No. 3b) N 5 Number of tube passes RE 5 Reynolds number µ 5Viscosity, cp
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Definitions DPT 5 Pressure loss through tubes, psi DPNI 5 Pressure loss through channel inlet nozzle, psi DPNO 5 Pressure loss through channel outlet nozzle, psi DPE 5 Tube entrance, exit and turn losses, psi w 5 Feedwater flow, lbm/hr L 5 Total length of tube travel, ft At 5 Flow area of tubes per pass, in2 d 5 Nominal inside diameter of tubes, in For minimum wall tube: nominal ID 5 nominal OD of tube 2 2 3 (quoted minimum wall thickness 1 1/2 wall tolerance) For average wall tube: nominal ID 5 nominal OD of tube 2 2 3 (quoted average wall thickness)
Density Correction Factor
Fig. No. 3a
Kt = 1.3
Projected Tube Expanded or Fillet Welded
Welded Tube with Slightly Rounded Edges
LOSS Correction Factor FOR TUBE CONFIGURATION
Fig. No. 3b
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Kt = 1.6
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Average Feedwater Operating Temperature (°F)
The diameter of straight condensing heaters, as well as two zone (integral drains subcooler) heaters, is greatly dependent on the location of steam nozzles and the resultant size of the steam distribution dome within the shell. The maximum velocity in the distribution dome at the maximum flow point along the longitudinal axis of the heater should be no greater than the steam inlet nozzle velocity given in Paragraph 2.8(d). The escape velocity into the dome as defined by the flow past the conical segment between the penetration point of the nozzle into the shell and the impingement plate should be no greater than the dome velocity; but, in no case is the distance between nozzle penetration point and impingement plate to be less than the inside nozzle diameter divided by 4. An impingement plate under the nozzle shall be provided and sized to prevent impingement of steam on the tube bundle assuming a minimum angle of diffusion of 45° from the point at which the nozzle penetrates the shell.
2.9.1 Single Nozzle Heaters
The steam nozzle should be located on the thermal centerline of the bundle. The thermal centerline is the point along the tube bundle where the steam flow (and duty) is distributed equally in both directions. This will provide 2-way flow from the nozzle as shown in Fig. No. 4 as well as resulting in a dome area equal to 1/2 the nozzle area and minimum shell diameter. For any other location, it may be necessary to increase the shell diameter.
G 4 Mass velocity, lbm/sec/ft2 (G not to exceed 250) r 4 Density of the mixture, lbm/ft3 (pounds per hour of mixture divided by ft3/hr of liquid plus ft3/hr of vapor at actual conditions) 2) Steam from Flash Tanks – G2 41,000 (150 ft/sec max. line r velocity) G 4 Mass velocity, lbm/sec/ft2 r 4 Density of vapor, lbm/ft3
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3) Liquid from Flash Tanks – 4 ft/sec at operating temperature (d) Steam Inlet Nozzle– 250 V= ft/sec (psia).09
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2.9 Steam Nozzle Location and Steam Distribution Dome
It is recommended that nozzle sizes based on the inside diameter be selected so that velocities listed below will not be exceeded at the design point operating condition. If a standard pipe reducer is utilized on external piping to the heater in order to meet the maximum velocities listed below, it is recommended that the reducer be located at least 10 times the larger diameter from the point of attachment to the closed feedwater heater. For feedwater inlet nozzles, a transition piece with a 7 degree included cone angle may be attached to, or be integral with, the inlet connection in lieu of utilizing the pipe reducer. Piping configurations not in compliance could result in undue wear, which is a situation the user must consider when designing the total system. These guidelines related to reducers and tapered nozzles, though recommended for replacement heaters, may not always be applied/considered due to space considerations. (a) Feedwater Nozzles – 10ft/sec at 60 °F (for Carbon Steel tubed heaters see Paragraph 3.6). (b) Condensate Drain Outlet Nozzles: Subcooled Drains – 4 ft/sec at operating temperature Saturated Drains – 1) Water level controlled in heater– 4 ft/sec at operating temperature 2) Water level not controlled in heater– 2 ft/sec at operating temperature (c) Drain Inlet Nozzles: 1) Flashing Liquid – G2 = 4,000 r
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2.8 Nozzle Sizes
Fig. No. 4
2.10 Drain Nozzle
The ideal location for nozzles located along the length of the heater shell is on the respective thermal center-line for the section of the bundle to which the nozzle provides steam. In practice this cannot always be achieved; therefore, it may be necessary to increase the shell diameter. However, in no case should the nozzles be located closer than the minimum dimension given in Fig. No. 5 in order to prevent undue restriction of the entrance area into the bundle. If nozzles are located closer, consideration should be given to offsetting the nozzles, thus staggering the impingement plates along the length of the heater.
The location of the drain outlet nozzle on a heater without a drains subcooler zone should be based on the criteria of 2-way flow into the nozzle. The flow centerline should be determined, taking into consideration the location and flow rate of drains entering the heater, as well as the uneven distribution of condensate draining off the tube bundle. If the drain nozzle is located at a point other than on the flow centerline, the drain area should be increased accordingly so that the maximum velocity at any point in the drain area does not exceed the velocity in the drain nozzle.
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2.9.2 Multi-Nozzle Heaters
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STEAM NOZZLE LOCATION – SINGLE INLET
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STEAM NOZZLE LOCATION – MULTIPLE INLETS
Fig. No. 5
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1 ZONE MULTIPLE NOZZLES
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A = DISTANCE NECESSARY FOR DOME AREA REQUIREMENT AS DEFINED IN 2.9
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MINIMUM DISTANCE BETWEEN MULTIPLE STEAM NOZZLES
2.11.1 General Control Considerations
Careful consideration must be given to the location of equalizer connections for level controllers and gage glasses to avoid false water levels. Because of the internal construction of feedwater heaters, changes should not be considered before contacting the Manufacturer. In horizontal heaters, equalizing connections must be located in or near a vertical plane where they will not be subject to any differences of pressure. Heaters with an integral drains subcooler must have the level controller equalizer connections located at or near the entrance to the zone. In vertical heaters, the level controller equalizer connections must straddle the level to be controlled. The amount of rise in level permitted is governed by the internal construction of the heater. The Manufacturer shall indicate on his drawings the maximum rise in condensate level that may be permitted without seriously affecting the performance of the heater. The Purchaser should be guided by this information when setting high water alarms. Each heater shall have its own independent level controller even though several heaters are operating in parallel. The level controller selected must be of a type that is capable of maintaining the level of condensate in the heater shell under steady load conditions within plus or minus limits on the level indicated by the Manufacturer. Separate equalizer connections should be considered for gage glasses, level controls, and water alarms. Independently connected controls and alarms assure the operation of at least one element in the event a line becomes plugged. When arrangements require a single set of equalizer connections, provisions should be made to assure that lines are free from sediment.
2.11.2 Capacitance Requirements for Vertical Heaters
10
T
K 3 P.B.
where: K 4 Proportionality constant compatible with the level controller. C 4 Required Capacitance, gal/in. This is the condensate volume per inch of depth, within the control band. T 4 Throughput, gal/min. This is the shell side flow leaving the heater. P.B. 4 Proportional Band Setting, percent. The smaller the band, the more accurate must be the level controller, but this increases the required volume within the heater. In determining water levels in a heater, certain dimensions must be maintained. The high and low water levels are normally two inches on either side of the normal water level. This provides the available volume for capacitance. If a desuperheating zone is supplied, the distance from the maximum water level to the exit of the zone must be at least twelve inches. Similarly, the low level should be maintained s everal inches above the drains subcooling zone inlet.
2.12 Overload and Abnormal Operating Modes
Where a heater, or bank of heaters, is operated at a level exceeding the design point, the flow rates may be increased to a level which will cause malfunction or damage to the operating units. Listed below are three of the many possibilities that can result in overload or abnormal conditions. (a) Doubling the condensate or feedwater flow causes approximately twice the steam to be extracted. (b) By-passing a heater or group of heaters causes the feedwater to enter the next higher stage at a colder temperature. This will result in g reatly increased extraction steam flow into the next higher stage operating heater or group of heaters. (c) Operation of the turbine generator at the overload limit will increase the shell and tube side flows. When such operation is anticipated, the effect on each individual heater must be considered and speci fied so that the internals can be properly designed. (See Paragraph 2.1.1 [e]). If design limits are exceeded, metal wastage and failure may occur within the feedwater heater. There are no correlations presently available that can adequately determine the relationship of wastage to length of time at overload or abnormal operating conditions. Refer to Appendix B5 for guidelines for heaters out of service.
2.13 Vent Off-Take Piping
Each feedwater heater continuous venting system should be individually piped to the condenser or deaerator as applicable. Manifolding or cascading of vents is not recommended. The vent off-take piping system should be adequately sized to remove the
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For proper operation of vertical feedwater heaters (specifically Channel Down designs) the water level must be accurately controlled. The level controller, which in turn operates the heater control valve, is activated by changes in the condensate reservoir within (or external to) the heater. The net control volume of condensate available within the heater will depend upon the specific type of heater design. For example, a two zone heater (condensing zone and drains subcooling zone) will have, for the same shell diameter, more condensate volume than a three zone heater (desuperheating zone added). The net volume available within the control range is determined by calculating the gross volume less the total volume of tubes within this volume. In order to avoid increasing the diameter of the heater to obtain required control volume, an external reservoir can be used. This is possible as the required volume per inch of level (see equation below) is only dependent upon the diameter of heater and not overall length. As the object in providing required heater volume and control systems is to ensure that the heater operates within the design control range, all factors involved in the total system must be compatible.
C=
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The following describes the relationship between the variables:
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2.11 Control of Feedwater Heaters
Under certain operating conditions, and with special design considerations incorporated into units, maximum oxygen levels may be guaranteed for closed deaerating feedwater heaters (drains leaving units). The maximum oxygen content in the drains leaving the heater will be a function of several variables and shall be determined in each case. The applicable parameters will be the oxygen content of extraction steam, the oxygen content in the drains introduced into the heater, and the operating conditions (i.e., temperature and pressure in the heat-
3. MECHANICAL DESIGN STANDARDS 3.2 Design Pressure
3.1 Code Requirements
The Purchaser shall specify the design pressures for both the shell and tube sides. In addition, if the shell side of the heater is subjected to vacuum under any conditions, the Purchaser shall so specify.
The design and construction of all feedwater heaters shall meet the requirements of the ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, including applicable addenda and case rulings. This Code is hereinafter referred to as the ASME Code. All units shall be stamped with the ASME Code Symbol. Variances brought about by other applicable codes shall be specified by the purchaser.
3.3 Design Temperature
The Purchaser shall specify the design temperatures on both the shell and tube sides. It is suggested that these design temperatures be established as follows: (a) Shell Side – Enter the Mollier Diagram at the normal operating steam temperature and pressure and follow a constant entropy line to the maximum operating pressure. Read the temperature at that point and round off to the next higher 10 °F. For a heater with a desuperheating zone, only the shell skirt need be designed for this temperature. The design temperature of the main shell barrel of such heater shall be at least equal to the saturation temperature at the design pressure. (b) Tube Side – The maximum design temperature shall be the saturated steam temperature corresponding to the shell side design pressure. Where a desuperheating zone is employed, the temperature of the straight lengths of tubes in the desuperheating zone shall be considered to be 35 °F higher than the saturated steam temperature corresponding to the shell side design pressure. The design temperature of tube sheet shall be as a minimum, same as tube side design temperature.
3.1.1 Corrosion Allowance Corrosion allowance will be provided in accordance with the table below: Pressure Part Thickness Corrosion Allowance up to .25" per paragraph UG-25 of the ASME Code over .25" 0.0 tubes 0.0 Any corrosion allowance in excess of the above alues shall be provided when specified by the v purchaser. No corrosion allowance need be considered for internal parts such as pass partition, desuperheating and draincooling shrouds, support plates and baffles, etc 11
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2.14 Oxygen Content in a Deaerating Heater
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er, as solubility of gas is directly proportional to the partial pressure of gas above the liquid – Henry’s law). The guaranteed oxygen content in drains leaving the heater, considering venting, shall be as agreed upon by Manufacturer and Purchaser. However, it is recommended that guaranteed oxygen content not be lower than 70 PPB. The measurement of the oxygen level shall be in accordance with the HEI Standard – “Method and Procedure for the Determination of Dissolved Oxygen.” As indicated above, in order to guarantee the oxygen content of drains leaving the heater, the following shall be specified by the Purchaser: (a) The oxygen content in the extraction steam. (b) The oxygen content of entering drains. (c) The oxygen content of steam from other sources. The Purchaser’s specified levels of oxygen entering the heater shall not be exceeded in order to maintain the Manufacturer’s guarantee of oxygen in the drains leaving the heater. Where specific data on oxygen levels cannot be provided, the specific levels shall be based on calculations by the dilution method. In order to maintain required oxygen level in a deaerating closed feedwater heater, special considerations should be given by the Manufacturer to the design of the internals and venting arrangement of the unit. The specific design shall be the responsi bility of the Manufacturer. The Purchaser should be aware that the magnitude of the vent system flow removed may be more than normally required for a non-deaerating heater.
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expected non-condensible flow. The off-take system should be routed in the most direct manner possible eliminating any loop seals that can trap condensate. The continuous vent off-take system should be insulated to minimize potential for condensate build-up. Shell side start-up vents should not be routed into the continuous vent off-take system unless the system has been designed for this service. They should be piped directly to the condenser or to atmosphere depending upon the pressure. Tube side start-up vents should not be routed into the continuous vent off-take or the shell side startup system unless those systems have been designed for this service. These vents can be piped to atmosphere except in those nuclear installations where radioa ctivity potential dictates directing these start-up fluids to the condenser or other specialized “off-gas” systems. Provisions should be made for venting a minimum of 0.5% of the steam entering the heater. See Fig. No. 42 in Paragraph B12.
3.4 Hydrostatic Test
TABLE III Maximum Temperature of Expanded Tube Joints Temp. Material °F
The test pressure shall be in accordance with the ASME Code, Section VIII, Division 1, paragraph UG‑99. The test temperature should be established as recommended by the ASME Code.
3.5 Nil Ductility Temperature
Arsenical Copper Admiralty Metal 90-10 Copper-Nickel 80-20 Copper-Nickel 70-30 Copper-Nickel (Annealed) 70-30 Copper-Nickel (Stress Relieved) 70-30 Nickel-Copper (Annealed) 70-30 Nickel-Copper (Stress Relieved) Carbon Steel Stainless Steel
It is recommended that all materials used for forged carbon steel channels and tube sheets of high pressure heaters be procured to the minimum requirement of Charpy “V” notch values of 15 foot-pounds average for 3 tests and 12 foot-pounds minimum for any one test, at a maximum test temperature of 40 °F.
3.6 Tubes
The useful life of a heater tube is normally affected by the conditions of service, such as: water chemistry, operating temperatures and fluid velocities, as well as the effects of short and long term shutdowns. These factors must be taken into consideration by the Purchaser when making a tube material selection. In the case of carbon steel tubed feedwater heaters, various combinations of nozzle and tube velocities and channel configurations, as well as factors listed above, can contribute to inlet metal wastage. ASME/ASTM do not have mandatory requirements for UT examination of tube weld seam on certain Feedwater Heater tube materials. HEI recommends all welded Feedwater Heater tubing be subject to UT examination at the mill, subject to customer request, in order to increase reliability and quality of the final product prior to installation in the vessel.
3.6.3 Tube Wall Thickness Limitations Average wall or minimum wall tubes are equally acceptable providing that, in the case of average wall tubes, the calculated thicknesses for pressure requirement takes into consideration the plus or minus toler ance in wall thickness. TABLE IV Design Minimum Tube Wall Thickness Copper and Copper Alloy Nickel Alloy Stainless Steel (U-Tubes) Stainless Steel (Straight Tubes) Carbon Steel Low Alloy Steel
3.6.1 Tube Metal Temperature
It is recommended that the maximum tube metal temperature shown in Table II not be exceeded. TABLE II Maximum Metal Temperatures for Tube Materials Temp. Material °F
0.049" avg. wall 0.049" avg. wall 0.035" avg. wall 0.028" avg. wall 0.050" avg. wall 0.050” avg. wall
For design purposes, tube wall thickness should not be less than those shown in Table IV. For U-Tubes, the minimum thickness per Table IV, is prior to bending.
3.6.4 Tube Length
400 450 600 700 700 800 900 800 800 800
Circumferential welding of tubes to extend their lengths is not recommended.
3.6.5 U-Tubes The minimum radius of U-bends should be 1-1/2 times the tube diameter. The following formula should be used to determine the required thickness of the tube wall before bending.
(
d P 3 d t4 3 11 2S 1.8P 4R
)
t 4 Tube wall thickness before bending, in d 4 Outside diameter of tube, in P 4 Design pressure, psig R 4 Radius of bend at centerline of tube, in S 4 Allowable design stress at the appropriate design temperature defined in Paragraph 3.3 (b), psi
3.6.2 Tube Joint Temperature
Where tubes are installed in steel tubesheets by expansion only, the recommended maximum temperature at the joint for which the tube materials shall be specified is tabulated in Table III. For this purpose, the temperature of the tube joint shall be considered to be the outlet temperature of the feed12
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Arsenical Copper Admiralty Metal 90-10 Copper-Nickel 80-20 Copper-Nickel 70-30 Copper-Nickel (Annealed) 70-30 Copper-Nickel (Stress Relieved) 70-30 Nickel-Copper (Annealed) 70-30 Nickel-Copper (Stress Relieved) Carbon Steel Stainless Steel
350 350 400 450 500 500 550 550 650 500
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water at the specified operating conditions. Welded tube joints should be used when temperatures range from the v alues in Table III up to the maximum metal temperatures given in Table II.
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(c) The Purchaser shall specify the minimum design metal temperature (°F) for both the shell and tube side as required by ASME Code, Section VIII, Division 1, paragraph UG-20.
3.6.7 Tube Plugging Tubes will occasionally fail when the assembled bundle is hydrostatically tested to Code pressure. Where the location is either inaccessible or impractical for replacement, the defective tube may be plugged by an acceptable permanent procedure and the Purchaser notified.
3.7 Tube Bundle All baffles and support plates in the tube bundle should be securely held in place by tie rods and spacers, or equivalent construction. The tube bundle shall be removable from the shell or the shell removable from the tube bundle. Straight tube/fixed tubesheet feedwater heater is exempted from the removable requirements.
3.7.1 Tube Layout It is recommended that tubes be laid out on a triangular pitch. Tubes shall have a minimum centerto-center spacing equal to the tube diameter plus 3/16 inch or 1.25 times the nominal tube OD, whichever is greater.
3.7.2 Baffles and Support Plates 3.7.2.1 Tube Holes Baffle holes and tube support plate holes shall be drilled 1/64 inch greater than nominal outside diameter of tubes, except that baffles in subcooling zones may have holes 1/32 inch greater than nominal OD of tubes. All burrs shall be removed to prevent damage to the tubes.
3.7.2.2 Spacing and Tube Vibration
3.7.2.3 Support of U-Bends
Any U-bend tubes wherein the diameter of the bend plus twice the length from the tangent point to the last support plate exceeds the values given in Paragraph 3.7.2.2 shall have provisions in the U-bend area for support of such tubes.
3.7.2.4 Thickness
The minimum thickness of support plates and baffles in the desuperheating and condensing zones shall be 3/8 inch for shell diameters of 18 inches and smaller and 5/8 inch for larger diameter shells. The minimum thickness of baffles in the subcooling zone of all heaters shall be 1/4 inch for spacing less than 18 inches, and 3/8 inch for spacings of 18 inches and greater.
3.7.2.5 Drain Subcooling Zone End Plate
The end plate of the drain subcooling zone in horizontal heaters should be designed to prevent leakage of steam from the condensing zone into the drain subcooling zone. Close tube to tube hole clearance and adequate end plate thickness is provided for this reason. To ensure that the latter is obtained, the end plate tube hole drilling, exclusive of over-tolerance, shall be the same as that used for the tubesheet as provided in Table V. In addition, the end plate thickness shall be not less than two inches.
3.7.2.6 Shrouds and Longitudinal Baffles
Shrouds and longitudinal baffles should have a minimum thickness of 1/4 inch.
3.7.2.7 Impingement Baffles
The tube bundles of feedwater heaters should be designed to avoid direct impingement of incoming shell side fluids on the tubes. A stainless steel impingement plate shall be placed in front of each shell inlet nozzle. Flow area not less than the nozzle area shall be provided between the nozzle and the impingement plate (See Paragraph 2.9). The flow passages for distribution of fluids into the tube bundle should be designed to minimize tube vibration.
3.8 Tubesheet
ASME Code, Section VIII, Division 1, Part UHX, provides specific rules for calculating the thickness of tubesheets for shell and tube heat exchangers for both bending and shear. Part UHX-12 specifically deals with rules for design of U-tube tubesheets. Refer to the appropriate section of ASME code, as the calculations are too extensive to be included in this Standard. ASME may not be the design code or the specific design may not be addressed by ASME. In these cases, the minimum tubesheet thickness calculations may be based on the following:
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The design of the spacing of tube supports is a complex problem which has been studied in great depth by the HEI. However, since tube vibration is affected by many factors, including but not limited to: (a) fluid entrance port geometry, (b) fluid exit port configuration, (c) the cross-flow and longitudinal flow components as influenced by the baffle configuration (e.g. segmental or other variations), it has not been possible to establish definitive criteria for calculation of support spans for all specific designs. It is recommended that the basic criteria should be the fluidelastic method described by H.J. Connors, Jr. (ASME, Dec. 1970 pp. 42-56). Also, in liquid to liquid zones such as integral or separate drain subcooling zones, vortex shedding criteria may be used as a secondary check. It is necessary for each Manufacturer to establish the necessary coefficients and factors by test, experience or analytical methods compatible with the individual design configuration. It should be recognized that due to the various derivations of methods and the number of different values used for variables as criteria for vibration analysis, results will vary and are not definitive.
As a minimum requirement, baffles and support plates shall be spaced so that the unsupported straight lengths of the tubes will be no greater than 48 inches for 5/8 inch OD tubes, 54 inches for 3/4 inch OD tubes, 57 inches for 7/8 inch OD tubes and 60 inches for 1 inch OD tubes. Each leg of all U-bends in the condensing zone shall be supported within 8 inches of the point of tangency. These maximum unsupported lengths are established for mechanical support of the tube bundle only.
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Cold work in forming U-bends may induce susceptibility to stress corrosion cracking in certain materials and environments. The Purchaser should specify if stress relief of the U-bends is required.
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3.6.6 Stress Relieving U-Bends
=
Wall Thickness/I.D. Ratio for Integral Tubesheets
F 5 Design factor. See Paragraph 3.8.1 for values of F 0.785 1 – Pitch tube O.D. h 0.907 1 – Pitch tube O.D.
(
)
for square or rotated square tube patterns
(
)
for triangular or rotated triangular tube patterns
2
2
Fig. No. 6b NOTE: If the tubesheet is integral with both the tube side and shell side, Wall Thickness and I.D. are to be based upon the side that would yield the s maller value of F.
3.8.1 Tubesheet Corner Radius
All Manufacturers have established corner radii that they have determined through experience are suitable for most applications. Integral tubesheets with larger corner radii than the Manufacturer’s standards are sometimes justified. The variables that affect this area of discontinuity stresses are too numerous to permit the use of an empirical relationship. It is suggested that a minimum radius be specified with the other data provided as recommended in Paragraph 2.1.1. Additionally, the expected operating conditions, including the number of expected cycles (such as number of cold starts, hot restarts, load trips, etc.), and the temperature and pressure ranges should be identified as well as the expected rate of change should be defined in the Purchaser’s specification. An evaluation of the expected operating history can then be made by the Manufacturer to determine if larger corner radii are justified for the specific conditions defined.
b) Shear TS 4
)( )
0.31 DL do 1– Pitch
(
P S
where: TS 5 Effective tubesheet thickness (in shear), in DL 5 4A 5 Equivalent diameter of the tube center limit perimeter, in C C 5 Perimeter of the tube layout measured stepwise in increments of one tube pitch from center-to-center of the outer most tubes, in. Fig. No. 6 shows the application to typical triangular and square tube patterns
3.8.2 Tube Hole Diameters and Tolerances(2)
TABLE V
Tube Hole Diameters and Tolerances for Tubesheets
Tubesheet Formula Perimeter Calculation
Fig. No. 6a
Tube Hole Diameter & Under Tolerance Over Tolerance Nominal Tube in–Standard Fit in–Close Fit in O.D. Nominal Under Nominal Under Standard Max. in Diameter Tolerance Diameter Tolerance
A P S
5 Total area enclosed by perimeter C, in2 5 Design pressure, psig 5 Code allowable stress in tension, psi, for tubesheet material at design metal temperature do 5 Outside tube diameter, in Pitch 5 Tube center-to-center spacing, in NOTE: Shear will not control when
(
do P , 1.6 1 – S Pitch
)
5/8 3/4 7/8 1
0.635 0.004 0.760 0.004 0.885 0.004 1.012 0.004
0.633 0.002 0.002 0.010 0.758 0.002 0.002 0.010 0.883 0.002 0.002 0.010 1.010 0.002 0.002 0.010
NOTES: 1) Special close fit tolerances are recommended for tubes subject to work hardening. (2) Tubular Exchanger Manufacturers Association
2
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Tube holes in tubesheets should be finished to the sizes and tolerances shown in Table V; 96% of the tube holes must not exceed the value for standard overtolerance. The tube holes shall be smooth, and burrs shall be removed to prevent damage to the tubes.
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For supported tubesheets (e.g. fixed tubesheets and floating type tubesheets) integral with either or both sides F shall be the value as determined by the curve H in Fig. No. 6b.
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a) Bending FG P Tb = 3 hS where: Tb = Thickness of tubesheet (in bending) measured at bottom of partition grooves, in G = Inside diameter of channel when tubesheet is integral with channel, in P = Design pressure, psig S = Code allowable stress in tension, psi, for tubesheet material at design metal temperature (1) Tubular Exchanger Manufacturers Association.
3.8.3 Ligament Widths and Tolerances
Table VI tabulates the widths for nominal ligament, minimum standard ligament and minimum permissible ligament for the tube pitches shown. 96% of the ligaments must be at least equal to the value for minimum standard ligament width and the remainder must be at least equal to the value for minimum permissible ligament width.
~
where: Y 5 Channel cover deflection at the center, i n G 5 Gasket load reaction diameter as defined by the Code, in E 5 Modulus of elasticity at design temperature, psi T 5 Thickness under consideration, in P 5 Design pressure, psi SB 5 Allowable bolting stress at design temperature, psi AB 5 Actual total cross-sectional root area of bolts, in2 hg 5 Radial distance from diameter G to bolt circle, in
TABLE VI
Tubesheet Drilling Tolerances
(3)
Nominal Nominal Tube O.D. in
5 ⁄ 8
Tube Nominal Minimum Standard Ligament Minimum Width, in Tube Hole Ligament Permissible Pitch Dia. Width Tubesheet Thickness, in Ligament in Std. Fit in 3 4 5 6 Width, in.
13 ⁄16 0.635 0.178 0.133 0.128 0.122 0.117 0.090 27⁄32 0.209 0.164 0.159 0.153 0.148 0.105 7⁄ 8 0.240 0.195 0.190 0.184 0.179 0.120
31⁄ 32 0.209 0.166 0.162 0.157 0.153 0.105 1 0.240 0.197 0.193 0.189 0.184 0.120 1 1⁄ 16 0.303 0.259 0.255 0.251 0.247 0.150 11⁄ 8 0.365 0.322 0.318 0.314 0.309 0.185 3 ⁄4
!
15 ⁄ 16 0.760 0.178 0.135 0.131 0.126 0.122 0.090
If the calculated deflection is greater than the recommended limit, the deflection may be reduced by acceptable methods such as: (a) Increase channel cover thickness by the cube root of the ratio of calculated deflection to the recommended limit. (b) Use of strong backs. (c) Change type of construction.
7⁄ 8 1 3 ⁄ 32 0.885 0.209 0.168 0.164 0.160 0.157 0.105 11⁄ 8 0.240 0.199 0.195 0.192 0.188 0.120 1 3 ⁄ 16 0.303 0.261 0.257 0.254 0.250 0.150 1 1⁄4 0.365 0.324 0.320 0.317 0.313 0.185 1 1 1⁄4 1.012 0.238 0.198 0.195 0.192 0.189 0.120 1 5 ⁄ 16 0.301 0.260 0.257 0.254 0.251 0.150 13⁄ 8 0.363 0.323 0.320 0.317 0.314 0.185
The above table of minimum standard ligaments is based on a ligament tolerance not exceeding the sum of twice the drill drift tolerance plus 0.030". Drill drift tolerance = 0.0016 x (thickness of tubesheet in tube diameters), in.
3.10 Heater Supports
NOTES: 1. Interpolate for intermediate tubesheet thicknesses. 2. For thicknesses over 6" the minimum standard ligament is calculated using procedure below Table VI. 3. For tubesheet thicknesses below 3" use values indicated for 3".
3.9 Channel Covers (a) With Partition Seal Covers When using the construction illustrated in Fig. No. 16, where the partition rib does not form a gasketed joint with the channel cover, the appropriate ASME Code formula shall be used to calculate the thickness of the channel cover. (b) Without Partition Seal Covers When using the construction illustrated in Fig. No. 17, the effective thickness of a flat channel cover shall be the thickness at the bottom of the pass partition groove (or the face if there is no groove) minus corrosion allowance in excess of groove depth. The thickness is to be at least
3.11 Condenser Installation
When a feedwater heater is designed for installation in the condenser exhaust neck, the fixed end closure seal plates that seal the heater to the condenser shall be shipped loose and welded in the field by the erectors after the heater is in place. Provision for differential expansion between the heater and the condenser neck should be provided by the condenser manufacturer. Provisions for attaching lagging or shrouding on feedwater heaters within the condenser neck should be furnished by the Manufacturer. (3,4) © by Tubular Exchanger Manufacturers Association
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Heater shall be supplied with two or more brackettype supports. These should be suitably proportioned to carry the flooded heater loadings. Projection of the supports on horizontally installed heaters shall be greater than the nozzle projections (if possible) to avoid interference with the pedestals or operating floor. The Manufacturer provides the magnitude of the static reactions at each support that the heater will impose on the building support structure in the flooded condition. This data is based on the heater weight only and shown on the Outline Drawing. The power plant designer must consider the effect of the piping system in addition to the static reactions. When these reactions at each support are combined at the heater support, the load transmitted to the building support structure can be significantly increased.
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that required by the appropriate Code formula and thicker if required to meet proper deflection criteria. The recommended limit for channel cover deflection is: 0.03" for nominal diameters through 24" 0.125% of nominal diameter (nominal diameter/800) for larger sizes A method for calculation of channel cover deflection is: (4) G 3 0.0435G P 1 0.5S A h Y 5 B B g ET3
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2) In no case shall the tube hole in the tubesheet minus the maximum O.D. of the tube be less than 0.002 inches.
Where welded joints (shells, channels, tube ends) are specified, construction details and procedures shall be determined by the Manufacturer. Due consideration must be given to design features, quality of materials and ease of maintenance where welded joints are used.
3.13 Connections-Nozzle Length
Nozzle projections for flanged and butt welded connections should be between 6 and 8 inches.
3.14 Nozzle Loads
The determination of acceptable nozzle loads is a complex problem involving the interaction of external forces and moments applied at the vessel wall. These loads are functions of the piping mechanical and thermal design. Frequently, the piping’s designer needs to know the allowable loads at the nozzle in order to determine the piping configuration and generate the
NOZZLE LOAD NOMENCLATURE
Fig. No. 7
PROCEDURE FOR CALCULATING NOZZLE EXTERNAL FORCES AND MOMENTS IN CYLINDRICAL VESSELS
3.14.1 Nomenclature
P ro Rm T Sy s Sa b g
5 Design Pressure, psig 5 Nozzle Outside Radius, in 5 Mean Radius of Shell, in 5 Shell Thickness, in 5 Yield Strength of Shell material At Design Temperature, psi** 5 Stress Due to Design Pressure, psi 5 Allowable Stress of Shell material At Design Temperature, psi** 5 Dimensionless Number 5 Dimensionless Number
3.14.2 External Forces and Moments
To calculate the maximum force and moment, first evaluate b and g. Then determine a, S and D from Fig. Nos. 8, 9 and 10 for the specified b and g, substitute into the equations below and calculate FRRF, MRCM, and MRLM. (5) Local Stresses in Spherical and Cylindrical Shells Due to External Loadings, K.R. Wichman, A.G. Hopper and J.L. Mershon – Welding Research Council. Bulletin 107/August, 1965 – Revised Printing – March, 1979.
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a 5 Dimensionless Number S 5 Dimensionless Number D 5 Dimensionless Number FRRF 5 Maximum Resultant Radial Force, lbf* MRCM 5 Maximum Resultant Circumferential Moment, in-lbf* MRLM 5 Maximum Resultant Longitudinal Moment, in-lbf* FRF 5 Maximum Resultant Force, lbf* MRM 5 Maximum Resultant Moment, in-lbf* *Use absolute values. **Per ASME Section VIII, Division 1 Code.
tures and floors. It should be understood by the user that the heaters are not intended to serve as anchor points for the piping.
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3.12 Welded Joint Construction
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actual loads. The procedure below permits estimating nozzle loads for cylindrical shells. The procedure is based in part on the design data included in Welding Research Council Bulletin 107(5). The allowable loads have been linearized to show the interaction between the maximum permitted external radial load and the maximum permitted applied moment vector. The procedure represents a simplification of the method of WRC 107 and users of the procedure included in this standard are cautioned that more exact analysis is required to verify the adequacy of final designs. The stresses considered in developing the procedure have been defined as secondary stresses with stress limits established according to that definition. Although the effect of internal pressure has been included in the combined stresses, the effect of pressure on nozzle thrust has not been included and requires combination with other radial loads. Loads exceeding those calculated by this method usually require additional reinforcement. The user is cautioned that the higher allowable loads obtained through design modification may require strengthening other parts; such as supports, supporting struc-
The arrangement of the extraction lines and supports of the feedwater heater are subject to the approval of Manufacturer (See Paragraph 2.9).
Calculate Pressure Stress
Rm T
(
Determine a, (, and D from Fig. Nos. 8, 9 and 10.
)
T 2P R 2 s = T m 2
(
Sy 2 s
)
(
Sy 2 s
=
Use s = 14,850 psi in the equations for calculating FRRF and MRLM. Calculate Allowable Forces and Moments R 2 FRRF = m a
R 2r S MRCM = m o y ( R 2r MRLM = m o D
)
14,850 psi , Sa = 20,000 psi
If s is greater than Sa, then use Sa as the stress due to design pressure: R 2 FRRF = m a
(
.75 2 (150) 37.5 2 2 .75
Calculate Pressure Stress (s).
(
)
2P T s = R 2 = 2 T m
)
)
Sy 2 s
(37.5)2 440
MRCM =
Plot the value of FRRF as FRF and the smaller of MRCM and MRLM as MRM. The allowable nozzle loads are bounded by the area FRF, 0, MRM.
(
(
31,600 2 14,850
FRF
0 MRM
Rm2 ro D
(
Determine Resultant Force and Moment
Sa = 20,000 psi
)
Sy 2 s
(
=
31,600 2 14,850
)
=
1,039,177 in-lbf
Plot the value of FRRF as FRF and the smaller of MRCM and MRLM as MRM. The allowable nozzle loads are bounded by the area of FRF, 0, and MRM.
3.14.3 Sample Problem
ro = 15 in
= 53,533 lbf
Rm2 ro Sy = (
(37.5)2 (15) 340
Sy = 31,600 psi @ 460°
)
(37.5)2 (15) (31,600) = 605,966 in-lbf 1,100 M = RLM
Rm = 37.5 in
=
FRF = 53,533 lbf
T = 0.75 in P = 150 psig
0
( )
15 = 0.875 = 0.35 37.5
MRM = 605,966 in-lbf
R 37.5 = 50 g = m = T 0.75
Therefore, a nozzle reaction of F 5 20,000 lbf and M 5 100,000 in-lbf would be allowable (point A) but a nozzle reaction of F 5 5,000 lbf and M 5 605,000* in-lbf would not be allowable (point B). ______
From Fig. No. 8, a = 440 From Fig. No. 9, ( = 1,100 From Fig. No. 10, D = 340
*Note: Use absolute values in the graph.
3.15 TOLERANCES
Standard tolerances for nozzle end preparations and nozzle support locations are indicated in Figure Nos. 11a and 11b. The average inside diameter of nozzle weld preparations may be measured after machining but prior to installation on the vessel.
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( ) ( )
r b = 0.875 o Rm
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g=
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( )
r b = 0.875 o Rm
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a
ALLOWABLE NOZZLE LOADS
Fig. No. 8
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b
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S
ALLOWABLE NOZZLE LOADS
Fig. No. 9
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b
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D
ALLOWABLE NOZZLE LOADS
Fig. No. 10
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b
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Fig. No. 11a
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Standard Tolerances for Nozzles and Support Locations - English Units
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Standard Tolerances for Nozzles and Support Locations - SI Units Fig. No. 11b
The materials used for pressure parts shall be in accordance with ASME material specifications, and the stress values used shall be those permitted by the ASME Code. The following materials are typical and are provided as a reference only. For information regarding material compatibility, refer to Paragraph B3.
4.2 Quality
All materials specified shall be considered the minimum qualities of their kind but specifications shall not exclude the use of any material of equal or superior quality.
4.3 Specifications
ASME SA-516 Alloy Steel ASME SA-204 ASME SA-387 Grade 2 Class 1; Grade 11 Class 1 or 2; Grade 12 Class 1 or 2 3) Forged Steel Carbon Steel ASME SA-181 ASME SA-105 ASME SA-266 Grade 1 to 4 ASME SA-350 Grade LF2 Alloy Steel ASME SA-182
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(d) Tubesheets (a) Shells and Shell Covers 1) Plate 1) Pipe Carbon Steel Carbon Steel ASME SA-285 Grade C ASME SA-106 ASME SA-515 ASME SA-53 Grade A or B (0.35 percent ASME SA-516 maximum carbon) Stainless Steel Alloy Steel ASME SA-240 ASME SA-335 Grade P1, P2, P11, P12 or P22 2) Forgings 2) Plate Carbon Steel Carbon Steel ASME SA-181 ASME SA-285 Grade C ASME SA-266 Grade 1-4 ASME SA-515 ASME SA-350 Grade LF2 ASME SA-516 Alloy Steel Alloy Steel ASME SA-182 ASME SA-204 ASME SA-336 ASME SA-387 Grade 2 Class 1; Stainless Steel Grade 11 Class 1 or 2; ASME SA-182 Grade 12 Class 1 or 2 (e) Tubes (b) Channels and Channel Covers Refer to paragraph 3.6 concerning tube 1) Plate material selection Carbon Steel ASME SA-285 Grade C 1) Carbon Steel ASME SA-515 ASME SA-214, UNS K01807 (Welded) ASME SA-516 ASME SA-557-A2, UNS K01807 (Welded) ASME SA-557-B2, UNS K03007 (Welded) 2) Forged Steel ASME SA-557-C2, UNS K03505 (Welded) Carbon Steel ASME SA-179 (SMLS) ASME SA-181 ASME SA-210 A-1, UNS K02701 (SMLS) ASME SA-105 ASME SA-210-C, UNS K03501 (SMLS) ASME SA-266 Grade 1–4 ASME SA-556-A2, UNS K01807 (SMLS) ASME SA-350 Grade LF2 ASME SA-556-B2, UNS K02707 (SMLS) 3) Pipe ASME SA-556-C2, UNS K03006 (SMLS) Carbon Steel 2) Copper and Cooper Alloys ASME SA-106 Arsenical Copper - DPA ASME SA-53 Grade A or B (0.35 percent ASME SB-395, UNS C14200 (SMLS) maximum carbon) Admiralty Metals - B/C/D (SMLS) (c) Shell and Channel Nozzles ASME SB-395, UNS C44300, C44400, 1) Pipe C44500 (SMLS) Carbon Steel 70-30 Copper-Nickel ASME SA-106 ASME SB-395, UNS C71500 (SMLS) ASME SA-53 Grade A or B (0.35 80-20 Copper-Nickel percent maximum carbon) ASME SB-395, UNS C71000 (SMLS) Alloy Steel 90-10 Copper Nickel ASME SA-335 Grade P1, P2, P11, P12 or P22 ASME SB-395, UNS C70600 (SMLS) 2) Plate 3) Low Alloys Carbon Steel ASME SA-213 T11, UNS K11597 (SMLS) ASME SA-285 Grade C ASME SA-213 T22, UNS K21590 (SMLS) ASME SA-515 23
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4.1 Materials
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4. MATERIAL DESIGN STANDARDS
It should be recognized that it is not always possible to meet all of the original features of arrangement, envelope size, or nozzle locations due to improvements in the state of the art and changes in specification requirements. Terminal points and overall dimensions may be affected by internal design changes necessitated by, for example, tube material changes. Therefore, the Purchaser should review structural and piping drawings of the area near and around the heater showing adjacent equipment. It is also recommended that evaluation parameters be given for relocation of each nozzle; for example, state the order of importance of meeting certain nozzle locations. Continuous vent piping will likely require revisions since the state of the art has advanced. Many plant design parameters are established based on the original equipment design and it is recommended that the outline drawing of the heater be included. If available, any additional information concerning structural and piping, such as forces and moments, should be included. When retubing heaters, experienced Manufacturers and designers can analyze and recommend any required design changes. However, before considering retubing rather than replacement, the condition of pressure bearing components should be evaluated closely. For replacement heaters, the maximum tube side pressure loss should be given along with the method or penalty of evaluation. Where the restrictive or available heater size is given, the tube side pressure loss can be controlling.
Experienced personnel knowledgeable in past and present industry practice including metallurgy, fabrication, design and all phases of heater operation should be consulted when the replacement of feedwater heaters or tube bundles is being considered. Information required when specifying replacement equipment should include the entire original heat bal-ance, the actual operating conditions, and any abnormal and/or overload conditions that may affect the redesign and selection of the replacement equipment. Additional data should include tube material of all the heaters and condenser and any pertinent information concerning water chemistry and feedwater treatment. Replacement tube material should be compatible with existing system materials. When specifying, the Purchaser should identify all the causes and types of failures, so that problems inherent in the original equipment or system can be avoided. Many failures, such as corrosion, drain cooler inlet erosion, and leaking welded tube joints can be strictly equipment related or the result of system or operational malfunctions. A change in tube material, in addition to affecting surface area and/ or performance, may require changes in baffling, desuperheating zone, and drain cooler zone to avoid recurrence of original problems. Therefore, it is recommended that the Purchaser consult with experienced Manufacturers and designers on current needs when developing specifications for replacements. 24
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5.1 Replacement of Heaters/Bundles
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5. DESIGN AND SPECIFICATION OF REPLACEMENT HEATERS/BUNDLES
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Carbon Steel ASME SA-285 Grade C ASME SA-515 ASME SA-516 (g) Bolting 1) Stud and Stud Bolts ASME SA-193 Grade B7, SA-320 Grade L7. Threads to be in accordance with ANSI B1.1 for high strength bolting. Sizes 1 inch and smaller shall be threaded in accordance with the coarse thread series, and 1-1/8 inch and larger in diameter with the 8-pitch-thread series. 2) Nuts ASME SA-194 Grade 2H, Grade 7. Threads shall be in accordance with those on studs, as noted above. (h) Gaskets The choice of a suitable gasket material depends on the design of the closure, and therefore, the selection shall be in accordance with the standards of the heater Manufacturer or as specified by the Purchaser. (i) Baffles and Support Plates 1) Plate Commercial Quality Steel (j) Tie Rods and Spacers 1) Commercial Quality Steel
4) Nickel Alloys 70-30 Nickel-Copper ASME SB-163, UNS N04400 (SMLS) 5) Stainless Steel - Austenitic ASME SA-688 TP304, TP304L, TP304N (UNS S30400, S30403, S30451 (Welded)) ASME SA-688 TP316, TP316L (UNS S31600, S31603 (Welded)) ASME SA-249 TP316N, UNS S31651 (Welded) ASME SB-676, UNS N08367 (Welded) ASME SA-213 TP304, TP304L, TP304N, TP316, TP316L (UNS S30400, S30403, S30451, S31600, S31603 (SMLS)) 6) Stainless Steel - Ferritic ASME SA-803 TP439, UNS S43035 29Cr-4Mo ASME SA-268, UNS S44735 (Welded) (f) Flanges 1) Forged Flanges Carbon Steel ASME SA-181 ASME SA-105 ASME SA-350 Grade LF2 Alloy Steel ASME SA-182 2) Plate Flanges
(e) Back pressure at the valve outlet connection shall be considered zero psi unless otherwise specified (See Paragraph 2.1.1 [f]).
Because of the variety of protective measures and devices in common use, compliance with the provisions of the ASME Code for protection of closed feedwater heaters against over-pressure is the responsibility of the Purchaser.
6.2 Flashback Protection
Certain design features may be required in the feedwater heater to restrict the stored volume of the contained liquid and to confine flashed vapor. Details of the flashback protection provisions shall be incorporated in the initial inquiry by the Purchaser. The Manufacturer can provide the following information to assist in the Purchaser’s evaluation of turbine overspeed during load rejections. (a) Steam volume (b) Condensate volume at the normal operating level (not including drain volume in drain cooling zone). (c) Drain volume in drain cooling zone. (d) Flow area at entrance to drain cooler. (e) Flow area through flashback system. This area will be the total flow area through flashback baffle as well as clearance areas between drains cooling zone and shell I.D. Maximum flow areas should be furnished by the turbine manufacturer; however, the design of the heater will not be compromised to meet this requirement.
6.1.1 Tube Side Relief Valves
The tube side of the heaters shall be protected against over-pressure from water expansion when the water inlet and outlet valves are closed. A minimum 3/4" connection for installation of a relief valve shall be provided between the water inlet and outlet valves.
6.1.2 Shell Side Relief Valves
6.3 Cleanliness and Corrosion Protection
Internal surfaces of all heaters shall be cleaned as necessary to remove loose scale. Dirt, weld-rod stubs, and other foreign objects shall be removed prior to final assembly of heater parts. Excess oil and grease shall be removed by wiping. Liquids used for hydro-testing or cleaning shall be drained from the heaters. All nozzles and openings shall be covered to guard against damage and the entrance of foreign objects during shipment. When heaters are tubed with carbon steel, water used for hydrostatic testing should be treated with a suitable rust-inhibiting agent. Prior to shipment, the heaters shall be drained and all openings sealed in accordance with the Manufacturer’s commercial procedure. Due to the complex internal design features of a feedwater heater, it is not practical to completely eliminate all moisture from the heater. Heaters should be thoroughly drained by tilting and maneuvering as required to ensure that all pockets are cleared. It is recommended that carbon steel tubed heaters be heated and evacuated to remove additional trapped moisture and that the heater be purged and blanketed to a positive pressure with an inert atmosphere, such as nitrogen, immediately after evacuation. Some means to monitor the pressure during shipment and storage should be provided by the Manufacturer. The Purchaser should monitor the pressure immediately after receipt and on a weekly basis thereafter to insure that the inert blanket is maintained continuously. The above procedure will eliminate the excessive moisture that could be detrimental to the tubing material. The user should inspect and record the condition of all covers and seals upon receipt of the heater at the job site. Any damaged or defective seals must be reported immediately to the Manufacturer. 25
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When the shell design pressure is less than the tube design pressure, a connection for a relief valve shall be provided to protect the shell from over-pressure in case of tube or tubesheet failure. The design temperature and pressure of the valve should be equal to the design temperature and pressure of the shell. When no valves are present in the extraction line and there are no means of isolating the heater shell from the turbine, the user should be certain that the control arrangements (high level alarms, emergency dump systems, etc.) are such that corrective steps can be taken before condensate (from tube rupture) reaches the turbine. Although the shell side relief valve is normally exposed only to steam during normal operation of the heater when not relieving, it may be required to pass water (possibly flashing) when relieving, as the shell will fill with water. Hence the valve should be sized for liquid service. It is suggested that this relief valve be sized to pass the larger of the following flows at 10 percent accumulation: (a) Minimum of 10 percent of the maximum overload feedwater flow specified through the heater based on water at Tv (See Paragraph 2.1.1[e]). (b) Flow based on the clean rupture of one heater tube resulting in two (2) open ends discharging as orifices. Flow shall be determined for orifices of a diameter equal to the nominal inside diameter of the tubes using an orifice coefficient of 0.9, a pressure differential across the orifice equal to the difference between the tube and shell design pressures, and water at Tv. Q = 54 d2 √ Pt 2 Ps Where Q = Flow of water, gal/min at 70 °F d = Nominal inside diameter of tubes, in Pt = Tube side design pressure, psig Ps = Shell side design pressure, psig Tv = The temperature to be used for valve selection is the average tube side temperature at the normal operating conditions, °F. (c) In no event shall the value of Q be greater than the specified maximum overload feedwater flow. (d) The valve manufacturer shall be responsible for the selection of the valve based on data supplied by the heater Manufacturer and/or the user.
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6.1 Safety Requirements
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6. FEEDWATER HEATER PROTECTION
7. INSTALLATIONS plant designer consult this Standard for guidance in the selection. The standard arrangements available are depicted in Fig. No. 12 thru 15 below.
The type of installation selected must consider, as a minimum, space allocation, piping arrangements, access for maintenance and repair, and operational considerations. It is recommended that the power
HORIZONTAL INSTALLATION
Fig. No. 12
HORIZONTAL IN CONDENSER NECK INSTALLATION Fig. No. 13
Fig. No. 14
VERTICAL CHANNEL DOWN INSTALLATION 26
Fig. No. 15
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VERTICAL CHANNEL UP INSTALLATION
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All high and low points on shell and tube spaces of a heater, not otherwise vented or drained by nozzles, shall be provided with connections for vents and drains. See Fig. No. 42 Paragraph B11 and Paragraph 2.13.
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6.4 Venting and Draining
After seals are broken and covers removed to permit installation and attachment of piping, the user should protect the heater internals against corrosion and contamination and periodically inspect the heater, prior to operation and during shut-down periods, for corrosion damage. Appendix A should be consulted for additional information.
b) Without Partition Seal Covers The pass partition design shown in Fig. No. 17 is more prone to interpass leakage due to deflection of the channel cover. However, when used, this design is recommended for channel diameters less than 40 inches.
For maintenance purposes, full diameter access channels are more desirable than limited access channels; however, the full diameter access channels are generally more costly than the limited access channels. The common types of channels are discussed below:
8.1.2 High Pressure, Full Access
8.1.1 Low Pressure, Full Access
Fig. No. 18a shows a full access channel where the hydraulic load is transmitted to the channel barrel by means of shear members, not by bolts in tension. The final closing joint (water-tight seal) may be either welded or mechanically sealed. Fig. No. 18b illustrates a full access channel where the hydraulic force against the cover is taken by bolts in tension. Sealing is accomplished by either a gasket or a seal-welded diaphragm. These types of channels provide considerably larger access openings, but at very large diameters and high pressures the availability of the large forgings becomes a problem. The need for special cover handling equipment should be considered. The cost will generally be more than that of manway access channels.
Full diameter, bolted and gasketed channels as shown in Fig. Nos. 16 and 17 are recommended for low pressure heater designs where the channel diameters are less than 48 inches. a) With Partition Seal Covers The pass partition cover design shown in Fig. No. 16 is the welded type; if desired, the pass partition cover may be bolted and gasketed.
WELDED TYPE PASS PARTITION COVER DESIGN
Fig. No. 16 HIGH PRESSURE, FULL ACCESS CHANNEL
Fig. No. 18a
HIGH PRESSURE, FULL ACCESS CHANNEL
Fig. No. 18b
Fig. No. 17 27
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GASKETED CHANNEL COVER PASS PARTITION DESIGN
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8.1 Full Diameter Access Channels
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8. CHANNEL TYPES
When the user has decided upon a manway access channel, the following should be considered:
8.2.1.1 Minimum Manway Sizes
The minimum acceptable manway sizes are 12" x16" elliptical and 16" circular.
8.2.1.2 Pass Partition Cover Design and Type
Pass partition cover design must be such that it does not restrict channel entry through the access opening. A design with a pass partition cover which is parallel with the tubesheet face may require a larger manway opening in order to gain access. This entry restriction can be eliminated by sloping the pass partition cover. The end of the cover adjacent to the center of the tubesheet should be approximately four (4) inches from the tubesheet face; however, this distance will vary because of hydraulic and maintenance considerations required for the design of the pass par-
TYPICAL FULL ACCESS BOLTED PASS PARTITION COVER
Fig. No. 19
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28
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8.2.1 Minimum Access Manway Sizes
tition section that is perpendicular to the tubesheet face. Pass partition covers are to be designed for the maximum expected differential pressure. Pass partition covers should be sectioned as required to remove them through the manway, rather than having personnel being restricted by the covers lying in the bottom of the channel. Should welded pass partition covers be used, they should not be thermally cut closer than 1/2" to the pressure boundary. The pass partition cover type is an option for the Purchaser to consider. Welded covers provide a more positive seal but require thermal cutting for access. Bolted and gasketed covers are more readily removable but are more susceptible to interpass leakage. Shown in Fig. No. 19 is a typical full access bolted and gasketed pass partition cover design. It is important that fasteners be locked in place in order to avoid having stray fasteners introduced into the condensate/feedwater system. Recommended weight of removable sections should not exceed 50 pounds for ease of handling.
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8.2 Manway Access Channels
Option A
Option B
HEMISPHERICAL HEAD CHANNEL DESIGN - LP
Option C
ELLIPTICAL HEAD CHANNEL DESIGN-LP
Fig. No. 20
Fig. No. 21
The manway sealing joint would be one of the configurations shown above Fig. Nos. 20 and 21. One configuration (Option A) has a seal welded diaphragm which provides all welded construction when required. The other optional configurations have gasketed joints with one being externally gasketed and the other having an internal gasket which is called a “pressure sealing type” design.
29
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Fig. No. 20 shows a channel design using a hemispherical head which may present difficulties in fitting nozzles and manway around the hemisphere’s periphery. This design generally has a greater access restriction. Due to the nozzle centerlines being approximately 30° off the vertical plane, 30° elbows are generally required in the piping if vertical runs are required. Fig. No. 21 shows channel design using an elliptical head which provides greater access and does not have the nozzle configuration complications of the hemispherical head.
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heater designs could be one of the two (2) designs shown below:
Manway access channels used for low pressure
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8.2.2 Low Pressure, Manway Access
Option A
HEMISPHERICAL HEAD CHANNEL DESIGN-HP
Option B
COMBINATION TUBESHEET CHANNEL TYPE DESIGN-HP
Fig. No. 22
Fig. No. 23
Option C
MODIFIED HEMISPHERICAL HEAD DESIGN-HP
Fig. No. 24
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The manway sealing joint would be one of the c onfigurations shown above Fig. Nos. 22, 23, and 24. One configuration (Option A) has a seal welded dia phragm which provides all welded construction when required. The other optional configurations have gasketed joints with one being externally gasketed and the other having an internal gasket which is called a “pressure sealing type” design. The pressure sealing type is used when bolting may be too large for the externally gasketed joint.
Fig. No. 22 shows a channel design using a hemispherical head which may present difficulties in fitting nozzles and manway around the hemisphere’s periphery. This design generally has a greater access restriction. Due to the nozzle centerline being approximately 30° off the vertical plane, 30° elbows are generally required in the piping if vertical runs are required. Fig. Nos. 23 and 24 show channel designs which do not have the nozzle configuration complications of the hemispherical head.
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heater designs could be one of the three (3) designs shown below:
Manway access channels used for high pressure
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8.2.3 High Pressure, Manway Access
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Fig. No. 25
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STRAIGHT CONDENSING FEEDWATER HEATER HORIZONTAL MOUNTING
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9. TYPICAL FEEDWATER HEATER INTERNAL ARRANGEMENTS
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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32
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Fig. No. 26
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2-ZONE FEEDWATER HEATER (Condensing and Subcooling Zones) HORIZONTAL MOUNTING
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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33
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Fig. No. 27
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2-ZONE FEEDWATER HEATER (Desuperheating and Condensing Zones) HORIZONTAL MOUNTING
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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Fig. No. 28
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3-ZONE FEEDWATER HEATER (Desuperheating, Condensing and Subcooling Zones) HORIZONTAL MOUNTING
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STRAIGHT CONDENSING FEEDWATER HEATER Vertical Channel Down Mounting
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Fig. No. 29
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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2-ZONE FEEDWATER HEATER (Condensing and Subcooling Zones) Vertical Channel Down Mounting
36
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Fig. No. 30
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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3-ZONE FEEDWATER HEATER (Desuperheating, Condensing and Subcooling Zones) Vertical Channel Down Mounting
37
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Fig. No. 31
SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
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SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
Fig. No. 32
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STRAIGHT CONDENSING FEEDWATER HEATER Vertical Channel Up Mounting
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SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
Fig. No. 33
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2-ZONE FEEDWATER HEATER (Condensing and Subcooling Zones) Vertical Channel Up Mounting
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SEE FIG. No. 16 THRU 18 AND 20 THRU 24 FOR TYPICAL CHANNEL CONFIGURATIONS
Fig. No. 34
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3-ZONE FEEDWATER HEATER (Desuperheating, Condensing and subcooling Zones) Vertical Channel Up Mounting
A1 INSTALLATION OF CLOSED FEEDWATER HEATERS A1.1 General Considerations
A1.4 High Level Condensate Dump
Feedwater heaters should be installed with sufficient clearance to allow convenient and proper maintenance of the units without disturbing adjacent equipment. Installation should be made so that cranes and hoists installed in the plant can be used to service the heaters. Ample space should be provided for the removal of covers, shells, or bundles and for the retightening of all bolted joints. Similarly, for heaters with welded joints, space should be provided to permit disassembly and rewelding of all joints. For heaters to operate properly, they must be correctly oriented. Horizontal heaters should be installed level and vertical heaters should be installed plumb. For condenser neck mounted heaters, shell protective stainless steel lagging and condenser neck closure plate, when required, are shipped loose for field attachment.
If a high level condensate dump connection has been provided, also referred to as a “drains subcooling zone by-pass” or an “emergency dump”, this should be routed directly to the condenser.
A1.5 Accessories
A1.2 Installation Under Freezing Conditions
In order to avoid damage from freezing, the user must prevent water from remaining in a heater exposed to freezing conditions after a plant is shut down. The user should also provide and maintain proper protection from freezing of the equipment before, during and after installation. It has been demonstrated that tubes in horizontal positions will not drain sufficiently by gravity alone to preclude freezing damage.
A1.3 Pre-Operational Cleaning and Flushing Operation
The pre-operational cleaning and flushing operation must consist of chemicals and water that are not detrimental to the equipment (tubing in particular). It is recommended that the Purchaser’s metallurgist be consulted for specific cleaning procedures or the Purchaser should engage a chemical company which can provide them with this service. Under no circumstances should the heater be laid up using the flushing or cleaning solutions.
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Accessories required by the Purchaser can be provided by the Manufacturer. The normal practice is to have the Manufacturer provide shell side safety valves, tube side thermal relief valves, and operating air vent orifice plates (when external orifice plates are required) with the remaining accessories provided by the Purchaser. Prior to purchase and operation, the Purchaser should consider the following accessories, which are required for proper operation and testing of a feedwater heater: (1) Gage glass with a sight range equal to or exceeding the maximum liquid level range. (2) Diaphragm control valve and level controller for maintaining the liquid level within the heater. (3) High and low level alarms to alert the operator of any abnormal levels within the heater. (4) Pressure measuring equipment should be provided for the following: a. Feedwater inlet and outlet connections. b. Steam inlet connection. c. Drains outlet connection. d. Shell. (5) Temperature measuring equipment should be provided for the following: a. Feedwater inlet and outlet connection. b. Steam inlet connection. c. Drains outlet connection. d. Shell vapor. e. Shell condensate.
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GUIDELINES FOR INSTALLATION, OPERATION, AND MAINTENANCE OF FEEDWATER HEATERS
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APPENDIX A
Method of Tightening Bolted Joint. (1) Tighten all bolts hand tight. (2) Tighten bolts, one flat at a time in pattern shown. (3) Continue until joint is tight.
BOLT TIGHTENING SEQUENCE
Fig. No. 35 all major bolted connections on the shell and heads so that these joints can be checked and tightened as noted in Fig. No. 35. Retightening of bolts and periodic verification of bolt torque should only be done when the vessel is not pressurized. Refer to the Manufacturer’s instruction manual for additional precautions and specific operating procedures. (Refer to Paragraph A3.4 concerning safety precautions).
A2.2 Liquid Level Control
The control of the liquid level is important to the proper operation of the heater. The liquid level is used to provide a water seal between the condensing zone and the entrance to the integral drains subcooling zone or the heater drain connection. This serves the same purpose as a steam trap and will isolate one extraction point from another. The primary purpose of the condensate seal is to promote single phase condensate flow through the drains subcooling zone. 42
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Improper liquid levels may result in the loss of the water seal allowing steam to flow directly into the drain piping or through the entrance to the drains subcooling zone. Steam flow into a drains subcooling zone reduces its effectiveness for subcooling and can lead to erosion and/or vibration. In horizontal heaters with a drains subcooling zone, the loss of the water seal may eliminate essentially all of the subcooling. This two-phase flow through the subcooling zone can result from steam by-pass leaking through the end plate of a horizontal subcooling zone and/or flashing of the incoming drains entering the integral subcooling zone. Liquid level standpipes and their associated gage glasses sense the level through static taps. In both vertical and horizontal heaters, the steam flow velocity past the higher connection may be different from the velocity at the liquid surface. In the absence of shock or friction losses, the pressure of the stream having the lesser velocity will be greater as a result of Bernoulli or momentum exchange effects. More common is steam flow into the vapor equalizing line of the standpipe. Condensation in the vapor equalizing line results in a lower pressure above the float than inside the heater leading to a higher level in the float cage. These effects result in measuring higher levels than actually exist inside the heater. This leads, in some cases, to loss of the necessary submergence on the entrance to the subcooling zone, resulting in flashing. Although the required liquid level location can be accurately marked, measurement of the actual liquid level can be difficult. In heaters with drains subcooling zones, the proper location can be obtained by the liquid level test stated below. Steam flow paths in heaters are complex and the effect upon liquid levels of flow maldistribution cannot always be evaluated. When liquid level connections can not be located in areas of low steam velocities, the proper level location must be established by test. Momentum effects will generally affect the measured level if one of the control connections is located near a steam or drains inlet. When tubes in drains subcooling zones near the zone entrance fail prematurely or when drain subcooling zones fail to properly subcool, false liquid levels are usually the cause of the difficulty and the level should be raised. In the case of a horizontal heater with an integral drain cooler having a siphon-type inlet (as opposed to a full-length, submerged drain cooler), consideration should be given to performing a test to establish a true level at the subcooler inlet. This would avoid (a) severe erosion due to steam entering the drain cooling zone due to an excessively low level, or (b) a less dangerous, but expensive scenario where a loss of performance occurs due to an excessively high level in the heater. In this test the drain cooler approach is measured at a series of liquid levels, as illustrated in Fig. No. 36, beginning with a relatively high level, and incrementally dropping the level until the “knee” in the curve is reached. At this point the level is low enough that the seal at the inlet to the drain cooling zone is broken and the steam enters or condensate flashes, creating a two-phase mixture.
It is important that all bolted joints be tightened uniformly and in a diametrically staggered pattern as illustrated in Fig. No. 35, except for special closures or spiral wound gasketed closures, when the instructions of the Manufacturer should be followed. The bolts should be retightened shortly after the heater has been put in service for the first time. Operational factors, including thermal cycling, pressure surges/spikes, etc., can lead to loosening of bolted joints. Periodic checks should be made during the first six months of operation and routinely thereafter to insure that all bolted joints remain tight. It is recommended that removable insulation be used at
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A2.1 Initial Start-Up Precautions
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A2 CLOSED FEEDWATER HEATER OPERATION
The subcooling zone arrangement and level control settings for a typical channel down heater are covered in Fig. No. 37. The vertical channel down feedwater heater arrangement is more forgiving with respect to mechanical damage to the tubes and baffles of the subcooling zone caused by a low shell liquid level, than with a horizontal heater with a full pass “short” drain cooler. Inadequate subcooling performance in either case results in the drains out flow being close to or at the saturated condition.
LIQUID LEVEL TEST
Fig. No. 36 To avoid premature tube failures, a level test should be conducted as soon as possible, preferably within the first month of operation. The level test should monitor the Drain Cooler Approach (DCA) temperature difference against the elevation of the liquid level
Note: All numbers shown are for example only. Individual heater designs and levels vary.
Fig. No. 37 43
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LIQUID LEVEL CONTROLS FOR TYPICAL VERTICAL CHANNEL DOWN HEATER
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A2.3 Liquid Level Control in Vertical Channel Down Heaters
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measured either from the bottom of the shell or from the heater shell centerline. When the operating level at the design load results in a DCA approaching the design DCA, the level should be set, as a minimum, 2" above that test elevation but should not be set lower than the Manufacturer’s original level marker. This set point for the Normal Liquid Level should be marked on the level indicator as well as on any level plate provided on a shell mounting bracket, if available. Parallel heaters may operate at slightly different pressures as a result of differing steam piping, fouling, or maldistribution of feedwater flow between the heaters. Individual liquid level controls and gage glasses are required to provide proper level locations under operating conditions that will differ between parallel operated heaters.
A2.6 Effect of Load Rejection on Shell Liquid Level
Shell liquid levels are affected by rapid increases or rejection of unit load. Both cases, in their own way, can cause a sharp rise in shell liquid level and an adequate margin between the normal and alarm or dump levels must be allowed. Traditionally, the normal and alarm levels have been set too close. This does not permit reasonable load swings, without alarm, or allow adequate range of level adjustment to obtain the specified drains approach temperature. Also, on a sudden, high rate of load reduction, vapor is generated in the condensate in the shell, as the saturation temperature drops below the actual condensate temperature. A small amount of vapor, due to its much greater specific volume, sharply increases the overall volume of the condensate/vapor mix in the shell until the turbine extraction pressure stabilizes and the vapor is released from the condensate. This transient, which may best be called a “swell”, must be accommodated without unnecessary alarm or dumping as long as the level is controlled within safe limits as shown in Fig. No. 38 for horizontal heaters and Fig. No. 37 for vertical channel down heaters.
A2.7 Effect of Failed Tubes on Heater Operation
A2.5 Effect of Low Liquid Levels on External Drain System
The suppression of subcooling due to low shell liquid levels causes the heater drains to approach the saturation temperature. Any subsequent line pressure loss through valves and/or in the piping causes condensate flashing, with gross tendencies toward vapor binding, slug flow, and resultant problems such as pipe movement, and/or banging and choking 44
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The shell liquid level is also significantly affected by continued operation with failed tubes. The drains control system is required to pass the added flow from the two broken ends of each clean ruptured tube and from impingement failures. With continued operation, failed tubes have the potential to seriously damage surrounding tubes, tube holes, internal structures, pressure parts, etc. Feedwater entering the shell thru a failed tube will flash into a two-phase mixture and combine with the shell side flow. This can initiate vibration as well as erosion of components. In addition, high velocity water jets (if present) can erode and penetrate thru pressure parts. (Refer to Paragraph A3.4 concerning safety precautions). It will be noted that flow from only a few ruptured tubes will exceed 10% of rated feedwater flow in short order, particularly in high pressure heaters. Continued operation with damaged tubes can rapidly escalate leakage flows due to secondary failures resulting from feedwater impingement on adjacent tubes. Oversized valves in low pressure heater drain
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associated with two-phase flow in a piping system. If the system utilizes a heater drain pump, the loss of subcooling can have a significant adverse effect on the necessary net positive suction head requirement and/or cavitation. Heater liquid levels should be controlled by displacement sensors or by any other type of sensors that are responsive to rapid changes in the shell liquid level and that faithfully reflect changes in extraction, cascaded drains or possible internal leakage flows. Although heater levels must be set by temperature, namely the level that provides the rated drains approach temperature, heater levels are not to be controlled by temperature. Time delays in sensing temperature changes would probably result in unacceptable, erratic level swings.
Of all the possible reasons for false sensing of vapor/liquid interface levels in closed feedwater heaters, the following appear to be most commonly encountered. Note that when a false high shell liquid level indication is adjusted down to the “normal” set level, the actual liquid level in the shell is set equivalently too low. •E xcessive condensing in a top equalizing leg that is too long induces a compensating flow into the leg. This results in a pressure loss causing a rise of the level in the sensor and gage glass relative to the actual level in the shell. It should be obvious that the longer the vapor equalizing leg, the greater will be the discrepancy between indicated level outside the heater and actual level inside the heater. For any given vapor equalizing leg length, insulation of the equalizing piping will minimize the false level indication. • A high localized velocity of steam across the top equalizing connection opening in the shell aspirates or reduces pressure in the top equalizing leg, which raises the level in the sensor relative to the actual level in the shell. • A cascade of condensate flowing down a vertical channel down shell into the top equalizing connection tends to flood the sensor and thus raise the level indication relative to the actual level in the shell. •S ediment or partially closed valve settings in the bottom equalizing leg inhibit the return of excess condensate to the shell, resulting in a higher level in the sensor than actually exists in the shell. • Any loop seals trapping condensate in the top equalizing leg or high points trapping gas in the bottom leg will cause a false level indication. • I mproperly installed or closed gage glass valves result in false indications. Often a false level indication tends to be relatively stable at a given load and unstable fluctuations in indicated level generally result from some other cause. Whatever the cause and magnitude of a false level indication, regular monitoring of the drains approach temperature will provide an immediate, accurate determination as to whether the actual shell liquid level is adequate. There will always be some discrepancy between the indicated level and the actual level, since condensation in the vapor equalizing leg will always be present to some degree. For this reason, as well as the combined effect of the other factors identified above, the heater operating level should always be established by conducting a level test. Please see Paragraph A2.2 for level test recommendations.
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A2.4 False Liquid Level Indication
Fig. No. 38
ing end plate, permitting the bypass of wet vapor from the condensing zone into the subcooling zone. This not only leads to erosion of the tube, if carbon steel, and of the hole in the end plate, but also can produce a similar effect on performance as an inadequate shell liquid level. Another liquid level test should be performed to reestablish the normal level. As a recommended practice when tubes are plugged in the bottom rows, the controlled level should be raised to submerge these plugged tubes when the row is 50% plugged or more.
A2.9 Start-Up Limitations For normal start-ups, the entire string of heaters is subjected to increasing feedwater flow rates. This is normal and will usually be acceptable provided the flow rates are changed gradually and within the temperature ramp rates provided in the Manufacturer’s instruction manual, if any. One start-up condition that requires special precautions is when one heater of the string has been out of service and is “cold” and needs to be restarted. This situation occurs when one heater is isolated for maintenance or repairs and the remaining heaters are kept in service. When this heater is ready to be put back into service, a different start-up procedure may be required. The owner should either follow the Manufacturer’s instruction manual or call the Manufacturer directly for specific instructions.
A2.8 Effect of Plugged Tubes
When a tube is plugged and becomes inactive in a horizontal heater that has a short drain cooler, two corollary events must be considered. If the plugged tube is in a bottom row, it contributes to pressure loss of the entering saturated condensate without attendant subcooling. Several such tubes can aggravate the failure problem and a liquid level test is necessary to establish a new adequate shell liquid level. Please see Paragraph A2.2 for level test recommendations. Further, the condensate choke is lost between the inactive tube OD and the drilled hole in the subcool-
A2.10 Shutdown Limitations The same precautionary measures used at startup are also recommended for shutdown in order to prevent thermal shock by rapid or forced cooling. 45
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systems often mask increasing leakage by maintaining a normal liquid level until additional tubes fail. To keep this condition from occurring, any incoming drains should be diverted to the condenser when the level rises above the normal high operating level at least 3" to 6". Additionally the station operators should mark the valve stem position of the Drain Control Valve in its normal 100% drain flow position. On each shift the valve stem position should be checked, and if the valve opening is greater than the marking, then a broken tube is very likely introducing feedwater into the heater shell. In any discussion of the operation of a closed feedwater heater with tube leaks, it is very important to keep in mind the fact that a shell safety valve is designed to release a given amount of water (not steam) at a shell pressure 10% above the design pressure of the shell. If tubes continue to fail, it must be recognized that the safety valve capacity will be exceeded. In such a case, the shell pressure will continue to rise and, in short order, can cause the shell to rupture. In other words, a safety valve provides a limited margin of time to get the heater off line to avoid an accident.
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LIQUID LEVEL CONTROLS FOR TYPICAL HORIZONTAL HEATER
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Note: All numbers shown are for example only. Individual heater designs and levels vary.
6. All external leaks must be repaired immediately. At the first sign of any internal or external leak, it is recommended that the heater should be immediately taken out of service and repaired. 7. If a heater has temporary non-welded tapered tube plugs installed, a pneumatic test might be considered for determining if plugs are leaking. The pressure should be limited to fifty percent of the shell design pressure or 10 psig, whichever is lower. 8. All gage glasses must be protected against damage, as this can be a source of dangerous leakage. 9. The following must be observed when personnel plan to enter or are working near a heater. A. Positive lock stops should be used to prevent accidental opening of any steam or water valves.
It must be recognized that many solutions used in the cleaning operating may contain corrodents which will have an effect on the materials in a feedwater heater. Use of such solutions must be done in a controlled manner, and care must be taken to assure that the accumulated effect does not affect the thickness of pressure-bearing components or contaminate the materials. In-plant cleaning of the feedwater heater internals is generally accomplished by a preoperational cleaning and flushing operation used to clean all vessels, piping, etc., prior to initial operation. Also, in-plant cleaning of the feedwater heater tubing surface is required when the heater performance becomes impaired due to fouling of the tubing. Due to the triangular pitch, it is not possible to mechanically clean other than the perimeter tubes’ surfaces; therefore, the generally accepted cleaning method is chemical cleaning.
B. If any insulation is removed, precautions should be observed to avoid injuries (both during repair/inspection operations and after start-up).
A3.2 Chemical Cleaning
It is recommended that the Purchaser’s metallurgist be consulted for specific cleaning procedures or the Purchaser should engage one of the chemical cleaning companies which can provide them with this service.
C. Proper ventilation must be supplied when making internal repairs on a heater.
A3.3 Stagnant or Entrapped Areas
D. Prior to performing work on nuclear installations the radioactivity level should be determined to be certain it is within acceptable levels.
It is imperative that all stagnant or entrapped areas within the heater are properly flushed in order to avoid excessive exposure to the chemical cleaning agent.
E. Do not use chlorinated solvents (or similar solvents) such as carbon tetrachloride, etc., inside a unit for weld repair processes, etc.
A3.4 Special Product Warnings (Safety)
F. Pools of water must be dried prior to use of electrical devices including electric arc cutting and/or arc welding equipment. G. The user shall pay particular attention to any safety notices on the heater.
A3.5 Lay-Up Procedure for Non-Operating Heaters
In order to reduce shell and tube side corrosion to a minimum in non-operating heaters, the following layup procedures are recommended. For heaters expected to be out of service for an extended period, both the shell and tube sides should be drained, dried, and, after air is removed, a nitrogen blanket at 5 psig should be maintained. This applies to heaters with all types of tube materials. The above is also the preferred method for units temporarily out of service, or in by-pass mode (for limited period), but if this is not possible then the following procedures should be observed. 1. Tube side – condensate should be maintained in the system with a pH compatible with all tube materials. 2. Shell side – air must be removed from the shell side as soon as the unit is shut down and a nitrogen blanket at 5 psig should be maintained.
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Note: As an alternate to nitrogen blanketing, steam blanketing may be considered. Steam temperature should not exceed tubeside design temperature.
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Ultimate responsibility for the safe operation and maintenance of heaters rests with the user, but the following will provide a description of areas where special precautions should be observed. It is imperative that the user become thoroughly familiar with all instruction manuals that are provided, as these documents will provide important safety instructions. A number of applicable areas to be observed prior to and during operation will be described below. (The list is not intended to be all inclusive). 1. Prior to performing any work on a unit, be certain that all valves are tagged and all pressures on the unit are relieved. If maintenance cannot be performed during an outage, then personnel should be protected from incoming fluids by double valves. 2. Any temporary gaskets are to be replaced prior to initial operation (with required permanent gaskets). 3. Do not gag any safety valves during operation. 4. Be certain that all closures are secured as required prior to pressurizing a unit. 5. The nameplate maximum allowable working pressures are not to be exceeded. The Manufacturer’s instructions on test water temperature should be observed to avoid nil ductility temperature problems.
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A3.1 In-Plant Cleaning
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A3 MAINTENANCE OF FEEDWATER HEATERS
A3.6.1 Tube Leak Repairs 1. Refer to Manufacturer’s instruction manual for specific repair sequence recommendations. 2. Isolate heater from operating systems and allow to cool down to safe working temperature. If valves leak, keep heater out of service until unit can be taken off the line. Refer to Paragraph A3.4 concerning safety precautions. 3. Record tube failure location by establishing all the data listed below which will permit an early diagnosis of potential failure modes. A layout of the tube pattern is usually provided in the instruction manual for this purpose. The data to be recorded is: row number, tube number, inlet or outlet tube leg, and longitudinal failure location with respect to the tubesheet face. This can be done by pressurizing the shell side with nitrogen at 10 psig maximum and by inserting a plug along the length of the tube and observing changes in the direction of flow. Eddy current devices may also be used. Proper safety precautions shall be observed when working in the presence of nitrogen. 4. Defective tube welds can be repaired by following the Manufacturer’s instructions. 5. Failed tubes can be plugged with tapered drive plugs when tube joint is mechanically expanded only. Welded tube joints must be plugged by the installation of a welded tube plug or specialty plug as recommended by the Manufacturer. 6. Tubes that are ruptured completely in two must be anchored as recommended by the Manu facturer prior to plugging the tube ends. 7. Leak testing and hydrostatic testing of the repair should be in accordance with the Manufacturer’s recommendations. 8. Specifications for feedwater heaters should require that tube plugging procedures be included in instruction manuals.
Tube Plugs 10% of To include tube count special welding supplies if welded plugs are used. Bolting: Manway Cover, 10% of A set implies a Channel Cover, or Sets bolt and nut. Pass Partition Cover Gaskets 2 Sets This set should include gaskets for pass partition cover. NOTE: Proper storage procedures must be observed since some gasket materials can deteriorate in a short time if improperly stored. Diaphragm (if used) 1 Set Including special welding supplies if required. Accessories — As recommended by (when supplied the accessory by the heater manufacturer. Manufacturer) Pass Partition Nuts 1 Set
A3.7.2 Special Tools
The recommended special tools for feedwater heaters are listed below: Special Tools Typical Quantity Comments Tube 1 set roller Expanders expanders for each tube diameter and gage
A3.6.2 Pressure Boundary Repairs
A3.8 Inspection
Feedwater heaters should be inspected periodically to reveal any evidence of corrosion or other a b n o r m a l c o n d i t i o n s w h i ch m ay a f f e c t t h e performance and life of the equipment.
A3.9 Alterations or Repairs
It is recommended that any alterations or repairs which may become necessary during installation, testing or operation be made under the Manufacturer’s direction and in accordance with his recommendations.
A3.7 Spare Parts and Special Tools
The following list of typical spare parts and special tools should be considered by the Purchaser of feedwater heaters. The specific parts and quantities should be listed in the specifications. In the preparation of the specification the Purchaser should consider pre-operational and post-operational spares. 47
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1. The recommendation of the Manufacturer should be solicited when this type of repair is contemplated. 2. Any repair or penetration of the heater pressure boundary should be reviewed with the local Authorized Inspection Agency servicing the plant site prior to the repair. Approval of the repair method by the Authorized Inspector is necessary to preserve the integrity of the vessel as an ASME Code approved pressure vessel.
Drivers optional Spare rolls optional
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The recommended spare parts for feedwater heaters are listed below. Typical Spare Parts Quantity Comments
Repair welding after the heater has been in service can be broken down into the following categories:
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A3.7.1 Spare Parts
A3.6 Repair Procedures
B1 Vertical Feedwater Heaters
heater shells, which basically have less free surface area within the confines of the cross section of the shell I.D., may require a 1/2 inch damping orifice in the bottom equalizing leg to increase the effective capacitance. The damping orifice will reduce the effect of short rapid level fluctuations but will not affect level trends. In this manner the small capacitance of the vertical heater becomes more effective. The cross sectional area of the vertical channel down heater shell may be enlarged to increase capacitance as required and shown in Fig. No. 39. Capacitance of a vertical heater can also be increased by increasing the level control range from a minimum of ±2" to ±3" or ±4" or as required to satisfy drain flow of the heater. As this control range is increased consideration should be given to increasing the float of the controller to longer float lengths. As the level is dropped in a vertical channel down heater, the point is reached where the indicated level coincides with the top of the draincooler shroud. This point must be indicated on the gage glass and also on the level indication in the control room. The heater should never be operated below this point since control of drain flow through the subcooler and the normal drain outlet piping would be completely lost. All of the above considerations should be evaluated by the Purchaser against the advantages described in the first paragraph.
B2 Cycling and Off Load Conditions
Since the performance of a feedwater heater is guaranteed at one specific “design point” condition (refer to Paragraph 2.1), other possible operating conditions, referred to as “off load conditions”, must be evaluated by varying some of the terminal conditions in order to predict the possible performance for the same heater design. This is more common with cycling units, which vary load with demand rather than base units, which typically meet a constant load. Cycling makes it difficult to optimize heater design since limits on velocities and pressure drops, for example, must be checked for worst case conditions, which can alter the design significantly. One major area of concern with cycling is when a desuperheating zone is used. Developing a design to prevent “wet tubes” at all required conditions is often very difficult. (Refer to Paragraph B4.1) Plant cycling can be detrimental to existing equipment because, until recently, most equipment was not designed to accommodate the fatigue effects of daily thermal and mechanical cycles.
B3 M aterial Compatibility in Operating Environments Tubing is protected from chemical attack as the result of passivation, the or the formation of protective films. If the integrity of the film is destroyed, the base
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The majority of feedwater heaters are installed in a horizontal position. However, some users prefer a vertical installation since less floor space is required. The channels can be either above or below the shells with most installations using the channel below the shell, commonly called “channel down”. This design enables the plant designer to run the feedwater piping between the heaters at a lower, more consistent elevation and shell removal may be somewhat simplified. If the channel is above (channel up), the tube bundle must be removed, necessitating breaking the major connections and handling heavier parts to gain similar access. In either of the vertical heater configurations complete tube bundle access may be more difficult than in the case of horizontal heaters. Other considerations for vertical heaters involve proper distribution of steam and condensate within the shell. In some designs the condensate will fall like rain from the tube supports while steam usually rises against the flow. A means of separation is required to preclude the steam flow from holding up the condensate with a resulting slugging or surging which could result in heater vibration, hydrodynamic instability, and impaired thermal performance. In vertical channel down feedwater heaters, the desuperheating zone must be longer than the drain subcooling zone to prevent flooding and possible water backflow to the turbine. This may require an inactive tube section below the desuperheating zone and/ or thermal limitations to the design such as reduced subcooling and no desuperheating. A channel down feedwater heater with a drain subcooling zone and no desuperheating zone requires flooded, ineffective surface alongside the drain subcooling zone. A channel up heater with a drain subcooling zone requires a full length section to accomplish a siphon-type lifting of the condensate. Part-load operation must be considered to assure sufficient pressure differential with the downstream heater to lift the drains without flashing. System upsets which break this siphon can occur, and it should be recognized that reestablishing the siphon is difficult, if not impossible, without a shutdown. Either flashing or breaking the siphon could result in a vapor-water mixture with resulting tube erosion and vibration. Water level control becomes more critical in vertical channel down heaters, especially those with desuperheating zones since there is less capacitance (storage volume per inch of water level) available. This may require a larger diameter shell or a greater level control band. Generally, more sophisticated level control systems are required to compensate for low capacitance. As shown in Fig. No. 39, vertical feedwater heaters present a unique level control requirement. Unlike horizontal heaters, which have a large surface area at the condensate-vapor interface, vertical channel down
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GENERAL FEEDWATER HEATER INFORMATION
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APPENDIX B
B3.1 Compatibility of Tube Materials
When selecting tube materials for mixed systems (different alloys in the feedwater heaters and surface condensers), the chemistry (specifically pH) of the condensate system is of primary importance and must be considered. The mechanism of failure will be peculiar to the specific alloy proposed and will involve the following for indicated alloys. Corrosion of copper-based alloys will eventually result in the copper pickup plating out in the system (turbine, etc.), while carbon steel erosion-corrosion problems can cause tube failures (especially at tube inlets and drain cooler inlet area on the shell side). The optimum pH required to control copper-base material problems is not the same as that required for carbon steel, and this is the basis of the problem. For example, carbon steel alloys require a pH of about 9.5, while the corresponding pH for copper-base materials is between 8.8 and 9.0. In a mixed system, a compromise pH level, usually in the range of 9.2, would be selected. If stainless steel tubes are used with carbon steel tubes, a pH of 9.5 is often maintained. The above mentioned pH levels provide the normally selected values for some materials and mixed systems; however, these are only examples. It is recommended that the user consult a chemist to determine the pH level best suited for their system when considering all parameters. In addition to pH, there are other parameters to consider in reducing potential metallurgical problems in tubing (e.g. velocity, temperature, oxygen content, chloride level, etc.); therefore, the particular station chemistry, and history of any tube problems, must be considered in the analysis. Some of the operating parameters may not be able to be changed to accommodate alloy selection, but their effect upon specific alloys must be considered in the selection process. 49
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material may enter into solution, gradually reducing the wall thickness. Each tube material has a pH range within which chemical attack on the protective films or on the base material is minimized. Certain environments enhance the formation of protective films. Chemical additives which are introduced to maintain proper feedwater quality can break down, producing gases that are corrosive to some tube materials. Control of pH alone is not necessarily a true representation of the gas content. The operator must assure that proper measurement of corrosion-producing gases is obtained to assure good water chemistry. In addition to pH control, it is recommended that electrical resistivity also be checked. The tubing material must be selected in conjunction with other materials used in the system. Early failures result from lack of consideration of the compatibility of the various system materials that must operate in a common environment. During the life of a generating unit, advances are made in chemical treatment of feedwater. Before adopting new technologies, the system materials should be reviewed to determine whether or not the new treatment will be compatible. For example, the change from solids treatment to volatile treatment has resulted in rapid attack of some types of feedwater heater tubing. Heaters removed from service for relatively long periods of time are sometimes filled with treated water. These additives should also be reviewed for compatibility with the tubing. Chemical cleaning solutions should be carefully reviewed for compatibility as well as complete drainage and flushing requirements. The responsibility for the operating environment is with the user. For this reason, the user is responsible for the initial material selection and material compatibility with the intended environment.
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Fig. No. 39
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FREE SURFACE AREA FOR SHELL LIQUID LEVEL CONTROL
B4.1 Desuperheating Zone
Without a desuperheating zone, the feedwater can only approach the saturated steam temperature, but cannot equal or exceed it. Additional temperature rise can be obtained by use of a desuperheating zone which exchanges the sensible heat in the steam through the influence of the large temperature difference between the steam and the feedwater. Although the heat transfer rate in a gas to liquid heat exchanger is less than that in the condensing zone, the temperature difference is much greater and, therefore, each square foot of surface in the desuperheating zone will transfer a significant amount of heat. Using a desuperheating zone permits heating of the feedwater to a temperature higher than the shell side saturation temperature.When superheat is available, the additional cost of a desuperheating zone is usually economically justifiable due to the cycle efficiency improvement which is realized. The use of a desuperheating zone is subject to some limitations. First, the steam temperature at the exit of the zone must be sufficient to heat the exposed tubing to a temperature exceeding the condensing temperature. Secondly, there must be sufficient heat in the entering steam to permit heating the feedwater to the desired outlet temperature. The requirements on steam temperature leaving the desuperheating zone indicated above apply not only to design conditions. Other operating parameters should be considered to avoid wet tube conditions. The amount by which the tube wall metal temperature within the zone exceeds the saturated steam temperature at the corresponding pressure is referred to as “dry wall safety margin”. This should be a minimum of 2°F at the design point.
B4.2 Condensing Zone
The condensing zone is the major internal section of all feedwater heaters. A large amount of tube surface area, held in place by tube support plates, condenses all of the incoming steam and additional steam produced by flashing of incoming drains, if any. In the process of condensing the steam, entrained non-condensible gases must be continuously removed in order to prevent blanketing of surfaces, resulting in loss of performance and corrosion (refer to Paragraph 2.13).
B4.3 Subcooling Zone
The use of a subcooling zone exchanges sensible heat between the saturated condensate and the colder incoming feedwater. The drains outlet temperature is subcooled below the saturation temperature of the condensate, thus reducing the potential for flashing and erosion in piping and valves. When the shroud of the subcooling zone is exposed to the steam within the shell, a certain amount of heat is transferred from the hotter steam through the shroud to the colder condensate within the zone. This is referred to as “reheat” since it is adding heat back into the condensate, which is being cooled. A calculation is done to produce a “corrected” MTD which adds in additional surface area to compensate for the added duty. Shrouds which are covered with saturated condensate in the shell, referred to as “flooded” zones, have much less reheat since the transfer of heat is lower for liquid than condensing vapor. The only way to obtain “no reheat” is through the use of an external drain cooler. A frequently requested optional feature is a drains subcooling zone “by-pass”, or “emergency dump” con-
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B4.1.1 Dry Wall Safety Margins at DSZ Outlet The condition known as “wet tubes” occurs when the tube wall metal temperature within the desuperheating zone is at or below the saturated steam temperature at the corresponding pressure (i.e. inlet steam pressure minus desuperheating zone pressure drop) allowing steam to condense on the tube wall. The lowest tube wall metal temperature within the desuperheating zone occurs at the shell side outlet of the zone; therefore, if the tube wall temperature is designed to be at some “safety margin” value above the saturated temperature at the desuperheating zone outlet, the tube wall at the outlet as well as throughout the entire desuperheating zone will remain dry. Since steam velocities within the desuperheating zone are relatively high, it is important to avoid any condensation of the steam on the outside of tubes within the desuperheating zone because entrained water droplets at high velocity can cause major damage. A calculation for “dry wall safety margin” at the desuperheating zone outlet is performed at the optimized “design point” condition. The designer can adjust the margin by changing the superheated steam outlet temperature and pressure drop of the desuperheating zone to obtain the desired minimum safety margin value and optimized heater design at the “design point” condition.
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It must be recognized, however, that the dry wall safety margin varies with every set of operating conditions. Check rating the optimized heater design at other “off design” or “off load” conditions will show a range of varying safety margins, which could be higher or lower than the minimum. The margin could even appear to be negative (i.e. producing wet tubes). This is not a concern with “base-loaded” units which operate at or near the “design point” continuously and may only experience “wet tubes” during infrequent shut downs and restarts. The varying safety margin is a concern, however, when units are subjected to “cycling” load operation that may occur on a continual basis. Designing a heater for a minimum safety margin at “off load” conditions may require decreasing the surface in the desuperheating zone to increase tube wall metal temperature at the DSZ outlet. This will result in a larger and more costly heater. It is difficult to design a heater to avoid “wet tubes” at all loads, as noted in paragraph B2; therefore, when units are subjected to “cycling” load operation, consideration must be given to the potential for a “less than optimized” heater design which may include minimized desuperheating zone length and options such as (a) an increase in heater size to obtain full performance, (b) optimized heater size but with decreased heater performance or (c) elimination of the desuperheating zone with decreased heater performance, if design temperatures allow.
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B4 S pecific Zone Designs (See Figures in Paragraph 9)
Today’s large installations frequently require more than one stream, so that heaters operate in parallel as well as in series. When one of the parallel heaters is isolated for maintenance, the total stream may flow through the remaining heaters unless by-passes are provided or load limitations are imposed. Feedwater heater piping systems, valves, and the feedwater heater itself shall be designed with consideration given to the fact that the steam flow to a feedwater heater will increase when a parallel heater or stream is removed from service. The increase in steam flow is related to the thermal effectiveness which is defined as: t – t1 Dt2 1 P = 2 =1– = 1– Dt1 UA/WC Ts – t1 e Where: t2 5 condensing zone outlet temperature, °F t1 5 condensing zone inlet temperature, °F TS 5 saturated steam temperature, °F Dt2 5 condensing zone outlet temperature difference 5 TS2 t2, °F Dt1 5 condensing zone inlet temperature difference 5 TS2 t1, °F U 5 heat transfer rate, Btu/hr-ft2-°F A 5 heating surface, ft2 W 5 feedwater flow, lbm/hr C 5 feedwater heat capacity, Btu/lbm-°F
B7 Integral Flash Chamber Considerations Integral flash chambers are shell extensions
beyond the U-bends for flashing drains inlets. They are unique to horizontal feedwater heaters and come in varying designs. Fig. No. 40 shows just one possible arrangement. The purpose of integral flash chambers is to conservatively allow for the introduction of flashing drains into the heater. The empty space behind the U-bends allows for maximum entrance area to disperse the kinetic energy of the flashing drains and minimizes any droplet entrainment of the flashing steam as it enters the tube bundle. Integral flash chambers may also be lined with stainless steel material depending on design. The result is a reduced potential for damaging tube vibrations, erosion, and in some rare cases reduced condensing zone performance due to flooding of the condensing zone tubes. One should consider an integral flash chamber if one of the following conditions occur: • Experience with previous equipment in a similar service indicates additional protection for the inlet drains is required.
Each feedwater heater system is unique; however, typical changes in steam flow are given in the Table VIII below. (Note: as indicated, the multipliers are typical only for a specific design and should not be used as the basis of design performance.) STEAM FLOW MULTIPLIER (One stream to be removed) Design Condensing Zone Thermal Original Streams Effectiveness 2 Streams 3 Streams .88 .90 .92 .94
1.58 1.33 1.61 1.35 1.64 1.36 1.67 1.38 Table VII
The system designer shall determine the specific steam flow multiplier for his system upon selection of his feedwater heaters.
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B5 Heaters Removed from Service
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From an accessibility standpoint, it is obviously desirable to make the manway as large as possible, but there are size, weight, and economic consequences to consider. An optimum choice for most purposes is an 18" I.D. if it is round, or an 18" x 14" opening if it has an obround profile. There are a number of older heaters that have been built with smaller openings, such as 16" I.D., but access into them is usually difficult. Larger sizes (such as 20" or 24") may seem desirable, but can be very costly, as these sizes often require an enlargement of the hemispherical head, which also affects the tubesheet thickness. The feasibility of larger sizes depends on the bundle size, the design pressure, as well as the orientation of the nozzles and manway. For the configuration of Fig. No. 22 of Paragraph 8.2.3 (which includes the majority of hemispherical head designs), the head size is particularly sensitive to the manway size. For the low pressure hemispherical head of Fig. No. 20, Paragraph 8.2.2, or the hemi-plus-barrel design shown in Fig. No. 24 of Paragraph 8.2.3, the sensitivity is less. In a retrofit situation, where there are limitations on space, it may be impossible to use a manway with an I.D. of 20" or larger without increasing the feedwater nozzle projection or in the case of vertical heaters, relocating structural members. In the case of feedwater heaters designed for new power plants, where the diameter is not limited, then the economics may be the main consideration in determining the manway size. If an access opening diameter greater than 20" is selected, consideration should be given to a configuration other than hemispherical.
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B6 Manway Sizes for Hemispherical Heads
nection on the shell. If significantly large shell side overload conditions are possible that require condensate dumping, this allows condensate to be removed directly from the shell without passing through the subcooling zone, thus reducing the restriction to flow and decreasing the potential for mechanical damage to the zone. The emergency dump connection should be at least as large as the normal drains outlet.
INTEGRAL FLASH CHAMBER
Fig. No. 40 B8 Floating Pass Partitions
Floating pass partitions are a design concept to aid in minimizing the temperature effects due to the temperature difference of the incoming fluid versus the outgoing fluid. This design is generally not used in feedwater heaters as the temperature rise in low pressure heaters is in the 50 degree F. range and in high pressure heaters is in the 100 degree F. range. Feedwater heater manufacturers have standards for the utilization of floating pass partitions that have been established through experience and/or analysis. The Manufacturer will determine whether a floating pass partition design is warranted based on the information provided by the purchaser as recommended in Paragraphs 2.1.1 and 2.1.2. Concern for weld fatigue of pass partitions under normal and cyclic operation has been minimized due to today’s weld techniques, joint geometry and additional non-destructive examination.
B9 Emergency Liquid Bypass for Feedwater Heaters
The main function of shell side liquid by-pass connections on feedwater heaters is to prevent water from flooding and damaging associated components connected to the heater like vents and most importantly the steam turbine. Water induction from plant 52
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Before specifying an integral flash chamber, one should consider the following factors: • Only horizontal heaters may have an integral flash chamber. Vertical heaters would require a separate external flash-pot arrangement. • Integral flash chambers take up additional shell length. An integral flash chamber would result in a larger tube bundle and shell if the heater length were limited. This may cause further shell and channel piping changes for a replacement heater. At minimum, the piping location for the drains inlet line would change.
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equipment into the turbine occurs mainly due to problems arising during start-up and shut-down and is often associated with once through flow steam generator units. Feedwater heaters however can also become a source of water ingress during operational periods when tubes rupture, or when normal drains back up, if the appropriate bypass mechanisms are not in place. An additional source of water that needs to be considered in the design of the bypass is the cascading of drains that typically occurs from higher to lower pressure heaters. It is recommended that mechanisms be in place that will isolate all of these sources of water. Two suggested external system arrangement options are provided in the ASME TDP-1 Recommended Practices for The Prevention of Water Damage To Steam Turbines Used for Electric Power Generation to achieve this goal. The first option would be provision of a bypass in the Primary drain line from the heater as well as automatic isolation of the steam extraction to the heater. The second option provided mainly for condenser neck heaters would be to isolate the tubeside flow in place of the extraction line isolation in the first option. Schematics for both of these arrangements can be found in the ASME TDP-1. The level control is integral to all of these suggested arrangements. With heaters that have drains cooling zones level controls are provided to maintain adequate height above the entrance to the drains cooling zone in addition to monitoring high levels for possible liquid ingress into the turbine. Location and accurate level indication are critical to the prevention of damage to the heater and turbine. Additional guidelines are described in Paragraphs A2.2 thru A2.6 and in addition the OEM should be consulted on specific heater designs. Also with respect to heaters having integral drains cooling zones, an additional emergency bypass can be located on the feedwater heater itself. A suggested schematic is shown in Fig. No. 41. The nozzle should be located in an area that will facilitate drainage. Due to the variety of configurations the final location should be discussed with the OEM. The connection should be sized to 4 ft/ sec maximum liquid velocity at operating conditions. On Fig. No. 41, level connections for normal operation and for emergency dump are shown separately. If the same level stand is used the level should be located as close to the drains cooling inlet area as possible so that proper level readings for the inlet are obtained. Although Fig. No. 41 is for horizontal heaters, an additional emergency bypass can be beneficial to a Vertical Head Up (VHU) heater also. In those VHU heaters with an integral drains cooling zone, the condensate must be pushed upward from the bottom of the shell to the drains outlet just below the tubesheet. Under low load conditions, a reduced pressure condition in the shell, in addition to a possible lower differential pressure with the next shell, can cause the water level to rise within the shell. In addition to loss of performance due to flooding surface, there is a potential for the water level to rise to the height of the steam inlet nozzle. A drains bypass can be located in the bottom of the shell or shell cover for this specific design.
into the feedwater heater. One typical installation that experiences large drain inlet flows is nuclear power stations. • Excessive kinetic energy being released due to the percentage of flashing of the incoming drains and the configuration of the shell and bundle. As a minimum, G2/r as defined in Paragraph 2.8.c should always be less than 4,000 for the entrance area. Based on the design, this may require an integral flash chamber.
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• A large quantity of inlet drains being introduced
Disadvantages: • More subject to leakage than a welded diaphragm. • Generally requires larger bolting. • Generally results in larger channels. • Higher initial capital cost.
Welded Diaphragm Closures Advantages: • Less subject to leakage than a gasketed closure. • Generally requires smaller bolting. • Generally results in smaller channels. • Lower initial capital cost. Disadvantages: • Longer access times required for maintenance crews. • Requires burning and/or grinding along with welding operations. • Safety Issue – Care must be taken to prevent pressurization of the channel side without the channel cover (properly bolted) in place.
EMERGENCY BY-PASS TO PREVENT WATER DAMAGE TO TURBINE FOR HEATERS WITH DRAINS COOLING ZONES. (ADAPTED FROM ASME TDP-1 - 1998)
B11 Drains and Vents for Heaters Every Closed Feedwater Heater should be properly
Fig. No. 41
The selection between gasketed or welded diaphragm closures is usually a matter of preference for plant maintenance personnel. These preferences are individually derived from plant experiences. Both closures are acceptable for most channel arrangements; i.e. full access and manway access. Option A & Option B in Paragraph 8.2.3 are typical arrangements for these closures. Gasketed closures may be limited by bolting for certain arrangements due to channel design pressure and/or the channel ID opening.
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designed with drain ports and vent ports where there is possible accumulation of drains and non-condensable gases at any location. The specific number of drains and vents will depend on the particular configuration of the heater. Normally, the shell side drain ports and tube side vent ports in a Vertical Channel Down heater, for example, can be best located at the tubesheet (provided that the tubesheet is thick enough to accommodate the hole area). Careful consideration must be given to the location of the Desuperheating Zone drain connection to avoid any entrapment of condensate that may cause flashing when steam is introduced. It is also worth knowing that the design and operation of external drains and vent piping are significant factors in the performance of the total draining and venting systems of closed feedwater heaters. The following are some recommended external piping arrangement for closed Feedwater heaters.
B10 High Pressure Closures: Gasketed vs. Welded Diaphragm
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Advantages: • Quick access for maintenance crews. • Requires no burning, grinding, or welding operations.
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Gasketed Closures
A further note should be made on the capacitance of Vertical Head Down (VHD) Feedwater heaters. As a result of the arrangement of VHD heaters the available volume to be filled (capacitance) before water enters the steam inlet is much less than in horizontal heaters. For this reason the drains by-pass connection is important in protecting from drains flowing into the DSZ and ultimately the turbine.
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RECOMMENDED SCHEMATIC PIPING ARRANGEMENT FOR FEEDWATER HEATERS
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(Horizontal with Side Outlet or Vertical Channel Down) No further reproduction or networking is permitted.
(Vertical Channel Down Only)
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Fig. No. 42
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RECOMMENDED SCHEMATIC PIPING ARRANGEMENT FOR FEEDWATER HEATERS
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(Vertical Channel Up Typical)
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Fig. No. 42 Continued
Notes: 1. (SI) Denotes an “International System of Units” unit. 2. Pressure should always be designated as gage or absolute. 3. The acceleration of gravity, g, is taken as 9.80665 m/s2. 4. One gallon (U S liquid) equals 231 in3. 5. For temperature interval, 1°K = 1°C exactly.
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OTHER UNITS
m z kg/s2 Note 5. Note 5.
N z m, m2 z kg/s2
J/s, N z m/s, m2 z kg/s3 lbf/in2
N/m2, kg/(m z s2)
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NAME SYMBOL inch/inches in foot/feet ft meter (SI) m millimeter mm square inch in2 square foot ft2 square meter (SI) m2 square centimeter cm2 square millimeter mm2 cubic inch in3 cubic foot ft3 gallon (US liquid) gal cubic meter (SI) m3 liter L pound mass (avoirdupois) lbm kilogram (SI) kg pound force (avoirdupois) lbf kilogram force kgf newton (SI) N degree Fahrenheit °F kelvin (SI) K degree Celsius (SI) °C British thermal unit (International Table) Btu kilocalorie (International Table) kcal joule (SI) J kilojoule kJ second (customary) sec second (SI) s minute min hour (customary) hr hour (metric) h watt (SI) W megawatt MW pound force/square inch psi inches of mercury in Hg feet of water ft H O 2 pascal (SI) Pa kilopascal kPa bar bar millimeter of mercury mmHg torr torr centipoise cp
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C-1 METRIC CONVERSION FACTORS NOMENCLATURE
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APPENDIX C REFERENCE DATA
PREFIX SYMBOL MULTIPLICATION FACTOR micro m 0.000 001 5 10-6 milli m 0.001 5 10-3 centi c 0.01 5 10-2 deci d 0.1 5 10-1 deca da 10 5 101 hecto h 100 5 102 kilo k 1 000 5 103 mega M 1 000 000 5 106 giga G 1 000 000 000 5 109
CONVERSION FACTORS LENGTH MULTIPLY BY TO OBTAIN (SI) in 2.540 3 10-2 m mm in 2.540 3 101 m (SI) ft 3.048 3 10-1 ft 2.540 3 102 mm AREA MULTIPLY BY TO OBTAIN 3 10-4 m2 (SI) in2 6.451600 3 102 mm2 in2 6.451600 ft2 9.290304 3 10-2 m2 (SI) 2 3 104 mm2 ft 9.290304 VOLUME MULTIPLY BY TO OBTAIN 3 10-5 m3 (SI) in3 1.638706 3 10-2 L in3 1.638706 3 3 10-2 m3 (SI) ft 2.831685 3 3 101 L ft 2.831685 gal 3.785412 3 10-3 m3 (SI) gal 3.785412 L MASS MULTIPLY BY TO OBTAIN lbm 4.535924 3 10-1 kg
(SI)
(SI)
TEMPERATURE K 5 (°F 1 459.67)/1.8 K 5 (°C 1 273.15) °C 5 (°F 2 32)/1.8 °C 5 ( K 2 273.15) °F 5 1.8 °C 1 32 °F 5 1.8 K 2 459.67
(SI) (SI)
ENERGY, WORK OR QUANTITY OF HEAT MULTIPLY BY TO OBTAIN Btu 1.055056 3 103 J Btu 2.519958 3 10-1 kcal ftzlbf 1.355818 J ftzlbf 3.238316 3 10-4 kcal
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(SI)
(SI) (SI)
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FORCE MULTIPLY BY TO OBTAIN lbf 4.448222 N lbf 4.535924 3 10-1 kgf kgf 9.806650 N
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PREFIXES DENOTING DECIMAL MULTIPLES OR SUBMULTIPLES
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APPENDIX C-1 – Continued
PRESSURE OR STRESS (FORCE/AREA) MULTIPLY BY TO OBTAIN psi 6.894757 3 103 Pa psi 6.894757 kPa psi 6.894757 3 10-2 bar psi 7.030696 3 10-2 kgf/cm2 2 lbf/ft 4.788026 3 101 Pa 2 3 10-2 kPa lbf/ft 4.788026 2 4.882428 kgf/m2 lbf/ft 3 inHg (32°F) 3.38638 3 10 Pa inHg (32°F) 3.38638 kPa inHg (32°F) 3.38638 3 10-2 bar inHg (32°F) 3.45315 3 10-2 kgf/cm2 inHg (32°F) 2.540 3 101 mmHg torr (0°C) 1.33322 3 102 Pa torr (0°C) 1.0 mmHg 2.98898 3 103 Pa ftH2O (39.2°F) 2.98898 kPa ftH2O (39.2°F) 3.047915 3 102 kgf/m2 ftH2O (39.2°F)
(SI) (SI) (SI)
(SI)
(SI)
(SI)
(SI) (SI)
VELOCITY (LENGTH/TIME) MULTIPLY BY TO OBTAIN m/s (SI) ft/sec 3.048000 3 10-1 m/s (SI) ft/min 5.080000 3 10-3 MASS FLOW RATE (MASS/TIME) MULTIPLY BY TO OBTAIN lbm/hr 1.259979 3 10-4 kg/s lbm/hr 4.535924 3 10-1 kg/h
(SI)
VOLUME FLOW RATE (VOLUME/TIME) MULTIPLY BY TO OBTAIN 3 10-4 m3/s (SI) ft3/min 4.719474 1.699011 m3/h ft3/min -5 m3/s (SI) gal/min 6.309020 3 10 -1 m3/h gal/min 2.271247 3 10 gal/min 3.785412 L/min
SPECIFIC VOLUME (VOLUME/MASS) MULTIPLY BY TO OBTAIN 3 10-2 m3/kg (SI) ft3/lbm 6.242797 3 101 L/kg ft3/lbm 6.242797 gal/lbm 8.345406 3 10-3 m3/kg (SI) gal/lbm 8.345406 kg/L L/kg
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MASS VELOCITY (MASS/TIME-AREA) MULTIPLY BY TO OBTAIN 3 10-3 kg/(s z m2) (SI) lbm/(hr z ft2) 1.35623 4.882428 kg/(h z m2) lbm/(hr z ft2) 2 4.882428 kg/(s z m2) (SI) lbm/(sec z ft )
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POWER (ENERGY/TIME) MULTIPLY BY TO OBTAIN Btu/hr 2.930711 3 10-1 W Btu/hr 2.930711 3 10-7 MW Btu/hr 2.519958 3 10-1 kcal/n
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APPENDIX C-1 – Continued
ENTHALPY (ENERGY/MASS) MULTIPLY BY TO OBTAIN 3 Btu/lbm 2.326000 3 10 J/kg Btu/lbm 2.326000 kJ/kg Btu/lbm 5.555556 3 10-1 kcal/kg
(SI)
HEAT CAPACITY AND ENTROPY (ENERGY/MASS-TEMPERATURE) MULTIPLY BY TO OBTAIN Btu/(lbm z °F) 4.186800 3 103 J/(kg z °C) (SI) Btu/(lbm z °F) 4.186800 kJ/(kg z °C) Btu/(lbm z °F) 1.000000 kcal/(kg z °C) THERMAL CONDUCTIVITY (ENERGY-LENGTH/TIME-AREA-TEMPERATURE) MULTIPLY BY TO OBTAIN Btu z in/(hr z ft2 z °F) 1.442279 3 10-1 W/(m z °C) (SI) Btu z in/(hr z ft2 z °F) 1.240137 3 10-1 kcal z m/(h z m2 z °C) Btu z ft/(hr z ft2 z °F) 1.730735 W/(m z °C) (SI) Btu z ft/(hr z ft2 z °F) 1.488164 kcal z m/(h z m2 z °C) DYNAMIC VISCOSITY (MASS/TIME-LENGTH OR FORCE-TIME/AREA) MULTIPLY BY TO OBTAIN cp 1.000000 3 10-3 Pa z s (SI) cp 1.000000 mPa z s lbm/(hr z ft) 4.133789 3 10-4 Pa z s (SI) lbm/(hr z ft) 4.133789 3 10-1 cp lbm/(sec z ft) 1.488164 Pa z s (SI) lbm/(sec z ft) 1.488164 3 103 cp lbf z sec/ft2 4.788026 3 101 Pa z s (SI) 2 4 lbf z sec/ft 4.788026 3 10 cp HEAT FLUX DENSITY (ENERGY/TIME-AREA) BY TO OBTAIN 3.154591 W/m2 (SI) 2.712460 kcal/(h z m2)
HEAT TRANSFER COEFFICIENT (ENERGY/TIME-AREA-TEMPERATURE) MULTIPLY BY TO OBTAIN Btu/(hr z ft2 z °F) 5.678263 W/(m2 z °C) (SI) 2 2 Btu/(hr z ft z °F) 4.882428 kcal/(h z m z °C) FOULING RESISTANCE (TIME-AREA-TEMPERATURE/ENERGY) MULTIPLY BY TO OBTAIN hr z ft2 z °F/Btu 1.761102 3 10-1 m2 z °C/W 2 -1 hr z ft z °F/Btu 2.048161 3 10 h z m2 z °C/kcal
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MULTIPLY Btu/(hr z °ft2) Btu/(hr z °ft2)
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DENSITY (MASS/VOLUME) MULTIPLY BY TO OBTAIN lbm/in3 2.767990 3 104 kg/m3 (SI) lbm/in3 2.767990 3 101 kg/L 3 lbm/ft 1.601846 3 101 kg/m3 (SI) lbm/ft3 1.601846 3 10-2 kg/L lbm/gal 1.198264 3 102 kg/m3 (SI) lbm/gal 1.198264 3 10-1 kg/L
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APPENDIX C-1 – Continued
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APPENDIX C-2 AREAS OF CIRCULAR SEGMENTS
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ASME Section II, Part D
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APPENDIX C-3 MODULUS OF ELASTICITY E OF MATERIALS FOR GIVEN TEMPERATURES
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ASME Section II, Part D
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APPENDIX C-3 – Continued MODULUS OF ELASTICITY E OF MATERIALS FOR GIVEN TEMPERATURES
25.8 25.9 25.9 25.8 25.6 25.4 25.2 24.9 24.6 24.2 23.8 23.4 23.0 22.6 20.9 21.0 21.2 21.3 21.4 21.5 21.5 21.5 21.5 21.4 21.3 21.1 20.9 20.7
Low Alloys “ASME SA-213 T11, UNS K11597 (SMLS)” “ASME SA-213 T22, UNS K21590 (SMLS)”
7.7 7.9 8.2 8.4 8.7 9.0 9.2 9.5 9.8 10.0 10.3 10.5 10.7 11.0
7.7 7.9 8.2 8.4 8.7 9.0 9.2 9.5 9.8 10.0 10.3 10.5 10.7 11.0
8.6 8.7 9.0 9.3 9.6 9.8 10.1 10.4 10.6 10.9 11.1 11.3 11.6 11.8
12.6 12.9 13.4 13.9 14.5 15.0 15.6 16.1 16.6 17.0 17.5 17.9 18.4 18.9
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References: ASME Section II, Part D, 1995 Edition Allegheny Teledyne Incorporated
1988 Tubular Exchanger Manufacturers Association Copper Development Association
Stainless Steel - Ferritic “ASME SA-803 TP439, UNS S43035 (Welded)” 12.3 12.5 12.6 12.8 12.9 13.1 13.3 13.4 13.6 13.8 13.9 14.1 29Cr-4Mo “ASME SA-268, UNS S44735 (Welded)” 10.1 10.3 10.5 10.7 10.8 11.0 11.2 11.3 11.5 11.7 11.8 12.0
“ASME SB-676, UNS N08367 (Welded)” 6.7 7.1 7.4 7.7 8.0 8.3 8.6 8.9 9.2 9.5 9.8 10.1
Stainless Steel - Austenitic “ASME SA-688 TP304, TP304L, TP304N” “UNS S30400, S30403, S30451 (Welded)” “ASME SA-688 TP316, TP316L” “UNS S31600, S31603 (Welded)” “ASME SA-249 TP316N, UNS S31651 (Welded)”
Nickel Alloys 70-30 Nickel-Copper “ASME SB-163, UNS N04400 (SMLS)”
26.0 26.9 28.4 29.9 31.5 33.0 34.5 36.0 37.5 39.1 40.6 42.1
21.0 21.5 22.3 23.1 23.9 24.7 25.5 26.3 27.1 27.9 28.7 29.5 30.3 31.1
17.0 17.5 18.3 19.1 19.9 20.8 21.6 22.4 23.2 24.0 24.8 25.7 26.5 27.3
64.0 65.4 67.7 70.1 72.4 74.7 77.1 79.4
112
30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6 30.0 29.9 29.6 29.2 28.9 28.4 28.0 27.6 27.1 26.6 26.1 25.6 25.1 24.6
“Thermal Conductivity k, Btu-ft/hr-ft2-°F for Temp °F of” 70 100 150 200 250 300 350 400 450 500 550 600 650 700
Copper and Copper Alloys Arsenical Copper - DPA “ASME SB-395, UNS C14200 (SMLS))” Admiralty Metals - B/C/D (SMLS) “ASME SB-395, UNS C44300, C44400, C44500” 70-30 Copper-Nickel “ASME SB-395, UNS C71500 (SMLS)” 80-20 Copper-Nickel “ASME SB-395, UNS C71000 (SMLS)” 90-10 Copper Nickel “ASME SB-395, UNS C70600 (SMLS)”
Carbon Steel “ASME SA-214, UNS K01807 (Welded)” “ASME SA-557-A2, UNS K01807 (Welded)” “ASME SA-557-B2, UNS K03007 (Welded)” “ASME SA-557-C2, UNS K03505 (Welded)” “ASME SA-179, UNS K01200 (SMLS)” “ASME SA-210 A-1, UNS K02701 (SMLS)” “ASME SA-210-C, UNS K03501 (SMLS)” “ASME SA-556-A2, UNS K01807 (SMLS)” “ASME SA-556-B2, UNS K02707 (SMLS)” “ASME SA-556-C2, UNS K03006 (SMLS)”
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APPENDIX C-4 THERMAL CONDUCTIVITY OF MATERIAL FOR GIVEN TEMPERATURES
External Nominal Nominal TransSurface BWG Thick- Tube Internal Ratio Constant Wt/Ft verse Moment of per Ft. of Gauge ness ID Area OD/ID C* (Steel) Metal Inertia 2 2 2 Tube (ft ) (in) (in) (in ) (lbm/ft) Area (in ) (in4)
10 11 12 13 14 15 16 17 18 19 20 21 22
0.134 0.120 0.109 0.095 0.083 0.072 0.065 0.058 0.049 0.042 0.035 0.032 0.028
0.232 0.260 0.282 0.310 0.334 0.356 0.370 0.384 0.402 0.416 0.430 0.436 0.444
0.0423 0.0531 0.0625 0.0755 0.0876 0.0995 0.1075 0.1158 0.1269 0.1359 0.1452 0.1493 0.1548
2.155 66. 1.923 83. 1.773 97. 1.613 118. 1.497 137. 1.404 155. 1.351 168. 1.302 181. 1.244 198. 1.202 212. 1.163 227. 1.147 233. 1.126 242.
0.524 0.1541 0.002926 0.487 0.1433 0.002844 0.456 0.1339 0.002758 0.411 0.1209 0.002615 0.370 0.1087 0.002457 0.329 0.0968 0.002280 0.302 0.0888 0.002148 0.274 0.0805 0.002001 0.236 0.0694 0.001786 0.206 0.0604 0.001598 0.174 0.0511 0.001390 0.160 0.0470 0.001294 0.141 0.0415 0.001160
5 ⁄8 0.1636
10 11 12 13 14 15 16 17 18 19 20 21 22
0.134 0.120 0.109 0.095 0.083 0.072 0.065 0.058 0.049 0.042 0.035 0.032 0.028
0.357 0.385 0.407 0.435 0.459 0.481 0.495 0.509 0.527 0.541 0.555 0.561 0.569
0.1001 0.1164 0.1301 0.1486 0.1655 0.1817 0.1924 0.2035 0.2181 0.2299 0.2419 0.2472 0.2543
1.751 1.623 1.536 1.437 1.362 1.299 1.263 1.228 1.186 1.155 1.125 1.114 1.098
156. 182. 203. 232. 258. 283. 300. 317. 340. 359. 377. 386. 397.
0.703 0.2067 0.006693 0.648 0.1904 0.006412 0.601 0.1767 0.006143 0.538 0.1582 0.005733 0.481 0.1413 0.005311 0.426 0.1251 0.004863 0.389 0.1144 0.004543 0.352 0.1033 0.004195 0.302 0.0887 0.003704 0.262 0.0769 0.003285 0.221 0.0649 0.002833 0.203 0.0596 0.002528 0.179 0.0525 0.002345
3 ⁄4 0.1963
10 11 12 13 14 15 16 17 18 19 20 21 22
0.134 0.120 0.109 0.095 0.083 0.072 0.065 0.058 0.049 0.042 0.035 0.032 0.028
0.482 0.510 0.532 0.560 0.584 0.606 0.620 0.634 0.652 0.666 0.680 0.686 0.694
0.1825 0.2043 0.2223 0.2463 0.2679 0.2884 0.3019 0.3157 0.3339 0.3484 0.3632 0.3696 0.3783
1.556 1.471 1.410 1.339 1.284 1.238 1.210 1.183 1.150 1.126 1.103 1.093 1.081
285. 319. 347. 384. 418. 450. 471. 492. 521. 543. 567. 577. 590.
0.882 0.2593 0.012882 0.808 0.2375 0.012211 0.747 0.2195 0.011600 0.655 0.1955 0.010704 0.592 0.1739 0.009822 0.522 0.1534 0.008912 0.476 0.1399 0.008278 0.429 0.1261 0.007601 0.367 0.1079 0.006661 0.318 0.0934 0.005874 0.268 0.0786 0.005036 0.246 0.0722 0.004661 0.216 0.0635 0.004145
pounds per tube per hour *Liquid velocity in feet/second 5 Specific gravity of water at 60 deg. F 5 1.0 C 3 specific gravity of liquid
For weights of other materials, multiply carbon steel weights by the following factors: 90-10 CuNi UNS C70600 – 1.140 Nickel-Copper (Alloy 400) – 1.126 70-30 CuNi UNS C71500 – 1.140 Nickel-Iron-Chrome (Alloys 800/800H) – 1.013 Arsenical Cu UNS C14200 – 1.140 300 Series Stainless Steel – 1.013 Admiralty UNS C44300 – 1.088
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1 ⁄2 0.1309
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Nominal Tube OD (in)
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APPENDIX C-5 MECHANICAL CHARACTERISTICS OF TUBING
External Nominal Nominal TransSurface BWG Thick- Tube Internal Ratio Constant Wt/Ft verse Moment of per Ft. of Gauge ness ID Area OD/ID C* (Steel) Metal Inertia 2 2 2 Tube (ft ) (in) (in) (in ) (lbm/ft) Area (in ) (in4)
10 11 12 13 14 15 16 17 18 19 20 21 22
0.134 0.120 0.109 0.095 0.083 0.072 0.065 0.058 0.049 0.042 0.035 0.032 0.028
0.607 0.635 0.657 0.685 0.709 0.731 0.745 0.759 0.777 0.791 0.805 0.811 0.819
0.2894 0.3167 0.3390 0.3685 0.3948 0.4197 0.4359 0.4525 0.4742 0.4914 0.5090 0.5166 0.5268
1.442 451. 1.378 494. 1.332 529. 1.277 575. 1.234 616. 1.197 655. 1.174 680. 1.153 706. 1.126 740. 1.106 767. 1.087 794. 1.079 806. 1.068 822.
1.061 0.969 0.893 0.792 0.703 0.618 0.563 0.507 0.433 0.374 0.314 0.288 0.254
0.3119 0.2846 0.2623 0.2328 0.2065 0.1816 0.1654 0.1489 0.1272 0.1099 0.0924 0.0847 0.0745
1 0.2618
10 11 12 13 14 15 16 17 18 19 20 21 22
0.134 0.732 0.4208 1.366 657. 1.241 0.3646 0.034994 0.120 0.760 0.4536 1.316 708. 1.129 0.3318 0.032711 0.109 0.782 0.4803 1.279 749. 1.038 0.3051 0.030731 0.095 0.810 0.5153 1.235 804. 0.919 0.2701 0.027957 0.083 0.834 0.5463 1.199 852. 0.814 0.2391 0.025339 0.072 0.856 0.5755 1.168 898. 0.714 0.2099 0.022732 0.065 0.870 0.5945 1.149 927. 0.650 0.1909 0.020965 0.058 0.884 0.6138 1.131 957. 0.584 0.1716 0.019111 0.049 0.902 0.6390 1.109 997. 0.498 0.1464 0.016594 0.042 0.916 0.6590 1.092 1028. 0.430 0.1264 0.014529 0.035 0.930 0.6793 1.075 1060. 0.361 0.1061 0.012367 0.032 0.936 0.6881 1.068 1073. 0.331 0.0973 0.011411 0.028 0.944 0.6999 1.059 1092. 0.291 0.0855 0.010106
10 11 12 13 14 15 11⁄8 0.2945 16 17 18 19 20 21 22
0.134 0.857 0.5768 1.313 900. 1.420 0.4172 0.052150 0.120 0.885 0.6151 1.271 960. 1.289 0.3789 0.048516 0.109 0.907 0.6461 1.240 1008. 1.184 0.3479 0.045409 0.095 0.935 0.6866 1.203 1071. 1.046 0.3074 0.041113 0.083 0.959 0.7223 1.173 1127. 0.925 0.2717 0.037110 0.072 0.981 0.7558 1.147 1179. 0.811 0.2382 0.033167 0.065 0.995 0.7776 1.131 1213. 0.737 0.2165 0.030516 0.058 1.009 0.7996 1.115 1247. 0.662 0.1944 0.027750 0.049 1.027 0.8284 1.095 1292. 0.564 0.1656 0.024021 0.042 1.041 0.8511 1.081 1328. 0.486 0.1429 0.020982 0.035 1.005 0.8742 1.066 1364. 0.408 0.1199 0.017818 0.032 1.061 0.8841 1.060 1379. 0.374 0.1099 0.016423 0.028 1.069 0.8975 1.052 1400. 0.328 0.0965 0.014525
pounds per tube per hour *Liquid velocity in feet/second 5 Specific gravity of water at 60 deg. F 5 1.0 C 3 specific gravity of liquid
65
0.022110 0.020793 0.019628 0.017966 0.016370 0.014758 0.013653 0.012484 0.010882 0.009558 0.008161 0.007539 0.006689
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Nominal Tube OD (in)
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APPENDIX C-5 MECHANICAL CHARACTERISTICS OF TUBING - Continued
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APPENDIX C-6 MECHANICAL CHARACTERISTICS OF STEEL TUBING
LESSER TERMINAL TEMPERATURE DIFFERENCE
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NOTE 2 – The determination of the LMTD must be done for each individual zone of a feedwater heater.
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NOTE 1 – For points not included on this sheet multiply Greater Terminal Temperature Difference and Lesser Terminal Temperature Difference by any multiple of 10 and divide resulting value of curved lines by same multiple.
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GREATER TERMINAL TEMPERATURE DIFFERENCE
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APPENDIX C-7 CHART FOR SOLVING LMTD FORMULA
Type Effective Sq. Ft. No. of Units
Date Cust. Ident. No. Mfg. Ident. No. Proposal No. Job No. Item No. Prepared By Total Position
Sq. Ft.
PERFORMANCE OF ONE SHELL 05 Fluid Circulated 06 Total Fluid Entering 07 08 Inlet Enthalpy 09 Outlet Enthalpy 10 Inlet Temperature 11 Outlet Temperature 12 Operating Pressure 13 Number of Passes 14 Velocity 15 Pressure Drop
Shell Side Steam
Drains
Tube Side Feedwater
#/HR. BTU/# BTU/# °F °F PSIA FT/SEC PSI
(
DSH
Heat Exchanged BTU/HR 16 Desuperheating Zone 17 Condensing Zone 18 Drain Subcooling Zone
SAT.)
Not Applicable DC
Surface Sq. Ft. LMTD Effective °F
Transfer Rate BTU/HR-– Baffle SQ. FT. -– °F Spacing
Reference Temperature Differences TTD °F DCA
°F
CONSTRUCTION – EACH SHELL
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Shell Side Tube Side 19 Design Pressure PSIG 20 Test Pressure PSIG 21 Design Temperature °F SHELL SKIRT 22 Minimum Design Metal Temperature °F Shell Side Tube Side 23 Tubes No. (U’s) (STR) O.D. BWG WALL (avg/min) Length 24 Shell Steel I.D. THICKNESS Pitch TRIANGULAR 25 Shell Cover Steel – Welded to Shell Shell Skirt THICKNESS 26 Channel Steel Channel Cover Steel 27 Tubesheet Steel Overlay 28 Support Plates – Steel Air Baffle Zone Baffle – Steel 29 Shrouds: DSH DC Impingement Baffles 30 Type Joints—Shell Side Tube Side 31 Gasket-Shell Channel 32 Connections: Steam – Inlet (W.E.) (FLGD) Drains – Inlet (W.E.) (FLGD) 33 Drains – Outlet (W.E.) (FLGD) 34 Feedwater – Inlet (W.E.) (FLGD) Outlet (W.E.) (FLGD) 35 Code Requirements: ASME SECT. VIII DIV. Heat Exchange Institute 36 Weights – Shell and Bundle Bundle Flooded 37 Accessories: Shell Relief Valve Tube Side Relief Valve 38 Shell Gage Glass 39 Method of Tube Attachment (Rolled) (Welded) 40 Remarks: 41 42 43
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Customer Engineer/Consultant Address Plant Name Plant Location 01 Service of Unit 02 Size 03 Surface Per Shell 04 No. of Shells Per Unit
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APPENDIX C-8.1 CLOSED FEEDWATER HEATER SPECIFICATION SHEET – ENGLISH UNITS
Type Effective m2 No. of Units
Date Cust. Ident. No. Mfg. Ident. No. Proposal No. Job No. Item No. Prepared By Total m2 Position
PERFORMANCE OF ONE SHELL 05 Fluid Circulated 06 Total Fluid Entering 07 08 Inlet Enthalpy 09 Outlet Enthalpy 10 Inlet Temperature 11 Outlet Temperature 12 Operating Pressure (abs) 13 Number of Passes 14 Velocity 15 Pressure Drop
Shell Side Steam
Drains
Tube Side Feedwater
Kg/s kJ/Kg kJ/Kg °C °C kPa m/s kPa
(
DSH
Heat Exchanged MW 16 Desuperheating Zone 17 Condensing Zone 18 Drain Subcooling Zone
SAT.)
Not Applicable DC
Surface LMTD Transfer Rate Baffle m2 Spacing Effective °C w/m2 • °C
Reference Temperature Differences TTD °C DCA
°C
CONSTRUCTION – EACH SHELL
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Shell Side Tube Side 19 Design Pressure kPag 20 Test Pressure kPag 21 Design Temperature °C SHELL SKIRT 22 Minimum Design Metal Temperature °C Shell Side Tube Side 23 Tubes No. (U’s) (STR) O.D. BWG WALL (avg/min) Length 24 Shell Steel I.D. THICKNESS Pitch TRIANGULAR 25 Shell Cover Steel – Welded to Shell Shell Skirt THICKNESS 26 Channel Steel Channel Cover Steel 27 Tubesheet Steel Overlay 28 Support Plates – Steel Air Baffle Zone Baffle – Steel 29 Shrouds: DSH DC Impingement Baffles 30 Type Joints—Shell Side Tube Side 31 Gasket-Shell Channel 32 Connections: Steam – Inlet (W.E.) (FLGD) Drains – Inlet (W.E.) (FLGD) 33 Drains – Outlet (W.E.) (FLGD) 34 Feedwater – Inlet (W.E.) (FLGD) Outlet (W.E.) (FLGD) 35 Code Requirements: ASME SECT. VIII DIV. Heat Exchange Institute 36 Weights – Shell and Bundle Bundle Flooded 37 Accessories: Shell Relief Valve Tube Side Relief Valve 38 Shell Gage Glass 39 Method of Tube Attachment (Rolled) (Welded) 40 Remarks: 41 42 43
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Customer Engineer/Consultant Address Plant Name Plant Location 01 Service of Unit 02 Size 03 Surface Per Shell 04 No. of Shells Per Unit
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APPENDIX C-8.2 CLOSED FEEDWATER HEATER SPECIFICATION SHEET – SI UNITS
Type Effective m2 No. of Units
Date Cust. Ident. No. Mfg. Ident. No. Proposal No. Job No. Item No. Prepared By Total m2 Position
PERFORMANCE OF ONE SHELL Shell Side 05 Fluid Circulated Steam Drains 06 Total Fluid Entering Kg/h 07 08 Inlet Enthalpy kcal/Kg 09 Outlet Enthalpy kcal/Kg 10 Inlet Temperature °C ( SAT.) 11 Outlet Temperature °C 12 Operating Pressure (abs) kg/cm2 13 Number of Passes 14 Velocity m/s Not Applicable 15 Pressure Drop kg/cm2 DSH DC Heat Exchanged kcal/h 16 Desuperheating Zone 17 Condensing Zone 18 Drain Subcooling Zone
Tube Side Feedwater
Surface Transfer Rate LMTD kcal/h - Baffle m2 Spacing Effective °C m2 - °C
Reference Temperature Differences TTD °C DCA
°C
CONSTRUCTION – EACH SHELL
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Shell Side Tube Side 19 Design Pressure k/cm2g 20 Test Pressure k/cm2g 21 Design Temperature °C SHELL SKIRT 22 Minimum Design Metal Temperature °C Shell Side Tube Side 23 Tubes No. (U’s) (STR) O.D. BWG WALL (avg/min) Length 24 Shell Steel I.D. THICKNESS Pitch TRIANGULAR 25 Shell Cover Steel – Welded to Shell Shell Skirt THICKNESS 26 Channel Steel Channel Cover Steel 27 Tubesheet Steel Overlay 28 Support Plates – Steel Air Baffle Zone Baffle – Steel 29 Shrouds: DSH DC Impingement Baffles 30 Type Joints—Shell Side Tube Side 31 Gasket-Shell Channel 32 Connections: Steam – Inlet (W.E.) (FLGD) Drains – Inlet (W.E.) (FLGD) 33 Drains – Outlet (W.E.) (FLGD) 34 Feedwater – Inlet (W.E.) (FLGD) Outlet (W.E.) (FLGD) 35 Code Requirements: ASME SECT. VIII DIV. Heat Exchange Institute 36 Weights – Shell and Bundle Bundle Flooded 37 Accessories: Shell Relief Valve Tube Side Relief Valve 38 Shell Gage Glass 39 Method of Tube Attachment (Rolled) (Welded) 40 Remarks: 41 42 43
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Customer Engineer/Consultant Address Plant Name Plant Location 01 Service of Unit 02 Size 03 Surface Per Shell 04 No. of Shells Per Unit
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APPENDIX C-8.3 CLOSED FEEDWATER HEATER SPECIFICATION SHEET – MKH UNITS
Please submit all questions and inquiries to the HEI at
[email protected], or visit the HEI website at www.heatexchange.org. Symptoms
Possible Causes
Possible Solutions
Pass Partition Leaks (Exhibited by reduced feedwater temperature rise, and higher TTD.)
Pass partition gasket failure
Consult supplier for appropriate replacement
Pass partition nut failure due to cycling operation
Consult supplier over stud and nut material selections, and consider tack welding replacement nuts, self locking nuts, or tension controlled washers
Pass partition cracking due to cycling Water hammer or abnormal operating conditions Erosion damage from feedwater inlet nozzle Tube Failures
Excessive tube vibration due to abnormal operating conditions Excessive tube vibration due to location of connections Chloride attack—stainless steel tubing
Make repairs as required and review operating procedures Consult supplier and review pass partition plate material Correct abnormal conditions. Contact supplier for reevaluation Reevaluate connections for baffles, shields, or impingement protection Review water chemistry and tube compatibility
Stagnant water during extended shutdown
Tubes may need to be rinsed and dried for extended shutdown.
Ammonia attack—copper alloy tubing
Check with plant chemist
Maintenance or construction damage
Plug or replace as required
Tube inlet erosion
Check water flow and adjust to design. Check water quality, especially suspended solids
Malfunctioning level controller / control valves Improper piping size
Check to ensure that level controller and control valves are functioning properly. Ensure that control valves are correctly sized
Transient operating conditions
Check for any reduction in the condensate outlet piping size that may cause a restriction to flow
False instrumentation readings
Evaluate after steady state is reached Check calibration of instrumentation (See Paragraph A2.4).
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Fluctuating or Unstable Liquid Levels
Consult supplier over possible repairs
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This troubleshooting guide has been prepared to assist operators of closed feeedwater heaters. The guide provides general guidance, and operators are advised to consult with the manufacturer when necessary for specific instructions regarding their equipment. Many of the items listed below are not in the scope of the heat exchanger manufacturer; however, these items do affect operation and must be considered by operators.
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TROUBLESHOOTING GUIDE APPENDIX D
Decreased Performance Due to Improper Venting
Possible Causes
Possible Solutions
Inadequate controller response for available capacitance (Vertical Head Down)
Check to ensure that level controller and control valves are correctly selected to achieve specified level range with available capacitance. Check level controller feedback gain setting. Inspect and repair vent opening(s) and orifice plate(s) as required
Blocked air vents Insufficient air vent piping capacity
Missing or unused startup vent line or valves
Consult the supplier of the equipment for evaluation. Weld failure in drains cooler shroud or end plate
Remove shell and repair weld
Air trapped in drains cooling zone
Open cooling zone start up vent or add additional vent in shell skirt section
Condensate or feedwater entering desuperheating zone
Repair failed tube, check operating water level or check for functioning steam trap at desuperheater drain Check to ensure liquid levels are being properly maintained. Perform a Liquid Level Test as described in Paragraph A2.2
Low liquid levels
Draincooler shroud damage
Consult the supplier of the equipment for possible repairs
Draincooler endplate damage
Consult the supplier of the equipment for possible repairs
Abnormal operating conditions
72
Operating conditions other than the “Design Case” will result in different DCA readings
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Decreased Draincooler Performance-Higher than expected DCA
Check that all startup vents are piped and valves are being opened during startup and closed when operating. Check that all orifice plates are located in a horizontal run of piping that is sloping away from the heater and not trapping condensate that could stop venting. Any vertical piping run should have an appropriate drainer at the bottom.
Improper vent piping
Unusual Sounds: Horizontal Heaters, Vertical Channel Down Heaters, Vertical Channel Up Heaters
Calculate piping system air release and check vent size. Check that vent piping area is greater than or equal to the combined vent lines areas if manifolded.
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Symptoms
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APPENDIX D - Continued
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ASSOCIATE MEMBERS
Alfa Laval AB Richmond, VA
Plymouth Tube Company Warrenville, IL
American Heat Exchanger Services, Inc. Greenfield, WI
Vallourec Heat Exchanger Tubes Morristown, TN
BFS Industries, LLC Butner, NC Croll Reynolds Company, Inc. Parsippany, NJ DC Fabricators Inc. Florence, NJ Gardner Denver Nash Elizabeth, PA GEA Heat Exchangers T hermal Engineering Division Lakewood, CO
WEBCO Industries, Inc. Sand Springs, OK Legal Council K&L Gates LLP New York, NY Secretary-Treasurer Thomas Associates, Inc. Cleveland, OH
GEA PHE Systems, Inc. York, PA Graham Corporation Batavia, NY Hamon Research Cottrell, Inc. Somerville, NJ
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Holtec International Marlton, NJ Hydro Dyne Inc. Massillon, OH Industrial Steam Oak Brook, IL Johnston Boiler Company Ferrysburg, MI Kansas City Deaerator Company Overland Park, KS Maarky Thermal Systems, Inc. Cherry Hill, NJ SIHI Pumps, Inc. Grand Island, NY SPIG USA, Inc Phillipsburg, NJ SPX Heat Transfer, LLC Tulsa, OK Sterling Deaerator Company Cumming, GA Thermal Engineering International (USA) Inc. Santa Fe Springs, CA Tranter Wichita Falls, TX Unique Systems, Inc. Cedar Knolls, NJ Vooner FloGard Charlotte, NC
1300 Sumner Avenue Cleveland, Ohio 44115-2851 216-241-7333 FAX: 216-241-0105 www.heatexchange.org e-mail:
[email protected]
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MEMBERSHIP LIST
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Heat Exchange Institute, Inc.
