Chemical Engineering Handbook
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Chemical Engineering Handbook
Table of Contents
1.0
2.0
3.0
4.0
Introduction .......................................................................................................................................... 1-1
1.1
Purpose and Applicability ................................................................................................................ 1-1
1.2
Roles and Responsibilities ............................................................................................................... 1-1
Water Chemistry.................................................................................................................................. 2-1
2.1
Purpose and Applicability ................................................................................................................ 2-1
2.2
Approach ................................................................................................................................................. 2-1
2.2.1
Water Sources .................................................................................................................... 2-1
2.2.2
Water Quality...................................................................................................................... 2-2
2.2.3
Basic Water Chemistry ................................................................................................... 2-6
2.2.4
Analysis Report ................................................................................................................ 2-15
2.2.5
Water Resources Data ................................................................................................... 2-15
2.2.6
Treated Municipal Wastewater................................................................................. 2-16
2.2.7
Description of Water Uses in a Power Plant ........................................................ 2-17
2.3
References............................................................................................................................................. 2-20
Water Mass Balances ......................................................................................................................... 3-1
3.1
Purpose and Applicability ................................................................................................................ 3-1
3.2
Approach ................................................................................................................................................. 3-1
3.2.1
Proper Uses of the Water Mass Balance .................................................................. 3-1
3.2.2
Overview of the Water Mass Balance ....................................................................... 3-1
3.2.3
Documentation................................................................................................................... 3-5
3.2.4
Raw Water Pretreatment............................................................................................... 3-9
3.2.5
Service Water.................................................................................................................... 3-12
3.2.6
Demineralized Water .................................................................................................... 3-13
3.2.7
Potable Water ................................................................................................................... 3-15
3.2.8
Ash Handling ..................................................................................................................... 3-15
3.2.9
Coal Dust Suppression .................................................................................................. 3-16
3.2.10 Flue Gas Desulfurization .............................................................................................. 3-16
3.2.11 Wastewater ....................................................................................................................... 3-16
3.3
References............................................................................................................................................. 3-17
Filtration................................................................................................................................................. 4-1
4.1
Purpose and Applicability ................................................................................................................ 4-1
4.2
Approach ................................................................................................................................................. 4-1
4.2.1
Overview............................................................................................................................... 4-1
4.2.2
Types of Filters................................................................................................................... 4-1
4.3
References............................................................................................................................................. 4-10
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6.0
7.0
8.0
Sedimentation, Clarification, and Softening .............................................................................. 5-1
5.1
Purpose and Applicability ................................................................................................................ 5-1
5.2
Approach ................................................................................................................................................. 5-1
5.2.1
Sedimentation .................................................................................................................... 5-1
5.2.2
Clarification ......................................................................................................................... 5-1
5.2.3
Softening ............................................................................................................................... 5-2
5.2.4
Pretreatment Considerations..................................................................................... 5-10
5.2.5
System Configuration .................................................................................................... 5-11
5.2.6
Process Performance and Control ........................................................................... 5-18
5.3
References............................................................................................................................................. 5-21
Ion Exchange ......................................................................................................................................... 6-1
6.1
Purpose and Applicability ................................................................................................................ 6-1
6.1.1
Summary............................................................................................................................... 6-1
6.1.2
Types of Ion Exchangers ................................................................................................ 6-2
6.1.3
Pretreatment....................................................................................................................... 6-6
6.1.4
Process .................................................................................................................................. 6-7
6.1.5
Wastewater Neutralization ........................................................................................... 6-8
6.2
Approach ................................................................................................................................................. 6-9
6.2.1
System Design .................................................................................................................... 6-9
6.2.2
System Configuration .................................................................................................... 6-10
6.2.3
Degasifiers ......................................................................................................................... 6-11
6.2.4
System Startup ................................................................................................................. 6-12
6.3
References............................................................................................................................................. 6-13
Reverse Osmosis .................................................................................................................................. 7-1
7.1
Purpose and Applicability ................................................................................................................ 7-1
7.2
Approach ................................................................................................................................................. 7-1
7.2.1
Overview............................................................................................................................... 7-1
7.2.2
System Design .................................................................................................................... 7-4
7.2.3
Application......................................................................................................................... 7-17
7.2.4
System Operation............................................................................................................ 7-17
7.3
References............................................................................................................................................. 7-18
Condensate Polishing......................................................................................................................... 8-1
8.1
Purpose and Applicability ................................................................................................................ 8-1
8.2
Approach ................................................................................................................................................. 8-1
8.2.1
Overview............................................................................................................................... 8-1
8.2.2
Types of Condensate Polishers.................................................................................... 8-2
8.2.3
System Design .................................................................................................................... 8-8
8.2.4
Application......................................................................................................................... 8-12
8.2.5
System Operation............................................................................................................ 8-13
8.3
References............................................................................................................................................. 8-13
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10.0
11.0
12.0
13.0
Degasification ....................................................................................................................................... 9-1
9.1
Purpose and Applicability ................................................................................................................ 9-1
9.2
Approach ................................................................................................................................................. 9-1
9.2.1
Overview............................................................................................................................... 9-1
9.2.2
Vacuum Degasifier ............................................................................................................ 9-1
9.2.3
Forced Draft Degasifier................................................................................................... 9-2
9.2.4
Membrane Degasification .............................................................................................. 9-3
9.2.5
Design .................................................................................................................................... 9-4
9.3
References............................................................................................................................................... 9-4
Cycle Chemistry.................................................................................................................................. 10-1
10.1 Purpose and Applicability .............................................................................................................. 10-1
10.1.1 Overview............................................................................................................................. 10-1
10.1.2 Chemical Conditioning .................................................................................................. 10-3
10.1.3 Conditioning Chemicals ............................................................................................. 10-10
10.2 Approach ............................................................................................................................................ 10-15
10.2.1 Equipment Design........................................................................................................ 10-15
10.3 References.......................................................................................................................................... 10-22
Circulating Water Chemical Feed ................................................................................................ 11-1
11.1 Purpose and Applicability .............................................................................................................. 11-1
11.1.1 Overview............................................................................................................................. 11-1
11.1.2 Circulating Water Treatment Chemicals ............................................................... 11-1
11.2 Approach ............................................................................................................................................... 11-4
11.2.1 Equipment Design........................................................................................................... 11-4
11.3 References.......................................................................................................................................... 11-13
Sampling and Analysis..................................................................................................................... 12-1
12.1 Purpose and Applicability .............................................................................................................. 12-1
12.2 Approach ............................................................................................................................................... 12-1
12.2.1 Overview............................................................................................................................. 12-1
12.2.2 System Design .................................................................................................................. 12-2
12.2.3 System Operation............................................................................................................ 12-9
12.2.4 Calculation and Documentation................................................................................ 12-9
12.3 References............................................................................................................................................. 12-9
Evaporative Wastewater Treatment .......................................................................................... 13-1
13.1 Purpose and Applicability .............................................................................................................. 13-1
13.2 Approach ............................................................................................................................................... 13-1
13.2.1 Overview............................................................................................................................. 13-1
13.2.2 Evaporative Treatment Technologies .................................................................... 13-1
13.2.3 Conceptual Design .......................................................................................................... 13-7
13.3 References............................................................................................................................................. 13-8
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14.0
15.0
16.0
17.0
18.0
Seawater Desalination..................................................................................................................... 14-1
14.1 Purpose and Applicability .............................................................................................................. 14-1
14.2 Approach ............................................................................................................................................... 14-1
14.2.1 Overview............................................................................................................................. 14-1
14.2.2 Seawater Quality ............................................................................................................. 14-1
14.2.3 Desalination Technology.............................................................................................. 14-2
14.2.4 Materials of Construction ............................................................................................ 14-7
14.3 References............................................................................................................................................. 14-8
Heavy Metals Reduction ................................................................................................................. 15-1
15.1 Purpose and Applicability .............................................................................................................. 15-1
15.2 Approach ............................................................................................................................................... 15-1
15.2.1 Overview............................................................................................................................. 15-1
15.2.2 Sources of Heavy Metals .............................................................................................. 15-1
15.2.3 Estimating Heavy Metals Concentration Prior to Treatment ....................... 15-2
15.3 Heavy Metals Treatment Methods .............................................................................................. 15-3
15.3.2 Heavy Metal Characteristics ....................................................................................... 15-8
15.4 References.......................................................................................................................................... 15-13
Laboratory Design ............................................................................................................................ 16-1
16.1 Purpose and Applicability .............................................................................................................. 16-1
16.2 Approach ............................................................................................................................................... 16-1
16.2.1 General Design Considerations ................................................................................. 16-1
16.2.2 Laboratory Types ............................................................................................................ 16-6
16.2.3 Design Coordination ...................................................................................................... 16-9
16.3 References.......................................................................................................................................... 16-11
Safety Showers and Eyewashes .................................................................................................... 17-1
17.1 Purpose and Applicability .............................................................................................................. 17-1
17.2 Approach ............................................................................................................................................... 17-1
17.2.1 Overview............................................................................................................................. 17-1
17.2.2 Safety Shower Design .................................................................................................... 17-1
17.2.3 Tempered Water Design .............................................................................................. 17-2
17.2.4 SS/EW Locations ............................................................................................................. 17-5
17.3 References............................................................................................................................................. 17-6
Chemical Cleaning ............................................................................................................................. 18-1
18.1 Purpose and Applicability .............................................................................................................. 18-1
18.1.1 Summary............................................................................................................................. 18-1
18.2 General Project Considerations ................................................................................................... 18-1
18.3 Approach ............................................................................................................................................... 18-2
18.3.1 Cleaning Techniques and Procedures .................................................................... 18-2
18.3.2 Neutralization and Passivation Stages ................................................................... 18-9
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18.3.3 Draining, Rinsing, and Lay-up................................................................................. 18-11
18.3.4 Post Cleaning Inspection and Lay-up................................................................... 18-12
18.4 Process Considerations ................................................................................................................ 18-13
18.4.1 Manufacturer’s Procedures ..................................................................................... 18-13
18.4.2 Construction Practice ................................................................................................. 18-13
18.4.3 Disposal Options........................................................................................................... 18-14
18.4.4 Demineralized Water Capacity............................................................................... 18-14
18.4.5 Construction/Startup Schedule ............................................................................. 18-14
18.4.6 Mobilization and Cleaning Schedule .................................................................... 18-15
18.4.7 Site Considerations...................................................................................................... 18-15
18.4.8 Flow Path Determination.......................................................................................... 18-18
18.5 Design and Specification Preparations .................................................................................. 18-19
18.5.1 Design ............................................................................................................................... 18-19
18.5.2 Specification Scope of Work .................................................................................... 18-20
18.5.3 System Sizing ................................................................................................................. 18-22
18.6 Systems Requiring Chemical Cleaning ................................................................................... 18-25
18.6.1 Combined Cycle Units................................................................................................. 18-25
18.6.2 Thermal Units ................................................................................................................ 18-27
18.7 References.......................................................................................................................................... 18-27
Cleanliness Control ........................................................................................................................... 19-1
19.1 Purpose and Applicability .............................................................................................................. 19-1
19.2 Approach ............................................................................................................................................... 19-2
19.3 Overview................................................................................................................................................ 19-2
19.4 Provisions for Cleanliness Control During Design and Procurement .......................... 19-2
19.4.1 Preparation of Design Documents – Pipeline Lists ........................................... 19-2
19.4.2 Preparation of Design Documents – Pipeline Design ....................................... 19-4
19.4.3 Preparation of Equipment Procurement Specifications ................................. 19-5
19.4.4 Preparation of Mechanical Construction Specifications ................................. 19-6
19.5 Provisions for Cleanliness Control During Fabrication...................................................... 19-7
19.5.1 Fabrication of Equipment ............................................................................................ 19-7
19.5.2 Shop Verification of Equipment Cleanliness........................................................ 19-7
19.5.3 Packaging of Equipment............................................................................................... 19-7
19.6 Provisions for Cleanliness Control During Construction................................................... 19-7
19.6.1 Receipt and Unloading .................................................................................................. 19-8
19.6.2 Storage Prior to Erection ............................................................................................. 19-8
19.6.3 Equipment Erection ....................................................................................................... 19-8
19.6.4 Storage Prior to Commissioning ............................................................................... 19-9
19.6.5 Blast Media for Steam Cycle Service ....................................................................... 19-9
19.7 Provisions for Cleanliness Control During Commissioning ............................................. 19-9
19.7.1 Piping and Equipment Cleaning and Flushing ................................................. 19-10
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19.7.2
19.7.3
20.0
Hydrostatic Testing ..................................................................................................... 19-10
Verification of Cleanliness of Inaccessible and Non-flushable
Areas.................................................................................................................................. 19-11
19.7.4 Chemical Cleaning and Blowing of Steam Pipe ................................................ 19-11
19.7.5 System and Equipment Outages ............................................................................ 19-12
19.8 Considerations for Cleanliness Control During Initial Operation ............................... 19-13
19.8.1 Poor Quality Cycle Makeup Water ........................................................................ 19-13
19.8.2 Condenser Tube Leaks ............................................................................................... 19-14
19.8.3 Operator’s Chemical Feed Selection..................................................................... 19-14
19.8.4 Contaminated Process Condensate Return ....................................................... 19-15
19.8.5 Inadequate Deaeration .............................................................................................. 19-15
19.8.6 Special Considerations for Joint Venture EPC Projects and
Consortia ......................................................................................................................... 19-15
Startup Water Chemistry ................................................................................................................ 20-1
20.1 Purpose and Applicability .............................................................................................................. 20-1
20.2 Approach ............................................................................................................................................... 20-1
20.3 Overview................................................................................................................................................ 20-1
20.4 Responsibilities................................................................................................................................... 20-2
20.5 Hydrostatic Test Water ................................................................................................................... 20-2
20.6 Steam Blow Chemistry..................................................................................................................... 20-3
20.6.1 Steam Blow Chemical Feed ......................................................................................... 20-3
20.6.2 Steam Blow Makeup Water Quality and Monitoring ........................................ 20-4
20.7 Startup Steam Cycle Chemistry .................................................................................................... 20-4
20.7.1 Cycle Chemistry ............................................................................................................... 20-5
20.7.2 Steam Cycle Parameters and Action Levels ......................................................... 20-6
20.8 Startup Steam Cycle Chemistry – Oxygenated Treatment ............................................. 20-11
20.8.1 Cycle Chemistry ............................................................................................................ 20-11
20.8.2 Steam Cycle Parameters and Action Levels ...................................................... 20-13
20.9 Corrective Actions .......................................................................................................................... 20-16
20.9.1 Makeup Water ............................................................................................................... 20-16
20.9.2 Condensate ..................................................................................................................... 20-17
20.9.3 LP Drum ........................................................................................................................... 20-19
20.9.4 Intermediate-Pressure Drum.................................................................................. 20-19
20.9.5 High-Pressure Drum ................................................................................................... 20-22
20.9.6 Steam................................................................................................................................. 20-24
20.9.7 Condensate Polisher Effluent .................................................................................. 20-25
20.10 Startup ................................................................................................................................................. 20-29
20.10.1 Phosphate and Caustic (if applicable) ................................................................. 20-29
20.10.2 Oxygen (if applicable) ................................................................................................ 20-30
20.10.3 Ammonia ......................................................................................................................... 20-30
20.10.4 Silica................................................................................................................................... 20-30
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22.0
23.0
20.10.5 Cation Conductivity ..................................................................................................... 20-31
20.10.6 Dissolved Oxygen ......................................................................................................... 20-31
20.11 Lay-Up.................................................................................................................................................. 20-32
20.11.1 Wet Lay-Up ..................................................................................................................... 20-32
20.11.2 Dry Air Lay-Up............................................................................................................... 20-32
20.11.3 Nitrogen Blanketing .................................................................................................... 20-32
20.12 Circulating Water Operating Chemistry ................................................................................ 20-33
20.12.1 Circulating Water Chemical Feed .......................................................................... 20-33
20.12.2 Sodium Hypochlorite .................................................................................................. 20-33
20.12.3 Sodium Hypochlorite and Sodium Bromide (if applicable)........................ 20-34
20.12.4 Sulfuric Acid ................................................................................................................... 20-35
20.12.5 Scale Inhibitor ............................................................................................................... 20-35
20.12.6 Corrosion Inhibitor ..................................................................................................... 20-36
20.12.7 Sodium Bisulfite............................................................................................................ 20-36
20.12.8 Circulating Water Quality and Monitoring ........................................................ 20-37
20.13 Auxiliary Boiler Chemistry .......................................................................................................... 20-38
20.13.1 Steam Purity ................................................................................................................... 20-38
20.13.2 Auxiliary Boiler Water Quality ............................................................................... 20-39
20.13.3 Ammonia Feed .............................................................................................................. 20-39
20.14 Inlet Air Chiller Chemistry .......................................................................................................... 20-39
20.14.1 Makeup Water Quality ............................................................................................... 20-40
20.14.2 Scaling Index .................................................................................................................. 20-40
20.14.3 Chemical Additives ...................................................................................................... 20-41
20.15 References.......................................................................................................................................... 20-41
Flow Accelerated Corrosion .......................................................................................................... 21-1
Sulfuric Acid Handling and Dilution ........................................................................................... 22-1
22.1 Purpose and Applicability .............................................................................................................. 22-1
22.2 Approach ............................................................................................................................................... 22-1
22.2.1 Overview............................................................................................................................. 22-1
22.2.2 Sulfuric Acid Storage Tanks ........................................................................................ 22-1
22.2.3 Sulfuric Acid Dilution System for Ion Exchange Regeneration ................. 22-13
22.2.4 Sulfuric Acid Safety Equipment .............................................................................. 22-15
22.3 References.......................................................................................................................................... 22-15
Carbon Dioxide Storage and Direct Gas Feed for pH Control ............................................23-1
23.1 Purpose and Applicability .............................................................................................................. 23-1
23.2 Approach ............................................................................................................................................... 23-1
23.2.1 Overview............................................................................................................................. 23-1
23.2.2 Materials of Construction ............................................................................................ 23-2
23.2.3 Estimation of Carbon Dioxide Requirements ...................................................... 23-3
23.2.4 System Operation and Control .................................................................................. 23-3
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25.0
23.2.5 Injection Point Considerations .................................................................................. 23-5
23.2.6 Feed Rate Measurement............................................................................................... 23-5
23.3 References............................................................................................................................................. 23-5
Gas Chlorination Chemical Feed System ...................................................................................24-1
24.1 Purpose and Applicability .............................................................................................................. 24-1
24.2 Approach ............................................................................................................................................... 24-1
24.2.1 Overview............................................................................................................................. 24-1
24.2.2 Gas Chlorination Major Equipment and Appurtenances ................................ 24-2
24.2.3 Gas Chlorination System Design ............................................................................... 24-5
24.3 References............................................................................................................................................. 24-7
On-Site Sodium Hypochlorite Generation and Feed System..............................................25-1
25.1 Purpose and Applicability .............................................................................................................. 25-1
25.2 Approach ............................................................................................................................................... 25-1
25.2.1 Overview............................................................................................................................. 25-1
25.2.2 Major Equipment and Appurtenances ................................................................... 25-1
25.2.3 On-Site Hypochlorite Generation System Safety Requirements ................. 25-6
25.2.4 On-Site Hypochlorite Generation System Design .............................................. 25-8
25.3 References............................................................................................................................................. 25-9
LIST OF TABLES
Table 2-1
Table 2-2
Table 2-3
Table 3-1
Table 3-2
Table 3-3
Table 4-1
Table 5-1
Table 5-2
Table 6-1
Table 7-1
Table 7-2
Table 7-3
Table 8-1
Table 8-2
Table 10-1
Table 14-1
Table 14-2
Table 18-1
Classification of Dissolved Inorganic Constituents in Water ............................................. 2-2
Alkalinity Relationships .................................................................................................................... 2-6
Cooling Tower (Circulating) Water Quality Limits .............................................................. 2-18
Water Mass Balance Basic Design Values .................................................................................. 3-2
Coagulant, Acid, and Sulfate – 1 ppm Equivalents................................................................ 3-10
Cycle Makeup Water Quality Parameters ................................................................................ 3-14
Water Quality Guidelines for Use of Activated Carbon Filters or Manganese
Greensand Filters ................................................................................................................................. 4-6
Typical Softening Process Effluent Characteristics* ........................................................... 5-19
Effectiveness of Lime Softening for Inorganic Contaminant Removal* ...................... 5-19
Typical Design Criteria for a Mixed Bed Ion Exchanger ...................................................... 6-9
RO Feedwater Quality Guidelines ................................................................................................. 7-6
Typical Maximum Saturation Limits with Antiscalant Feed ............................................ 7-11
Instrumentation for RO Normalization .................................................................................... 7-15
66 Degree Baumé Sulfuric Acid Quality Requirements........................................................ 8-7
50 Percent Sodium Hydroxide Quality Requirements.......................................................... 8-7
Typical Turbine Steam Purity Requirements ......................................................................... 10-2
Typical Seawater Quality at 3.5 Percent Salinity .................................................................. 14-2
Typical Materials of Construction for a Multi-Stage Flash Unit ...................................... 14-8
Chemical Degreasing/Cleaning Critical Parameters ........................................................... 18-4
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Table 18-2
Table 18-3
Table 18-4
Table 18-5
Table 18-6
Table 18-7
Table 18-8
Table 18-9
Table 19-1
Table 19-2
Table 20-1
Table 20-2
Table 20-3
Table 20-4
Table 20-5
Table 20-6
Table 20-7
Table 20-8
Table 20-9
Table 20-10
Table 20-11
Table 20-12
Table 20-13
Table 20-14
Table 20-15
Table 20-16
Table 20-17
Table 20-18
Table 20-19
Table 20-20
Table 20-21
Table 20-22
Table 20-23
Table 22-1
Table 22-2
Alkaline Cleaning Critical Parameters ....................................................................................... 18-5
Solvent Cleaning (Iron Stage) Critical Parameters............................................................... 18-7
Dissolution Reactions for Solvent Cleaning ............................................................................ 18-8
Dissolution Reactions for Mineral Acid Cleaning ................................................................. 18-9
Neutralization Stage Critical Parameters.............................................................................. 18-10
Passivation Stage Critical Parameters .................................................................................... 18-10
Passivation Reactions for Solvent Cleaning ......................................................................... 18-11
Approximate Characterization of Chemical Cleaning Wastewater ............................ 18-12
Cleanliness Control Project Checklist ........................................................................................ 19-1
Cleanliness Control Guidelines for Various Piping Systems ......................................... 19-16
Steam Blow Demineralized Water Quality After Chemical Feed Parameters........... 20-4
Steam Blow Makeup Water Quality Parameters ................................................................... 20-4
Makeup Water Quality Parameters ............................................................................................ 20-7
Condensate Pump Discharge Quality Parameters................................................................ 20-7
Condensate Polisher Effluent ........................................................................................................ 20-8
Condensate After Chemical Feed Quality Parameters ........................................................ 20-8
Low-Pressure Drum Water Quality Parameters ................................................................... 20-9
Intermediate-Pressure Drum Water Quality Parameters ................................................. 20-9
High-Pressure Drum Water Quality Parameters ............................................................... 20-10
Steam Purity Requirements........................................................................................................ 20-11
Oxygenated Treatment Actions................................................................................................. 20-14
Oxygenated Treatment – Cycle Makeup Water Quality Parameters ......................... 20-14
Oxygenated Treatment – Condensate Pump Discharge Quality Parameters ......... 20-15
Oxygenated Treatment – Condensate Polisher Effluent Quality Parameters ........ 20-15
Oxygenated Treatment – Boiler Water Quality Parameters ......................................... 20-16
Troubleshooting Parameters ..................................................................................................... 20-26
Example Startup Water Chemistry Guide ............................................................................. 20-27
Boiler Pressure Versus Silica ..................................................................................................... 20-31
Circulating Water Quality Parameters ................................................................................... 20-37
Auxiliary Boiler Steam Purity Parameters ........................................................................... 20-39
Auxiliary Boiler Water Quality Parameters ......................................................................... 20-39
Inlet Air Chiller Makeup Water Quality Parameters ........................................................ 20-40
Recommended Scaling Indices for Evaporative Cooling ................................................ 20-41
Effective Tank Capacities for Horizontal, Cylindrical Tank With Standard
Dished Heads ....................................................................................................................................... 22-2
Alloy 20 Material Specifications .................................................................................................. 22-9
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LIST OF FIGURES
Figure 4-1
Figure 4-2
Figure 4-3
Figure 4-4
Figure 4-5
Figure 4-6
Figure 4-7
Figure 4-8
Figure 4-9
Figure 5-1
Figure 5-2
Figure 5-3
Figure 5-4
Figure 5-5
Figure 5-6
Figure 5-7A
Figure 5-7B
Figure 5-8
Figure 5-9
Figure 6-1
Figure 7-1
Figure 7-2
Figure 7-3
Figure 7-4
Figure 7-5
Figure 7-6
Figure 7-7
Figure 7-8
Figure 8-1
Figure 8-2
Figure 8-3
Figure 8-4
Figure 8-5
Figure 8-6
Figure 9-1
Figure 9-2
Figure 10-1
Figure 10-2
Examples of Lateral Type Drain Configurations ..................................................................... 4-2
Example of False Bottom .................................................................................................................. 4-2
Typical Vertical Downflow Pressure Filter ............................................................................... 4-4
Rio Nogales Continuously Backwashed Filters ....................................................................... 4-5
Zeeweed Membrane Schematic ..................................................................................................... 4-7
Ultrafiltration Membrane Skid ....................................................................................................... 4-8
Hydrotech Disc Filter.......................................................................................................................... 4-9
Cartridge Filter Element ................................................................................................................... 4-9
Cartridge Filters Installed at Cane Run ..................................................................................... 4-10
Conventional Solids Contact Clarifier ........................................................................................ 5-12
Solids Contact Clarifier Internals during Construction ...................................................... 5-12
High-Rate Solids Contact Process................................................................................................ 5-14
DensaDeg® Installation.................................................................................................................... 5-14
Veolia Actiflo® Sand-Ballasted Clarifier.................................................................................... 5-15
WesTech RapiSand™ Sand-Ballasted Clarifier ........................................................................ 5-15
Plate and Frame Filter Press Plates............................................................................................ 5-16
Plate and Frame Filter Press ......................................................................................................... 5-16
Belt Filter Press................................................................................................................................... 5-17
Centrifuge .............................................................................................................................................. 5-17
Ion Exchange Vessel............................................................................................................................ 6-5
Pore Size of Filtration Processes ................................................................................................... 7-1
Mechanism of Osmosis and Reverse Osmosis.......................................................................... 7-2
Reverse Osmosis Process Flow ...................................................................................................... 7-2
Spiral Wound Membrane .................................................................................................................. 7-3
Two Pass, Two Stage RO Configuration ...................................................................................... 7-4
Solubility of SiO2 versus Temperature ........................................................................................ 7-8
SiO2 pH Correction Factor ................................................................................................................ 7-9
Typical Cartridge Filter Design .................................................................................................... 7-10
Precoat Polisher System.................................................................................................................... 8-2
Precoat Polisher Internals ................................................................................................................ 8-3
Bottom Tubesheet Precoat Polisher ............................................................................................ 8-3
Top Tubesheet Precoat Polisher.................................................................................................... 8-4
Deep Bed Condensate Polisher ...................................................................................................... 8-5
Open Loop Recirculation Precoat Process................................................................................. 8-9
Forced Draft Degasifier Storage Vessel....................................................................................... 9-3
Illustration of a Membrane Contactor, Courtesy of Liqui-Cel ............................................ 9-3
Chemical Transfer in the Conventional Drum Boiler System .......................................... 10-2
Maximum Boiler Water Silica (SiO2) Concentration versus Drum Pressure
at Different Values of pH (10 µg/L SiO2 Limit in Steam) ................................................... 10-4
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Figure 10-3
Boiler Water pH versus Phosphate Residual for Various Sodium to
Phosphate Molar Ratios .................................................................................................................. 10-6
Figure 10-4
Effect of pH on Iron Concentration ............................................................................................. 10-8
Figure 10-5
Solubility of Iron Hydrate Oxides ................................................................................................ 10-9
Figure 10-6
Comparison between AVT Conditioning and OT Conditioning (for OnceThrough Units) ................................................................................................................................. 10-10
Figure 10-7
Ammonia Feed System ................................................................................................................. 10-11
Figure 10-8
Traditional Phosphate Feed System ....................................................................................... 10-12
Figure 10-9
Phosphate Makedown Module Feed System ....................................................................... 10-13
Figure 10-10 Hydrazine Feed System ................................................................................................................ 10-14
Figure 10-11 Ammonia - Conductivity - pH Curve ....................................................................................... 10-21
Figure 11-1
Circulating Water Sodium Hypochlorite Feed System, Inhibitor Feed
System, and Acid Feed System...................................................................................................... 11-2
Figure 11-2
Liquid Chemical Measuring Tank ................................................................................................ 11-7
Figure 11-3
Logic Diagram Symbol Legend .................................................................................................. 11-11
Figure 11-4
Inhibitor Feed Control Logic Diagram.................................................................................... 11-12
Figure 12-1
Typical Sample Line .......................................................................................................................... 12-5
Figure 13-1
Process Flow of Brine Concentrator (courtesy of Power Magazine)............................ 13-2
Figure 13-2
Process Flow of Steam Driven Crystallizer (courtesy of Veolia) .................................... 13-3
Figure 13-3
Process Flow of MVC Crystallizer (courtesy of Power Magazine) ................................. 13-4
Figure 13-4
Process Flow Diagram of Spray Dryer Treating Flue Gas Desulfurization
Wastewater .......................................................................................................................................... 13-6
Figure 14-1
Reverse Osmosis Based Desalination Flow Diagram .......................................................... 14-3
Figure 14-2
Electrodialysis Schematic ............................................................................................................... 14-4
Figure 14-3
Electrodialysis Reversal Schematic ............................................................................................ 14-4
Figure 14-4
Multiple Effect Distillation Desalination Flow Diagram .................................................... 14-6
Figure 14-5
Multi-Stage Flash Desalination Flow Diagram ....................................................................... 14-6
Figure 16-1
Fume Hood............................................................................................................................................ 16-3
Figure 16-2
Example Lab Arrangement Drawing.......................................................................................... 16-4
Figure 17-1
Tempering Skid Piping and Instrumentation Diagram ...................................................... 17-3
Figure 18-1
Chemical Degreasing Surfactant Addition ............................................................................... 18-4
Figure 18-2
EDTA Chelation ................................................................................................................................... 18-6
Figure 18-3
Solvent/Chelant Cleaning ............................................................................................................... 18-7
Figure 18-4
Passivation ......................................................................................................................................... 18-11
Figure 18-5
Boiler Drum Internal ..................................................................................................................... 18-13
Figure 18-6
Chemical Cleaning Circulating Pumps .................................................................................... 18-22
Figure 22-1
Standard Drawing for Sulfuric Acid Storage Tank ............................................................... 22-3
Figure 22-2
Interior of Uncoated, Carbon Steel Acid Storage Tank ....................................................... 22-5
Figure 22-3
Typical Circulating Water Sulfuric Acid Feed System......................................................... 22-8
Figure 22-4
Standard Drawing for Acid Diffuser Nozzle ......................................................................... 22-11
Figure 22-5
Standard Drawing for Acid Mixing Tee .................................................................................. 22-12
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Figure 22-6
Figure 22-7
Figure 23-1
Figure 25-1
Figure 25-2
Figure 25-3
Standard Drawing for Acid Mixing Trough .......................................................................... 22-13
Typical Demineralizer Acid Feed System ............................................................................. 22-14
Typical Carbon Dioxide Storage and Direct Gas Feed System ......................................... 23-2
Typical Electrolytic Cell and Hydrogen Dilution Arrangement ...................................... 25-2
Typical Sodium Hypochlorite Bulk Storage and Metering Equipment
Arrangement ........................................................................................................................................ 25-3
Typical Brine Preparation Equipment ...................................................................................... 25-4
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1.1
Introduction
Purpose and Applicability
This handbook provides instructions and guidance on performing the typical activities and
functions required of a chemical engineer. The intent is to provide information to the engineer so
he or she can make informed decisions when evaluating water treatment at specific sites.
1.2
Roles and Responsibilities
The Process/Chemical Department Head is the owner of this handbook and is responsible for its
review and approval. Each section has an assigned team of subject matter experts. Each subject
matter expert team has the responsibility of maintaining and revising its particular section of the
handbook and related items, such as calculation tools and training modules. Each team will serve
as a resource and point of contact for all technical inquiries, from within the discipline and from
other disciplines/departments.
To ensure that this handbook stays current with water treatment technology, each team will have
the responsibility of staying up to date on applicable codes and industry standards. Further, the
team will assess the latest articles and publications for changes in conventional wisdom, novel
applications of existing technology, and new discoveries relevant to each technical topic. Each team
is comprised of the following roles:
Facilitator--A mid-level engineer who will be the driving force behind keeping each section
of the handbook current and up to date. For more significant efforts requiring additional
personnel, the Facilitator will request support from the department head and coordinate
the work of other department members.
Sponsor--A senior engineer who will advise the Facilitator and guide the research and
background work. Along with the department head, the Sponsor will approve any changes
prior to revision.
OUS Liaison--A liaison chemical engineer from outside the United States who will be
assigned to each subject matter expert team. This person will serve as a local point of
contact for the global offices and will communicate with the Facilitator and Sponsor to
resolve questions and concerns in those locations.
The active assignments are as follows:
Topic
Section
Sponsor
Introduction
1
Mike Preston
Water Mass
Balances
3
Mitch Mueller
Water Chemistry
Filtration
2
4
Facilitator
Mike Preston
Vince Mazzoni
Mitch Mueller
Vince Mazzoni
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Topic
Section
Sponsor
Facilitator
Sedimentation,
Clarification, and
Softening
5
Alec Frank
Dan Gordon
Ion Exchange
Condensate
Polishing
6
Mason Mechler
Degasification
8
Terry Stout
9
Terry Stout
Reverse Osmosis
Cycle Chemistry
Circulating Water
Chemical Feed
Sampling and
Analysis
Evaporative
Wastewater
Treatment
7
10
11
12
13
Tonya Anton
Dan Gordon
Bob Craig
Amanda Kinney
Kathy Steichen
Sunee Ngaoaram
Tonya Anton
Mason Mechler
Kathy Steichen
Mitch Mueller
Meryl Bloomfield
Danny Rellergert
Mason Mechler
Seawater
Desalination
14
Mike Preston
Dan Gordon
Laboratory Design
16
Kathy Steichen
Amanda Kinney
Heavy Metals
Reduction
Safety Showers
Chemical Cleaning
Cleanliness Control
Startup Water
Chemistry
Flow Accelerated
Corrosion
Sulfuric Acid
Handling and
Dilution
15
17
18
19
20
21
22
Bob Craig
Kathy Steichen
Alec Frank
Alec Frank
Dan Gordon
Amanda Kinney
Mason Mechler
Danny Rellergert
Danny Rellergert
Tonya Anton
Kathy Steichen
Tonya Anton
Amanda Kinney
Meryl Bloomfield
Carbon Dioxide
Storage and Direct
Gas Feed for pH
Control
23
Tonya Anton
24
Kathy Steichen
Sunee Ngaoaram
Onsite Sodium
Hypochlorite
Generation and
Feed System
25
Kathy Steichen
Sunee Ngaoaram
Gas Chlorination
Chemical Feed
System
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2.1
Water Chemistry
Purpose and Applicability
The availability and quality of water is an important consideration in the siting and sizing of a
power plant. Water is used for equipment cooling, cleaning, air pollution control, conveying of
solids, and the steam used to generate power. Proper treatment and conditioning is required to
minimize scaling and corrosion within the plant.
2.2
Approach
This section provides an introduction to water chemistry to use in development of water treatment
at power plants.
2.2.1
Water Sources
Generally, water sources are either ground or surface. Groundwaters are those which exist below
the earth, and surface waters are those in rivers, streams, lakes, and oceans. Both of these sources
combined can be referred to as natural waters. Treated municipal wastewater is also becoming a
viable source of water for power plants.
A water inventory of the world shows that about 97 percent of water is present as surface water,
mainly seawater, and less than 3 percent is present as groundwater. In the United States, thermoelectric power generation is the largest water user. In 2005, 41 percent of groundwater
withdrawals, 61 percent of surface water withdrawals, and 95 percent of saline water withdrawals
were used to support thermoelectric power generation.
Precipitation is the primary source of all natural water supplies. Depending on the atmospheric
conditions and topography, approximately 25 percent of precipitation runs off to surface waters,
less than 10 percent infiltrates the soil, and the remainder returns to the atmosphere by
evapotranspiration.
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2.2.2
Water Quality
2.2.2.1
General Characteristics
As precipitation passes through the ground, it dissolves both organic and inorganic matter.
Groundwater dissolves minerals from the aquifer rock formation. Groundwaters are generally
clear and free of suspended solids because of the filtration that occurs as the water passes through
the earth. Surface waters gradually increase in dissolved solids as a result of concentration caused
by evaporation. Oceans have the greatest concentration because of the large surface areas available
for evaporation. Surface waters generally pick up color from organic matter and suspended solids
from dirt and vegetation. The amount of suspended matter can vary from 0 in oceans and quiet
bodies of water to 30 percent by weight in heavy flowing streams or as a result of storm conditions.
Water is an excellent solvent for many ionic compounds. Natural waters dissolve mainly the
cations (positively charged ions) of calcium (Ca+2), magnesium (Mg+2), and sodium (Na+1) and the
anions (negatively charged ions) of bicarbonate (HCO3-1), sulfate (SO4-2), and chloride (Cl-1).
The total concentration of these six major items normally make up more than 90 percent of the
total dissolved solids (TDS) in natural water, regardless of whether the water is dilute or has
salinity greater than seawater.
A classification of the dissolved inorganic constituents that occur in water is shown in Table 2-1.
Table 2-1
Classification of Dissolved Inorganic Constituents in Water
CONSTITUENTS
Major Constituents (typically greater than 5 mg/L)
Bicarbonate
Silicon
Chloride
Sulfate
Calcium
Magnesium
Sodium
Carbonic Acid
Minor Constituents (typically 0.01 to 10.0 mg/L)
Boron
Nitrate
Fluoride
Strontium
Carbonate
Iron
Potassium
Trace Constituents (typically less than 0.1 mg/L)
Aluminum
Manganese
Arsenic
Nickel
Antimony
Barium
Beryllium
Bismuth
Molybdenum
Phosphate
Platinum
Selenium
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CONSTITUENTS
Bromide
Silver
Chromium
Silver
Cadmium
Cobalt
Copper
Gold
Iodide
Lead
Lithium
Tin
Tin
Titanium
Tungsten
Uranium
Vanadium
Zinc
Source: Stanley N. Davis and Roger J.M. DeWiest,
Hydrogeology, John Wiley & Sons, 1966.
mg/L = milligrams per liter
The concentrations of the major, minor, and trace inorganic constituents in water are controlled by
the availability of the elements in the soil and rock through which the water has passed, by
geochemical constraints such as solubility and adsorption, by the rates (kinetics) of geochemical
processes, and by the sequence in which the water has come into contact with the various minerals
occurring in the geologic materials along the flow paths.
Human activity influences the concentration of the dissolved inorganic constituents. Contributions
from manmade sources can increase some of the elements listed as minor or trace constituents in
Table 2-1 to concentration levels that are orders of magnitude above the normal ranges indicated in
this table.
2.2.2.2
Regional Characteristics
As is apparent from the preceding discussion, both the quality and quantity of water can vary
significantly in different areas. The amount of rainfall and evaporation, the soil conditions, the
subsurface rock formation, and the discharge concentration of manmade contaminants all have an
impact on the water supplies. Arid regions can be expected to have limited quantities of high solids
water. Wet areas have large quantities of water usually low in dissolved solids. Flatlands have
greater amounts of groundwater. Mountains and hilly country have greater amounts of surface
water. Large rivers have turbidity but relatively low dissolved solids water. Farmland streams may
be highly contaminated with organic nitrogen.
Perhaps some experts can predict the water characteristics of a given area, but it is at best an
educated guess, and such predictions should not be used for long-range planning or design.
2.2.2.3
Organic Constituents
Organic compounds have carbon and usually hydrogen and oxygen as the main elemental
components in their structural framework. By definition, carbon is the key element. The species
carbonic acid (H2CO3-1), carbon dioxide (CO2), bicarbonate (HCO3-1), and carbonate (CO3-2), which
are important constituents in all water, are not, however, classified as organic compounds.
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Dissolved organic matter is ubiquitous in natural water, although the concentrations are generally
low compared to the inorganic constituents. Little is known about the chemical nature of organic
matter in water. Investigations of soil water suggest that most dissolved organic matter in
subsurface flow systems is fulvic and humic acid. These terms refer to particular types of organic
compounds that persist in subsurface waters because they are resistant to degradation by
microorganisms. The molecular weights of these compounds range from a few thousand to many
thousand grams. Carbon is commonly about half of the formula weight. Although little is known
about the origin and composition of organic matter in water, analyses of the total concentrations of
dissolved organic carbon (TOC) are becoming a common part of water investigations.
Concentrations in the range of 0.1 to 10 mg/L are most common, but in some areas values are as
high as several tens of milligrams per liter.
2.2.2.4
Dissolved Gases
The most abundant dissolved gases in water are nitrogen (N2), oxygen (O2), carbon dioxide (CO2),
methane (CH4), hydrogen sulfide (H2S), and nitrous oxide (N2O). The first three make up the earth’s
atmosphere and, therefore, it is not surprising that they occur in surface water. Methane, hydrogen
sulfide, and nitrous oxide can often exist in water in significant concentrations because they are the
product of biogeochemical processes that occur in non-aerated surface zones. The equilibrium
equations for H2S and CO2 are as follows:
H2S
H2S (g)  H2S (l)
H2S +H2O  H3O+ + HSHS-+ H2O  H3O+ +S2CO2
CO2 (g)  CO2(l)
CO2 + H2O  H2CO3  H+ + HCO3  H+ + CO32-
Dissolved gases can have a significant influence on the surface hydrochemical environment. They
can limit the usefulness of water and, in some cases, can even cause major problems or even
hazards. For example, because of its odor, hydrogen sulfide at concentrations greater than about
1 mg/L renders water unfit for human consumption. Hydrogen sulfide bubbling out of solution can
accumulate in wells or buildings and cause explosion hazards. Gases coming out of solution can
form bubbles in wells, screens, or pumps, causing a reduction in well productivity or efficiency.
Radon 222, a common constituent of water because it is a decay product of radioactive uranium
and thorium, which are common in rock or soil, can accumulate to undesirable concentrations in
unventilated spaces. Decay products of Radon 222 can be hazardous to human health.
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2.2.2.5
Alkalinity
A basic understanding of alkalinity relationships is important in the study of water chemistry. The
alkalinity of water is the capacity of that water to accept protons (combine with hydrogen ions). It
is a measure of the capacity of the water to neutralize acids. The alkalinity of natural waters is due
primarily to the salts of weak acids. Weak acids do not completely dissociate into ions in solution.
The salts of weak acids, however, dissociate more completely. Therefore, the negative ions of the
weak acids combine with the available hydrogen ions. Alkalinity affects hardness, other ion
solubility, and pH.
Although several basic compounds can contribute to the alkalinity of water, in most natural waters
the alkalinity is described by the following relationship:
Total alkalinity = [HCO3-] + 2[CO3-2] + [OH-]
Bicarbonates (HCO3-) represent the major form of natural alkalinity, because they are formed in
considerable amounts from the action of carbonic acid (carbon dioxide plus water) upon basic
materials in the soil. At low carbon dioxide concentration (higher pH), carbonate alkalinity can be
present in natural waters. Hydroxide (OH-) alkalinity is normally not present in natural waters that
have not been treated or otherwise altered.
Carbon dioxide and the three forms of alkalinity are all part of one system that exists in equilibrium,
as can be seen by the following equations. The symbol ↔ indicates a reversible reaction. M is a
metallic ion.
CO2 + H2O ↔ H2CO3 ↔ H+ + HCO3M(HCO3)2 ↔ M+2 + 2HCO3HCO3- ↔ CO3-2 + H+
CO3-2 + H2O ↔ HCO3- + OH-
A change in the concentration of any one member of the system causes a shift in the equilibrium,
alters the concentration of the other ions, and changes the pH. Conversely, a change in pH shifts the
relationships.
The traditional analysis for alkalinity is by two-step titration with sulfuric acid. In the first step, a
phenolphthalein indicator turns the solution from pink to colorless at the end point (pH is about
8.3). In the second step, methyl orange indicator is added to the first-step liquid and the acid
titration continues until a pink color develops. At this point, the pH is about 4.5 and all of the
alkalinity has been neutralized. The first end point is noted as the P alkalinity and the second end
point as the M or total alkalinity. From these data, established alkalinity relationships are shown in
Table 2-2.
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Table 2-2
Alkalinity Relationships
HYDROXIDE
ALKALINITY AS
CaCO3
CARBONATE
ALKALINITY AS
CaCO3
BICARBONATE
ALKALINITY AS
CaCO3
P=0
0
0
M
P = 1/2M
0
TITRATION
RESULT
P < 1/2M
P > 1/2M
P=M
0
2P
M – 2P
2P – M
2(M – P)
0
M
2P
0
0
0
Table 2-2 is theoretical and does not take temperature into account. Although a figure based on an
actual solution in an experimental situation is more an indication of actual alkalinity relationships,
the table can be used for most purposes.
The presence or absence of the following constituents and the amounts of those present may be
determined as follows:
Calcium Alkalinity
=
Calcium Hardness or Alkalinity, whichever is smaller.
(1) Magnesium Alkalinity =
Magnesium Hardness, if Alkalinity ≥ Total Hardness.
(2) Magnesium Alkalinity =
Hardness.
Total Alkalinity – Calcium Hardness, if Alkalinity < Total
Sodium Alkalinity
=
or
Alkalinity – Total Hardness.
(If any calculation results in a zero or negative number, that substance is not present.)
Low levels of alkalinity can make water corrosive. Purified waters such as demineralized water or
reverse osmosis (RO) permeate are corrosive to mild steel because of their low levels of alkalinity.
In some cases, a water supply may need to be stabilized with the use of a limestone bed to mitigate
corrosion issues.
2.2.3
Basic Water Chemistry
To understand the need for specific water treatments and what those treatments accomplish, some
basic chemistry needs to be discussed involving water and the components dissolved in water.
The chemistry of water treatment is based on what is dissolved in the water and how those
constituents behave. To understand how the different components affect the water chemistry, the
chemistry of dissolving should be understood.
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The most common contaminants that are dealt with in water are the ions produced from dissolving
solids found in the soil and rocks through which the water passes. These items are commonly
called minerals and salts when in their natural state, but chemists call them ionic compounds.
These ionic compounds are composed of negatively charged particles and positively charged
particles. The negative and positive particles are joined together, like opposite poles of a magnet
are stuck together, when found in an undissolved state. But, when they are dissolved in water, they
dissociate (or split apart) forming what we refer to as “ions” in solution.
The positively charged particles are called cations and the negatively charged particles are called
anions. Common ionic compounds that are dissolved in natural water sources include calcium
carbonate, magnesium sulfate, and sodium chloride, which is common table salt. Once dissolved in
the water, the ions are free to move independently and form new chemical combinations.
Since it would be laborious and time consuming to write out, in full, the various chemical
combinations, chemical symbols have been assigned to the various ions so that the various
chemical combinations may be shown in a simplified manner. The symbols for the substances most
commonly encountered in water are as follows:
Positively Charged Units
Valence
Calcium, Ca
+2
Iron, Fe
+ 2 or + 3
Magnesium, Mg
Sodium, Na
Manganese, Mn
Aluminum, Al
Hydrogen, H
Potassium, K
Negatively Charged Units
Bicarbonate, HCO3
Carbonate, CO3
Hydroxide, OH
Sulfate, SO4
Chloride, Cl
Nitrate, NO3
+2
+1
+ 2 or + 3
+ 2 or + 3
+1
+1
Valence
-1
-2
-1
-2
-1
-1
The positive and negative ions combine to form compounds. The valence shows the combining
equivalent of the positive and negative ions. For example, one sodium (Na) with a valence of + 1
can combine with one chloride (Cl) with a valence of -1 to form NaCl (sodium chloride, i.e., common
table salt). Note that the +1 and -1 add up to zero.
Each chemical combination has a different solubility in water. (Solubility is a measure of the
number of particles that will be dissociated when the substance comes in contact with water.) For
example, sodium carbonate is very soluble in water, and almost all combined particles of sodium
carbonate will dissociate in water. While in water, a carbonate anion (CO3-2) may meet up with a
calcium cation (Ca+2), and together they form calcium carbonate (CaCO3), which has a very low
solubility in water and may precipitate out of the solution as a solid.
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2.2.3.1
Units of Measure
Before the determination of how to treat a water source, it is necessary to not only know what is
dissolved in the water but also how much of each constituent is dissolved. The discussion of
solubility in Subsection 2.2.3 is based on the measurement of how much of a compound will
dissolve in water. Solubility is usually expressed in mg/L. The following information explains the
units of measure for most constituents used to quantify water impurities:
mg/L
Ppm
Epm
mg/L as
CaCO3
Gpg
2.2.3.2
Water chemistry typically does not deal with percentage level of impurities in the
water. It is more common to use mg/L. That is the milligrams of constituent dissolved
in a liter of water.
Another common measurement is parts per million. That is an equal measurement
without units. For example, 100 grams dissolved in 1,000,000 grams would be
100 grams/1,000,000 grams. The gram unit cancels out leaving 100 parts per million,
ppm. In pure water, the terms mg/L and ppm are functionally equivalent. The reason
is that 1 liter of water without significant dissolved solids content is roughly equal to
1,000,000 mg. That gives x mg/1,000,000 mg or x ppm.
Equivalent weight is defined as the weight of an ion that will displace the same amount
as a unit weight of hydrogen (the smallest ion). Equivalent weight is equal to
molecular weight divided by the valence. This is generally reaction dependent. The
epm is equal to the ppm divided by the equivalent weight. This measurement is useful
because all chemicals are on a hydrogen based system. That means that they can be
compared directly using the epm. The epm is usually used when determining chemical
feed dosages.
Similar to the epm, the CaCO3 equivalent reduces all constituents to a common
denominator. The formula to figure out the CaCO3 conversion factor for a given ion is
the equivalent weight of CaCO3/equivalent weight of the ion. The equivalent weight
for CaCO3 is 50.1. To find the CaCO3 equivalent for an ion, multiply the concentration
of the ion (mg/L) by the CaCO3 conversion factor. When the CaCO3 equivalent is used,
the sum of the anions should equal the sum of the cations. Other chemical
comparisons in water treatment also use the CaCO3 equivalent.
Grains per gallon is used for an equivalent measurement for acids and caustics by US
manufacturers in demineralizer design and demineralizer resin ratings.
1 gallon = 8.34 pounds. 1 pound = 7,000 grains. 1 gpg = 17.1 mg/L.
Constituents in Water
Now that there is an understanding how the components get into the water and how to work with
the measurements of how much is in there, it is time to move on to the impurities of the water that
are cause for treatment.
Calcium
Concentrations normally range from 5 to 500 mg/L as CaCO3 in water. It is dissolved into water
from contact with limestone formations and gypsum formation. Calcium is a constituent of
hardness. Calcium is a limiting factor in cooling tower cycles of concentration. Typically, a
concentration above 900 mg/L as CaCO3 that is below a temperature of 100° F (38° C) will cause
precipitation of CaCO3 and a scaling condition. Proprietary scale inhibitors, however, can be used to
exceed this calcium limit without scaling.
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Magnesium
Concentrations normally range from 40 to 200 mg/L as CaCO3, generally one third of the calcium
concentration. It is dissolved into water from contact with dolomitic limestone formations.
Magnesium is a constituent of hardness. Magnesium salts break down at high temperatures and
will form scale in boilers or other high temperature systems.
Sodium and Potassium
In freshwater, these constituents normally range from 20 to 200 mg/L as CaCO3 combined. In
seawater the concentrations can be as high as 35,000 mg/L as CaCO3 combined. These constituents
come from contact with rock formations containing these constituents and entrainment from any
saltwater sources. Brackish water and seawater are very high in sodium because of the
concentration effect of evaporation. Sodium solids are very soluble, so there is very little
precipitation of sodium except at very high temperatures. Sodium scale rarely occurs. Sodium and
potassium can have detrimental effects in boiler water, where they can carry over with the steam to
cause pitting corrosion in the afterboiler area. Sodium and potassium can also cause problems in
combustion turbine evaporative coolers when present in the inlet cooling water.
Mineral Acidity
Surface waters contaminated with industrial wastes contain sulfuric acid plus ferrous, aluminum,
and manganous sulfates, which all are corrosive to ferrous metals.
Bicarbonate and Carbonate
These constituents come from contact with rock formations. Carbonate is rather unusual and found
only in small amounts in water. Carbonates and bicarbonates are associated with calcium,
magnesium, sodium, and potassium. They are responsible for the alkalinity of water, which buffers
the water from pH changes caused by the addition of acidic or basic compounds.
Sulfate
Sulfate comes from contact with rock formations and has a normal range of 5 to 200 mg/L as CaCO3.
Sulfates are soluble to about 2,000 mg/L. High levels of sulfates can cause calcium sulfate scaling or
sulfate attack on concrete structures contacted by circulating water.
Chloride
Concentrations range from 10 to 100 mg/L in freshwater and around 30,000 mg/L as NaCl in
seawater. The chloride ion comes from contact with rock formations and from saltwater intrusion
of seawater in freshwater sources. High chloride levels are of concern because of their corrosive
effect on metals. The concentration of chloride is limited in the boiler water because of pitting
caused by NaCl. The concentration of chlorides may also dictate the material of construction for the
condenser tubes (refer to Table 2-3). The concentration of chloride also affects the solubility of
calcium sulfate in scrubbers.
Nitrates
Nitrates are a result of the nitrogen cycle. The combination of air and organic material creates
ammonia. They are usually indicative of sewage or agricultural pollution. Nitrates are usually only
present in very small amounts.
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Iron and Manganese
Both iron and manganese create serious problems in water supplies. Iron exists in soils and
minerals mainly as insoluble ferric oxide. Manganese exists primarily as manganese dioxide, which
is insoluble in water containing carbon dioxide. Iron and manganese are responsible for
encrustation, staining, and fouling. For most plant services, the iron content should not exceed
0.1 mg/L. The manganese limit for circulating water is reported by Electric Power Research
Institute (EPRI) as 0.5 mg/L and by a cooling tower manufacturer as 0.1 mg/L.
Silica
Concentrations typically range from 1 to 100 mg/L. Silica is the second most abundant element in
nature (oxygen is first), and it comes from most rock formations. Silica produces a hard, glass-like
scale on heat exchanger surfaces. Especially vulnerable are surface condenser tubes in closed
(cooling tower) loop cooling systems, where the circulating water becomes concentrated because of
tower evaporation. The most harmful effect of silica is its deposits on turbine blades. This occurs
when silica dissolves in the generated steam in the boiler and is carried over onto the turbine
blades. Such deposits reduce the turbine operating efficiency.
Silica should be controlled at less than 0.01 mg/L (confirm this value with the steam turbine
manufacturer) in the feedwater and less than 0.01 mg/L in the steam. Since silica can enter the
system as sand and dust, one preventive measure must be a dustproof system that is thoroughly
cleaned before closure. Silica can also enter the condensate through a condenser tube leak. Boiler
blowdown is a tool for controlling silica concentration.
The available technologies for removal of silica either only partially remove silica or remove silica
as part of demineralization. Silica is partially removed by adsorption onto precipitated magnesium
hydroxide as part of a chemical softening process. Silica can be reduced to low levels by utilizing
RO, ion exchange, or an evaporative process; however, reduction of silica to low levels while not
removing the bulk of all the other dissolved solids is not achievable.
Suspended Matter
Suspended matter consists of suspended oil, precipitated iron, and other miscellaneous debris. It
causes deposits in heat exchange equipment and boilers. Suspended matter makes water unusable
for most purposes until removed. Suspended matter is often reported as TSS (total suspended
solids) or as turbidity.
TSS is a very useful parameter since it gives a direct mass measurement of the solids that are
suspended in solution. However, TSS measurement in a laboratory is difficult, and online TSS
measurement is not practical. Turbidity is measured in Nephelometric Turbidity Units (NTUs).
Turbidity is often used as a substitute for TSS measurement because of the relative ease of
obtaining turbidity data. Turbidity is a measurement of the reflection of light as it is passed
through a sample. A sample with higher suspended solids will have a tendency to reflect more light,
resulting in a higher turbidity. The correlation between turbidity and TSS is specific to the size,
shape, and light absorption/reflection properties of the suspended solids and, therefore, is specific
to the water supply.
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Dissolved Oxygen
Oxygen is a significant factor in the corrosion of metal alloys, particularly in piping systems and in
the condensate feedwater cycle. Oxygen is only slightly soluble in water, and the solubility
decreases with increased temperature. Oxygen can be reduced to a very low concentration by a
mechanical deaerator. Chemical treatment to reduce oxygen concentrations is no longer
recommended because it contributes to flow-accelerated corrosion in steam cycle piping/tubing.
Color
Color in water comes from decaying organic matter and from the presence of iron and manganese.
The color is usually yellowish or brownish after suspended matter has settled or been removed.
Color in the water causes staining and may inhibit or retard chemical reactions. It is important to
note that even low concentrations of organic matter can color the water significantly.
Fluorides
Fluorides come from contact with many rock formations. Fluorides cause mottled tooth enamel in
children but is not usually significant industrially. High levels of fluorides in a flue gas
desulfurization system can be problematic because of aluminum fluoride blinding of the reagent.
Treatment specifically for the purposes of fluoride removal is rare.
Oil
Oil comes from industrial wastes in surface supplies, from lubricating oil in condensate, and from
general plant uses such as equipment washdown. Oils induce boiler foaming and stimulate boiler
carry-over. They also tend to carbonize and can cause scaling on all heat transfer surfaces.
Preventive measures are the best insurance against oil in the water.
Biological Oxygen Demand
Biological oxygen demand, reported as BOD5, is an indication of the concentration of organic matter
in the sample. BOD5 is based on the principle that aerobic biological decomposition by
microorganisms will occur until the organic matter is consumed if sufficient oxygen is available.
The BOD5 test measures the dissolved oxygen concentrations at the beginning of the test as well as
5 days later.
Chemical Oxygen Demand
Chemical oxygen demand, reported as COD, is also an indication of the concentration of organic
matter. The COD test takes only a few hours to complete and is, therefore, easier to perform than
the BOD5 test. The COD test utilizes potassium dichromate in a 50 percent sulfuric acid solution to
oxidize both organic and inorganic substances. COD values are typically higher than BOD5 values
since BOD5 does not measure the oxidation requirements of inorganic substances.
Total Organic Carbon
Total organic carbon, reported as TOC, is an indication of the organic carbon that is present in the
sample. In the TOC test, organic carbon is converted to carbon dioxide and is then typically
measured with an infrared analyzer.
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Total Dissolved Solids
By definition, TDS of water is the residue remaining after evaporation of a filtered sample. It can
also be defined as the total of all the dissolved ions in the water. The two definitions differ because
the evaporation residue does not contain the solids that may have volatilized or have been
converted to gaseous compounds and carried out with the water vapor. Thus, a solids
concentration determined by evaporating a sample in the laboratory would be smaller than if the
solids concentration were calculated by adding the analytical value of all ions (including heavy
metals, bicarbonates, carbonates, and silica). Because there is no correlation between the two
values, both must be determined separately if both are needed.
If dissolved solids content is being used to determine the scaling potential of the water, the
evaporative value is preferentially used, if available. In demineralizer design, the actual total ion
concentration is needed, so the calculated value should be used.
TDS have an appreciable effect on the design of demineralization systems and affect the corrosive
and scaling tendency of the water. Normally, natural waters with a TDS less than 1,000 mg/L
should not be of concern. Palatability is a concern if TDS is greater than 1,000 mg/L, but brackish
water or seawater with a TDS greater than 30,000 mg/L can be used for cooling. It can be seen that
TDS content alone cannot be used as a criterion for the usability of the water.
Hardness
Historically, hardness is defined as the soap consuming power of water. The higher the hardness of
the water, the more soap is consumed. Hardness is defined as the sum of the concentration of Ca
and Mg as calcium carbonate (CaCO3). Hard water will form scale on metal surfaces when heated or
boiled. There are two types of hardness:


Carbonate hardness results from combination of Ca and Mg with bicarbonate (HCO3-). It is
also referred to as temporary hardness. This type of hardness precipitates out when the
water is heated (not boiled), so it is easy to remove.
Noncarbonate hardness results from a combination of Ca and Mg with SO4 and Cl. It is also
referred to as permanent hardness because these compounds remain soluble when heated.
These compounds also form harder scale when the water is boiled.
After determining the amount of hardness in the water, it is possible to determine hardness form by
comparing total hardness with alkalinity (Alk), assuming Alk = HCO3.
If Hardness > Alkalinity,
Carbonate Hardness = Alkalinity, Noncarbonate Hardness = Hardness – Alkalinity
If Hardness = Alkalinity,
Carbonate Hardness = Alkalinity, Noncarbonate Hardness = 0
If Hardness < Alkalinity,
Carbonate Hardness = Hardness, Noncarbonate Hardness = Alkalinity Hardness
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This comparison can be used to predict treatment methods. Carbonate hardness can be reduced to
35 ppm by lime softening and to 0 ppm by ion exchange. Noncarbonate hardness can be reduced by
adding soda ash to the lime softening process.
pH
pH is an indication of the acidity or alkalinity of a solution. This is a measurement of intensity, not
of quantity. pH is measured as the inverse log of the hydrogen ions. Most natural waters have a pH
of 6.0 to 8.0.
Specific Conductance
Specific conductance is a measurement of water’s capacity to conduct an electric current. This
property is related to the total concentration of the ionized substances in water and the
temperature at which the measurement is made.
An aqueous system containing dissociated molecules will conduct an electric current. Most
inorganic acids, bases, and salts are good conductors. In a direct-current field, the positive ions
migrate toward the negative electrode and the negative ions migrate toward the positive electrode.
The standard unit of electrical resistance is the ohm. The standard unit of electrical conductance is
the inverse of the ohm, the mho. The measurement of conductance or resistance implies the use of
two electrodes 1 cm square placed 1 cm apart. Therefore, specific conductance is generally
reported as micromhos per centimeter (µmhos/cm). The “modern” unit of measure of conductance
is the microSiemen/cm. 1 microSiemen/cm (µS/cm) is the same value as 1 micromho/cm. A
conductance cell and a Wheatstone bridge are used to measure the electrical resistance in reference
to a standard potassium chloride solution. The standard temperature is usually 77° F (25° C), and
corrections must be made for samples tested at other temperatures.
Specific conductance is a quick, simple way to determine the total solids content of water. It does
not measure the TDS content of the water as such, but the two are related, and for a rough estimate
it can be assumed that the specific conductance in µS/cm is equal to 1.6 times the TDS in mg/L as
measured by TDS residue test. A lower factor may be required for saline water and a higher factor
for water with considerable hydroxide or free acid.
The conductivity of demineralized water should be approximately 0.1 µS/cm. Most natural waters
will have conductivity between 50 and 500 µS/cm.
Saturation Indices
Water sources have a tendency to be either corrosive or scaling. Several different indices have been
developed to quantify the corrosive or scaling tendency of water. The saturation indices are
calculated as follows:
LSI (Langelier Saturation Index) = pH - pHs
RSI (Ryznar Stability Index) = 2*pHs - pH
PSI (Puckorius Scaling Index) = 2*pHs - pHeq
pH = Actual pH
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pHs = (9.3 + A + B) – (C + D)
A = [Log10 (TDS) – 1]/10
B = -13.12Log10(Temp °C + 273)+34.55
C = Log10 (Calcium Hardness as CaCO3) – 0.4
D = Log10(Total alkalinity as CaCO3)
pHeq = 1.465[Log10(Total alkalinity as CaCO3) + 4.54
If the LSI is positive, the water will have a scaling tendency; a negative LSI indicates that the water
will have a corrosive tendency. An RSI or PSI value below 6 will have a scaling tendency; a value
above 6 will have a corrosive tendency. All three of these saturation indices are logarithmically
based, and therefore, every one point of change in the index translates to a tenfold increase or
decrease in the scaling or corrosive nature. It is also important to note that these indices
specifically address calcium carbonate formation, and that other scale forming chemistries are not
considered.
The RSI was developed by John Ryznar in response to the observation that it is possible for both
low hardness and high hardness waters to have the same LSI value. He developed the RSI to give
greater distinction and significance to the index value by increasing the scale and by making the
index values positive. Unlike the LSI and RSI, the PSI is calculated using a theoretical equilibrium
pH rather than the actual pH of the system. The equilibrium pH is calculated using the total
alkalinity and is used instead of the actual pH to account for the buffering capacity of the water and
the scale present in the water at equilibrium.
When selecting an index to use, consider the level of conservatism appropriate for the design and
whether the index is appropriate for the type of system. These indices should not be used to predict
the scaling potential for salt or brackish waters because they have been correlated to fresh water
data. If needed, other indices have been developed to predict scaling potentials for salt and brackish
waters.
Of the three indices, the LSI is the most conservative. While the RSI is calculated using the same
variables as the LSI, the RSI is considered less conservative because of the difference between the
two scales. The PSI tends to be the least conservative of the three. Additionally, the PSI should only
be used for water systems that are open to and in equilibrium with the atmosphere. This ensures
that the CO2 has reached equilibrium in the water yielding more representative carbonate and
bicarbonate concentrations. When considering the three indices, the LSI or RSI can be selected if it
is desired to see how manipulating the pH of the water would affect the scaling potential. This
cannot be done with the PSI because it is based on a theoretical equilibrium pH.
When evaluating results, keep in mind that the indices were developed using data from municipal
water treatment systems. The water in municipal systems typically has a longer residence time
than water in industrial processes, which is a factor that is not accounted for in the index
calculations. Something to also consider when using these indices is that they indicate the
propensity for precipitation to occur, not the quantitative result. These calculations are based on
equilibrium and solubility, not kinetics, so they do not indicate how much or how long it will take
for scale to form in a system.
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2.2.4
Analysis Report
The kind and amount of the various dissolved and suspended solids in a water sample are
determined by standardized laboratory testing methods. Some determinations are made by
actually weighing the constituent being determined, others are made by titration with standardized
reagents. These tests can determine the amount of calcium, magnesium, bicarbonate, sulfate,
chlorides, silica, alkalinity, acidity, etc. For each constituent, the results are reported in units (mg/L,
ppm, or g/gal) of that constituent stated as ions, such as calcium, magnesium, etc., or alternately
stated as hypothetical chemical compounds such as calcium carbonate, calcium sulfate, etc. A list of
Environmental Protection Agency (EPA) methods, standard methods, and ASTM test methods are
found in the file WTRQUAL rev 2.xls (refer to Section 2.3, References).
For many years it has been the practice to report hardness and alkalinity in terms of CaCO3
equivalent. By the use of conversion factors, all constituents determined by analysis can be
converted to CaCO3 equivalent. Having converted the amount of all dissolved constituents to
equivalents, the “arithmetic” of water chemistry is simplified. For example, the sum of all the
positively charged ions, expressed as CaCO3, called cations, gives us the total cation content of water
expressed as CaCO3. Similarly, the sum of the negatively charged ions or radicals called anions,
expressed as CaCO3, gives us the total anion content expressed as CaCO3. In a correct analysis, the
sum of the cations is always equal to the sum of the anions when both are expressed as CaCO3.
In actual practice, the sum of the cations is seldom precisely equal to the sum of the anions because
of normal analytical errors experienced with the analysis of each individual constituent. A variation
of 2 to 5 percent between the cation and anion balance in actual analyses is generally considered
acceptable. In some cases, the analysis may not be complete and a constituent such as sodium may
be determined by the difference between the cation and anion balance; the final adjusted analysis
then presents an exact balance.
For convenience, Black & Veatch has developed a form with the conversion factors indicated for
reporting water analysis data. This form is used to summarize water data received and determine
water quality data to be used for equipment design.
2.2.5
Water Resources Data
Surprisingly, it is often difficult to obtain reliable water data for a given area. The US Army Corps of
Engineers (USACE) can usually provide comprehensive flow data on all major and most minor
rivers and streams. But quantity data on groundwater and quality data for both surface and
groundwater are usually very limited and often unreliable.
The following sources of data may have to be explored:





USACE.
US Geological Survey (USGS).
State and local geological, health, and water resources agencies.
Local public utility companies.
State or local agricultural agencies.
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

Local well drillers.
Environmental and pollution control organizations.
If time and the scope of the project allow, samples can be collected and analyzed and test wells
drilled.
For surface water, especially on rivers or streams, multiple analyses will be required to ascertain
seasonal and annual variations. Groundwater will usually maintain constant quality if the aquifer is
not overpumped or fed by a surface water supply. When multiple quality data are used, the
analysis having the highest total solids should be used for design. If a typical analysis is required, it
should be an actual analysis that is nearest in composition to the average analysis of the available
data. In no case should an average analysis be used. A design analysis should be established on the
basis of the available data. Design analysis is typically based on the analysis with the highest
concentrations of dissolved solids. The design analysis may also be adjusted to account for higher
levels of specific constituents that may be present in analyses that were not used as the starting
point for the design analysis. It is also common to adjust the concentration of one of the
constituents in the design analysis (typically sodium) so that the cations and anions balance.
In some cases, a water supply has unique or unpredictable treatability characteristics. If practical,
the chemical engineer should check with the client to see whether there is anything unique about
the water supply or the treatment requirements and limitations. It may also be possible to contact
other industries within the local area to determine what their experience has been with the
treatment and use of the water source. This is more critical when a water supply has a higher
likelihood of having unique characteristics, such as the tertiary treated effluent from a municipal
wastewater treatment facility.
2.2.6
Treated Municipal Wastewater
Because of increasing shortages of good quality water, treated municipal wastewater is being
considered as a source of supply for power plants. Typical treatment processes used to treat
municipal wastewater include the following:



Primary treatment–-Removes approximately 50 percent of the suspended solids by settling
and/or filtration.
Secondary treatment–-Removes dissolved and suspended biological matter. Suspended
solids reduction is typically 90 to 95 percent of what is not removed by primary treatment.
Secondary treatment is typically an activated sludge process.
Tertiary treatment–-Any further treatment that is performed for the wastewater to meet
specified water qualities for reuse or special discharge requirements. Treatment can
remove additional solids, provide additional disinfection, and/or reduce specific
constituents like phosphorus and nitrogen.
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To be considered for use, the wastewater should have secondary treatment at a minimum.
Secondary treated wastewater has approximately 90 percent of the suspended solids and
90 percent of the 5 day biochemical oxygen demand (BOD5) removed. Common concerns regarding
the reuse of treated wastewater include the following:






2.2.7
Treated municipal wastewater can affect microbiological control within equipment, storage
tanks, collection ponds, and cooling towers. Additional chemical feeds may be required
since ammonia, nitrate, and phosphate are nutrients for microbiological growth.
TSS may be higher and require clarification or filtration to increase the cycles of
concentration within the cooling tower. Lime softening may also be required to remove
hardness (which contributes to scaling).
TDS concentration is higher than potable water sources and can impact demineralized
water treatment equipment design.
High chlorides concentration could impact the cooling tower cycles of concentration and/or
the condenser tube material.
High phosphate and TOC concentrations in the water can affect cooling tower operation and
can cause scaling/fouling of membranes.
If the site returns its wastewater to the same treatment facility where it receives treated
wastewater for use, a problematic cycling up of certain constituents could occur.
Description of Water Uses in a Power Plant
A power plant has many uses for water. Most plants have the same basic uses for water, but the
water source, water qualities, amount of water required, and the treatment methods differ for each
facility. Though every power plant has a multitude of water uses, the primary uses can be
categorized as cooling water, service water, demineralized (high purity) water, and potable water.
The following is a short description of these uses.
Cooling Water
Cooling water includes the water used for condenser cooling in the steam cycle heat rejection
system and for the cooling of auxiliary equipment. The condenser cooling system can be a oncethrough system with the discharge returned to the river or surface impoundment which is serving
as the source, or a recirculating cooling system using a cooling tower.
Once-through cooling systems were common in the past. Waters with up to approximately
50,000 mg/L of TDS can be used. The pH of once-through cooling water normally ranges between
about 6 and 8.5. pH adjustment is rarely used. Biocide injection is typically required for control of
biofouling and macroinvertebrate control. Once-through cooling systems utilize a much higher
water flow rate than open recirculating cooling systems because the water is only heated and not
evaporated to aid in cooling.
Open recirculating cooling systems using a wet cooling tower are most often used currently. Open
recirculating cooling systems with cooling towers require biological control, pH adjustment, and
inhibitor feed for control of scaling. Water requirements for cooling towers are much more
stringent than once-through systems. Cooling tower limits for water quality vary depending on the
chemical conditioning program being utilized at the power plant, but generally, the quality
maximum guidelines shown in Table 2-3 can be used for the circulating water.
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Table 2-3
Cooling Tower (Circulating) Water Quality Limits
CONSTITUENT
LIMIT
Calcium, mg/L as CaCO3
900
Silica, mg/L as SiO2
150
Alkalinity, mg/L as CaCO3
150-200(1)
[Magnesium, mg/L as CaCO3] X [Silica, mg/L as SiO2]
Chloride, mg/L as Cl(3)
Sulfates, mg/L as CaCO3
35,000(2)
200
(304SS condenser tubes)
1,000 (316SS condenser tubes)
>1,000 (titanium condenser tubes)
800
[Calcium, mg/L as such] X [Sulfate, mg/L as such]
500,000(4)
Iron, mg/L as Fe
3
Manganese, mg/L as Mn
0.1
Nitrate, mg/L as NO3
300
Phosphate, mg/L as PO4
(5)
Total Dissolved Solids, as ppm
> 5,000 ppm can derate thermal
performance
Total Suspended Solids, as ppm
150(6)
Oil and Grease, as ppm
5(7)
Sulfides, mg/L as H2S
1.5(7)
Ammonia, mg/L as NH3
25(7)
(1)Alkalinity in the cooling tower is controlled by feeding sulfuric acid. This limit should be used to
calculate the quantity of acid required and should be the basis for determining tower cycles of
concentration.
(2)While the <35,000 solubility product guideline is useful, it is important to note that control of
magnesium silicate depositions is sensitive to the circulating water pH. When the pH is at or below
7.5, the solubility product defined above could approach 100,000 with only limited concern for
excessive magnesium silicate deposition.
(3)The chloride limits listed are used for materials of construction only. General guidelines and the
true compatibility of these materials are dependent on other parameters including sulfates, pH, and
temperature. The Responsible Engineer should consult with the Materials Application Section for
project-specific material requirements.
(4) The solubility product could be increased up to 2,400,000 if a common scale inhibitor such as AMP,
HEDP, or PAA is used. The solubility product could be increased to 10,000,000 if a phosphine
carboxylic acid type scale inhibitor is used.
(5) Typically, only a concern if phosphate is present in the feedwater. Calcium phosphate solubility is a
function of calcium and phosphate concentrations, pH, and temperature and will require research.
(6)The total suspended solids limit is based on the type of cooling tower fill used. Total suspended
solids is influenced by the solids in the makeup water, the cooling tower cycles of concentration, as
well as the amount of solids scrubbed out of the air by the cooling tower.
(7)The oil and grease, sulfides, and ammonia limits are based on the type of cooling tower fill used.
Refer to the cooling tower manufacturer proposals for project-specific limits.
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The amount of recirculation that can be completed in a cooling tower is referred to as the cycles of
concentration. The water mass balances referenced in Section 3.3 contains a calculation that can be
used to determine the design cycles of concentration for a specific plant/water source based on the
constituents listed above that most commonly limit the cooling tower cycles of concentration.
These calculations also indicate the amount of acid feed required to meet the alkalinity limits.
Makeup to the open recirculating cooling system is required to replace losses in the cooling tower
resulting from evaporation, blowdown, and drift. This is covered in more detail in Section 3.0,
Water Mass Balances.
A completely closed cooling water system is often used to cool auxiliary equipment such as oil
coolers, air compressors, bearing water, etc. This system typically requires the use of inhibited
demineralized-quality water.
Service Water
Service water is used for general plant services such as sanitary water, washdowns, fire water, and
pump seal water.
Service water should be essentially free of suspended solids (less than 3 ppm), turbidity, and color.
The pH will typically be between 6.0 and 8.5, and TDS preferably limited to less than 1,000 mg/L.
Consideration should be given to the saturation indices to determine whether the water has a
tendency to be corrosive or scaling. Refer to Subsection 2.2.3.2 for information on LSI, RSI, and PSI.
Demineralized (High Purity) Water
Demineralized (high purity) water is required for makeup to the condensate feedwater cycle, as
dilution water for condensate feedwater chemicals and for various laboratory uses. The quality of
the water required is dictated by the quality necessary in the condensate feedwater system to
prevent scaling and corrosion and to prevent carryover of solids with the steam from the steam
generator. The boiler manufacturer specifies the water quality required for its equipment and
needs to be reviewed on every project.
Water quality requirements are also dependent on the operating pressure of the boiler, with higher
quality water required at higher pressures. Expected boiler feedwater quality required for a
subcritical all-volatile treatment-oxygenated (AVT-O) boiler in accordance with EPRI is as follows:









Dissolved oxygen
5 to 10 parts per billion (ppb) as such
Total iron
< 0.002 ppm as total iron
pH
9.2 to 9.6
Copper
Silica
Sodium
Alkalinity
≤ 0.002 ppm as such
≤ 10 ppb as such
≤ 3 ppb as such
0 mg/L as CaCO3
Specific conductance Consistent with pH
Cation conductance
< 0.2 µS/cm
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The cycle chemistry program (all-volatile treatment-reducing [AVT-R], AVT-O, oxygenated
treatment, etc.) and the presence or absence of copper tubing in the cycle will also affect the boiler
feedwater quality requirements. Although EPRI standards are most commonly referenced for
steam cycle chemistry considerations for power generation projects, other standards such as
American Society of Mechanical Engineers (ASME), American Boiler Manufacturers
Association (ABMA), International Association for the Properties of Water and Steam (IAPWS), and
VGD may also be considered. The EPRI standards are based on higher pressure boilers, and
therefore, ASME or ABMA standards will likely need to be referenced for projects that utilize lower
pressure boilers.
Potable Water
Potable water must be chlorinated and conform to applicable drinking water standards. Potable
water standards are typically dictated by the project location and by the governing authority (e.g.,
United States EPA, World Bank, or local country requirements). Potable water is typically supplied
from a municipal potable water supply. This can be combined with the service water system if it
meets potable water quality requirements; however, care must be taken to prevent backflow
contamination from service water users.
Occasionally, sites may generate potable water from a desalination system. Typically, the water
must be remineralized prior to consumptive use.
Potable water systems require disinfection prior to use. This is often accomplished by chlorination
to proscribed levels for certain durations.
2.3
References

Lawrence F. Drbal, ed., Power Plant Engineering, Chapman & Hall, New York, 1996.

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

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Water Analysis Form – WTRQUAL rev 2.xls (Found through the Industrial Water Treatment
Community page).
Stanley N. Davis and Roger J.M. DeWiest, Hydrogeology, John Wiley & Sons, 1966.
Robert J. Ferguson, Water Treatment Rules of Thumb: Myths or Useful Tools, French Creek
Software, Inc. (Found through the Industrial Water Treatment Community page).
Earth’s Water Supply. Element Four. http://www.elementfour.com/about-water-overview.
Accessed 8/28/2017.
A New Dynamic Method for Quantifying the Precipitation of Mineral Species from Aqueous
Solutions within Industrial Process Equipment. White Paper. Daniel Robinette, P.E. Merrick
& Company.
Examining Scaling Indices: What Are They? Water World.
http://www.waterworld.com/articles/iww/print/volume-12/issue-6/featureeditorial/examining-scaling-indices-what-are-they.html. Accessed 8/28/2017.
Scaling Indices. Corrosion Doctors. http://corrosion-doctors.org/Corrosion-byWater/Scaling-indices.htm. Accessed 8/28/2017.
Pierre R. Roberge: Corrosion Engineering. Corrosion by Water, Chapter (McGraw-Hill
Professional, 2008), Access Engineering.
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3.0
3.1
Water Mass Balances
Purpose and Applicability
This section provides instructions for the proper development of water mass balances in order to
characterize the power plant water use, define the design basis for permitting, and support design
of water/wastewater treatment equipment. The intent is to provide a uniform and consistent
approach to developing water mass balances for project execution of all Black & Veatch (B&V)
Energy projects.
It is anticipated that each Project Chemical Engineer will use this section to produce a projectspecific water mass balance for various project and proposal applications.
3.2
Approach
This section is intended to be used as a basis for the development of the project water mass
balance(s).
3.2.1
Proper Uses of the Water Mass Balance
The water mass balance should be utilized for the following activities:

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
Identify major water users for the plant.
Quantify the average daily and maximum daily water requirement and wastewater
generated for each of these users.
Define the overall treatment (makeup and wastewater) scheme for meeting the plant
demands.
Determine the equipment sizing for those parts that can be sized on the basis of an average
daily usage.
Calculate the average daily and maximum daily quantity and quality of wastewater.
Water mass balance calculation templates for different types of fuel sources and cooling
technologies are referenced in Section 3.3.
The Chemical design engineer should be consulted prior to sizing any equipment or piping based on
the project water mass balance. The intent of the balance is not to size equipment or piping;
additional detail is provided as follows.
3.2.2
Overview of the Water Mass Balance
A water mass balance diagram includes systems, represented by boxes, which identify the
equipment used to treat the water, provide the water, or use the water. Embedded within the
document, the water demand for each system is calculated, along with the inlet and outlet water
qualities. In some cases, the quality of the water is not tracked, which leaves a balance that
calculates the water flow rates only. Because the water mass balance is usually one of the first
project calculations, several assumptions or general guidelines are used to define water
requirements. These guidelines are included in each of the equipment subsections included in this
handbook and are summarized in Table 3-1.
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Table 3-1
Water Mass Balance Basic Design Values
PARAMETER
DESIGN BASIS
Cooling Tower Drift
0.001% of the
circulating
water flow
Clarification
Clarifier Efficiency (includes sludge thickening)
99%
Clarifier Effluent TSS
10 ppm
Solids Concentration in Clarifier Effluent Sludge
Conventional clarifier – Clarification only
1%
Dense sludge unit – Clarification only
4%
Conventional clarifier – Softening
3%
Dense sludge unit – Softening
8%
Media Filtration
Flow Rate Multiplier for Backwash
4
Length of Backwash
15 minutes
Number of Backwashes Performed (per filter)
1 time/day
Product TSS
1 ppm
Membrane Filtration
Outlet TSS
<1 ppm
Recovery Rate
90%
Cycle Makeup Rates
Percent of Total Steaming Rate as Steam Cycle Makeup
Combined cycle/gas plant
2%
Supercritical coal plant
2%
Coal/heavy oil plant/cycling combined cycle
3%
Percent of Makeup Rate as Nonrecoverable Losses
Combined cycle/gas plant
33%
Supercritical coal plant
100%
Coal/heavy oil plant
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PARAMETER
DESIGN BASIS
Condensate Polishing Guidelines
Final Quenched Boiler Blowdown Temperature
140° F
Time between condensate polisher precoats
3 weeks
Precoat Polishers
Water required per precoat application (per 1,000 gpm
condensate flow)
Deep Bed Condensate Polisher Waste
Hydrogen cycle (per 1,000 gpm condensate flow)
0.2 gpm
1.0 gpm
Ammonia cycle (per 1,000 gpm condensate flow)
0.25 gpm
Cycle Makeup Treatment
RO Yield*
First pass
75%
Seawater RO
40%
Second pass
85%
Demineralizer Yield
Cation/anion/mixed bed
90%
Electrodeionization Yield
90%
Mixed bed
98%
Potable Water Consumption
Without Shower Facilities (gallons/employee/day)
25
With Shower Facilities (gallons/employee/day)
75
Service Water Usage
Combined Cycle Plant
60 gpm
Coal Plant
100 gpm
Ash Handling
Percent Moisture in Bottom Ash
15-25%
Percent Water in Fly Ash (dry handling)
5-7%
Percent Water in Fly Ash (wet handling)
15-25%
Percent Water in Bed Ash (fluidized bed boiler)
Bottom Ash Evaporation, (gpm/day/ft2 of boiler opening)
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PARAMETER
DESIGN BASIS
Wastewater (Non-FGD)
Runoff Coefficients (c):
Ash Pile (compacted)
Asphalt
Coal and Gypsum Piles
Concrete
Grass
Gravel (road)
Gravel (surfacing)
Brine Concentrator Blowdown Total Solids (TDS + TSS)
Concentration
Crystallizer Waste Concentrate Total Solids (TDS + TSS)
Concentration
0.85-0.95
0.95
0.75-0.85
0.95
0.35
0.85
0.75
300,000 mg/L
500,000 mg/L
* RO yield is dependent upon water quality. Certain constituents such as
aluminum, barium, iron, manganese, silica, and strontium will scale or foul the
membranes above certain concentration.
TDS = Total dissolved solids
TSS = Total suspended solids
PPM = Parts per million
gpm = Gallons per minute
RO = Reverse osmosis
The water mass balance calculation, in almost all cases, is developed in an Excel file. Projectspecific inputs are entered along with general guidelines from Table 3-1 for information that is not
yet calculated or determined. Each of the systems identified on the water mass balance diagram
include calculations in the Excel file to determine water requirements and quality changes for that
system. Water quality from each of the systems is carried through the calculation and can either be
calculated or manually input depending on the process.
It should be noted that the water mass balance templates are not calculations where final results
are obtained from entering a set of specific inputs in the Excel file. Because each project is different,
the templates should be treated as starting points or shells of the final calculations. Equipment,
flow paths, and calculations will need to be modified as needed for the specific project. The water
mass balance is a working file and as additional design information is available, project updates are
made, or equipment information is received, the water mass balance should be updated.
The water mass balance is not a design document in the sense that flows shown on the balance can
be used to support detailed equipment and piping design. The water mass balance diagram is
configured to show time averaged flow rates over a full day or other defined time period, not
instantaneous water flow rates. For example, if equipment requires 500 gpm intermittently for
only 15 minutes at a time, 10 times a day, the flow rate shown on the water mass balance for that
piece of equipment would be 52 gpm, but this cannot be used to size piping, pumps, etc. In some
cases, a flow may be shown as 0 gpm even though there may be certain times when the
instantaneous flow is greater than 0 gpm. On-site storage tanks can provide a buffer for
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instantaneous flows; however, a separate detailed calculation will be needed for each tank, pump,
and piping system to establish a firm sizing basis. A statement should be included on the water
mass balance diagram to advise users not to use the time averaged flow rates to size pipe and
pumps. Instantaneous flow rates and fluctuations not included as part of the water mass balance
need to be considered when sizing equipment and pipe lines.
Within the water mass balance calculation, the water quality for each flow stream should be
determined, calculated, and/or carried through the balance. This is important and useful for
projecting water quality at different points in the plant. Depending on the purpose of the water
mass balance, this information can be used to assist in determining whether wastewater permits
will be met or for developing wastewater permits. If the balance is used for development of
permits, it may be desirable for the water mass balance to consider worst-case water quality and
include a margin on the constituent concentrations. The water mass balance should consider
constituents added to or removed from water streams through chemical addition/reactions. It is
important to note that the water mass balance guide calculation does not include calculations to
determine solubility of various constituents in the water streams; this must be evaluated for each
system by the Responsible Engineer. Solubility or impacts from chemical precipitation reactions
will need to be calculated separately. In some cases it may be appropriate to not calculate the
quality of the water streams and track the water flow only.
The water mass balance can also model water use at an existing plant. A specific project may
require modeling the existing plant to look at potential measures to conserve water, to help develop
a sizing basis for new equipment, or to determine if existing equipment will be able to handle
increased water demand or flow rates due to plant modifications. When simulating an existing
plant in a water mass balance, it is highly recommended to collect actual plant data (flows and
qualities) to accurately represent water use/quality at the plant.
3.2.3
Documentation
Several documents are needed and/or useful for creating a water mass balance. The more
information available, the fewer design assumptions will be required, resulting in a more accurate
result. All references and design basis assumptions used in the water mass balance should be
stated within the calculation.
3.2.3.1
Heat Balance and Selecting Cases
The heat balance is an important resource for developing the water mass balance. Typically, a
design basis heat balance is developed early in a project during a proposal stage or initial stage of
design. There are several heat balance cases for different ambient conditions and operating
configurations. For a combined cycle/gas plant, different operating conditions (besides the
manufacturer/model of the combustion turbine) include type of condenser (cooling tower versus
air-cooled condenser), use of power augmentation (steam or water injection), use of heat recovery
steam generator (HRSG) duct firing, use of inlet air cooling (evaporative or chillers), and the
number of combustion turbine/HRSG trains operating. For an industrial plant or oil and gas
facility, the different operating conditions may include maximum condensate return, all units on
line, partial units on line, or water supply alternatives. The plant water requirement will change for
each of these different operating conditions. It is not typically necessary to create a water mass
balance to model each heat balance case.
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Part of developing the water mass balance is to determine which cases will provide the greatest
amount of value. The following list outlines three general cases that should be evaluated unless
specific project or unique operating scenarios require additional cases:
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Maximum water use-–Typically, this case determines the daily water usage during the
maximum summer ambient conditions and is meant to quantify the maximum daily water
use for the plant. The largest water users for most plants are the cooling towers. When
ambient temperatures are highest, there will be more evaporation from the cooling tower,
increasing the plant water demand. This case should also be based on 100 percent load.
For combined cycle plants, the maximum water use case should include duct firing (if used),
type of inlet air cooling (if used), need for nitrogen oxide control injection water, and
steam/water power augmentation where applicable. All of these operations increase
overall plant water demand. If the cooling tower demand for a particular plant is not the
largest user, another operating scenario must be selected to define the maximum water use
at the plant.
Average water use–-This case estimates water use for an “average day,” typically where
conditions are averaged out over the course of a year. This case uses the heat balance case
that most closely represents the annual average ambient temperature and assumes full
operating load conditions during that day; typically, this is the guarantee point for the
facility. When this case is used to determine annual average water and wastewater flows, a
capacity factor can be applied to account for time off-line. For combined cycle plants, this
case should normally not consider supplemental firing since this is typically only utilized
during peaking conditions. Inlet air cooling operates based on the ambient temperature
and the annual average temperature/humidity can be used to determine when the
evaporative cooler is normally in service and assist in determining evaporation rates.
Winter water use–-This case is not always required; however, it can provide information
regarding water demand during the winter months. This balance case should utilize the
heat balance case based on the winter design temperature. Duct firing, power
augmentation, and inlet cooling will normally not be in operation for this case, but water
use rates can increase because of greater outputs obtained from combustion turbines under
winter conditions.
The following list of information is needed for development of the water mass balance and can be
found within the heat balance:



Ambient wet and dry bulb temperature along with relative humidity for each condition. If
only two of these values are in the heat balance, the third value can be determined using a
psychrometric chart or web-based calculator.
Operating information about the unit, including the percent load assumed for a specific case,
number of combustion turbines on line; number of boilers on line; net plant output;
cogeneration cases; and whether duct firing, power augmentation, and/or inlet cooling are
in operation.
The total steaming rate which is used as the basis for determining steam cycle
nonrecoverable losses and boiler/HRSG blowdown. For a combined cycle, the total
steaming rate is the sum of the individual high-pressure (HP), intermediate-pressure (IP),
and low-pressure (LP) rates (this needs to be verified on the basis of the cycle
configuration). Care should be taken in reading and interpreting the heat balance data since
the data can be easily misinterpreted.
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Cooling water information for closed loop cooling including condenser duty, cooling tower
evaporation rate, heat duty, and circulating water flow rate.
Inlet cooling (if applicable) evaporation rate.
Power augmentation and nitrogen oxides (NOx) injection water requirements.
Condensate flow rate (required for determining condensate polishing flows).
Import or export conditions.
Off-case design scenarios (units off-line, 100 percent makeup).
A typical heat balance diagram for a coal fired unit and combined cycle unit can be found through
the Industrial Water Treatment Community page. The diagrams include marked locations showing
where to find some of the above information. The references are typical and can vary from project
to project. Any of the above information missing from the heat balance should be requested from
the Thermal Performance Section or the Process Engineer performing the heat balance. Although
the heat balance information supplied by the Thermal Performance Section will sometimes include
the cooling tower cycles of concentration and evaporation, makeup, and blowdown flow rates,
these need to be checked and calculated as part of the water mass balance calculation as discussed
in Subsection 3.2.4.1 based on specific water quality information and assumed ambient conditions.
3.2.3.2
Water Quality Data
Water source quality data are important for development of the water mass balance. The water
source, along with data provided, will aid in determining the water treatment equipment required,
equipment recovery rates, cooling tower cycles of concentration, and wastewater flow and quality
characterization. Water quality data are required in order to project water quality throughout the
balance. This information may be provided in project contract documents. If not available, it
should be requested from the client. If not available or easily obtainable, source water quality may
be available from the USGS or other published sources. The Water Quality Form provides a list of
constituents that typically should be requested. Ideally the data should include seasonal
fluctuations over several years to help capture ranges in the water quality. Water quality analyses
typically do not have perfect balance between the cations and anions. The sodium content of the
design analysis used in the calculation should be adjusted so that the cations and anions balance, so
that the remainder of the calculations can be checked easily by verifying the cation/anion balance.
3.2.3.3
Permits
Copies of any plant permits, permit applications, or other documents pertaining to water use and
discharge should be requested. This should include copies of any raw water supply contracts that
outline any water use restrictions. If well water is the plant makeup water source, maximum
capacity of the wells and any restrictions on use should be confirmed. If discharge permits are
available, this information, along with projected wastewater flows and quality determined from the
water mass balance, will help determine the need for and type of wastewater treatment equipment.
Permit information can help determine where each wastewater stream will be sent (e.g., sanitary,
combustion turbine blowdown, flue gas desulfurization [FGD] wastewater, ash handling). If
permits are not available, best practices/judgment should be used on the basis of Environmental
Protection Agency guidelines or other sources.
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When developing the water mass balance as input to new discharge permit applications, a design
margin should be added to any flows that will be regulated as part of the permit. Also, care should
be taken to ensure appropriate raw water quality information is available to analyze any possible
seasonal fluctuations. Several years of data during various seasons of the year, where possible,
should be included in order to capture weather events such as drought conditions. It is also
important that the client is involved with the assumptions and margins utilized as part of a permit
water mass balance, since this balance will likely limit its operations with regard to water usage
and discharge.
3.2.3.4
Project/Contract Documents
Prior to developing the water mass balance, all project documents should be thoroughly reviewed.
The following is a list of information to look for and collect that will aid in development of the water
mass balance:
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Water supply quality.
Any specified water/wastewater treatment equipment.
Wet or dry handling of ash.
Coal dust suppression requirements.
If FGD equipment is required and the type of equipment.
Type of plant cooling: Once-through, closed loop, or air cooled.
Collection requirements for various wastewater streams.
Chemical waste handling (on-site neutralization, reuse, or off-site disposal).
Wastewater treatment requirements.
Any requirements for storage/runoff ponds.
Water storage requirements (raw water, service water, demineralized water, etc.).
Cogeneration facilities return condensate quality.
Equipment makeup water quality requirements (boiler, evaporative cooler, FGD,
combustion turbine inlet air evaporative coolers, combustion turbine NOx or power
augmentation, off-site process water users, pump seal water specifications, etc.).
For existing plants, plant data, including any existing water mass balances, process flow designs,
piping and instrumentation diagrams, water quality information, permit requirements and any
other operating data available should be collected in order to accurately model existing operations.
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3.2.4
Raw Water Pretreatment
One of the first equipment boxes on the water mass balance calculation is pretreatment of the raw
water supplied to the plant. Pretreated water typically provides water to the service water system
and, depending on the type of cooling at the plant, makeup to a cooling tower. Service water may
require additional treatment after the pretreatment system, depending on the type of pretreatment.
To determine the flow rate through the pretreatment system, the type of treatment utilized, along
with the flow requirements at the cooling tower (if applicable) and service water system, should
first be determined.
3.2.4.1
Cooling Tower
A cooling tower rejects heat from the plant through an evaporative cooling process. Evaporation
causes constituents in the water in the tower to be cycled up. In order to control the water quality
in the tower, a portion of the water is blown down to waste. Evaporation, along with desired cycles
of concentration, determines the blowdown and makeup rate required for the cooling tower. For
once-through cooling, the water is pumped from the supply source through the condenser and back
to the supply without any treatment other than chemical feeds. This value is obtained from the heat
balance. If the plant has an air-cooled condenser, no water flow is required, unless an auxiliary
cooling tower is used to cool the closed cycle cooling water heat exchanger. Then the heat
exchanger duty will determine the evaporation rate from the auxiliary cooling tower. If the plant
used a dry fin-fan cooling system for cooling the closed cycle heat exchanger, no water flows are
applicable.
3.2.4.1.1
Evaporation and Drift
Evaporation from the cooling tower is determined on the basis of the cooling tower required heat
duty, type of cooling tower, and ambient conditions. This information should be provided with the
heat balance. If not, it can be requested from the Thermal Performance Section. Different values
are required for each water mass balance case. The summer temperature case will have the highest
evaporation rate corresponding to the highest makeup rate.
Cooling tower drift is the small water droplets that become entrained in the air leaving the cooling
tower. The basis for this value should be 0.001 percent of the circulating water flow rate. This is
the typical permit limit for new plants but should be verified with the cooling tower guaranteed
value for the plant considered.
3.2.4.1.2
Cooling Tower Limits
To prevent scaling in the cooling tower and condenser, the blowdown flow rate from the cooling
tower is adjusted to control water quality in the tower. Table 2-3 lists the water quality limits that
should be used as guidelines when developing the water mass balance. The values in this table are
based on using the most common type of fill material, high efficiency (or structured) fill. Use of
different types of fill may result in different criteria for some constituents. Also, particularly for
existing plants, the client (or its chemical vendor/consultant) may have input.
As noted in Table 2-3, alkalinity in the cooling tower is normally controlled by feeding sulfuric acid,
unless the source alkalinity is very low. Table 3-2 shows the relationship between alkalinity
reduction and sulfuric acid feed. When developing the water mass balance, the alkalinity controlled
value, along with added sulfate from sulfuric acid feed, should be included in calculating the
circulating water quality. The added sulfates can have a large impact on sulfate levels in the cooling
tower, which may impact selection of concrete materials in the tower and blowdown discharge
quality.
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Table 3-2
Coagulant, Acid, and Sulfate – 1 ppm Equivalents
ALKALINITY
REDUCTION
(PPM)
SO4 AS CACO3
INCREASE
(PPM)
NaSO4
INCREASE
(PPM)
CO2
INCREASE
(PPM)
TOTAL SOLIDS
INCREASE
(PPM)
NAME OF CHEMICAL
FORMULA OF CHEMICAL
Filter Alum
Al2(SO4)3·14H2O
0.45
0.45
0.64
0.40
0.16
Potash Alum
Al2(SO4)3·K2SO4·24H2O
0.32
0.43
0.60
0.28
0.30
Ammonia Alum
Copperas (ferrous sulfate)
Chlorinated Copperas
Ferric Sulfate (100% Fe2(SO4)3)
Ferric Chloride
Sulfuric Acid - 98%
Sulfuric Acid - 93.2% (66° Bé)
Sulfuric Acid - 77.7% (60° Bé)
Salt Cake - 95%
Sodium Aluminate - 88%
Al2(SO4)3·(NH4)2SO4·24H2O
FeSO4·7H2O
FeSO4·7H2O + (½Cl2)
Fe2(SO4)3
FeCl3
H2SO4
H2SO4
H2SO4
Na2SO4
Na2Al2O4
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0.33
0.36
0.54
0.75
0.92
0.44
0.36
0.36
0.75
-
0.63
0.51
0.51
1.07
-
0.29
0.31
0.48
0.66
-
0.27
0.13
0.18
0.27
-
1.00
1.00
1.42
0.88
0.36
0.79
0.79
1.13
0.70
0.28
0.95
-
Increase
0.54
3-10
0.95
0.66
-
1.35
0.95
-
0.84
-
Reduce
0.47
0.34
1.00
0.90
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3.2.4.1.3
Cooling Tower Cycles
Once the evaporation and drift rates are determined, the total makeup rate required for the cooling
tower is finalized by calculating the blowdown rate. The blowdown flow rate is set based on how
many times the constituents in the circulating water can be cycled (concentrated). The cooling
tower cycles of concentration are determined by dividing the limits in Table 2-3 by the overall
makeup water values. The lowest value from each of the different constituents (except Alkalinity)
should be used as the basis for cycles of concentration for the cooling tower. In the water mass
balance calculation, this may be an iterative calculation since different streams are sometimes
recycled to the cooling tower. Based on a mass balance around the cooling tower, the following
formula is used to calculate the blowdown flow rate given the evaporation, drift, and cycles:
Blowdown Flow Rate (gpm) =
Evaporation Rate (gpm)
- Drift (gpm)
Cycles-1
The water quality of the circulating water (cooling tower water) is the overall makeup water
quality multiplied by the cycles of concentration plus the constituents added from chemical feed to
the tower. If the number of cycles achievable is not acceptable or less than project requirements,
pretreatment of the makeup water that targets the problem constituents can be considered.
3.2.4.2
Pretreatment Equipment
The type of pretreatment equipment selected is based on project contract requirements, raw water
quality, cooling tower design (type of fill), any wastewater requirements/limits, and good practice.
The raw water hardness (calcium plus magnesium) or silica concentration will sometimes drive the
need for or desirability of lime or lime/soda ash softening. Although there are several different
types of treatment configurations available, typical configurations include clarification without
softening, clarification with lime softening, and clarification with lime/soda ash softening.
Filtration is sometimes coupled with clarification/softening, particularly if the effluent supplies the
service water system. Depending on the quality of the water supply, additional pretreatment steps
may be needed to remove iron, manganese, phosphates, organics, or other constituents. Since the
water mass balance is sometimes created early on in a project with limited equipment design
information, the guidelines outlined in Table 3-1 for different pretreatment equipment should be
used until more detailed information is available.
Because the water mass balance calculates water quality, the clarified water quality needs to be
determined using Table 3-1. If the water is softened, the outlet calcium and magnesium hardness,
silica, alkalinity, and (possibly) sodium should be adjusted dependent upon the extent of softening.
These values can be determined using the Lime Softening Calculation (found through the Industrial
Water Treatment Community page). Table 3-2 should be used to account for water quality
adjustments due to coagulant feed to the pretreatment system. If clarification for suspended solids
removal only is used, the outlet chloride, sulfate, and/or alkalinity levels should be adjusted on the
basis of the type of coagulant and disinfectant used. If removal of phosphate from the raw water is
desired, typically when reclaimed water (sewage treatment plant effluent) is used as a supply, the
coagulation dosages and reactions will need to be considered. These changes should be accounted
for in the water quality portion of the water mass balance.
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3.2.5
Service Water
Another system on the water mass balance is the service water storage and supply system. The
service water system stores and distributes service water at required flows and pressures to the
various plant users. The function of the water mass balance should be to identify the major plant
service water users and quantify the average flow rates required. The following are common major
users of service water identified on the water mass balance:
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Cycle makeup treatment supply.
Boiler/HRSG blowdown quench water.
FGD system makeup (coal plant).
NOx injection water.
Ash handling (coal plant).
Coal dust suppression (coal plant).
Inlet air evaporative cooling water supply (combined cycle).
Miscellaneous users, such as pump seals and washdown water.
The list above should be used as a guide, and project-specific service water users should be
evaluated. In addition, some of the users in the list above may use or require a water source other
than service water. For example, combustion turbine inlet evaporative cooling systems may
require demineralized water or a blend of demineralized water and service water (refer to
Subsection 3.2.5.1). This should be considered when developing the water mass balance.
Determining the steam cycle makeup treatment flows is covered in Subsection 3.2.6.2.
There are several miscellaneous water users throughout the plant, including pump seal/bearing
flush water, chemical dilution water, equipment flush water, and washdown water. Because of the
numerous users it is not practical to identify and determine each individual flow rate as part of the
water mass balance calculation. In addition, several of the users are intermittent and difficult to
quantify. The water mass balance should group all these miscellaneous users into one equipment
box typically titled “Plant and Equipment Drains.” Unless project-specific requirements dictate
otherwise, judgment should be used. For a large coal plant, 100 gpm (time-averaged flow) is
typically used. For a large multi-unit combined cycle/gas plant, typically 60 gpm is used. These
values are based on B&V experience.
3.2.5.1
Evaporative Cooling
Combustion turbine inlet air evaporative cooling on combined cycle plants requires a makeup
water source. The water source should be determined on the basis of the combustion turbine
vendor’s water quality requirements. If this is not available at the time, water quality from
previous projects should be used, based on the anticipated combustion turbine supplier. Water
quality requirements for evaporative coolers from GE, Siemens, and Mitsubishi can be found
through the Industrial Water Treatment Community page. For the water mass balance assuming
typical potable quality makeup supply, normally two to three cycles of concentration should be
used for the evaporative cooler. Demineralized water (or RO effluent) can be used for blending to
adjust makeup water quality so that the desired cycles of concentration may be achieved.
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If demineralized water is specified by the combustion turbine manufacturer, the responsible
engineer should attempt, if possible, to confirm with the evaporative cooler manufacturer and,
specifically, the fill manufacturer that all components are compatible with demineralized water as
makeup. If a 100 percent demineralized water source is requested, close attention should be given
to the required pH. The pH of the demineralized water when exposed to air will be depressed to a
point that will be unacceptable for corrosion mild steel components and the adhesives in the fill to
withstand. This pH can be difficult to control chemically with the lack of buffering capacity in
demineralized water. A remineralizer may be necessary to provide this buffering capacity; in which
case approval from the combustion turbine manufacturer would be required because the water
would no longer be demineralized.
3.2.6
Demineralized Water
The demineralized water system stores and supplies demineralized water to various plant users.
Major demineralized water users are steam/condensate cycle makeup, process uses,
steam/demineralized water injection for power augmentation, and NOx injection water (typically
used for certain small combustion turbines or used when fuel oil is used for combustion turbine
firing instead of natural gas). Steam injection is typically only utilized during peak power use
periods (summer months) and typically only a certain amount of hours per day. The hours per day
should be considered when developing the water mass balance case with steam injection. Other
smaller demineralized water users for the plant are regeneration water requirements for on-site
demineralizer ion exchangers and condensate polishers, if applicable to the project. These flow
rates are accounted for in the overall recovery of the equipment, which is discussed in
Subsection 3.2.6.1.1 and Subsection 3.2.6.2.
3.2.6.1
Condensate/Boiler
When developing the water mass balance, the makeup rate to the steam/condensate cycle should
be calculated to account for HRSG/boiler blowdown and nonrecoverable losses. This rate should be
calculated as a percentage of the total steaming rate. The steaming rate is provided on the heat
balances as discussed in Subsection 3.2.3.1 and as shown on the example heat balances can be
found through the Industrial Water Treatment Community page. The percentages of the steaming
rates in Table 3-1 should be used unless otherwise directed by the specific project. Table3-1 also
provides guidelines that should be used in the water mass balance to determine what percentage of
the cycle makeup is caused by blowdown and the percentage that are nonrecoverable losses.
3.2.6.1.1
Condensate Polisher
The purpose of condensate polishing is to remove impurities that enter the condensate/steam
cycle. HP boilers have more stringent water quality requirements driving the need for polishing.
As a general rule, coal fired plants should have condensate polishers, and combined cycle/gas
plants require polishers if an air-cooled condenser is installed. Refer to Section 8.0 of this
handbook and project-specific requirements to determine if polishing is required. The two most
common types of condensate polishing are precoat type and deep bed type polishers (refer to
Subsection 8.2.4 for typical applications). Both types will have wastewater from
backwash/regeneration. A precoat polisher does not use chemicals for regeneration and will not
require neutralization of the wastewater. A deep bed polisher, on the other hand, will require
neutralization of the wastewater. The guidelines in Table 3-1 can be followed for development of
the water mass balance concerning condensate polishing unless more detailed information is
available or project-specific calculations are performed.
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Since the water mass balance calculation tracks water quality throughout the plant, it is important
to accurately represent the constituents in the regeneration wastewater. Since regeneration of the
deep bed polishers require sulfuric acid and sodium hydroxide feed, there will be a significant
amount of sodium and sulfates in the wastewater, along with ammonia from the steam cycle. The
water mass balance should account for these values.
3.2.6.2
Cycle Makeup Treatment
The cycle makeup treatment system treats service water to demineralized water quality to provide
makeup to the plant. The type of treatment equipment used is project specific and dependent upon
water quality and client requirements. The following is a list of typical treatment configurations:

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Ion exchange (cation/anion/degasifier/mixed bed).
RO followed by mixed beds.
RO followed by electrodeionization (EDI) (sometimes followed by leased mixed bed
exchangers).
RO followed by off-site regenerated mixed beds.
Depending on the water source, sodium cycle cation exchange (“zeolite” softening) or additional
filtration, such as multimedia filters, activated carbon filters, or ultrafiltration may be required
upstream of the equipment above. If filtration is required, the guidelines in Subsection 3.2.5 should
be used to determine the waste flow rate. For specific design criteria and additional information on
each system outlined above, refer to the equipment’s individual design guide. For the purposes of
developing the water mass balance, guidelines in Table 3-1 may be used unless project-specific
calculations are performed.
After determining required system flow rates using Table 3-1, the effluent water quality from each
treatment system should be determined as part of the water mass balance calculation. Guidelines
for the effluent water from each of the systems listed above are in Table 3-3, or project-specific
calculations can be performed. The treatment system, including ion exchange, will require
neutralization of the regeneration waste.
Table 3-3
Cycle Makeup Water Quality Parameters
PARAMETER
DESIGN BASIS
Reverse Osmosis
97-98% salt rejection(1)
Ion Exchange/EDI Effluent
Sodium, mg/L as Na
0.003
Chloride, mg/L as Cl
0.003
Sulfate, mg/L as SO4
Silica, mg/L as SiO2
Conductivity, μS/cm
Total Organic Carbon, mg/L
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0.010
0.10
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PARAMETER
Ion Exchange Waste
DESIGN BASIS
Sodium, mg/L as Na
Quantity removed from feed plus
sodium from caustic regeneration
Remaining Ions
Quantity removed from feed
Sulfate, mg/L as SO4
Quantity removed from feed plus
sulfate from acid regeneration
(1) RO salt rejection is dependent on many factors including ion charge, ion
size, temperature, membrane type, and membrane age. An overall salt
rejection estimate is likely suitable for a water mass balance, but output
from membrane performance simulations should be used if more specific
salt rejection information is required.
3.2.7
Potable Water
The potable water system distributes potable quality water to all plumbing, safety showers and
eyewashes, and other potable water uses throughout the site. The source for potable water will
vary on each project and can be from a city water supply, well water supply, or on-site treatment of
the plant water to meet required water quality parameters. Disposal of the sanitary wastewater is
collected and can be discharged off-site or treated on-site. The guidelines listed in Table 3-1 should
be used for the water mass balance. Although the water use is small it still should be accounted for
on the water mass balance. The water mass balance should not be used to size lift stations or
treatment systems. This type of sizing should be based on local code requirements. It should be
noted that potable water and sanitary waste treatment systems are sometimes heavily regulated by
state or local regulations. The municipal treated water supply is preferred where available.
3.2.8
Ash Handling
Depending on the project requirements, water may be required for conditioning and/or
transportation of the bottom and fly ash on coal plants. Typically for new plants, fly ash will be
handled dry (with water used for dust control) and bottom ash will be removed as a wetted solid
using a drag chain conveyor or closed ash dewatering system. Consultation with the Materials
Application Section is recommended to define how the ash will be handled and the water
requirements such as flow and quality. The water quality will determine the water source (cooling
tower blowdown, service water, wastewater, etc.). The values in Table 3-1 can be used in
conjunction with data received from the Materials Application Section.
A portion of the water used for bottom ash handling will be lost to evaporation and this should be
reflected in the water mass balance. Water used for fly ash dust control/conditioning is considered
to be entrained in the solid ash product disposed. If wet sluiced ash handling is utilized (typically
used at existing plants only), disposal of the wastewater should be considered and reflected in the
water mass balance.
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3.2.9
Coal Dust Suppression
Depending on the project requirements, water may be required for conditioning and/or dust
suppression of the coal at the conveyors and coal pile. Consultation with the Bulk Material
Handling Section is recommended to define the water requirements such as flow, quality, locations,
duration, and frequency. The water quality will determine the water source (cooling tower
blowdown, service water, wastewater, etc.).
3.2.10
Flue Gas Desulfurization
When the project utilizes a wet or semi-dry scrubber, the water mass balance should show all
makeup water sources used to supply the flue gas desulfurization (FGD) system, evaporation losses,
and all wastewaters exiting from the system. The makeup water sources and wet FGD wastewater
disposal flows should be determined on the basis of specific design requirements for the scrubber.
These values should be obtained from the Air Quality Control Section. If a chloride bleed
wastewater stream is required, the FGD wastewater quality must be estimated on the basis of the
FGD mass balance and FGD supplier input.
The same process should be implemented when the project utilizes a semi-dry scrubber, except
that there will not be a wastewater stream to be accounted for.
3.2.11
Wastewater
The water mass balance identifies the various wastewater streams throughout the plant along with
the estimated water quality of each stream. This information, along with the facility discharge
permit requirements, determines the necessary wastewater treatment for the project. The
treatment equipment could include clarification, heavy metals reduction, on-site storage ponds,
evaporation ponds, reverse osmosis, brine concentration, and/or crystallization. If large storage
ponds are used, rainfall and evaporation should be taken into consideration and shown on the
water mass balance. Runoff from various plant process areas must be accounted for in the water
mass balance. The areas and flows for runoff should be determined in consultation with the project
Civil/Structural Engineer. For coal plants, runoff from the coal pile is collected in a runoff pond.
This information should be included on the water mass balance along with any treatment required
of the collected runoff. Water mass balance guidelines for brine concentration and crystallization
are included in Table 3-1.
Wastewater should be recycled if it does not require additional treatment to be able to be reused
and does not require extensive facilities to store and pump the water to the destination. One fairly
common example is the reuse of cooling tower blowdown as makeup to an FGD system. Projectspecific requirements are often based on how the facility is permitted, which requires the treatment
and reuse of the wastewater stream. When a stream is being recycled, care must be taken to ensure
that permitting requirements are followed and that the water quality of the recycled water is either
sufficient or has been treated to allow reuse. Consideration should also be given to the everchanging regulatory environment where wastewater usage and discharge practices of the past may
no longer be an option, even if a particular strategy was implemented in the past.
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3.3
References

Siemens, Water and Waste Treatment Data Book (formerly Permutit, Water and Waste
Treatment Data Book).
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Coal Fired Water Mass Balance with Cooling Tower template (Found through the Industrial
Water Treatment Community page).
Coal Fired Water Mass Balance with Cooling Tower, ZLD template (Found through the
Industrial Water Treatment Community page).
Combined Cycle Water Mass Balance with Cooling Tower template (Found through the
Industrial Water Treatment Community page).
Combined Cycle Water Mass Balance with Cooling Tower, ZLD template (Found through the
Industrial Water Treatment Community page).
Lime Softening Calculation (Found through the Industrial Water Treatment Community
page).
Water Analysis Form WTRQUAL rev 2.xls (Found through the Industrial Water Treatment
Community page).
Water Quality Recommendations for Evaporative Coolers, Siemens Energy, Inc. (Found
through the Industrial Water Treatment Community page).
Evaporative Cooler Operation Guideline, Mitsubishi Heavy Industries, Ltd. (Found through
the Industrial Water Treatment Community page).
Water Supply Requirements for Gas Turbine Inlet Air Evaporative Coolers, GE Power
Systems (Found through the Industrial Water Treatment Community page).
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4.0
4.1
Filtration
Purpose and Applicability
This section provides design criteria for filtration systems installed in all Energy power projects
and provides recommendations as well as specific criteria for system sizing and design for filtration
equipment.
4.2
Approach
This section is intended to be used as a basis for the design of filtration equipment.
4.2.1
Overview
Water filtration is the process of separating suspended and colloidal impurities from water by
passage through a porous medium. Filtration is often used for service water production, reverse
osmosis (RO) pretreatment, wastewater treatment, and cooling tower makeup. Filtration includes
both physical and chemical mechanisms. The physical mechanism can consist of straining while
chemical mechanisms consist of bridging and adsorption for particle attachment. A pretreatment
step using a coagulant or flocculant can be used to enhance filtration by preventing small particles
from completely passing through the filter. Dissolved solids are not removed by filters.
As particles continue to collect on the porous medium, the filter will eventually become ineffective.
At this point, the filter medium is either removed and discarded or cleaned. Cleaning typically
involves a backwash cycle in an upflow or reverse flow direction to flush particles out of the filter to
waste. Some backwash cycles utilize an air scouring or surface wash step to improve particle
removal effectiveness.
4.2.2
Types of Filters
The most common types of filters used within the power industry are granular media filters,
continuously backwashed sand filters, membrane type filters, activated carbon filters, manganese
greensand filters, and cartridge filters. Granular media filters are often used in most power plant
applications. However, membrane filtration is gaining market share. Although technically not a
filter, self-cleaning strainers are a viable alternative to a filter in some cases.
4.2.2.1
Granular Media Filters
Granular media filters function by passing water through a filter bed of granular media, where the
suspended solids in the water are collected or retained in the voids within the media. The retained
suspended solids decrease the void volume, which helps remove additional suspended solids but
increases the pressure loss across the filter bed. Water continues to pass through the filter until the
pressure loss rises to a preset value or contaminant breakthrough is detected.
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The treated water is collected in an underdrain system below the filter media. The two most
common types of underdrain systems are lateral types and false bottom types. A lateral type
underdrain system consists of a central header pipe with several laterals connected at right angles
to the header. The laterals could be screened, wrapped, slotted, wedge wire screened, etc. Refer to
Figure 4-1. The laterals are typically buried in a gravel support bed. A false bottom underdrain
system consists of a false steel plate floor penetrated by nozzles or strainers. Refer to Figure 4-2.
Nozzles require gravel to keep the media out of the nozzle while strainers use fine openings to
retain the filter media. Regardless of the type used, the underdrain system needs to be designed
such that backwash air and water are evenly distributed across the bottom of the filter.
Figure 4-1
Examples of Lateral Type Drain Configurations
Figure 4-2
Example of False Bottom
(courtesy of WesTech Engineering, Inc.)
The quality of filter effluent is a function of the filter medium type, size, and depth. In general, the
finer the filter medium size, the better the water quality produced, but the greater the head loss.
The most commonly used granular filter media are silica sand and anthracite coal. Garnet sand is
also used as a bottom layer in some mixed media filter designs.
When a single filter medium such as sand or coal is backwashed, the bed becomes graded with the
finest material on top and the coarser material at the bottom. For an upflow filter, this causes the
influent water to contact the coarsest grade material first, resulting in a more even loading of the
entire filter bed and longer service runs.
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To provide downflow filters, a coarse-to-fine graded bed effect similar to that from upflow filters,
dual, or multimedia beds are utilized. Dual media filters usually consist of silica sand and anthracite
coal media. The anthracite is selected so that the coarser anthracite material is still less dense than
the silica sand. Therefore, after backwashing, the coarser anthracite medium remains on top of the
sand medium. The addition of a layer of garnet sand, which is more dense than silica sand, gives an
even more distinct coarse-to-fine flow path. The use of dual and triple media filters typically
increases run lengths and produces better quality water than single medium filters.
Filters may be designed for either manual or automatic operation. Manual filters require an
operator to initiate backwash. Automatic filters receive their signal for backwash from controllers
actuated by pressure differential across the filter bed, solids breakthrough, or total volumetric
measured throughput volume.
4.2.2.1.1
Gravity Filters
Gravity filters are usually employed for municipal applications and on some industrial applications
where large quantities of filtered water are required. Public health agencies tend to prefer gravity
equipment since gravity filters cannot be overloaded as easily as pressure filters, and gravity filters
are open at the top so the operator can observe the filter during operation, including backwash. For
waters that have a higher potential for scale or overloading of solids, a gravity filter should be
considered in preference to a pressure filter since a gravity filter can more easily be cleaned out in
the case of excessive solids buildup or scaling.
Gravity filters normally use 8 foot to 12 foot (2.4 m to 3.7 m) high tanks with definite preference for
the higher shell heights of 10 feet to 12 feet (3.1 m to 3.7 m) to prevent operation of any part of the
filter bed under negative head. Negative head operation can have the disadvantage of releasing
dissolved air in the form of bubbles, which may accumulate in the filter bed and cause air binding.
Gravity filter tanks are constructed of steel or concrete. Concrete tanks are usually rectangular;
steel tanks are round or rectangular.
Conventional filter rates are usually 2 to 5 gallons per minute per square foot (gpm/ft2) of filter bed
cross-sectional area and 3 gpm/ft2 is commonly used for power plant service. For potable water
service, regulatory requirements may establish the filtration rate limits.
The end of gravity filter runs is usually determined by head loss or pressure loss developed across
the filter bed as indicated by the water level in the filter, and backwashing is initiated on this basis.
Water quality deterioration (turbidity breakthrough) or total throughput can also be used. When
pressure loss is the determining criterion, it is usually recommended that filters be backwashed
when the pressure loss builds up to about 8 to 10 feet of water (24 to 30 kilopascals [kPa]) above
the original pressure differential across the filter at the beginning of the run. Backwash should be
adequate in quantity and time to ensure good bed cleansing.
4.2.2.1.2
Pressure Filters
Three basic types of pressure filters are vertical downflow, horizontal downflow, and vertical
upflow. Each has its advantages and particular merits for general filtration purposes. Vertical and
horizontal downflow pressure filter units are the “work horses” of the filtration field and typically
provide reliable service.
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In a vertical downflow filter, unfiltered water enters the top of the filter tank and flows downward
through the bed of filter medium, wherein the suspended matter is removed. The filtered water is
collected at the bottom of the tank and delivered to service. A typical vertical downflow pressure
filter is shown on Figure 4-3.
Figure 4-3
Typical Vertical Downflow Pressure Filter
As the name implies, a horizontal downflow filter deploys the filter tank in a horizontal position.
Otherwise, the operation of the filter is identical to that of the vertical type. By using the filter tank
in a horizontal position, a larger bed area is obtained, thus increasing the flow rate available from a
given tank size. The horizontal filters are normally 6.5 feet to 10 feet (2 m to 3 m) in diameter and
are 7.5 feet to 30 feet (2.3 m to 9.1 m) long. A horizontal filter is usually split into several cells that
run independently of each other. Utilizing separate cells within the same pressure vessel reduces
the instantaneous backwash flow requirement and the overall footprint requirement. Horizontal
filters are typically utilized when the service flow rate is relatively high.
A pressure filter typically contains three layers of filter media to remove the suspended solids from
the raw water. The first layer is anthracite coal. This layer filters the gross solids from the water
and reduces finer solids by trapping them in the anthracite. The second layer is filter sand and is
located below the anthracite layer. This finer media traps the smaller particles that may pass
through the anthracite layer. The third layer is a layer of garnet and is located beneath the filter
sand. The garnet redistributes the water across the bed allowing for even collection of the water. A
gravel support bed is typically used to support the underdrain.
Refer to Technical Specification Section 11223 – Pressure Filtration Equipment, which specifies the
filter media layers.
Conventional pressure filter rates vary from 5 to 8 gpm/ft2 of filter bed cross-sectional area. The
rate typically used is dependent on the water quality and quantity and type of solids to be removed.
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Proper filter backwashing is the most important part of good filter operating procedure, since good
bed cleansing is required for continuously successful service cycles. Backwashing should expand
the filter bed about 20 percent to 40 percent. The backwash flow rates employed to obtain this
expansion vary with temperature; in the winter when water is colder and more viscous, lower flow
rates lift the filter beds more effectively.
Surface washers are used in many plants. The jets, directed at high velocity down onto the surface
of the filter medium, break up hardened mats and help prevent mud balls from building up. Some
manufacturers have employed the use of a separate air distribution manifold in the lower section of
a filter tank to bubble air through a filter bed during the backwash and bed cleansing operation.
The use of air with water is known as an air-water system. Air-water wash has been most
effectively used where the quantity of precipitate is large, and good agitation of the bed is needed to
dislodge coatings that have built up on the medium.
4.2.2.1.3
Continuously Backwashed Sand Filters
Continuously backwashed sand filters are a variation of a conventional sand filter, which does not
require backwash equipment. Water flows upward through the filter, where it is collected and
gravity-drained out as filtered water. A small continuous flow of dirty sand from the bottom of the
filter is pulled up to a sand washer located at the top of the filter. The sand is cleaned with a small
flow of filtered water and then falls back onto the top of the filter. A continuously backwashed sand
filter provides many advantages because backwash equipment is not needed; however the filter is
likely not suitable in applications where precipitation may occur on the sand within the filter
because of problems associated with sand particle size growth. An example of a backwashed filter
system is shown on Figure 4-4.
Figure 4-4
Rio Nogales Continuously Backwashed Filters
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4.2.2.1.4
Activated Carbon Filters
Activated carbon pressure filters are typically used when adsorption is needed to remove
impurities such as chlorine, organics, hydrogen sulfide, or constituents causing tastes and odors.
Use of activated carbon pressure filters is not recommended for removing suspended solids
because the solids coat the carbon medium surface and interior pores, which reduces the carbon
medium’s ability to adsorb and remove impurities. Activated carbon filters are typically used to
improve taste and remove odor in potable water systems and to reduce chlorine and organics in the
demineralization system influent water. These impurities degrade resin performance, reducing ion
exchange capacity. In general, activated carbon filters should be replaced every 12 to 24 months.
The preferred approach is to feed sodium bisulfite to the inlet of a demineralizer system to
dechlorinate the inlet water rather than using an activated carbon filter. While these filters are
effective at removing organic compounds, they also can become a breeding ground for bacteria that
feed off the organics that survive the biocide and are trapped in the filter structure. These filters
are generally not recommended ahead of an RO system.
4.2.2.1.5
Greensand Filters
Manganese greensand pressure filters are used to remove iron, manganese, and hydrogen sulfide in
raw water. A sodium hypochlorite, potassium permanganate, and/or sodium hypochlorite
chemical feed is fed to the raw water before entering the pressure filter. This causes the iron and
manganese to oxidize and precipitate on the filter media for removal. A manganese greensand
pressure filter is typically sized for a flow rate of 2 to 5 gpm/ft2. Unfortunately, the oxidant that can
prevent so many problems downstream can actually be harmful later on. The presence of oxidizers
can quickly degrade an RO membrane system. A dechlorination chemical feed system would be
required to remove any residual oxidizer that could damage the RO membranes. It is important to
note that if the iron and manganese in the water are mostly insoluble particulate, the greensand
will not provide much benefit over a typical media filter described in Subsection 4.2.2.1. Greensand
filters are typically similar to a multimedia filter in size and operation. These filtration systems are
slightly higher cost because of the additional chemical feed system as well as the greensand media.
Typical guidelines used to consider use of an activated carbon filter or manganese greensand filter
are given in Table 4-1.
Table 4-1
Water Quality Guidelines for Use of Activated Carbon Filters or Manganese Greensand
Filters
CONSTITUENT, PPM AS SUCH
ACTIVATED CARBON
FILTER
Iron
Manganese
> 0.5 - 15
Total Organic Carbon
>3
Chemical Oxygen Demand
>8
Biological Oxygen Demand
Hydrogen Sulfide
Taste/Odor Impurities
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> 0.05
>5
3-5
If specified
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4.2.2.2
Ultrafiltration
Ultrafiltration (UF) is a filtration process where the water being filtered is passed through a
molecular sieve-type membrane. UF membranes are similar to RO membranes. One notable
difference is that RO membranes reject the majority of dissolved solids, while UF membranes reject
colloidal and high molecular weight, greater than 300,000, dissolved organic solids. Organic solids
include humic and fulvic acids, viruses, and bacteria. Dissolved solids include calcium, magnesium,
sodium, sulfate, and chloride.
UF filtration works by passing water through a membrane, creating a filtered permeate while
contaminants are retained and rejected by the membrane, leaving in the backwash or cleaning
waste stream. The membrane is cleaned by a couple different methods, including backwashing and
chemical cleaning (maintenance cleaning and recovery). Backwashing occurs periodically and
involves low pressure air scouring of the membranes to remove contaminant buildup followed by
backpulsing pumped permeate through the membrane, which dislodges contaminants from the
filter surface and allows them to be directed to waste through the reject stream. Refer to
Figure 4-5. Typically UF systems include the option to add chemicals to the backflush influent
stream, which is referred to as a chemically enhanced backwash. Maintenance cleaning is a short
chemical cleaning cycle typically performed daily. Recovery cleaning is a long, more intensive
chemical cleaning cycle that can last up to 12 hours, depending on soaking times of cleaning
solutions.
Figure 4-5
Zeeweed Membrane Schematic
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RO membrane materials have been used to develop UF membranes. Other polymeric film-forming
substances have also been used. Membrane configurations are similar as well. Spiral wound,
tubular, and hollow fiber UF systems are available. Flow direction can be from the outside in or
from the inside out. Most UF designs are enclosed in a collection of membrane vessels; whereas,
others may be submerged in an open tank. Special consideration to ventilation requirements needs
to be given to open vessel UF designs in order to handle the significant amount of chlorine emitted
from them during recovery and maintenance cleans. Open tanks should be fitted with removable
lids with induced draft vents to outdoors, or the building ventilation system needs to provide
adequate air changes to ensure that accumulation of chlorine gases does not corrode metal
structures, piping, and components within the building.
When strategically combined with other purification technologies in a complete water system, UF is
ideal as pretreatment for an RO system or as a final filtration stage for deionized water.
UF systems are typically designed with low fouling membranes and have excellent filtration
performance with high flux, high chemical resistance, and high temperature tolerance for effective
membrane cleaning. UF membrane systems also have no need for additional chemicals, and
filtration is based on size exclusion (down to 0.1 micron) versus media depth. UF systems are more
expensive than media type filters but provide better pretreatment for an RO system because of a
higher level of suspended solids removal.
UF systems typically include upstream self-cleaning strainers to protect the membranes from
fibrous materials, sand, silt, and sharp particles and help prolong membrane life.
Figure 4-6 shows an ultrafiltration membrane skid.
Figure 4-6
4.2.2.3
Ultrafiltration Membrane Skid
Disc Filters
Disc filters function by passing water through specialized cloth media panels where the suspended
solids are collected on the cloth surface. The filter vessel contains removable discs that are covered
with the specialized cloth media. Backwash of the filters begins at a predetermined water level.
The filter vessel has a center tube that draws filtered water through a spray header and rotates to
clean the cloth panels.
Disc filters provide large filtration areas with a relatively small equipment footprint. They are
typically more cost effective at larger installations.
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Figure 4-7 shows a disc filter example.
Figure 4-7
4.2.2.4
Hydrotech Disc Filter
(courtesy of Veolia Water Technologies)
Cartridge Filters
Cartridge filtration uses filter elements or cartridges mounted in a pressure vessel. The filter
cartridges are sheet or wound fiber material supported by screens or perforated plate made of
stainless steel or plastic. A typical application is a final filtration step to completely remove
suspended solids in cycle makeup demineralizer influent water that has already been filtered using
granular media. Five to 20 micron polypropylene wound elements on a polypropylene core are
typically specified.
Figure 4-8 shows a cartridge filter element and Figure 4-9 shows cartridge filters installed at Cane
Run.
Figure 4-8
Cartridge Filter Element
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Figure 4-9
4.2.2.5
Cartridge Filters Installed at Cane Run
Self-Cleaning Strainers
Self-cleaning strainers are a good fit for limiting the size of the suspended solids particles for
particular applications such as FGD makeup water, seal water, and ultrafiltration pretreatment.
The self-cleaning strainer consists of a strainer element that is periodically cleaned by using
brushes or suction nozzles. With the brush arrangement, suspended solids are knocked off of the
strainer element and fall to the bottom of the strainer, where they are removed by purging water
out of the bottom of the strainer. The suction nozzle arrangement consists of nozzles that sweep
past the strainer element and pull solids off and out of the strainer. Both configurations clean while
the strainer is online and producing strained water.
A self-cleaning strainer is considerably less complicated and less expensive than a conventional
filter; however, it should be noted that its filtering efficiency is more limited than a conventional
filter even though the fairly small mesh size strainer elements can be specified. Self-cleaning
strainers may also have a tendency to extrude soft suspended solids particles through the strainer
element even if the incoming particles are larger than the strainer element mesh size.
Self-cleaning strainers with an incoming water pressure below 25 pounds per square inch
gauge (psig) will likely require a motor to move the cleaning brushes or vacuum nozzles. At higher
inlet pressures, it may be practical to utilize a configuration without motors that drives the rotation
of the cleaning brushes or vacuum nozzles with the inlet water pressure.
Consideration should also be given to the wastewater stream that is developed. The cleaning cycle
is usually initiated on either a high strainer pressure drop or on a timer. The wastewater stream
will be intermittent and will be at a slightly lower pressure than the incoming water. Consideration
should be given to the destination of the wastewater, along with the required pressure, to ensure
adequate flow to the wastewater destination.
4.3
References
Technical Specification Section 11223, Pressure Filtration Equipment.
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5.0
5.1
Sedimentation, Clarification, and Softening
Purpose and Applicability
Removal of suspended solids, hardness, alkalinity, silica, and other constituents may be required to
prepare a water supply for use as cooling tower makeup, plant service water uses, or as
pretreatment for other processes such as ion exchange and reverse osmosis (RO) membrane
treatment. This can be accomplished by sedimentation, clarification, or softening.
5.2
Approach
5.2.1
Sedimentation
Sedimentation is the removal of suspended solids by providing a quiescent condition for gravity
settling. Sedimentation employs a reservoir or pond with no mechanical equipment for removing
the settled solids.
Very few plants have or can afford to acquire the space required for effective settling by
sedimentation. Periodic disturbances in such bodies of water, and the prevalence of organic
growths such as algae, usually necessitate some supplementary provision to ensure clean water at
all times. This has led to the development of equipment for accomplishing clarification more
rapidly, and with greater assurance of the end result, by chemical coagulation/flocculation and use
of equipment to facilitate separation and removal of coagulated solids.
5.2.2
Clarification
Clarification is a broad term that refers to the removal of suspended solids by gravity settling
usually aided by the addition of a coagulant and/or a flocculant. The clarification tank or basin is
provided with a solids collection area and bottom scrapers for solids removal.
Coagulation is the process of mixing water with a coagulant (such as alum or ferric) and/or a
flocculant (polymer) to increase the particle size of the suspended solids, thus increasing their
settling velocity. The most common coagulant is aluminum sulfate, Al2(SO4)3. Other coagulants are
ferrous sulfate (FeSO4), ferric sulfate (Fe2(SO4)3), and ferric chloride (FeCl3).
The coagulants produce a jelly-like, spongy mass of floc with enormous surface area per unit of
volume, which entraps and binds together the infinitesimally small particles of silt, organic matter,
and even bacteria. The flocculent enlarged precipitate formed has many times the settling rate of
the finer particles it has absorbed, thus accelerating fine particle separation. In this process,
suspended solids are primarily affected since hardness is not removed; however, the concentration
of some dissolved solids such as phosphates and heavy metals can be reduced with the use of a
coagulant.
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Alum, as aluminum sulfate is generally called, is most effective as a coagulant in the pH range of 5.7
to 8.0, although it is often used satisfactorily in higher pH ranges, as in conjunction with lime
softening. Caution should be exercised when alum is used as a coagulant in front of an RO system.
Overfeed of alum can cause irreversible fouling of the RO system. From the chemical standpoint,
coagulation with alum, ferrous or ferric sulfates, and ferric chloride is alkali consuming. The alkali
required may be naturally present in the water as bicarbonates and carbonates. When these are
not present in sufficient amounts, alkaline chemicals such as lime (CaOH2), soda ash (Na2CO3), or
caustic soda (NaOH) can be added.
With natural alkalinity in the water, the dissociation of alum to form gelatinous aluminum
hydroxide liberates sulfuric acid, which reacts with the alkalinity to form CaSO4; the reaction is as
follows:
Al2(SO4)3·18H2O + 3Ca(HCO3)2 →2Al(OH)3↓+ 3CaSO4 + 6CO2 + 18 H2O
The iron coagulants usually function best in the higher pH ranges when hydroxide is present.
Typical reactions for ferric chloride (FeCl3) and ferric sulfate (Fe2(SO4)3) coagulation in limebearing water are the following:
2FeCl3 + 3Ca(OH)2 → 2Fe(OH)3↓ + 3CaCl2
Fe2(SO4)3 + 3Ca(OH)2 → 2Fe(OH)3↓ + 3CaSO4
Iron coagulants are particularly corrosive and must use special materials of construction. In
particular, the injection quill must be Hastelloy C, as plastic does not hold up well in this
application.
5.2.3
Softening
Softening typically involves the addition of lime or a combination of lime and soda ash (if required)
to convert soluble divalent cations (calcium and magnesium) to insoluble precipitates (calcium
carbonate and magnesium hydroxide), which are subsequently removed by sedimentation and
filtration. Removal of silica and other constituents is accomplished through adsorption onto the
magnesium hydroxide precipitate (“coprecipitation”). In softening of water for power plant use, it
is seldom necessary to remove the noncarbonated hardness or the MgCO3 hardness. Caustic can
also be used for softening, but use is typically limited because of the higher cost of caustic when
compared to the cost of lime. The normal practice is to selectively reduce the Ca hardness by use of
lime only.
5.2.3.1
Terms
Total Hardness--Total hardness typically refers to the sum of the dissolved divalent calcium and
magnesium ions present in the water, and is reported in units of mg/L as calcium carbonate
(CaCO3). While trivalent ions may also contribute to water hardness, their concentrations in water
supplies are usually negligible and, thus, they are usually ignored.
Carbonate Hardness--The portion of total hardness present in the form of bicarbonate salts
(Ca(HCO3)2 and Mg(HCO3)2) and carbonate compounds (CaCO3 and MgCO3). Sometimes referred to
as “temporary hardness,” since its concentration can be substantially reduced by boiling to
precipitate CaCO3.
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Noncarbonate Hardness--The portion of total hardness present as noncarbonate salts, such as
calcium sulfate (CaSO4), calcium chloride (CaCl2), magnesium sulfate (MgSO4), and magnesium
chloride (MgCl). Sometimes referred to as “permanent hardness,” since boiling cannot reduce its
concentration.
Straight Lime Softening--Addition of lime (only) to remove calcium and magnesium carbonate
hardness. Each unit of calcium bicarbonate hardness (calcium alkalinity) removed requires one
equivalent of lime. Each unit of magnesium bicarbonate hardness (magnesium alkalinity) removed
requires two equivalents of lime.
Lime-Soda Ash Softening--Addition of lime and soda ash to remove both calcium carbonate and
calcium noncarbonate hardness. Each unit of calcium noncarbonate hardness removed requires
one equivalent of soda ash. Each unit of magnesium noncarbonate hardness removed requires one
equivalent of soda ash plus one equivalent of lime.
Excess Lime, Excess Lime-Soda Ash Softening--Softening to remove magnesium hardness in
addition to calcium hardness, through operation with an excess lime dosage to increase pH to
approximately 10.6 or higher, to achieve the hydroxyl ion concentration needed to achieve the
desired amount of magnesium hardness removal.
Hydrated Lime--Common name for calcium hydroxide (Ca(OH)2); sometimes referred to as “slaked
lime.”
Quicklime--Common name for calcium oxide (CaO), which is often used for high-capacity lime
softening applications to reduce chemical purchase and shipping costs. Quicklime must be slaked
(combined with water at controlled lime/water ratios to form calcium hydrate [CaOH2] slurry) onsite prior to application in the softening process.
Soda Ash--Sodium carbonate (Na2CO3); added when removal of noncarbonate hardness is required.
“Caustic softening”--Use of sodium hydroxide (NaOH; “caustic soda”) to offset all or a portion of the
lime and/or soda ash required for softening.
Recarbonation--Adjustment of the pH of the softened water by using carbon dioxide to mitigate
scaling of downstream processes. Recarbonation is often needed if RO treated water is being used
for service water since RO permeate is corrosive to mild steel, and recarbonation will stabilize the
water.
Coprecipitation--The contamination of a precipitate by a substance that would otherwise have
remained in solution had the precipitate not formed. Adsorption of a contaminant to the surface of
magnesium hydroxide is the most common form of coprecipitation that occurs in the softening
process. Iron coprecipitation is effective at removing heavy metals.
5.2.3.2
Softening Chemistry
Softening involves a number of complex and dynamic chemical interactions. The chemical
reactions involved and the methods for calculating chemical feed requirements and projecting the
characteristics of the resulting softened water are discussed extensively elsewhere (McGhee, 1975;
Randtke, 2010, Seimens). The discussion that follows simplifies the chemistry involved,
highlighting only the predominant reactions and treating them as stoichiometric reactions that
proceed to completion.
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The reactions and solids removal can take place in separate coagulation and clarification tanks, but
the usual practice is to employ a solids contact unit in which mixing, coagulation, and settling all
take place in one vessel. The solids contact unit allows the reaction to take place in the presence of
previously formed solids. This enhances particle size growth and improves settling. If required,
clarification and iron removal can be accomplished simultaneously with the softening. Feeding a
coagulant usually increases efficiency.
5.2.3.2.1
Lime Softening Chemistry
Lime, the most commonly used chemical for water softening, reacts with carbon dioxide and
carbonate hardness to precipitate calcium carbonate and magnesium hydroxide. Lime is available
as calcium oxide (CaO, commonly referred to as quicklime or pebble lime) and as calcium hydroxide
(Ca(OH)2, commonly referred to as hydrated lime). Before calcium oxide can be added, it must be
combined with water (slaked) to produce calcium hydroxide:
CaO(s) + H2O → Ca(OH)2(s)
(Eq 1)
CO2 + Ca(OH)2(s) → CaCO3(s) + H2O
(Eq 2)
Reactions of calcium hydroxide with carbon dioxide and calcium carbonate hardness (calcium
bicarbonate) are shown in Eq 2 and Eq 3. These reactions convert carbon dioxide and bicarbonate
alkalinity to carbonate alkalinity, which precipitates with calcium to form relatively insoluble
calcium carbonate.
Ca2+ + 2HCO3− + Ca(OH)2(s) → 2CaCO3(s) + 2H2O
(Eq 3)
As lime is added to remove calcium carbonate hardness (Eq 3), the pH of the water will increase.
The optimum pH to minimize calcium hardness in lime-softened water is approximately 10.3,
depending on water temperature, total dissolved solids (TDS) concentration, and other factors
affecting the solubility of calcium carbonate. Adding lime beyond this point will increase calcium
hardness concentrations, because the amount of lime that dissolves into the water and increases
calcium hardness will exceed the amount of calcium hardness that precipitates. However,
additional lime and a higher pH is required if magnesium hardness is to be removed, as described
below. In precipitating calcium carbonate hardness with lime, two moles of calcium carbonate are
formed for each mole of calcium ion removed from the water (Eq 3).
5.2.3.2.2
Lime Soda Ash Softening Chemistry
Magnesium carbonate hardness present as magnesium bicarbonate is removed in a stepwise
fashion, as shown in Eq 4 and Eq 5.
Mg2+ + 2HCO3− + Ca(OH)2(s) → CaCO3(s) + Mg2+ + CO32− + 2H2O
Mg2+ + CO32− + Ca(OH)2(s) → CaCO3(s) + Mg(OH)2(s)
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Magnesium hydroxide does not precipitate quantitatively as suggested by Eq 5 because the
solubility of magnesium hydroxide depends on pH. Generally a pH of 11.0 to 11.3 is necessary to
reduce the magnesium ion concentration to low values. Excess lime must be added to raise the pH
for precipitation of magnesium hydroxide. The resulting excess hydroxide alkalinity must be
converted later to carbonate alkalinity to produce a water of minimum calcium hardness. This
process, generally referred to as recarbonation, requires addition of carbon dioxide:
Ca(OH)2 + CO2 → CaCO3(s) + H2O
(Eq 6)
Mg2+ + Ca(OH)2(s) → Mg(OH)2(s) + Ca2+
(Eq 7)
Removal of noncarbonate hardness requires the addition of soda ash. Eq 7 and Eq 8 illustrate NCH
removal:
Ca2+ + Na2CO3 → CaCO3 + 2Na+
(Eq 8)
No softening occurs in Eq 7, as magnesium hardness is only exchanged for calcium hardness. Soda
ash is used in Eq 8 to remove the calcium noncarbonate hardness either originally present or
formed as a result of the reactions in Eq 7.
5.2.3.3
Chemical Requirements
Stoichiometric equations allow reasonable approximations of the amounts of lime and soda ash
required for softening. The amount of lime required to remove carbonate hardness can be
calculated as shown in Eq 9:
where:
CaO (lb/mil gal) = 10.6 [CO2 ] + 4.7 [alkalinity + magnesium hardness + x]
(Eq 9)
CaO is 100 percent pure quicklime.
CO2 is the concentration of carbon dioxide present in the raw water expressed in mg/L as CO2.
Alkalinity and magnesium hardness are expressed in mg/L as CaCO3.
x is the required excess hydroxide alkalinity in mg/L as CaCO3.
(If hydrated lime (Ca(OH)2) is used instead of quicklime, the required amount can be calculated by
multiplying the required CaO dosage determined from Eq 9 by 74/56, the ratio of the molecular
weights of Ca(OH)2 and CaO.)
The magnesium hardness shown is the total amount present in the water to be treated. Required
excess hydroxide alkalinity can be estimated from the magnesium hydroxide solubility relationship
(Randtke, 2010; Siemens); it is typically in the range of 25 to 70 milligrams per liter (mg/L),
depending on the treatment objective and the pH, temperature, and ionic strength of the water. An
excess hydroxide alkalinity of 65 mg/L as CaCO3 will result in a pH of about 11.1 (at 77° F [25° C])
which is sufficient to achieve a minimum magnesium hardness concentration of approximately
10 mg/L as CaCO3, while an excess of approximately 25 mg/L will achieve a finished water
magnesium hardness of about 40 mg/L. Because CaO is usually 88 percent to 95 percent pure and
hydrated lime is usually 93 percent pure, results from Eq 9 must be adjusted to account for actual
chemical purity. It should be noted that makeup water from municipal wastewater treatment
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facilities (grey water) may not react according to the above stoichiometry. Organics and other
constituents may suppress softening reactions, resulting in slight excess feed requirements.
Furthermore, high TDS waters may not soften as well because of the common ion effect.
Eq 10 can be used to calculate the amount of soda ash required to remove NCH:
Na2CO3 (lb/mil gal) = 8.8 [NCH − y]
where:
(Eq 10)
Na2CO3 is 100 percent pure soda ash.
NCH is the total amount present in the water to be treated (expressed in mg/L as CaCO3)
y is the NCH remaining in the softened water (expressed in mg/L as CaCO3).
Soda ash is usually 98 to 99 percent pure, so no adjustment to the calculation to account for
chemical purity is typically made, since the adjustment would be smaller than the errors introduced
by other assumptions and measurements.
5.2.3.4
Use of Caustic Soda
If at least half of the calcium hardness in the feedwater is present as calcium carbonate hardness,
sodium hydroxide (NaOH, commonly referred to as caustic soda) can be used in place of lime or
soda ash (although the relative higher cost of caustic typically makes this prohibitive). As caustic
soda does not contribute calcium ions along with the hydroxide ions required for softening,
residual solids production is about 50 percent less than for conventional lime/soda ash softening,
and caustic soda is easier to store, handle, and feed. Caustic soda is generally purchased as a
25 percent or 50 percent aqueous solution. Softening reactions with caustic soda are shown in
Eq 11 through Eq 15.
CO2 + NaOH → Na+ + HCO3−
Ca2+ + HCO3− + NaOH → CaCO3(s) + Na+ + H2O
(Eq 11)
Mg2+ + 2HCO3− + 4NaOH → Mg(OH)2(s) + 2Na2CO3 + 2H2O
Mg2+ + 2NaOH → Mg(OH)2(s) + 2Na+
Ca2+ + Na2CO3 → CaCO3(s) + 2Na+
(Eq 12)
(Eq 13)
(Eq 14)
(Eq 15)
When using caustic soda to remove calcium carbonate hardness, only half as much alkalinity is
consumed (Eq 12). In addition, the bicarbonate produced when carbon dioxide is neutralized and
the carbonate produced when magnesium carbonate hardness is removed (Eq 13) is available to
remove noncarbonate hardness, as shown in Eq 15. A combination of lime and caustic soda can
also be used; the relative dosages required will depend on the amount of calcium noncarbonate
hardness to be removed. This combination provides some reduction in chemical cost, compared
with the use of caustic soda alone, because caustic soda is significantly more expensive than lime.
Using caustic soda may be a reasonable option for softening of low-alkalinity water, because caustic
soda softening consumes only one-half as much alkalinity as lime softening. Caustic softening may
also be advantageous for smaller treatment systems where the caustic dosage is low and dry solids
handling/storage systems can be avoided. Disadvantages of using caustic soda are higher chemical
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costs than with conventional lime/soda ash softening, an increase in finished water sodium
concentration, and the need for a higher carbon dioxide dosage for recarbonation/pH adjustment
as a result of the higher levels of alkalinity remaining in the softened water.
5.2.3.5
Residual Solids Production
The quantity of residuals produced in the softening process can be estimated by performing a mass
balance on the residuals-producing calcium and magnesium ions, which represent the hardness
removed in the process. One or both of the substances are present as hardness in the water
entering the process. In addition, calcium is added to the influent flow by the addition of lime.
Some hardness also leaves the process in the finished water, and the remainder leaves the process
in the residuals produced. The residuals are in the form of calcium carbonate for the calcium
hardness removed and magnesium hydroxide for the magnesium hardness removed.
The mass balance for calcium in terms of dry weight of CaCO3 solids formed is as follows:
CaCO3 residuals (lb/mil gal) = 20.9 [(Ca in) + (Ca added by lime) − (Ca out)]
(Eq 16)
where Ca is calcium in milligrams per liter as calcium (calcium carbonate equivalent divided by
2.5). For quicklime (CaO), Ca added by lime is 0.71 × CaO (mg/L) × percent purity/100. For
hydrated lime (CaOH2), Ca added by lime is 0.54 × Ca(OH)2 in mg/L × percent purity/100.
The mass balance for magnesium in terms of dry weight of Mg(OH)2 formed is as follows:
Mg(OH)2 residuals (lb/mil gal) = 20.0 [(Mg in) − (Mg out)]
(Eq 17)
where Mg is magnesium in milligrams per liter as magnesium (mg/L as CaCO3 divided by 4.12).
Impurities in lime are also a source of residuals produced in the softening process. The amount can
be estimated as follows:
Lime impurities (lb/mil gal) = Lime dose x [(100 – percent lime purity)/100]
where lime dose is expressed in pounds per million gallons treated.
(Eq 18)
While the total amount of dry solids produced by softening is site-specific and dependent upon both
source water quality characteristics and plant operating practices, total dry weight solids of
softening residuals for the excess lime treatment process is usually about 2.5 times the hardness
removed, expressed in mg/L as CaCO3. The straight lime process produces total dry weight solids
for softening residuals approaching 2.0 times the hardness removed.
Residuals are also produced by source water turbidity removed in the process, by the precipitation
of iron and manganese that may be removed in the process, and by coagulants and powdered
activated carbon that may be used in the process.
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5.2.3.6
Neutralization, Recarbonation, and Remineralization
Neutralization of lime and/or soda ash softened water is typically necessary because of the high pH
of the softener effluent. This is often accomplished by neutralization with an acid such as sulfuric
acid or hydrochloric acid. The majority of the acid is consumed by the alkalinity in the softener
effluent. The first reaction involves converting the carbonate alkalinity to bicarbonate alkalinity as
follows:
H2SO4 + 2CO32− → SO42- + 2HCO3−
After all of the carbonate alkalinity is converted to bicarbonate alkalinity at a pH of approximately
8.2, the acid begins to convert the bicarbonate alkalinity to carbon dioxide as follows:
H2SO4 + 2HCO3− → SO42- + 2CO2 + 2H2O
Consideration should be given to the alkalinity breakthrough point where the majority of the
alkalinity has been converted to carbon dioxide, and any additional acid addition will result in a
very severe, and usually unacceptable, reduction in the pH. Attempting to control the pH near
neutral conditions (pH ~7.0) is often problematic since the alkalinity breakthrough point is
typically around this point. pH control is further complicated by the logarithmic nature of pH as
well as the need for proper acid mixing and reaction time. Schemes involving acid addition in a
pipe with a downstream pH analyzer are also often problematic.
Recarbonation with carbon dioxide is used to convert carbonate alkalinity to bicarbonate alkalinity
and to stabilize the softened water prior to filtration, when needed. The reaction of carbonate
alkalinity with carbon dioxide to produce bicarbonate alkalinity is shown in Eq 19:
CO2 + CO32− + H2O → 2HCO3−
(Eq 19)
CO2 (lb/mil gal) = 3.7 [carbonate alkalinity]
(Eq 20)
The dosage of carbon dioxide required to react with the carbonate alkalinity to produce
bicarbonate alkalinity may be estimated as follows:
where carbonate alkalinity is that amount to be converted to bicarbonate alkalinity, expressed in
mg/L as CaCO3.
Although a recarbonation process is not subject to the risks of alkalinity breakthrough, the costs
associated with the carbon dioxide supply may be prohibitive, and although recarbonation is an
option, neutralization with an acid is more typical for power plant applications.
In some cases, a water supply may need to be remineralized prior to potable consumption or
because of its corrosive tendency. Distillate from a desalination process is often too low in
dissolved minerals and is remineralized to make it less corrosive to potable water system
components. Remineralization can be accomplished by blending with another water supply or by
the direct addition of minerals by exposure to a limestone bed or other methods.
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5.2.3.7
Silica Removal
Silica removal may be necessary for cooling tower makeup pretreatment or as pretreatment prior
to a reverse osmosis process. Silica can be removed by excess lime softening, which can precipitate
silica as magnesium silicate or coprecipitation with magnesium hydroxide, and by adsorption
(coprecipitation) on freshly precipitated aluminum or iron hydroxide. Silica can also be removed
with ion exchange media, but this is not practical for anything except demineralization or
condensate polishing. Since silica removal by lime softening is related to the amount of magnesium
removed, additional magnesium may need to be added to meet the treatment objective. This can be
accomplished through addition of magnesium oxide, magnesium sulfate, magnesium carbonate, or
use of dolomitic lime. (Magnesium oxide is generally the preferred additive, because it does not
increase the dissolved solids concentration of the softened water.) The effectiveness of silica
removal by excess lime softening increases with temperature, so hot-process lime softening may be
considered. As silica removal is enhanced through contact of the feedwater with previously
precipitated solids, effective recirculation of solids within the softening process is an important
factor in maximizing silica removal. Solids recirculation type solids contact units (SCUs) are
recommended for this application. Consideration should be given to the precipitation method of
silica removal in that silica is more efficiently removed with precipitating magnesium hydroxide in
comparison to aged magnesium hydroxide.
When removal of silica is required in cold process softening, improved magnesium hardness
removal may be achieved through addition of sodium aluminate. Sodium aluminate addition
increases hydroxyl ion concentrations, which enhances magnesium removal without increasing
calcium hardness concentrations in the finished water. Hydrolysis of sodium aluminate also results
in the formation of aluminum hydroxide precipitate, which can remove silica through
coprecipitation. Reactions are as follows:
Na2Al2O4 + 4H2O → 2Al(OH)3 + 2NaOH
(Eq 21)
MgCl2 + 2NaOH → Mg(OH)2 + 2NaCl
(Eq 23)
MgSO4 + 2NaOH → Mg(OH)2 + Na2SO4
(Eq 22)
Operating experience suggests the following general relationship for silica removal as a function of
magnesium hardness removal for cold process softening (note that performance is typically sitespecific and should be confirmed through bench-scale or pilot-scale testing):



5.2.3.8
~0.2 mole of SiO2 removed per mole Mg removed, or
~8 to 8.5 mg/L of magnesium hardness precipitated per 1 mg/L of SiO2 removed, or
~4.9 mg/L Mg(OH)2 precipitated per 1 mg/L of SiO2 removed.
Organics Removal
Chemical softening processes are also effective at reducing the concentrations of organics and
improving the color of a water supply. It is difficult to quantify the organics reduction because of
the variety of organics that could be present; however, higher pH levels and higher volumes of
softening precipitants (particularly magnesium and phosphate precipitants) typically result in
higher levels of organics reduction.
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5.2.4
Pretreatment Considerations
Pretreatment processes most frequently used before softening are aeration (air stripping) and
presedimentation.
5.2.4.1
Aeration
Aeration may be used to remove carbon dioxide from the source water before softening. This is
usually applicable to groundwaters where carbon dioxide concentrations are relatively high. The
additional lime required for removal of carbon dioxide from the source water results in both higher
chemical costs and additional residuals production, in accordance with Eq 2. The lime dosage
required to react with carbon dioxide may be estimated by using part of Eq 9, as follows:
(Eq 24)
CaO (lb/mil gal, 100 percent purity) = 10.6 × CO2
where CO2 is expressed in mg/L as CO2. Induced draft or open tray aeration is often used and may
reduce the carbon dioxide level to 10 mg/L or less.
Aeration also adds oxygen to anoxic source waters, facilitating oxidation of iron that is commonly
present in such waters. For some groundwaters containing substantial amounts of iron, clogging of
aerator trays can be a problem. The aerator should be designed to minimize clogging and to
facilitate access for periodic cleaning. Although aeration is often used to oxidize iron in iron and
manganese removal plants, the elevated pH of the softening process, together with chemical
oxidation (if needed), will effectively remove iron and manganese without the need for aeration.
The benefits of reduced lime consumption and residuals production achieved by aeration preceding
softening must be weighed against the capital cost of the aeration equipment and the associated
operating and maintenance costs. Aeration is generally used only where carbon dioxide levels are
high enough to justify the cost, or where the source water contains other undesirable constituents
(such as hydrogen sulfide or radon) that can be removed by aeration. Residuals produced by the
reaction of lime and carbon dioxide may be estimated as follows:
Dry weight CaCO3 residuals (lb/mil gal) = 19.0 × CO2
where CO2 is expressed in mg/L as CO2.
5.2.4.2
(Eq 25)
Presedimentation
Presedimentation is used primarily at facilities that treat highly variable, high turbidity surface
waters. Many of these facilities use metal salt or polymer coagulants to enhance removal of
turbidity and suspended solids in the presedimentation process prior to softening.
Presedimentation results in a more uniform water quality at the softening process influent.
Presedimentation also provides an opportunity for removal of organic compounds with powdered
activated carbon and oxidizing agents prior to the elevated pH associated with the softening
process. In some cases, this approach provides more efficient and effective treatment. Where
removal of total organic carbon (TOC) is required, the combination of chemically assisted
presedimentation and softening will often result in more effective TOC removal than would be
achieved by softening treatment alone.
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5.2.5
System Configuration
Consideration should be given to the various types of clarifiers that are available. The various
characteristics of the clarifier designs may result in a particular type of clarifier being beneficial for
a particular application. Allowable clarifier influent total suspended solids (TSS) levels,
concentration of the clarifier sludge, and treatment objectives are common considerations.
Furthermore, relative costs, footprints, level of shop fabrication versus field fabrication, and ease of
operations and maintenance should also be considered.
5.2.5.1
Traditional Solids Contact Clarifier
Water clarification and lime-soda softening are best accomplished in solids contact clarifiers (SCCs).
A solids contact clarifier is also referred to as a solids contact unit (SCU) in softening applications.
These are upflow settling units in which the raw water, reaction chemicals, and previously formed
solids are mechanically mixed and separated by gravity. The solids contact clarifier provides: (1)
rapid mixing of the raw water and chemicals, (2) slower mixing and circulating with existing sludge,
(3) separation of sludge and clarified water, and (4) sludge removal.
SCUs may be constructed in either steel or concrete basins. The internal equipment includes a
center mixing/reaction zone with a large impeller/turbine to maintain the previously precipitated
solids in suspension, baffles, rotating sludge collection equipment, and settled water collection
weirs. These components are typically constructed of coated carbon steel. The influent water
enters the center mixing/reaction zone, where lime (and soda ash if necessary) is added, and comes
into contact with previously formed precipitates. The turbine continuously draws precipitated
solids upward from the floor of the clarifier to maintain a substantial solids inventory within the
mixing/reaction zone (suspended solids concentrations of 5 to 10 percent by volume are typical).
The maximum turbine pumping capability is usually 5 to 10 times the unit’s design maximum flow
treatment capacity. The mixer is provided with a variable speed drive for adjusting the solids
recirculation rate. The softened water/solids slurry flows either upwards over a weir and radially
out into the SCU, or downward under the reaction zone hood where solids are separated from the
softened water. The clarified/softened water then flows upwards and exits the SCU over the
effluent collection weirs. (Some conventional SCU designs require the water from the center
reaction zone to pass upward through a blanket of previously precipitated solids.) The depth and
density of the precipitated solids in the basin are controlled by blowdown of precipitated solids and
by the degree of internal recirculation provided by the mixing turbine. Examples of conventional
solids contact units are shown on Figures 5-1 and 5-2.
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Figure 5-1
Conventional Solids Contact Clarifier
(courtesy of Infilco Degremont Inc., Richmond, VA)
Figure 5-2
Solids Contact Clarifier Internals during Construction
Sidewall water depth in solids contact basins usually varies from 14 to 20 feet (4.3 to 6.1 meters)
and depends on basin size and the equipment manufacturer’s requirements. The hydraulic contact
time in the mixing zone is typically 15 to 30 minutes, measured by the volume of water within and
directly under the baffle wall. Surface loading rate in the sedimentation zone is generally measured
2 feet (0.6 meter) below the water surface and is based on the surface area between the baffle wall
and the basin wall. Surface loading rates for softening applications are usually in the range of 1.25
to 1.5 gallons per minute per square foot (gpm/ft2) (3.1 to 3.7 meters per hour [m/h]). Where
coagulation for turbidity removal is also required, design surface loading rates are generally near
the lower end of this range or lower. Where possible, design requirements should be based on
experience with other well-operating plants using the same or similar source water.
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For the straight lime and lime–soda ash processes, precipitated solids consist primarily of heavy
calcium carbonate crystals without the more gelatinous and lighter magnesium hydroxide
component. The heavy calcium carbonate crystals can create difficulties with recirculating the
precipitated solids if the impellor/turbine design is inadequate. Therefore, the manufacturer must
be fully apprised of the nature of the process to ensure provision of equipment capable of reliably
meeting the specified operating conditions. Equipment specifications should establish a minimum
percentage of solids to be maintained in the mixing zone.
Conventional SCUs can be constructed in either round or square basin configurations. Square
basins may be used where site area is limited or if the basins are to be enclosed, but circular basins
are generally preferred in order to avoid problems with removal of precipitated solids from basin
corners.
While upflow solids contact units offer significant advantages over conventional softening basins,
they also require additional operator attention for monitoring and control of the solids inventory in
the basin and are more prone to upsets attributable to changes in inlet water temperature, flow
rate, and turbidity.
5.2.5.2
Proprietary Clarifiers
Several proprietary alternatives to conventional solids contact units are available which utilize a
combination of internal and external solids recirculation, high concentrations of solids in the
reaction zone, and tube-assisted sedimentation to reduce the overall plant footprint and to yield
high concentrations of settled solids. Treatment takes place in conjoined reactor and
clarifier/thickener vessels (Infilco Degremont, Inc. DensaDeg®, [Figures 5-3 and 5-4] or Veolia
Multiflo ™) or a single multi-compartment circular basin (WesTech CONTRAFAST®). The high
concentrations of reaction zone solids maintained within these units allow the use of surface
loading rates of 6 to 12 gpm/ft2 (14.7 to 36.7 m/h) in the settling zone.
Sand-ballasted clarifiers (Veolia Actiflo® or WesTech RapiSand™) may also be considered for
clarification when there is a large fluctuation in raw water turbidity and suspended solids
concentration. An Actiflo® is shown on Figure 5-5, and the RapiSand™ is shown on Figure 5-6.
A sand-ballasted clarifier adds sand to the clarification process to act as a ballast material, which
the floc particles attach to via the polymer, to provide faster floc formation and decreased particle
settling time. The “ballasted floc” settles at rates 15 to 35 times higher than traditional clarification.
This equates to a smaller equipment footprint than a conventional system.
The process includes mixing the raw water and coagulant in a mixing tank. This water is mixed
with coagulant aid and microsand in a flocculation tank. The flocculated water is then directed to a
clarification tank where the flocs settle. The clarified water is directed to an outlet at the top of the
tank where the settled flocs are raked and pumped to a hydrocyclone where the sand is separated
from the suspended solids. The sand is then recycled to the beginning of the process.
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Figure 5-3
High-Rate Solids Contact Process
(courtesy of Infilco Degremont Inc., Richmond, VA)
Figure 5-4
DensaDeg® Installation
(courtesy of Infilco Degremont Inc., Richmond, VA)
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Figure 5-5
Veolia Actiflo® Sand-Ballasted Clarifier
(courtesy of veoliawatertechnologies.com)
Figure 5-6
WesTech RapiSand™ Sand-Ballasted Clarifier
(courtesy of westechinc.com)
5.2.5.3
Hot Process Softening
In hot process softening, the water is preheated, typically to 212 to 248° F (100 to 120° C). Heating
the water significantly reduces the solubility of both calcium carbonate and magnesium hydroxide,
greatly increasing both the rate and extent of removal of hardness. Silica is effectively adsorbed by
magnesium hydroxide, and a magnesium salt can be added if needed to increase silica removal. Hot
process softeners require a steam source and are rarely used at power generation plants but may
be found more commonly at refineries and facilities that treat produced water.
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5.2.5.4
Solids Handling
Solids generated by the softening reactions are more dense than coagulation solids, with solids
concentrations varying from 3 to 15 percent or more by weight. Softening processes that remove
only calcium carbonate produce the highest density solids. Solids from excess lime processes are
generally less dense because of the influence of magnesium hydroxide, which is lighter and more
gelatinous. For excess lime softening, an average solids blowdown concentration of 5 percent by
weight is often used as a rough guideline.
Solids blowdown from softening clarifiers is usually controlled by a repeat cycle timer that allows
periodic, timed blowdowns at full pipe flow. Provisions for flushing the piping with clear water
after each blowdown must be included to reduce the possibility of lines becoming clogged by
settled solids. Provisions for sampling the solids blowdown should be included. Pumps used for
solids recirculation or disposal are typically solids handling centrifugal units, although positive
displacement pumps may be required for extremely dense residuals. Recirculation pumps should
be provided with variable speed drives.
Sludge thickening may be used to concentrate the solids blowdown from clarifiers to approximately
8 to 10 percent solids. A sludge thickener is comparable to a conventional clarifier except that a
solids slurry is fed into the thickener instead of a suspended solids laden water supply. The solids
settle to the bottom of the thickener while water with lower solids concentration is decanted off of
the top of the thickener. This can dramatically reduce the overall volume of flow to the
downstream dewatering equipment. Proprietary clarifier designs that generate more highly
concentrated solids blowdown streams typically do not, however, benefit from the use of a
downstream sludge thickener.
Precipitated solids can be disposed of by on-site thickening and mechanical dewatering (typically
using plate and frame presses, belt filter presses, or centrifuges [refer to Figures 5-7A, 5-7B, and
5-8, respectively]), with trucking of the dewatered solids cake to an ultimate disposal site. All of the
free water must be removed from the solids prior to transport. Even with the use of dewatering
equipment and removal of all of the free water, the solids will generally have around 40 percent
moisture; the actual level of dryness is dependent on the type of solids. The method of removing
solids from the site (e.g., dump trucks, dumpsters) has a great impact on the location of equipment
and roads around the water treatment area. Careful consideration should be given to this aspect
during the early phases of the design to ensure a workable and optimal layout.
Figure 5-7A
Plate and Frame Filter Press
Plates
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Figure 5-8
Belt Filter Press
Figure 5-9
Centrifuge
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5.2.5.5
Chemical Feed and Plant Layout Considerations
The design of softening plants is influenced to a large degree by the need to handle and feed large
quantities of lime. Lime solution readily encrusts solution pumps, pipelines, and troughs and
presents major maintenance concerns. While gravity flow of lime slurry in open troughs or through
hoses that are readily accessible is preferable from a cleaning point of view, pumping of lime slurry
to the point of application through rigid piping systems is most commonly used. Soda ash solution
conveyance systems may also experience encrustation problems if the water used to prepare the
soda ash solution contains significant hardness; the dilution tanks used for preparation of soda ash
solution must therefore be sized to provide adequate retention time for the soda ash to dissolve and
stabilize before it leaves the tank.
Lime and soda ash feed systems should be located as close to the point of application as possible.
On the other hand, feed systems for these chemicals, particularly for lime, require frequent
attention and should be located as close as practical to the operator’s station; therefore, it is
generally preferable to bring the water to be treated as close as practicable to central chemical feed
facilities that are readily accessible to the operator. The Slurry System Design Procedure should
also be considered when designing systems that include slurry feeds, sludge handling, and/or solids
dewatering.
Lime slurry and soda ash solution can be fed by using a constant concentration feed loop that
circulates slurry back to the solution tank with a feed control valve to each clarifier. Alternately, the
slurry or solution can be fed directly to the clarifier(s) while modulating the slurry/solution
strength.
Lime slurry piping should include rod out tees at every change in direction. Flanged piping sections
may also be advisable to allow scaled piping segments to be removed, cleaned, and replaced. Using
hoses in lieu of elbows at piping directional changes is also a viable alternative. This reduces the
chance of plugging, reduces wear, and allows for quick replacement compared to welded pipe. On
larger projects, the scaling potential of the lime slurry in the chemical feed lines may warrant an
acid clean-in-place (CIP) system.
As it is often necessary to use coagulants to enhance clarification within softening units, provisions
should be made to feed aluminum or ferric-based coagulants and coagulant polymer within the
mixing zones of upflow SCCs.
5.2.6
Process Performance and Control
5.2.6.1
Typical Performance
Typical performance for a raw water treated by various lime and lime soda softening process
alternatives is shown in Table 5-1. Effectiveness of lime softening for removal of various inorganic
constituents is shown in Table 5-2.
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Table 5-1
Typical Softening Process Effluent Characteristics*
PARAMETER
Hardness, mg/L as CaCO3
Total
Calcium
Magnesium
Alkalinity, mg/L as CaCO3
Phenolphthalein
Methyl Orange
Hydroxide
pH
Silica, mg/L as SiO2
RAW
WATER
REMOVAL OF
CA CH (COLD
LIME)
LIME SODA
SOFTENING
(COLD
LIME)
LIME SODA
SOFTENING
(HOT LIME)
LIME
SOFTENING
(HOT LIME)
250
150
100
145
85
60
81
35
46
20
15
5
120
115
5
0
150
0
27
44
10
37
55
19
23
40
6
18
28
8
7.5
20
10.3
19
10.6
18
*Source: General Electric, Handbook of Industrial Water Treatment.
Table 5-2
10.5
1-2
10.4
1-2
Effectiveness of Lime Softening for Inorganic Contaminant Removal*
CONTAMINANT
OPERATING CONDITIONS
APPROXIMATE REMOVAL, %
Arsenic (As5+)
pH < 10.8
pH > 10.8
30 - 95
> 95
pH 8.5 – 11.3
> 95
Barium
Cadmium
Chromium (Cr3+)
pH > 10 – 11
> 90
pH < 10.6
pH 10.6 – 11.3
70 - 95
< 98
Mercury
pH 10.7 – 11.4
60 - 80
Silver
-
Lead
Selenium
*Source: Randtke (2010)
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pH 9.5 – 11.3
5-19
> 98
20 – 40
80 - 90
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5.2.6.2
Process Control Parameters
Water quality parameters typically monitored in the raw and finished water are alkalinity, calcium
hardness, total hardness, turbidity, and pH. Other parameters commonly monitored for process
control purposes include pH in the mixing/reaction zone of the solids contact clarifier and pH,
alkalinity, and hardness in the settled water. Samples are typically collected manually and analyzed
on-site, although continuous online systems are available that can monitor hardness and alkalinity.
Continuous monitoring and/or control of the softening process using pH probes installed at various
points within the process has proven to be problematic because of difficulties in avoiding excessive
scaling/encrustation of the probes.
Lime and soda ash dosages are usually controlled to maintain specific pH, carbonate alkalinity,
calcium hardness, magnesium hardness, and/or hydroxide alkalinity in the settled water. The
solids concentration within the reaction zone is also typically monitored to ensure maintenance of
desired solids inventory within the reaction zone and to determine required solids blowdown
frequency and durations. This is typically accomplished through collection of samples from the
reaction zone and observation of settling characteristics in a graduated cylinder or other calibrated
column; one common criteria is to maintain a settled solids volume in the cylinder equal to a
percentage of the total cylinder volume (generally approximately 10 percent) after approximately
10 minutes of settling time.
Flow control is critical to the performance of the softening process. Large, instantaneous flow
changes can upset the softening process and result in large quantity of suspended solids in the
effluent. This is particularly challenging for cooling tower makeup softening systems. A surge tank
sized for about 15 to 30 minutes of storage is recommended for facilities that expect fluctuations in
flow rates. Typically, a three element control system is employed in the main plant control system
to dampen out flow changes from the inlet flow control valve and provide appropriate responses to
flow demands. The three elements are raw water flow, surge tank level, and cooling tower level.
Most SCUs are capable of handling flows down to 20 percent of design flow; however, it is
recommend not to exceed less than 50 percent of design flow for extended periods of time. For
greater flexibility, the engineer may consider 2 x 50 percent or 2 x 75 percent SCU configurations
depending on design and operating parameters.
5.2.6.3
Key Design and Operation/Control Parameters
Raw Water Analysis--An accurate water analysis showing major ions, in addition to any minor ions
that require removal, is essential in the design of a successful softening system to ensure that
chemical dosage capabilities provided and solids handling facilities are adequate to reliably achieve
the desired degree of treatment.
Pretreatment Requirements--Any site-specific pretreatment requirements (e.g., aeration to reduce
carbon dioxide concentrations, presedimentation to address highly variable surface water quality
characteristics) must be identified and appropriate treatment methodologies specified.
Treatment Process Requirements--Softened water quality objectives must be clearly defined. Often
full softening is not required or desirable.
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Chemical Feed Dosage Requirements--Required dosages are typically determined through
stoichiometric equations or other calculations, based on the raw water analysis and finished water
quality objectives, with appropriate factors of safety applied to account for anticipated variations in
feedwater quality.
Softening Clarifier Design Parameters--Design parameters such as reaction zone detention times,
mixing intensity levels, settling zone hydraulic loading rate, solids contact clarifier turbine pumping
capabilities, and solids recirculation rates must be specified and are typically selected on the basis
of experience with facilities treating similar source waters and through consultation with
equipment manufacturers.
5.3
References

S. J. Randtke, “Precipitation, Coprecipitation, and Precipitative Softening,” Water Quality &
Treatment, J. K. Edzwald, ed., Sixth Edition, American Water Works Association, McGrawHill, Inc. New York, N.Y., 2010, Chapter 13.







T.J. McGhee, “Heuristic Analysis of Lime–Soda Softening Processes,” Journal of the American
Water Works Association, 67:11, 1975, pp. 626-630.
Siemens, Water and Waste Treatment Data Book (formerly Permutit, Water and Waste
Treatment Data Book).
General Electric, “Precipitation Softening,” Handbook of Industrial Water Treatment, Chapter
07 (http://www.gewater.com/handbook/index.jsp).
D.B. Elder, M.B. Horsley, and S.J. Randtke, “Precipitative Softening”, Water Treatment Plant
Design, S.J. Randtke and M.B. Horsley, ed., Fifth Edition, American Water Works Association
& American Society of Civil Engineers. McGraw-Hill, Inc., New York, NY, 2013, Chapter 13.
Hung-Der Hsu, Shiao-Shing Chen, Cheng-Li Lin, and Tien-Chin Chang, “Silica Pretreatment
for RO Membrane Softening - Adsorption,” Environmental Engineering and Management
Journal, 18(2), 99-103 (2008).
Lime Softening Calculation (found through the Industrial Water Treatment Community
page).
Slurry System Design Procedure.
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6.0
6.1
Ion Exchange
Purpose and Applicability
This section provides design criteria that can be used to design ion exchange equipment.
6.1.1
Summary
Ion exchange is a process where one ion is exchanged for a different ion in a substance. Ion
exchange is used in water treatment to remove dissolved, ionic impurities from water. The
application of ion exchange to remove all ionic impurities from a water source is known as
demineralization.
Demineralized water is used in power plants for makeup water to the feedwater cycle. Any
impurities in cycle makeup water are carried to the boiler and potentially to the steam from the
boiler and can cause damage to both the boiler and steam turbine, such as pitting, corrosion, or
scaling, to piping and turbine blades. The water quality required for use as cycle makeup water is
defined by the boiler manufacturer and is dependent on the purity of the steam required by the
turbine manufacturer and the operating pressure of the plant.
Ion exchange is achieved by using manufactured ion exchange resin. Ion exchange resin is an
insoluble, porous, polymer bead. The polymer beads provide a solid support material that has ionic
sites where ion exchange can take place. Cation exchange resin has fixed negative sites so that a
positively charged ion can be replaced by another positively charged ion. Anion exchange resin has
fixed positive sites so that a negatively charged ion can be replaced by another negatively charged
ion. Resins are also classified as weak and strong acid cation resins and weak and strong base
anion resins.
The use of ion exchange equipment in cycle makeup treatment systems is becoming less common
because of the cost and safety issues associated with the chemicals necessary for regeneration. In
most cases, reverse osmosis (RO) followed by polishing mixed bed ion exchangers is the most
efficient and cost-effective solution and also the most reliable. This is typically the recommended
configuration for cycle makeup treatment systems supplied by Black & Veatch (B&V); however,
there is no one size fits all solution for water treatment systems. Also, in recent years, an ion
exchange process known as EDI (electrodeionization) has become very popular. The system is a
continuously regenerated ion exchange process where electricity is the motive force for
regeneration of the resin. As such, no chemical supply is required or a chemical wastewater
produced. Since virtually all of the issues associated with ion exchange resin regeneration are
eliminated, there is a great demand for this type of RO permeate polishing to produce
demineralized water. Unfortunately, the technology (in B&V’s opinion), has not proven to be as
reliable as expected because of the significant risk associated with meeting both the contractual and
performance obligations associated with production of demineralized water.
System capacity and product quality requirements, water availability, wastewater discharge
limitations, environmental concerns, risks associated with equipment nonperformance, etc., must
all be evaluated before a treatment system is selected.
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6.1.2
Types of Ion Exchangers
Ion exchange resin is placed in a vessel called an exchanger. These exchangers are classified by the
type of resin in the vessel.
Common exchanger types include the following:

Weak acid cation (WAC) exchangers. WAC exchangers contain WAC resin in the hydrogen
and sodium form, which means that the cations in the water are replaced with hydrogen or
sodium ions, respectively. Characteristics include the following:
●
●
●
●
●
●
Removes cations associated with alkalinity, specifically calcium and magnesium.
High regeneration efficiency.
Susceptible to calcium precipitation if regenerated with sulfuric acid.
Carbon dioxide (CO2) is generated in the removal process and should be removed by
a degasifier downstream of the WAC vessel.
Weak acid resins have no salt splitting capability. They are only capable of splitting
the calcium and magnesium alkalinity bonds. While they have limited capabilities,
they are highly efficient resins with regard to accomplishing their intended purpose.
Regenerations require only slightly more than the stoichiometric quantities of acid
required for regeneration of the resins.
Recommended commercial resins include the following:
−
−
−

Rohm and Haas: Amberlite Series.
Purolite C104.
Dow.
Strong acid cation (SAC) exchangers (hydrogen form). Characteristics include the following:
●
●
●
●
●
●
●
Removes all cations.
Large quantities of regenerant chemicals are required to regenerate the resins.
Susceptible to calcium sulfate precipitation if regenerated with sulfuric acid.
CO2 is generated in the removal process and should be removed by a degasifier
downstream of the SAC vessel.
Operational cost savings can be realized by simultaneously regenerating a WAC/SAC
exchanger sequence. During a WAC/SAC simultaneous regeneration, the acid
regenerant is fed to the SAC vessel. The partially used acid leaving the SAC vessel is
then cascaded to the WAC vessel before being sent to the neutralization facilities.
SAC resin ion affinity is in the following order: Calcium (Ca2+) > Magnesium (Mg2+) >
Sodium/Potassium (Na/K+).
Recommended commercial resins include the following:
−
−
−
Rohm and Haas: Amberlite Series.
Dow.
Purolite.
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
Strong acid cation (SAC) exchangers (sodium form). Characteristics include the following:
●
●
●

Commonly referred to as sodium zeolite softeners.
Removes all hardness (calcium and magnesium).
Regenerated with sodium chloride.
Weak base anion (WBA) exchangers. WBA exchangers contain weak base anion resin in the
hydroxide form, which means that the anions in the water are replaced with hydroxide ions.
Characteristics include the following:
●
●
●
●
●
●
●
Removes mineral acid ions; specifically sulfate, chloride, and nitrate.
Can be regenerated by caustic solutions (NaOH) at ambient temperatures, which
provides energy savings by not having to heat the dilute caustic solution.
High regeneration efficiency.
Organic fouling is partially reversible.
If a weak base anion is used, it will not remove any of the CO2 generated by
regeneration of the cation exchanger. In this case, the degasifier may be located
following the weak base exchanger. This will reduce the overall corrosivity of the
water to which the degasifier is exposed.
WBA resins remove mineral acids (sulfates [SO4], chlorides [Cl-], nitrates [NO3], and
phosphates [PO4]) in the following order: NO3 and PO4> SO4> Cl-.
Recommended commercial resins include the following:
−
−
−

Rohm and Haas: Amberlite Series.
Dow.
Purolite.
Strong base anion (SBA) exchangers (hydroxide form). Characteristics include the
following:
●
●
●
●
●
●
Removes all anions (including alkalinity, CO2, and silica).
If silica removal is required, the strong base resins must be regenerated at elevated
temperatures, typically 120° F (49° C). (Confirm temperature with resin supplier).
Low regeneration efficiency (relatively high dosages of NaOH regenerant is
required).
Organic fouling is generally irreversible unless an acrylic type resin is being used.
Acrylic type resins do exhibit resistance to organic fouling, but they have lower ion
exchange capacities, are less capable of removing silica, must be regenerated at
lower regenerant solution temperatures, and are more susceptible to resin bead
breakage.
SBA resin ion affinity is in the following order: NO3 and PO4 > SO4 > Cl- > bicarbonate
(HCO3-) > hydrogen silicate (HSiO3-).
Organic fouling is generally only removable by hot brining methods.
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●
●
Operational cost savings may be realized by simultaneously regenerating WBA/SBA
exchangers in series. During a WBA/SBA series regeneration, warm caustic
regenerant is fed to the SBA vessel. The initial 25 to 35 percent of the regenerant
solution is discharged to waste. After that step, the partially used caustic leaving the
SBA vessel is then cascaded to the WBA vessel before being sent to the
neutralization facilities.
Recommended commercial resins include the following:
−
−
−

Rohm and Haas: Amberjet and Amberlite Series.
Dow.
Purolite.
Mixed bed (MB) exchangers. Characteristics include the following:
●
●
●
●
●
●
Typically used as a polishing ion exchanger (after other exchangers to remove small
amounts of ionic impurities).
Contain strong acid cation and strong base anion resins and possibly a small amount
of inert resin.
Inert resin, while theoretically a good idea, has in actual practice been quite
troublesome. A number of times, the inert resin retains air from the initial bed
“agitation” step with air, and then the inert resin “floats” to the top during the resin
separation step and out the backwash outlet piping. This inert resin is nearly as
expensive as the ion exchange resin, making the overall process a startup problem.
Resins are floated (separated by specific gravity) prior to regenerations. The inert
resin has a specific gravity between that of the active resins and aids in the
separation by forming a boundary layer between them (if the inert resins work as
they are supposed to). The cation resin will have a higher specific gravity and, when
separated, will settle to the bottom of the resin bed. The anion resin will have a
lower specific gravity and, when separated, will rise to the top of the resin bed.
The separated resins are then simultaneously regenerated by feeding dilute acid
into the bottom of the vessel and dilute caustic into the top of the vessel. The two
regenerant solutions meet in the middle of the inert resin layer or, if inert resins are
not used, at the interface boundary between the cation and anion resins where a
regenerant outlet header discharges the wastewater. It should be noted that
vendors frequently propose that the mixed bed outlet underdrains be used as the
acid regenerant distribution header. This is almost always a bad idea since the
outlet header will be designed to provide distribution at vessel velocities of 12 to
15 gallons per minute per square foot (gpm/ft2) flows. The regenerant acid
application rate may be on the order of 1.5 to 2 gpm/ft2 flow. Use of the common
outlet distributer generally results in poor distribution of the regenerant acid and
can potentially lead to an inefficient regeneration, which leads to a mixed bed
polisher that cannot meet performance requirements.
Resins are mixed thoroughly following the rinse to waste step, which immediately
follows the regenerant application step. Mixing is provided by a low-pressure air
blower. The inlet on the air blower must be filtered to prevent contaminants from
entering the exchanger during the resin mixing process. Following the resin mixing,
the vessel is briefly rinsed to waste to bring the outlet quality to specified
conditions. The vessel is then ready to be put into operation.
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Figure 6-1 shows an ion exchange vessel.
Figure 6-1

Ion Exchange Vessel
EDI systems. Characteristics include the following:
●
●
●
●
●
●
●
Different companies produce variations of the same conceptual design: a single
chamber or multiple chambers containing ion exchange resins, ion rejecting
membranes, a series of electrodes to impart the direct current (dc) into the resin
chambers, and dc rectifiers and voltage and amperage controllers to provide the
electrical current to continuously regenerate the resins inside the chambers.
The chambers are designed for specific hydraulic conditions that can complicate the
overall design when trying to match available component capacities with the flow
demands of the plant.
The units are extremely sensitive to incoming contaminants, especially hardness,
CO2, and silica. They are also very sensitive to variations in the influent qualities.
B&V believes that several design features should be mandatory with every cycle
makeup treatment system, including EDI polishing.
Flanges, with blinds, should be installed to allow conventional or at least “bottle
type” mixed bed exchangers to be installed if the EDI is not performing adequately.
RO systems upstream of an EDI should be at least two-stage, two-pass units
(whenever fresh water is used as the supply to the EDI). If seawater is the supply,
there should also be an upstream seawater RO feeding the two-stage, two-pass
units.
Two-stage, two-pass RO units should be furnished with caustic feed between the
two passes, and the target second pass RO influent should be controlled between a
pH of 8.3 to 8.5 for CO2 reduction.
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●
6.1.3
EDI systems need a waste sump. Normally, the sump only receives the reject from
the EDI systems, which is typically about 10 percent of the product flow. However,
when EDI systems need to be chemically cleaned, they must be allowed to run to
waste at full flow for up to 3 days after the cleaning for reconditioning so that they
can again operate at steady-state conditons. The downstream waste sump and any
pumps must be capable of handling the full flow conditions for the entire
reconditioning period.
Because of this reconditioning requirement, makeup treatment system sizing would
be required to have 2 x 100 percent capability (and both trains would have to be
operable at the same time) to allow the plant makeup to be provided while one of
the EDI systems is being reconditioned.
Pretreatment
When designing an ion exchange system, the characteristics of the influent stream need to be
examined to determine if any pretreatment is required before the ion exchange treatment. The
following parameters should be considered for the influent water to the exchangers:

Total Suspended Solids – essentially 0 parts per million (ppm)
●
●

●
Organics will foul the ion exchange resins. Organic fouling will destroy the active
resin surfaces, preventing the resins from being able to exchange the minerals.
Pretreatment options include lime softening, chlorination, and filtration followed by
dechlorination, or activated carbon filtration. Other alternatives, depending on the
water source, may be considered as long as there are no oxidizing or reducing
chemicals left in the feed to the demineralizer.
Chlorine – < 0.1 ppm
●
●

Clarification and/or filtration (pressure or gravity) pretreatment should be
provided if suspended solids are present in the feedwater. A polishing filter
(20 micron cartridge filter) may be sufficient when suspended solids content is low
enough.
Organics – essentially 0 ppm
●

Ion exchangers have some filtering capability because of the resin bed, but should
not be relied upon for filtration because fouling of the active resin surfaces can
occur.
Free or residual chlorine can poison or break down the ion exchange resin.
Pretreatment options include activated carbon filtration or dechlorination by the
addition of a reducing agent such as sodium bisulfite or sodium sulfite.
Iron (ferrous, Fe2+) – < 0.1 ppm
●
●
Iron (ferrous, Fe2+) can poison or break down the ion exchange resin.
Pretreatment options include lime softening/filtration, oxidation followed by
filtration, manganese greensand filtration, and pressure/gravity filtration.
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
Total Dissolved Solids – typically < 500 ppm
●
●
●

For a TDS above 500 ppm, RO followed by a mixed bed exchanger is recommended.
It should be noted that this is a constantly changing value since RO system costs are
still dropping. At this time, the break-even point most likely is somewhat lower –
perhaps between 300 and 400 ppm TDS.
High oil and grease levels will foul the ion exchange resin, which would prevent it
from operating properly.
Temperature
●
6.1.4
Pretreatment options include lime softening/filtration and manganese greensand
filtration.
Oils and Greases - < 0.1 ppm
●

High feedwater total dissolved solids (TDS) content results in increased loading on
the ion exchangers and increased chemical consumption. Vessels will be larger and
more expensive and regenerations will be more frequent.
Inlet temperature should not exceed 100° F (38° C). Higher temperatures require
special design considerations because of the significantly reduced resin capacities
and the shortened resin life.
Process
The most common method of demineralization using ion exchange for power plants is a three-bed
configuration, which includes a strong acid cation exchanger, a strong base anion exchanger, and a
mixed bed exchanger (or EDI if required by a client). Water is first passed through the cation
exchanger to remove positively charged ions from the water. The cation resin removes positively
charged molecules from the water by exchanging the molecule with a positively charged hydrogen
ion. The constituents removed include sodium, calcium, magnesium, iron, and other metals.
Water is then passed through the anion exchanger to remove negatively charged molecules from
the water. The anion resin removes negatively charged molecules from the water by exchanging
the molecule with a negatively charged hydroxide ion. The constituents removed include chlorides,
sulfates, nitrates, carbon dioxide, and silica.
To reach the demineralized water quality required for steam cycle makeup, a mixed bed exchanger
(or EDI) is required to remove ion leakages through the cation and anion exchangers. As described
earlier, a mixed bed exchanger contains both cation and anion resin and will remove any remaining
ions from the water. This step is often called polishing because the mixed bed exchanger is not
designed to remove large loads of impurities from the water source. It is expected that the other
exchangers upstream of the mixed bed exchanger are the workhorses of the system.
After the resin in an exchanger becomes exhausted, a regeneration sequence is used to remove the
concentrated contaminants from the resin bed and replenish the resin with its exchange ions.
Depending on the process, a variety of chemicals can be used to accomplish this regeneration.
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In the United States, sulfuric acid is used to regenerate cation resins. Internationally, hydrochloric
acid is used. The choice of acid to be used is dependent on safety concerns for the location of the
power plant and the availability of the acids in the marketplace. Calcium sulfate precipitation must
be avoided if the resin is regenerated using dilute sulfuric acid. Often, the percent concentration is
applied in a stepwise fashion, with the first third of the dosage being applied at 2 percent, the
second third of the dosage being applied at 4 percent, and the last third being applied at 6 percent.
In some cases where the concentration of calcium is exceptionally high, the acid application may be
performed in 1-1/2, 3, and 4 percent steps. Generally, a vendor’s recommendation is followed
because precautions against damages, and damages associated with, calcium sulfate precipitation
are the responsibility of the vendor and are included in the performance guarantees for the
contract. Barium sulfate is less soluble than calcium sulfate, and therefore, sulfuric acid
regeneration of a cation resin that has appreciable amounts of barium may be problematic. Heated
and diluted sodium hydroxide (caustic) is almost always used to regenerate anion resins.
The regeneration process can be either co-current flow or countercurrent. B&V has used both
methods; however, the most frequently used process is co-current flow. While countercurrent
regeneration theoretically is more efficient, it is also much more “hydraulically” challenging. It has
been B&V’s experience that physical complications associated with controlling the countercurrent
chemical application negate the theoretical benefits. This results in a system that is more
complicated to operate with little if any functional improvement.
The waste stream produced from regeneration of the exchangers contains all of the mineral
constituents from the incoming water along with the acid and caustic used to regenerate the
system. This waste stream is sent to a neutralization tank or basin to neutralize the waste stream
before being discharged to the wastewater system.
6.1.5
Wastewater Neutralization
The wastewater neutralization system typically includes a neutralization tank or basin,
recirculation pumps, acid feed, and caustic feed. The neutralization process is a batch process in
which the contents of the neutralization tank/basin are recirculated while acid or caustic is added
to reach the “neutral” desired pH range.
A neutralization tank is typically a cylindrical fiberglass reinforced plastic tank.
A neutralization basin is typically constructed of concrete and then lined. The lining material can be
fiberglass reinforced vinylester resin based, trowel applied in combination with heavy reinforcing
layer of fiberglass cloth with a nominal thickness of at least 5 mm. The Responsible Engineer
should consult with the Project Material Specialist for the lining material and specification. The
basin should be cylindrical in shape for adequate mixing of the contents in the basin.
The neutralization mixing equipment can be a mechanical mixer or a mixing eductor to adequately
mix the neutralization tank or basin contents for neutralization. Neutralization basin baffles are
recommended to be installed in a large neutralization basin if a mixer is used for mixing the
content. Neutralization basin baffles design should be included in the mixer supplier’s scope of
supply to guarantee their mixer performance.
The neutralization mixer should be top center mounted over the neutralization basin. The mixer
impeller type should be radial flow, vertical flat blade or axial flow, pitched blade. Both the impeller
and the mixer shaft should be constructed of rubber coated carbon steel. All wetted materials of the
mixer shaft and impeller should be carbon steel coated with at least 1/8 inch (3 mm) thick natural
rubber covering or fiberglass.
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A mixing eductor is a low cost alternative to a mechanical mixer with a simple design and no
moving parts. An eductor produces a mixing action between the components of a liquid, while
keeping the contents of the tank or basin in constant motion. A predetermined amount of liquid
(called operating liquid) is pumped through a header to one or more eductors submerged inside the
tank or basin. The operating fluid is usually drawn from the tank or basin via a recirculating pump.
As the operating liquid leaves the nozzle of the eductor(s), it entrains material from the tank or
basin. The entrained material is mixed thoroughly inside the parallel section of the eductor before
being discharged. The material of construction of the neutralization mixing eductor should be type
316 stainless steel. The number and sizing of the mixing eductors can be estimated using the
Chemical Waste Neutralization Calculation, which can be found through the Industrial Water
Treatment Community page.
Acid and caustic for wastewater neutralization is typically fed from the regeneration acid and
caustic feed pumps. The acid and caustic should be diluted before injecting into the neutralization
tank or basin.
6.2
Approach
6.2.1
System Design
This section should be used in conjunction with the demineralizer sizing calculation.
A typical demineralizer system consists of a three-bed configuration with a cation exchanger, an
anion exchanger, and a mixed bed exchanger. A cation exchanger is typically sized on the basis of a
usable exchange capacity of 90 percent or less of the total exchange capacity. An anion exchanger is
typically sized on the basis of a usable exchange capacity of 75 percent or less of the total exchange
capacity. Cation and anion exchange resins in a mixed bed exchanger are sized on the basis of the
same usable exchange capacities previously noted. Table 6-1 lists typical design criteria for a mixed
bed ion exchanger.
Table 6-1
Typical Design Criteria for a Mixed Bed Ion Exchanger
Item
Detail
Type
Mixed Bed Ion Exchanger
Inlet Pressure
150 psig max, approximately 20 psig above the system losses
between the exchanger and the storage system
Vessel Materials
Design Temperature
Nominal Working Capacity
Hydraulic Capacity
On-Site Regeneration
Concentration
Feed Rate
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100° F max
10 to 12 kilograins per cubic foot (kgrains/ft3) as CaCO3
12 to 15 gpm/ft2
Sulfuric Acid
4% to 8% H2SO4
4 to 15 pounds per cubic
foot (lb/ft3)
6-9
Caustic (Heated)
4% to 6% NaOH
4 to 10 lb/ft3
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6.2.2
System Configuration
In cycle makeup treatment systems that rely solely on ion exchange, the most common
configuration in industry is the three-bed configuration. This configuration and others that have
been used are described below.

Three-Bed
●
●
●
●
●
●

WAC and/or WBA ion exchangers are not recommended in a three-bed
arrangement because they only partially remove their respective cations and/or
anions. The MB exchanger should not be relied upon to be the workhorse of the
arrangement; its function should be limited to polishing.
Degasifier is recommended for waters with alkalinity/dissolved CO2 content.
Low reliability and low flexibility.
Low capital cost.
Close monitoring of intermediate and effluent chemistry is required to prevent
sodium and/or silica leak through.
Four-Bed
●
●
●
●
●

SAC, Degasifier (Optional), SBA, MB.
Primary SAC (or WAC*), Primary WBA (or SBA*), Degasifier, Secondary SAC,
Secondary SBA
-orWAC, SAC, Degasifier, SBA, MB (less common).
Less reliable and less flexible than a six- or five-bed arrangement.
Efficient – reduced chemical use during regenerations when WAC and/or WBA are
used in the primary position.
Lower capital cost than a six- or five-bed arrangement.
Sodium and/or silica leak through may be a concern if a WAC and/or WBA,
respectively, are used in the primary position.
Five-Bed
●
●
●
●
Primary SAC (or WAC*), Primary WBA (or SBA*), Degasifier, Secondary SAC,
Secondary SBA, Polishing MB.
Reliable – minimal load on polishers.
Flexible – secondary and MB exchangers can be bypassed.
High capital cost, but less than six-bed arrangement.
* The decision to use WAC and/or SBA ion exchangers in the primary positions should be based on influent
and effluent water quality requirements.
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
Six-Bed
●
●
●
●
●

Primary SAC (or WAC*), Primary WBA (or SBA*), Degasifier, Secondary SAC,
Secondary SBA, Polishing SAC, Polishing SBA.
Reliable – minimal load on polishers.
Efficient – reduced chemical use during regenerations when WAC and/or WBA are
used in the primary position.
Flexible – secondary and polishing exchangers can be bypassed.
High capital cost.
Two-Bed
●
●
●
●
●
●
●
●
●
6.2.3
SAC, Degasifier (Optional), SBA.
Should only be used on systems feeding low-pressure (600 psi or lower class)
boilers.
Lack of secondary and/or polishing ion exchangers means that any leakage through
the SAC or SBA will be fed directly to the cycle.
Regenerations will be more frequent to prevent leakage resulting in higher chemical
costs and lower net system capacity.
Degasifier is recommended for waters with alkalinity/dissolved CO2 content.
Least reliable and least flexible configuration.
Lowest capital cost.
Close monitoring of effluent chemistry is required to prevent/minimize sodium
and/or silica leak through.
Anticipatory conductivity monitoring is recommended to provide indication of
when a bed is nearing exhaustion.
Degasifiers
Degasifiers are often used in between cation and anion exchangers when the water source has a
high alkalinity/ dissolved CO2 content. This is to reduce the load on the anion exchanger so that the
exchanger does not need to be regenerated as often. There are three types of degasifiers that are
used, with forced draft degasifiers being used the most in cycle makeup treatment systems. The
following provides a summary of each:

Forced Draft Degasifier
●
●
●
Removes dissolved carbon dioxide to approximately 10 to 12 ppm.
Saturates water with dissolved oxygen and nitrogen.
Low capital and operating costs.
* Decision to use WAC and/or SBA ion exchangers in the primary positions should be determined based on
influent and effluent water quality requirements.
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●

Typically sized for a flux around 20 gpm/ft2.
Vacuum Degasifier
●
●
●
●
●

Typical forced draft degasifiers are approximately 20 feet tall and self-supporting.
Removes dissolved carbon dioxide to less than 10 ppm.
Removes dissolved oxygen to approximately 20 parts per billion (ppb).
Recommended where effluent quality requires low dissolved oxygen levels.
Higher capital and operating costs associated with a larger/taller vessel and the
power requirements for the vacuum pumps to maintain the vacuum in the
degasifier.
Vacuum degasifiers can be 40 to 60 feet tall, may consist of multiple stages, and may
require external supports.
Typically sized for a flux around 25 gpm/ft2.
Membrane Degasifier
●
●
Smaller footprint requirement in comparison to a forced draft or vacuum degasifier.
Runs under vacuum and requires a vacuum pump.
Refer to Section 9.0 for more information on degasifiers.
6.2.4
System Startup
Some facts that are helpful to know for system startup include the following:







Operation of ion exchangers between regeneration cycles is considered a run.
Ion exchanger effluent quality will be best immediately after regenerations.
Influent ion concentration dictates how much ion the resin bed can remove before ions leak
through the resin bed into the effluent.
As the resin bed becomes saturated with absorbed ions, less resin is available for ion
removal.
The strength in which the resin holds on to a particular ion is a function of the ions affinity.
Ions with a higher affinity will have a stronger bond with the resin than an ion with a lower
affinity. Because of this, the resin will release an ion with a lower affinity in order to bond
with an ion with a higher affinity. In this way, the resin is said to have a preference for some
ions over others.
Eventually ions will leak through the resin bed. Because of the resin’s preference for higher
affinity ions, the first ions that will leak through the resin bed will have the lowest affinity.
Ion exchange will continue as long as ions are present that have a higher affinity than the
ions that are already bonded to the resin.
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

6.3

Typically, resin beds are said to be exhausted when all of the primary ions (H+ or OH-) on
the resin have been replaced with an ion with a higher affinity or when a predetermined
percentage of ions leak through the resin bed into the effluent. Rohm and Haas considers a
run to be 100 percent complete when the ion leakage reaches 10 percent.
Resin beds are not typically run to exhaustion. Instead, regenerations are typically initiated
at some percentage of run completion (percent exhaustion), total throughput, etc.
References
Demineralizer Calculation. (Found through the Industrial Water Treatment Community
page.)
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7.0
7.1
Reverse Osmosis
Purpose and Applicability
This section provides design criteria for brackish water reverse osmosis (RO) systems installed in
all Energy projects and provides recommendations as well as specific criteria for system sizing and
design for RO equipment. Desalination and wastewater RO system considerations can vary
significantly from brackish water RO systems which preclude the use of this section in the design of
those systems.
7.2
Approach
This section is intended to be used as a basis for the design of RO equipment.
7.2.1
Overview
RO is the process of removing dissolved solids from water by passage through a semi-permeable
membrane to produce high purity water. RO is often used as a step in producing demineralized
water, for wastewater volume reduction, and for desalinating seawater for use as service water and
other plant uses. Figure 7-1 shows how RO membrane pore size compares to other types of
filtration.
Figure 7-1
Pore Size of Filtration Processes
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The phenomenon of osmosis, as shown on Figure 7-2, occurs naturally when pure water flows from
a less saline solution through a semi-permeable membrane to a more concentrated saline solution
in order to balance the hydraulic pressure. The semi-permeable membrane will pass water but acts
as a barrier to dissolved salts and both inorganic and organic molecules. Osmotic pressure is the
pressure difference that exists once the system is in equilibrium. RO applies pressure in excess of
osmotic pressure on the more saline solution side of the membrane to push the water through the
membrane while the salts remain. This concentrates salts on the feed/inlet side of the membrane
while producing high purity water referred to as permeate on the product side of the membrane.
The concentrated salt stream, referred to as the reject or concentrate, is sent to waste. Rejection of
salts from the feedwater is typically 95 percent to greater than 99 percent depending on the
application and membranes used. RO is applied as a crossflow filtration process as shown on
Figure 7-3.
Figure 7-2
Mechanism of Osmosis and Reverse Osmosis
Figure 7-3
Reverse Osmosis Process Flow
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RO membranes predominately used in water treatment applications are thin film composite spiral
wound membranes. A spiral wound membrane contains multiple membrane leaves attached to a
center channel then wrapped spirally around the center channel on top of one another. A
membrane leaf consists of two membrane sheets glued together with a permeate spacer in between
them. The glue lines are on three sides with the fourth, open side of the leaf connected to and
sealed against the central part of the permeate water tube, which collects the permeate from all
leaves. A sheet of feed spacer is between each leaf to provide the channel for the feed and
concentrate flow. Membrane feed spacer thickness varies among different membranes. A thicker
feed spacer reduces fouling, reduces the frequency of cleanings, and improves cleaning efficiency.
Figure 7-4 shows the parts of the RO membranes and how they are constructed.
Figure 7-4
Spiral Wound Membrane
Standard membrane size is 8 inches (200 mm) in diameter and 40 inches (1,000 mm) long. The
active membrane area will vary depending on the membranes selected. Other membrane sizes are
available for use, but are not typical. Dow, Hydranautics, Torray, General Electric, and Koch are the
most common producers of membranes.
An RO system is configured such that membranes are placed in series inside a pressure vessel. As
the feedwater passes through the vessel, concentrate from the first membrane is fed to the second
membrane and so on while permeate is collected in the center. The center permeate tube for each
of the membranes is connected in one of two ways; the first is with interconnectors that have Orings to prevent contamination of the permeate with concentrate; the second is the membranes are
supplied with locking devices on the ends so that they connect to each other and lock in place when
twisted to form a permeate seal.
RO performance is highly dependent on pretreating the feedwater to minimize scaling and fouling
of the RO membranes. Scaling results from soluble salts being concentrated past their solubility
and precipitating on the membrane surface. Fouling occurs when particulates and/or organic
constituents in the feedwater settle on the surface of the membrane and impair its performance.
Forms of RO pretreatment include softening, filtration (media and membrane), disinfection, and
chemical conditioning. This is discussed further in Subsection 7.2.2.4.
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A single staged RO system consists of two or more pressure vessels configured in parallel. In order
to increase overall recovery, a second stage can be added to treat the concentrate from the first
stage. Each stage of RO membranes will recover approximately 50 percent of the feedwater.
Therefore, to recover additional water, many brackish water RO applications are two staged
systems that recover approximately 75 percent (50 percent first stage, 50 percent of 50 percent in
the second stage). Two stage RO systems are common for brackish water applications. To recover
additional water with additional stages, the chemistry of the feedwater needs to be analyzed
carefully. As recovery increases, fouling potential and feed pressures increase, adding to the
complexity of the system design. Desalination systems are single stage 40 to 50 percent recovery
systems due to the amount of salts in the feed and concentrate streams making a second stage
inefficient.
To increase the quality of permeate from RO, additional RO passes can be added to the system
design. Unlike an additional stage, which treats the concentrate from the previous stage, an
additional pass treats the permeate from the previous pass. Because the second pass feed is high
quality water, the permeate and the concentrate from the second pass is higher quality. The
permeate might be able to be used directly for lower pressure boiler makeup or as direct feed into
mixed bed exchangers to make demineralized water. The reject from second pass units is often
recycled back to the first pass feed in order to improve recovery. Figure 7-5 shows a conventional
two pass, two stage RO configuration.
Figure 7-5
Two Pass, Two Stage RO Configuration
7.2.2
System Design
7.2.2.1
Scope
The RO system design is based on the inlet water quality, process application, contractual
requirements, and client preferences. The basic design considerations for RO systems are
discussed in the following subsections.
7.2.2.2
Reliability
Reliability is an important factor in the design of an RO system. The level of reliability and how it is
accomplished varies by project. Redundancy is one way to improve reliability and can be provided
by different means.
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One way of providing reliability is providing redundant items of equipment that are most likely to
require frequent maintenance, fail, or malfunction and render the RO system inoperable. This
equipment may include RO units, RO feed pumps, chemical dosing pumps, control valves, and RO
pretreatment components. Providing spares of these components can increase the reliability of the
system. The Chemical design engineer should be responsible for determining redundancy if not
defined by contract/client requirements.
RO membranes periodically require offline chemical cleaning to remove scale, organics, and biofilm.
Multiple units allow continued RO permeate production while one unit is being cleaned. RO
cleanings typically take 8 to 10 hours, but could take longer depending on the type and extent of
fouling.
Where multiple RO units are preferred, the RO system should include at a minimum two trains
(either 50 percent or 100 percent capacity). Where a single full capacity RO unit is provided,
sufficient on-site treated water storage should be provided for at least 2 to 3 days of normal plant
operation while the RO is out of service.
Providing too much redundancy with the RO units should be avoided. RO units that sit idle must
have proper lay-up procedures performed, which can vary from a flush to sodium bisulfite
injection. A typical RO lay-up procedure is as follows:



Less than 24 hour lay-up – Water flush.
Lay-up between 24 and 48 hours – Water flush with biocide injection.
Greater than 48 hour lay-up – Immerse the membranes in a 1.5 percent sodium bisulfite
solution.
On-site water storage is another means of providing redundancy. Instead of increasing equipment
redundancy, water storage can account for unplanned equipment failures.
RO cartridge filters and feed pumps should be either two 100 percent capacity units or one
dedicated to each RO train. Cartridge filters contain disposable “throw away” filter elements that
require the filter to be taken offline for replacement.
Chemical feed systems associated with the RO system should include two 100 percent capacity feed
pumps.
Redundancy for equipment associated with the chemical cleaning skid is not required since this
equipment is only used quarterly.
7.2.2.3
Feedwater Quality
In order to properly design an RO system, including the pretreatment portion, a complete and
accurate water analysis should be obtained. A water analysis form lists what constituent
concentrations constitute a complete analysis. The Hydranautics RO Water Chemistry document
found through the Industrial Water Treatment Community page provides a detailed description for
each of these constituents, including how they affect the RO membranes. Based on the water
quality, the proper pretreatment configuration should be selected. Table 7-1 provides the
recommended water quality parameters for RO feedwater. These limits should be followed to
ensure successful operation of the RO system and to minimize fouling and chemical cleaning
frequency.
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Table 7-1
RO Feedwater Quality Guidelines
PARAMETER
Silt density index (SDI15)
MAXIMUM
LEVEL*
5
Oil and grease, mg/L
0.1
Chemical oxygen demand (COD),
mg/L
10
Total organic carbon (TOC), mg/L
Free chlorine, mg/L
Ferrous iron (Fe2+), mg/L
Ferric iron (Fe3+), mg/L
Manganese, mg/L
Aluminum, mg/L
Temperature, °F
3
Undetectable
0.05**
0.05
0.05
0.05
113 (higher
temperature
membranes are
available)
*Maximum levels are for typical applications. Operation
outside of these ranges may be possible but may impact
membrane selection, system design, and frequency of RO
cleanings.
**Ferrous iron concentration can be up to 0.5 mg/L with a
pH less than 7.0 and up to 4 mg/L with a pH<6.
7.2.2.4
Pretreatment
Proper pretreatment of feedwater is critical to increase the efficiency and life of RO systems. In
order to minimize membrane cleanings and maximize membrane life, the pretreatment system
should minimize the following:



Fouling
Scaling
Membrane degradation
Fouling RO membranes impacts performance by reducing permeate flow and salt rejection. Fouling
is the accumulation of iron, silt (TSS), phosphorus, biological, and organic compounds (TOC, COD,
and biochemical oxygen demand [BOD]) on the membranes. Pretreatment consisting of filtration is
required to reduce and/or remove these fouling constituents. Generally, multimedia filtration is
the most cost effective; however, membrane filters (i.e., ultrafiltration) provide a more reliable
barrier to solids reaching the RO. Waters with heavier fouling constituents may require a
physical/chemical process prior to the filters.
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Silt density index (SDI15) is a method used to predict the fouling potential of RO feedwater. SDI is
calculated from the rate of plugging of a 0.45 μm filter when water is passed through at a constant
pressure. The SDI Standard Test Method provides a procedure for measuring SDI and can be found
through the Industrial Water Treatment Community page. RO pretreatment should be designed to
produce an SDI15 less than 5, preferably less than 3. RO systems, as a minimum, should include
cartridge filters upstream of the RO feed pumps.
Scaling is the precipitation and deposit of sparingly soluble salts on the membranes by exceeding
the solubility limits in the RO concentrate stream. The common salts that create potential scaling
problems with RO design are listed below:








Calcium Carbonate - CaCO3
Calcium Sulfate - CaSO4
Silica - SiO2
Calcium Fluoride - CaF2
Barium Sulfate - BaSO4
Strontium Sulfate - SrSO4
Aluminum Salts
Calcium Phosphate (applies when treating tertiary treated water)
If the saturation level of these salts is exceeded, either the recovery rate can be reduced to lower
the concentration in the reject stream or chemical feeds such as acid and antiscalants can be
utilized to increase solubility. Design of these chemical feeds is discussed in Subsections 7.2.2.4.2
and 7.2.2.4.3. Silica scale is a concern and its solubility cannot be increased as high as the other
salts listed above. If silica concentration exceeds the solubility point, the recovery rate should be
decreased and pretreatment, such as softening or ultrafiltration, should be used to remove silica
from the RO feedwater or specific antiscalants that target silica need to be considered. The silica
concentration in the reject stream should be compared with the solubility limit to determine if silica
scale is a concern. Figure 7-6 shows the silica solubility limit as a function of temperature. A pH
correction factor as shown on Figure 7-7 should be applied to the solubility limit based on the
concentrate stream pH. As a rule of thumb, 150 – 200 mg/L of SiO2 is the limit in the concentrate.
Pretreatment systems may include lime softening, media filtration, membrane filtration, zeolite
softening, and/or chemical treatment. These systems should be designed to minimize RO scaling
and fouling concerns. The pretreatment equipment selected should be based on the feedwater
source, water quality, application, and contract/client requirements. Table 7-1 lists maximum
concentration levels for different components in feedwater to the RO. Pretreatment systems should
be chosen such that these parameters are met.
The RO pretreatment should include, at a minimum, a dechlorination process (preferably chemical
reducing agents) to fully remove any free chlorine, cartridge filters to reduce suspended solids, and
chemical feed to control scale (antiscalant and/or sulfuric acid). More robust pretreatment systems
will typically focus on reducing calcium, magnesium, silica, iron, and suspended solids since these
constituents can be problematic for RO systems. Aluminum sulfate should be avoided as a
coagulant for pretreatment systems because residual aluminum can foul the RO membranes.
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Ultrafiltration is gaining market share as pretreatment for RO systems. It can greatly improve the
life of the membranes and provide SDI values consistently less than 3. Wastewater RO
pretreatment systems may need multiple pretreatment technologies to avoid uncontrollable scaling
of the membranes.
Figure 7-6
Solubility of SiO2 versus Temperature
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Figure 7-7
SiO2 pH Correction Factor
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7.2.2.4.1
Cartridge Filtration
Cartridge filtration uses filter elements or cartridges mounted in a pressure vessel. Figure 7-8
shows a typical design. The filter cartridges are sheet or wound fiber material supported by
screens or perforated plate made of stainless steel or plastic. Cartridge filters should always be
included to protect the RO membranes from suspended solids. The cartridge filters are used only
for polishing fine solids and not for removal of high amounts of filterable solids. Upstream filtration
should be provided to remove these solids. The cartridge filters are typically polypropylene wound
elements on a polypropylene core and should have a minimum pore size of five microns absolute.
The cartridge filters should be designed with differential pressure measurement to indicate when
the filter elements need to be replaced.
Figure 7-8
7.2.2.4.2
Typical Cartridge Filter Design
Acid Feed
Acid can be fed to the RO feedwater to minimize its scaling potential. Acid is fed to control calcium
carbonate scale as measured by the Langlier Saturation Index (LSI). LSI is a qualitative method of
reporting the scaling or corrosive potential of low total dissolved solids (TDS) brackish water.
Water with a negative LSI is considered corrosive and will not form calcium carbonate scale. Water
with a positive LSI is not corrosive, but it will tend to form calcium carbonate scale.
Sulfuric acid is the preferred acid; however, sulfuric acid will add sulfates to the water increasing
the possibility of sulfate scaling. Hydrochloric acid may be required for projects outside the United
States where sulfuric acid is not as readily available. It is important to note that hydrochloric acid
has a tendency to fume, which causes specific handling issues that must be addressed in the design
of the storage system.
The acid feed pumps should be sized such that the proper LSI is maintained within the RO
concentrate stream. To control calcium carbonate scale exclusively with acid, the LSI in the RO
concentrate stream must be negative, otherwise antiscalant is required.
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7.2.2.4.3
Antiscalant Feed
An antiscalant should be fed to the RO feedwater upstream of the RO modules but far enough
downstream of acid feed to allow mixing of the acid. Antiscalant is fed to control calcium carbonate,
calcium sulfate, strontium sulfate, barium sulfate, calcium fluoride, and silica scaling. Typical
antiscalants are proprietary organic polymers. The antiscalant feed pumps should be designed to
maintain the desired residual of the specific antiscalant being used; however, the actual antiscalant
usually has not been established at the time of design. In the absence of more specific information,
each antiscalant feed pump should be sized to feed 5 milligrams per liter in the RO feedwater. The
feed should be continuous and may need to be automatically adjusted if fed to the inlet of multiple
units. Automatic adjustment can be performed with the use of an automatic electronic stroke
positioner or variable speed drive motor.
Table 7-2 lists the typical maximum limits of saturation of certain constituents when feeding an
antiscalant. If these concentrations are exceeded in the RO system, either a lower recovery rate or
additional pretreatment targeting these constituents is required.
Table 7-2
Typical Maximum Saturation Limits with Antiscalant Feed
SCALANT OR FOULANT
Langlier Saturation Index (LSI)
MAXIMUM
LEVEL
+1.8
Calcium Sulfate
230%
Barium Sulfate
6,000%
Strontium Sulfate
Calcium Fluoride
Calcium Phosphate
Silica
800%
10,000%
Refer to
antiscalant
supplier
information
100%
Antiscalant is typically not required upstream of a second pass RO unit.
7.2.2.4.4
Chemical Reducing Agent Feed
A chemical reducing agent should be fed to the RO feedwater downstream of the cartridge filters
prior to the inlet of the RO. A chemical reducing agent is fed to dechlorinate the water to prevent
irreparable oxidation damage to the membranes. A static mixer is recommended to ensure proper
mixing. Sodium bisulfite is a commonly used reducing agent. Other chemical reducing agents exist,
but they are not as cost effective as sodium bisulfite. Sodium bisulfite feed pumps should be
designed to feed 2 milligrams per liter of sodium bisulfite for each milligram per liter of total
chlorine expected in the RO feedwater. The concentration of sodium bisulfite being used needs to
be accounted for when sizing the chemical feed pumps. Sodium bisulfite should be fed in
proportion to the flow. An oxidation-reduction potential (ORP) electrode should be included
downstream of the static mixer to continuously monitor the presence of an oxidant. The ORP
reading should always be less than 300 millivolts (mV).
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7.2.2.4.5
Caustic Feed
For a two pass RO system, caustic can be fed to the second pass feed, if required. Carbon dioxide
being a dissolved gas will pass through RO membranes into the permeate steam and will use up
resin capacity in downstream mixed bed exchangers or might cause operational problems with a
downstream electrodeionization (EDI) system. Feeding caustic prior to the second pass feed to
raise the pH above 8.2 will convert all of the carbon dioxide to bicarbonate, which will be removed
by the RO.
Caustic can also be fed upstream of the RO system to increase silica rejection, to remove certain
TOC constituents that are better rejected at higher pH, and reduce biological and organic fouling.
Caution should be exercised when feeding caustic upstream of the RO because raising the pH
decreases the solubility of iron, manganese, and calcium carbonate.
7.2.2.5
Reverse Osmosis
The RO system consists of membrane elements housed in pressure vessels. A high-pressure pump
is used to feed the pressure vessels. The necessary piping, valves, instrumentation, and controls are
required for a properly functioning system. The following sections describe guidelines for each of
these aspects of the RO design. Two RO design/performance software projection tools, Dow
FilmTec’s ROSA and Hydranautic’s IMSDesign, are available to aid in designing a new RO system
and to evaluate performance of an existing RO system. ROSA step by step instructions can be found
through the Industrial Water Treatment Community page. The RO system should be modeled at
both the minimum feedwater design temperature and the maximum feedwater design temperature.
The membrane salt rejection decreases at higher feedwater temperatures so the maximum
feedwater temperature case will provide the poorest permeate water quality. The minimum
feedwater temperature case will provide the maximum inlet pressure required.
RO permeate is extremely corrosive to mild steel. Piping for the RO system is typically 316
stainless steel for the feed, concentrate, and permeate lines; however, in some cases, 316 stainless
steel is not appropriate for the concentrate piping because of high chlorides, and the material
selection may include higher alloy steels. It is also recommended that filter piping upstream of the
RO be provided in stainless steel to maintain a high level of cleanliness upstream. Plastic piping can
be used in low-pressure systems where cost is a concern but is more susceptible to leaks and
cracks.
7.2.2.5.1
System Configuration
RO systems consist of stages and passes that affect the overall yield and purity of the permeate
stream. When designing an RO system, the number of passes and the number of stages in each pass
need to be determined. The number of stages impacts the overall recovery of each pass. For
brackish water, a single stage can typically recover approximately 50 percent. Adding a second
stage increases the recovery to approximately 75 percent. The group of stages is called the first
pass. Each RO pass should be designed with a minimum of two stages unless specific project
parameters require otherwise. The maximum recovery for a first pass, two-stage RO should be
designed at 75 percent. Systems designed to greater than 75 percent recovery with three stages
need to be reviewed by the Chief Engineer.
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Based on the feedwater quality, the recovery may need to be lower than 75 percent for a two-stage
first pass. The saturation levels of the scaling constituents in the concentrate stream need to be
verified. The RO design projection tools can provide this information. If scaling constituents
exceed levels discussed in Subsection 7.2.2.4.3, then the process engineer must determine the
means to correct, which may include reducing the recovery, additional pretreatment, additional
acid to the feed, or fewer membranes per vessel.
The number of passes required for the RO system is dependent upon the use of the RO permeate.
Typically, when the RO permeate is feeding downstream mixed bed polishers, the system should
have two passes, unless feedwater quality allows only one. Two passes are always required ahead
of EDI units. A booster pump should be provided between the two passes to overcome the osmotic
pressure of the second pass. Since the feedwater to the second pass is RO permeate, the
concentrate from the second pass will likely be higher quality than the first pass feedwater. As
such, this water should be recycled to the front of the system, upstream of the RO feed/booster
pumps. Higher quality feedwater to the second pass allows for higher design recovery rates of the
second pass, typically 85 to 90 percent.
RO permeate should be collected in a tank immediately following the RO system to minimize
backpressure on the RO membranes. The RO permeate tank should be sized for at least 10 minutes
of RO permeate flow and have sufficient volume to allow for the flushing of the RO during
shutdown. RO permeate should be used to flush the RO system following system shutdown to
minimize membrane fouling while out of service.
7.2.2.5.2
Membrane Selection
Thin film composite membrane types are the primary membrane used for Energy applications.
Cellulose acetate membranes are also available; however, thin film composite membranes provide
better rejection of salts and organics, higher flux rates, lower operating pressure, and a wider pH
and temperature operating range. Unlike the thin film composite membranes, cellulose acetate
membranes can tolerate chlorine residuals.
RO membranes are selected based on feedwater quality, fouling potential, required salt rejection
rate, and energy requirements. The standard membrane size is 8 inches (200 mm) in diameter and
40 inches (1,000 mm) long. Low energy membranes require lower feed pressures, reducing the
feed/booster pump size. However, caution should be taken when using low energy membranes
upstream of EDI or mixed beds as they have lower salt rejection rates. The low energy membranes
would be more suitable for wastewater, service water, and cooling tower makeup applications.
Low fouling membranes have wider feed spacers to reduce plugging and improve the cleanability of
the membrane.
The permeate flux is a key design parameter for performance of the RO system. Permeate flux is
defined as the permeate flow rate per membrane surface area (commonly noted in gallons per
square feet per day [gfd] or liters per square meter per hour [lmh]). Flux rates for system design
vary depending on the fouling tendency of the RO feedwater. Suggested flux rates for the different
types of RO feedwater are in the “Dow FilmTec Membrane System Design Guidelines,” which can be
found through the Industrial Water Treatment Community page. In addition to flux rates, the
document has the suggested maximum permeate flow rate, minimum concentrate flow rate, and
maximum feed flow rate. The design guidelines in the “Dow FilmTec Membrane System Design
Guidelines” document should be followed when designing an RO system.
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7.2.2.5.3
RO Feed Pumps
High-pressure pumps for each RO pass are required to elevate the feedwater to the required
pressures for proper system operation. The first pass feed pumps should be located downstream of
the cartridge filters. The pumps should be designed such that the discharge pressure will maintain
the required permeate pressure at the maximum feedwater TDS and minimum feedwater
temperature and account for pressure increase to compensate for irreversible fouling over the life
of the membrane. The pumps shutoff discharge pressure should not exceed the maximum
allowable pressure of the RO membranes and pressure vessels, or an appropriately sized relief
valve should be included to provide overpressure protection of the system. The feed pumps should
be multistage centrifugal pumps; however, other pump types are acceptable. Generally, immersed
motor feed pumps such as Tonkaflo pumps are not recommended because they are not very
reliable and are difficult to maintain.
The first and second pass RO feed pumps should be designed with variable frequency drives
(VFDs). VFDs eliminate soft start requirements, improve membrane life, and regulate feed pressure
to compensate for TDS and temperature fluctuations and fouling of the membranes while still
maintaining the required flow rates. Generally, inlet pressure control valves are not required
where VFDs are used.
A typical limitation for shippable RO skids is 1,000 gpm of permeate. At 1,000 gpm of permeate and
a typical TDS of brackish water (250 to 10,000 ppm), the RO feed pumps can reach up to 400 hp. If
approaching these ranges, the process engineer needs to work with the electrical engineer to
understand the voltage requirements for VFD driven pumps.
7.2.2.5.4
Controls and Instrumentation
The RO system should be designed with a control valve on the reject line in lieu of only a pressure
reduction orifice. The control valve should control the reject flow rate such that the design
recovery rate is achieved. The VFDs on the feed pumps will maintain proper flow at the required
pressure to the RO vessels. If acid and caustic chemical feed are part of the system design, pH
probes should be included at the necessary locations for proper control of the acid and caustic
feeds. The first pass VFD should be controlled to maintain the effluent from the RO system, and the
second pass VFD should be manually adjusted as necessary based on seasonal temperature
variations.
RO normalization compares current performance of the RO membranes against a reference
condition such as initial operation of the membranes. Comparing current performance to the
reference condition provides indication of fouling. RO systems should be provided with the
necessary conductivity, pressure, temperature, and flow measurements to normalize the system
performance. The instrumentation listed in Table 7-3 should be included as a minimum for each
RO pass in order to be able to normalize the system performance. Additional instrumentation may
be required dependent upon project requirements. The RO control system should include
preprogrammed normalization software to perform the necessary calculations and indicate when
RO cleaning is recommended.
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Table 7-3
Instrumentation for RO Normalization
MEASUREMENT
FEED
PERMEATE
Conductivity
X
X
Flow(2)
X
X
Pressure(1)
Temperature
X
X
REJECT
X
X
X
(1)Pressure should be measured between each
stage.
(2)Flow only needs to be measured in two places
and the third can be calculated.
Note: All these measurements should be
transmitted to the programmable logic controller
(PLC) for display and recording and to use in
normalization calculations.
An RO system is not designed to modulate flow and should shut off/turn on based on level in the
downstream permeate tank. Upon shutdown of the RO, an automatic flush sequence should be part
of the system controls to remove the high TDS water from the pressure vessels to protect the
membranes. The flushing should be done at low pressure and RO permeate water should be used.
In order to prolong membrane life and optimize performance, the RO system should be run
continuously. Downstream equipment, including the RO permeate tank, should be designed to
minimize starts and stops on the RO system.
7.2.2.6
Reverse Osmosis Cleaning
RO membranes are subject to fouling and scaling, which decreases their performance. Periodic
chemical cleaning is required to remove foulants from the membrane surface and restore
performance. A permanent clean-in-place (CIP) system should be included as part of the RO system
design to facilitate cleaning of the membranes. Each RO should be designed with sufficient piping
and valving to clean each stage individually. This is more effective than cleaning both stages at once
because it prevents sending the removed contaminants from the first stage into the second stage.
Because cleaning is only required periodically, hoses are acceptable for connection of the CIP
system to the RO, unless project-specific requirements indicate otherwise or the unit capacity is
such that greater than 4 inch hoses are required for cleaning. Piping for the CIP system should be
chlorinated polyvinyl chloride (CPVC). The CIP system should include the following major
equipment:





Chemical mixing tank.
Cleaning pump.
Cartridge filter.
Immersion heater.
Solution coolers (when conditions require them).
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The chemical mixing tank should be constructed of polypropylene or fiberglass reinforced plastic
(FRP). The tank should have a removable cover for loading chemicals and an immersion heater for
heating the chemical solution. Since there are maximum temperature limits to cleaning cycles, a
tank cooler may also be required in certain geographical regions. A temperature control device
should be included to control the heater along with a local temperature gauge. The tank should be
sized based on the volume of the empty pressure vessels plus the volume of the feed and return
hoses or pipes for a single stage cleaning. Platforming and steps, as required for access to the tank,
should be provided on the CIP skid.
The cleaning pump should be sized based on a feed flow rate of 30 to 45 gpm per pressure vessel
and a feed pressure of 20 to 60 psig. A recirculation line from the pump discharge back to the
chemical mixing tank should be provided to mix the tank. An eductor for loading chemicals into the
recirculation line should be provided. Flow indication should be included on the discharge of the
pump to monitor the flow rates to the RO. A cartridge filter downstream of the pump prevents
suspended materials from plugging the RO membranes.
The chemical cleaning frequency of the RO membranes depends upon the type of water being
treated, system recovery rate, and the upstream pretreatment equipment. Cleaning frequency can
range anywhere from every 3 to 12 months. Cleaning more frequently than every 3 months can
indicate improper upstream pretreatment. RO membranes should be cleaned once there is
evidence of fouling. Waiting too long to clean the membranes may irreversibly affect membrane
performance. Normalized RO performance data, as discussed in Subsection 7.2.2.5.4, is used to
determine when cleaning is required. As a general rule of thumb, the following guidelines should
be used:



Normalized permeate flow decreases 10 percent.
Normalized salt passage increases 5 to 10 percent.
Normalized pressure drop increases 10 to 15 percent.
Low or high pH cleanings are used based on the type of fouling. High pH cleaning solutions are
used for organic fouling, including biological matter, while low pH solutions are used for inorganic
precipitates. Since more than one foulant can be present, RO chemical cleanings often require a
high and low pH cleaning. When this is the case, a high pH cleaning is the first step since an acid
cleaning solution could react with silica, organics, and biofilm, which may cause further decline of
membrane performance.
Different cleaning chemicals are recommended based on the type of foulant. A target pH range for
cleaning chemicals is 2 to 4 for acid cleaning and 10 to 12 for alkaline cleaning. The following is a
list of common chemicals used for cleaning. In addition to this list, chemical suppliers provide
proprietary cleaning solutions:

Acid cleaning:
●
●
●
Citric acid.
Hydrochloric acid.
Sodium hydrosulfite.
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
Alkaline cleaning:
●
●
●
●
EDTA.
Sodium tripolyphosphate (STPP).
Sodium salt of dodecylbenzene sulfonate (Na-DDBS).
Sodium hydroxide.
The cleaning chemicals and target pH should be verified with the membrane supplier. Sulfuric acid
should not be used as an acid cleaning solution because of the potential for calcium sulfate
precipitation.
7.2.3
Application
Typical applications for RO are listed below. Specific project or client requirements may warrant an
RO for applications other than the following:


Upstream of mixed bed exchangers or electrodeionization (EDI) as part of a demineralized
water treatment system.
Wastewater treatment.

Service water treatment.
7.2.4
System Operation

Cooling tower makeup.
The following is a list of operational aspects of an RO that need to be considered as part of the
system design:






The RO feed pump pressure should be slowly ramped up when started to avoid damaging
the elements or pressure vessels. Use of VFDs on RO feed pumps addresses this concern.
Single speed RO feed pumps should include controls to soft start the pumps.
Layout of the RO skids should include 5 feet (1.5 meters) of clear space on both ends of the
skids for loading and unloading of membranes.
A nonoxidizing biocide can be fed on a continuous or shock basis to help control biological
fouling of the membranes.
Sodium bisulfite can function as a nutrient if sulfur reducing bacteria is present in RO
feedwater.
The maximum operating temperature for thin film composite membranes is 113° F.
If a cationic-based coagulant is used for upstream pretreatment, anionic-based antiscalants
should be used with caution as the two can form insoluble gels that blind off section of the
RO membrane, inhibiting proper permeate flow, and are difficult to clean off. Cationic
polymers should be avoided upstream of RO membranes.
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


7.3





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

RO membranes are designed for continuous operation. On/off operation is hard on the
membranes. In addition, the membranes require periodic flushing when shut down.
RO permeate is extremely corrosive to mild steel.
RO trains should not be off-line for extended periods of time (more than 1 day). If only one
train is required in operation, the operator should alternate which train is used.
If RO concentrate is being recovered in a process such as a cooling tower or scrubber, the
range of back pressure imparted by the process should be considered in the design of the
RO control system and specified to the RO supplier. Back-pressure variation can be
minimized when RO concentrate is being recovered in tanks or basins by having it enter
above the water line at a fixed elevation.
References
Dow Water & Process Solutions, FilmTec™ Reverse Osmosis Membranes Technical Manual
(Found through the Industrial Water Treatment Community page).
Dow FilmTec Membrane System Design Guidelines (Found through the Industrial Water
Treatment Community page).
Hydranautics, Chemical Pretreatment for RO & NF, October 2013 (Found through the
Industrial Water Treatment Community page).
Koch Membrane Systems, “Membrane Technology for Industrial Wastewater Treatment,”
April 20, 2011 (Found through the Industrial Water Treatment Community page).
Hitachi, “Desalination System Design,”
(http://www.hitachi.com/environment/showcase/solution/industrial/desalination_plant.h
tml.)
SDI Standard Test Method (Found through the Industrial Water Treatment Community
page).
Hydranautics RO Water Chemistry (Found through the Industrial Water Treatment
Community page).
ROSA Step-by-Step Instructions (Found through the Industrial Water Treatment
Community page).
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8.0
8.1
Condensate Polishing
Purpose and Applicability
This section provides design criteria for condensate polishing systems installed in all Energy power
projects. This section is for condensate polishing used directly in the condensate system of a fossil
fuel power station. It does not apply to nuclear polishing applications, mixed bed polishing in
demineralizer systems, or return condensate polishing in cogeneration applications. This section
provides specific design criteria for vessel sizing, resin/precoat materials, and
backwash/regeneration for both precoat and deep bed condensate polishers.
8.2
Approach
This section is intended to be used as a basis for the design of condensate polishing equipment.
8.2.1
Overview
Condensate polishing is the process of purifying condensate before returning it to a boiler.
Condensate polishers operate in the condensate system. The condensate pumps pump condensate
from the condenser through the polishers and into the feedwater system.
Impurities in feedwater can affect boiler performance and can be transported from the boiler to the
steam turbine, causing damage to piping and turbine components in the form of pitting, corrosion,
or scaling. The water quality required for boiler feedwater is defined by the boiler manufacturer
and is dependent on the operating pressure of the plant.
Condensate contains various impurities. Corrosion products from the steam cycle, mostly iron,
travel through the cycle and can concentrate in the boiler. They can inhibit heat transfer, cause hot
spots, and eventually cause failure of the boiler tubes. Additionally, they can carry over with the
steam and degrade the steam purity to the level that it no longer meets the steam turbine suppliers
steam purity guarantee requirements. Dissolved solids enter the system as impurities in the
makeup water, impurities in chemicals being added to the cycle, and from condenser leaks. These
impurities can accumulate and cause corrosion in the boiler or cause corrosion or scale on the
turbine blades.
Dissolved gases can enter the cycle as impurities in the makeup water as well as through the
condenser (air in-leakage to the condenser, which is under vacuum). Dissolved gases, particularly
uncontrolled oxygen and carbon dioxide, can cause corrosion in the cycle. Dissolved gases are
generally removed in the condenser and deaerator. Oxygen can also be removed with chemical
oxygen scavengers, but this is typically limited to facilities that are required to utilize all-volatile
treatment-reducing (AVT-R) because of the presence of copper in the steam cycle system.
However, carbon dioxide can accumulate in the condensate/feedwater/boiler train because of its
pH equilibrium chemistry and can only be effectively removed with condensate polishing.
High-pressure (1,500 pounds per square inch [psi] or greater) drum boilers have stringent
feedwater quality requirements in order to meet the steam turbine suppliers steam purity
guarantee. Drum boilers blow down to eliminate impurities from the cycle. Condensate polishing
provides a means to minimize blowdown and better ensure boiler water quality requirements.
Supercritical units have no blowdown; therefore, condensate polishing is required for removal of
impurities.
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Air-cooled condensers require condensate polishing to minimize corrosion product transport to the
boiler and to address greater potential for air in-leakage with this type of condenser.
In addition to improving condensate/feedwater quality, condensate polishers decrease unit startup
time by minimizing chemistry-related delays, minimizing impacts of condenser leaks, and reducing
frequency of boiler chemical cleaning. Consequently, condensate polishers are a worthy
consideration in most any high-pressure steam cycle.
8.2.2
Types of Condensate Polishers
The two most common types of polishers are precoat polishers and deep bed polishers. Other types
include cartridge filters, hollow fiber filters, and backwashable pleated filters.
8.2.2.1
Precoat Polishers
A precoat polisher is a vessel containing media-retaining filter elements. A powdered media is
placed on the elements, and the condensate is passed through the media-coated filter element and
returned to the condensate flow. Upon the end of the useful life of the media, it is discarded and
replaced with a fresh supply. The media used to coat the elements can be inert, ground cellulose
fiber, or powdered ion exchange media. Figure 8-1 is a flow diagram of a precoat polisher system.
Figure 8-2 shows the internals of a precoat polisher with the filter elements installed. Filter
elements are constructed of different materials including stainless steel, polypropylene, wound
filaments, etc.
Figure 8-1
Precoat Polisher System
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Figure 8-2
Precoat Polisher Internals
The precoat polisher system consists of filter polisher vessels, a precoat system, a resin holding
system, and a resin recovery system. Precoat polisher systems may include a body feed system;
however, these are not often used in power applications. There are two types of precoat polishers:
top tubesheet and bottom tubesheet. The bottom tubesheet design is shown on Figure 8-3. A
tubesheet separates the lower chamber, which receives the treated water, from the upper chamber
that contains the filter elements. During operation, condensate enters the vessel upper chamber,
flows through the precoat on the outside of the filter elements, down the center of the elements to
the lower chamber, and exits the vessel. The top tubesheet design is shown on Figure 8-4. There is
also a tubesheet separating the upper and lower chambers, but here, the lower chamber contains
the filter elements and the upper chamber receives the treated water. An important maintenance
step to keep in mind during design is that the top tubesheet design requires removal of the entire
top portion of the vessel above the tubesheet in order to remove the filter elements, whereas the
bottom tubesheet only requires removal of the top manway to access the filter elements.
Figure 8-3
Bottom Tubesheet Precoat Polisher
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Figure 8-4
Top Tubesheet Precoat Polisher
Both top tubesheet and bottom tubesheet precoat polishers use essentially the same process to
apply the precoat material. A slurry of filter media and water is prepared in the precoat tank. The
media is circulated through the precoat tank and polisher vessel where the media is coated onto the
outside of the filter elements (also called septa or septum). When the precoat process is complete, a
holding pump circulates water in the polisher to hold the media on the elements. In service,
condensate flows across the media, through the filter elements, and out of the polisher. The holding
pump is turned off during the service cycle. The polisher remains in service until there is high
differential pressure or high conductivity.
The precoat process is initiated by cleaning the used media from the septum. The polisher is
drained, and water and air are directed to the inside of the filter elements to backwash the media
from the elements. The backwash step is repeated several times in order to accomplish complete
removal of the media. The backwashed media is collected in a nearby sump and pumped to a waste
tank. CAUTION: This process pressurizes the filter polisher to 60 pounds per square inch
gauge (psig) or so and quickly releases energy to an atmospheric sump in order to wash the media
off the septum. The collection sump must be sized to contain the media and water exiting the
polishers quickly at this pressure. The media is removed as a solid waste.
Once the filter elements are clean, the precoat media is coated on the elements as described above.
The precoat polisher design uses an external air receiver to provide air for the backwash step.
Precoat polishers can remove over 90 percent of the suspended matter in the condensate.
However, even when precoated with resin, they have only limited ability to remove dissolved
material.
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8.2.2.2
Deep Bed Polishers
Deep bed condensate polishers are high flow rate mixed bed exchangers with the following
characteristics:



Ion exchanger polishing to remove trace amounts of ionic impurities.
Strong acid cation and strong base anion resins specifically designed for this application.
Externally regenerated resins using sodium hydroxide and sulfuric acid.
A deep bed polisher design is shown on Figure 8-5.
Figure 8-5
Deep Bed Condensate Polisher
Deep bed polishers are mixed bed ion exchangers designed to operate at the high flow rates and
higher pressures required for condensate polishing. During the service cycle, condensate flows
down through the resin bed and impurities, such as sodium, chloride, sulfate, and silica, are
removed and held on the resin. A polisher vessel is removed from service and readied for
regeneration when a preset volumetric throughput is reached, the differential pressure is high, or
the effluent conductivity is high.
Deep bed polishers are operated either in the hydrogen or ammonia cycle. During hydrogen cycle
operation, all cationic impurities in the condensate are replaced by hydrogen ions on the resin, and
the resin is considered exhausted when the hydrogen ions on the resin have been completely
exchanged. At this point, ammonia ions will be the first cations to break through the bed and will
signal the need for regeneration by way of high effluent conductivity and pH.
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Ammonia cycle operation essentially allows the deep bed polisher to run past the hydrogen cycle
endpoint and allows ammonia to break through. At this point, cation exchange sites will be
occupied by either ammonia and other cationic impurities but not hydrogen ions. Ammonia cycle
operation requires higher levels of resin separation during regeneration along with routine quality
control sampling/analysis of the resin to control the level of cross-contamination during
regeneration and to ensure adequate resin performance during a condenser tube leak. Less
frequent regenerations are required when operating in ammonia cycle. However, hydrogen cycle is
preferred for oxygenated treatment where the levels of influent ammonia are reduced to the
relatively lower condensate pH.
Deep bed polisher resin is regenerated in separate regeneration vessels, external to the service
vessels. This process has two advantages. First, it separates the strong chemicals being added to
the resin from the boiler cycle, reducing the potential for contamination. Second, external
regeneration results in more highly regenerated resin and better effluent quality from the polisher.
Cross-contamination of the resins (e.g., sodium on the cation resin) from regeneration is also
reduced by using external regeneration. External regeneration is generally accomplished in two or
three vessels depending on the equipment supplier. The deep bed polishers will also remove about
half of the suspended matter in the cycle. However, the iron fouls the cation resin, increasing resin
bead density and making the resin more difficult to break up for transfer and to separate for
regeneration. Filters may be used ahead of mixed bed polishers to reduce this concern.
As noted above, regeneration takes place in two or three vessels, but the overall regeneration
process is still similar between them. When resin in a service vessel is exhausted, the polisher is
removed from service and the exhausted resin from the service vessel is sluiced to a receiving
vessel for backwashing and air scrubbing. Backwashing and air scrubbing remove suspended
material and broken resin while also separating the cation and anion resin. The cation resin has a
higher specific gravity and will settle to the bottom of the vessel, and the anion resin will rise to the
top of the vessel when separated. Once the resins are separated, the cation resin either stays in the
receiving vessel and the anion resin is transferred to a different vessel or vice versa. The two resins
are regenerated separately in their individual vessels. Dilute acid is used to regenerate the cation
resin, while caustic diluted with heated water is used to regenerate the anion resin. Both beds of
resin are then rinsed. Once regenerated, either the anion resin is transferred to the cation vessel or
both resins are transferred to a separate storage vessel where they are mixed, rinsed to quality, and
stored until another bed becomes exhausted.
Sulfuric acid is most often used to regenerate cation resins. Hydrochloric acid may also be used, but
it is more difficult to handle because of fuming concerns. The choice of acid is generally based on
local availability. Technical grade 66 degree Baumé sulfuric acid is required, and Table 8-1 lists the
maximum allowable concentration for various impurities in parts per million (ppm). Sodium
hydroxide (caustic) is used to regenerate anion resin. Membrane grade caustic is required for ion
exchange, and Table 8-2 lists maximum allowable concentrations for impurities in the chemical.
The waste stream is sent to a neutralization tank to neutralize the regenerants before being
discharged to the wastewater system. The waste stream produced from regeneration of the resin
contains the same constituents as the incoming water, along with additional amounts of sodium and
sulfate due to the acid and caustic used to regenerate and neutralize the wastewater.
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Table 8-1
66 Degree Baumé Sulfuric Acid Quality Requirements
MAXIMUM PPM
ALLOWABLE
IMPURITIES
Iron, Fe
20.0
Lead, Pb
1.0
Copper, Cu
1.0
Manganese, Mn
0.5
Nickel, Ni
1.0
Arsenic, As
0.2
Antimony, Sb
0.2
Calcium, Ca + Magnesium, Mg
(as CaCO3)
25.0
Total Residue
60.0
93.19 percent sulfuric acid, H2SO4 minimum
Color – Colorless
Material to contain no inhibitors
Table 8-2
50 Percent Sodium Hydroxide Quality Requirements
IMPURITIES
MAXIMUM PPM
ALLOWABLE
Iron, Fe
4.0
Silica, Si
4.0
Chlorate, ClO3
Aluminum, Al
Copper, Cu
Nickel, Ni
Manganese, Mn
Sodium Chloride, NaCl
Sodium Sulfate
Na2SO4
Sodium Carbonate
Na2CO3
0.0
2.0
0.5
0.5
0.5
30
40
300
50 percent sodium hydroxide, NaOH minimum
Color – Colorless
Turbidity – None
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8.2.3
System Design
Design criteria for the two different types of polishers are discussed in the following subsections.
These guidelines should be used when designing a condensate polisher system.
All condensate polishing systems should be designed with bypass capability. The bypass should be
used only to continue to supply feedwater in the event of a malfunction of the condensate polishing
system. The bypass around the condensate polishing system should include a control valve
designed to control differential pressure. If the differential pressure across the polisher system
increases about the setpoint, the control valve will begin to open. The recommended differential
pressure setpoint for the two types of polishers is discussed in the following subsections.
8.2.3.1
Precoat Polishers
Guidelines that should be followed for the design of precoat polishers include the following:








The condensate pump should be designed assuming 40 pounds per square inch
differential (psid) of pressure drop for the condensate polishing system.
The condensate polisher service and bypass systems must be designed for the same
pressure as the condensate system.
The maximum pressure drop through the polisher from the inlet to the outlet should be
specified as 25 psid.
Filter polisher should be designed for a filtration rate of 2 to 3 gallons per minute per
square foot (gpm/ft2) of bare element area at normal condensate flow and less than
4 gpm/ft2 at the maximum condensate flow.
When using ion exchange resin, the cation to anion ratio should be 2:1 by weight for normal
operation, and a ratio of 1:1 during high suspended solids conditions, such as startup, and
during a condenser leak.
The amount of precoat on the elements should be 0.2 to 0.3 lb/ft2.
The holding pump should be designed to provide a constant flow of 0.1 gpm/ft2 of filter area
for fiber-wound elements and 0.5 gpm/ft2 for metal elements.
The holding pump discharge pressure must be adequate to overcome the differential
pressure in the polisher vessel. However, because it can be exposed to an operating
polisher vessel, the design pressure must be the same as the service design pressure.
An external air receiver should be included in the design for air-assisted water backwashes. The air
receiver should be sized for the highest instantaneous rate of air consumed.
The filter polisher vessel and condensate piping should be carbon steel unless project-specific
requirements indicate otherwise. The precoat slurry tank and precoat piping should be stainless
steel.
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Different precoat processes should be considered when designing the filter polishing system. The
typical regeneration process shown on Figure 8-1 is a closed loop precoat process. The precoat
slurry mixed in a single precoat tank is pumped through the filter polisher and returned to the tank.
The mixer should be a low shear mixer. An open loop precoat process shown on Figure 8-6
includes a second tank, the recirculation tank, and an eductor that transfers the slurry from the
precoat tank into the recycle line. It is also an option to use a second pump in lieu of an eductor.
Injecting the precoat slurry from the precoat tank into the recycle line provides a controlled precoat
slurry concentration to the filter vessels. This ensures the precoat is applied uniformly over the
entire filter element.
Figure 8-6
Open Loop Recirculation Precoat Process
Another option is to include a body feed pump. With this type of system the precoat filter vessel is
placed in service after a base precoat is applied. The body feed is used to add additional media to
the filter elements during the service run, with the intent of extending the time until the filter needs
to be removed from service.
A dedicated slurry sump is recommended to catch the contents of the backwash process. The sump
should be sufficiently sized to dissipate the energy associated with the backwash process. A lid is
recommended to ensure media and water remain in the sump. The slurry sump pumps should be
designed to pump one backwash volume from the sump into the recovery tank within 20 minutes.
Top tubesheet designed polisher vessels should include provisions for removing the vessel head
and tubesheet. This includes adequate overhead and surrounding space, and hoist or crane access.
8.2.3.1.1
Precoat Media
A variety of precoat media can be used, including powdered cation resin, powdered anion resin,
mixtures of powdered cation and anion resin, ground cellulose fiber, and mixtures of cellulose fiber
and resin. As noted above, the cation and anion resin blend can be adjusted based on expected
process conditions.
Cellulose fiber is a good filter media and is low cost. It has no ion exchange capacity and is difficult
to remove from the filter elements.
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Powdered resin can be blended in the mixing tank to a proportion desired or can be supplied as a
premixed blend. Due to the limited volume of resin in the precoat polisher, it has limited ion
exchange capacity and provides minimal protection during condenser leaks.
Blends of resin and cellulose backwash well from the filter elements, are not as expensive as
powdered resin, and have some ion exchange capacity. Their exchange capacity is very limited.
8.2.3.2
Deep Bed Polishers
Guidelines that should be followed for design of the deep bed polishers include the following:











The condensate pump should be designed assuming 50 psid of pressure drop for the
condensate polishing system.
The condensate polisher service and bypass systems must be designed for the same
pressure as the condensate system.
Condensate polisher systems generally are configured as 2 x 100 percent, 3 x 50 percent, or
4 x 33 percent vessels depending on the condensate flow rate.
The service vessel should be designed for a hydraulic flux rate of 50 gpm/ft2 (122 cubic
meter per hour per square meter [m3/h per m2]).
The cation to anion resin ratio should be 2:1 by volume. The higher cation volume
maximizes the time required for the ammonia in the condensate to exhaust hydrogen form
cation resin while still maintaining reasonable anion exchange efficiency. This blend may
be altered based on other process considerations (such as seawater condenser service).
If the system is to be run past the point when ammonia starts leaking through the resin, a
process for minimizing the sodium leakage should be considered. A system using
oxygenated treatment should operate in the hydrogen cycle. This will result in more
frequent regenerations.
The resin bed depth should be between 3 and 4 feet. Occasionally the resin required can be
calculated using an assumed condenser leakage rate, circulating water quality, and
minimum run time during the leak for the polisher.
Resin specifically designed for the condensate polisher should be used. Characteristics of a
good resin include uniform particle size and a significant difference in density between the
cation and anion resin. A difference in color between the cation and anion helps show the
interface between resins during the separation steps.
Inert resin has traditionally been used in mixed bed applications to enhance the separation
between cation and anion resins. However, recent developments in resin and regeneration
methods have minimized the need for inert resins. The benefit is only seen in special
situations and should not be specified as part of a standard design.
Cation resin should be purchased in the hydrogen form and anion resin in the hydroxide
form.
A deep bed polisher system should be provided with a charge of resin for each service
vessel and at least one spare charge of resin for the storage vessel.
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

Sight glasses should be provided on the service vessels located at the resin bed level.
Each service vessel should be provided with effluent strainers to protect the boiler from
accidental loss of resins during service due to an underdrain failure. A clean resin trap
differential pressure should be less than 2 psi. The strainer must be capable of
withstanding a differential pressure equal to system operating pressure.
The guidelines listed below should be used for design of the regeneration equipment associated
with the polisher system:








The resin separation vessel (also the anion or cation regeneration vessel depending on the
regeneration process) should have 125 percent freeboard for air scrubbing and backwash.
The anion/cation regeneration vessel (the vessel not performing the resin separation)
should have 100 percent freeboard for backwashing.
Both the cation and anion regeneration vessels should have a minimum of 36 inch resin bed
depth, preferably 48 inches.
The resin mixing vessel should have 50 percent freeboard for air mixing.
The air scrubbing should be designed for 6 to 12 standard cubic feet per minute per square
foot (scfm/ft2) for approximately 10 minutes.
Acid regeneration should be 10 to 12 pounds of acid per cubic foot of cation resin.
Caustic regeneration should be 10 to 12 pounds of acid per cubic foot of anion resin.
The dilute caustic regenerant should be at 120° F (49° C) with a minimum contact time of
60 minutes.
Service vessels may be cylindrical or spherical. Spherical vessels are typically used at higher
condensate pressures to reduce the required shell thickness of the vessel, which reduces the overall
cost. The regeneration vessels and processes can vary considerably. Some common processes are
discussed in the following paragraphs.
The two most common configurations for regeneration are the three or two vessel system. The
three vessel system consists of a cation resin regeneration vessel, an anion regeneration vessel, and
a resin holding tank. Resin is transferred from the service vessel into the cation vessel for the
backwashing, air scrubbing and separation steps. The anion resin is then transferred to the anion
vessel, and both vessels are regenerated and rinsed. Following regeneration, both resins are
transferred to the resin holding tank where the resin is mixed, rinsed, and stored until transfer to a
service vessel. This approach is most often used with an inert resin.
For a two vessel regeneration system, the exhausted resin is sluiced from the service vessel to an
anion regeneration vessel for backwashing, air scrubbing, and separation. The cation resin is then
transferred to a cation regeneration vessel, and the two resins are regenerated separately in the
same way as the three vessel system. Following regeneration, the anion resin is transferred to the
cation vessel for mixing, rinsing, and storage until another bed is exhausted. This process
eliminates the need for a third resin storage vessel. Both regeneration philosophies are acceptable
and should be considered when designing a system.
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8.2.3.2.1
Advanced Resin Separation Processes
An area of concern for externally regenerating condensate polishers is separation of the anion and
cation resins. The conventional separation process uses a fixed nozzle location designed for the
resin interface level. Variations to the resin volumes eventually occur because of incomplete resin
transfers and losses during backwashing. This changes the resin interface level, which leads to
cross-contamination of the resins. Cation resin regenerated in the anion vessel will be in the
sodium form, and anion resin regenerated in the cation vessel will be in the sulfate form. This will
lead to increased sodium and sulfate leakage when the resin is placed into the service vessel. This
is particularly important if the resin will operate in the ammonium cycle, because very low sodium
contamination levels are required.
There are several different technologies used to achieve effective separation of the anion and cation
resins. For a condensate polisher operating in hydrogen cycle mode, the cation resin crosscontamination of the anion resin should be specified as less than 0.5 percent of the bulk anion resin
volume for cation resin greater than 35 mesh. The anion resin cross-contamination of the cation
resin should be specified as less than 0.8 percent of the bulk cation resin. Lower levels of crosscontamination during resin separation are necessary for satisfactory operation beyond ammonia
break. The following is a list of different proprietary separation approaches:


Conesep®: The bottom transfer of cation resin to a dedicated cation regeneration vessel
with interface identified by conductivity and maintained in piping between regeneration
tanks.
Seprex®: The normal hydraulic separation and fixed lateral transfer of anion resin is
combined with anion resin flotation in 16 percent caustic that floats and regenerates anion
resin and drops out cation resin.

SepraEight®: The bottom transfer of cation resin with interface identified by pH within the
piping between the regeneration vessels. This technology may be combined with anion
resin flotation as part of the Seprex process.
8.2.4
Application

Amsep®: Anion resin is floated out the top of the separation tank in a benign amine salt such
as ammonium sulfate; the bottom transfer of cation resin to a dedicated cation regeneration
vessel permits enhanced removal of cation resin fines.
The typical applications for precoat polishers are listed below. Specific project or client
requirements may warrant a precoat polisher for applications other than those listed below:


Combined cycle plant with an air-cooled condenser.
Iron filter in front of a deep bed polisher.
Typical applications for a deep bed polisher are listed below. Specific project or client
requirements may warrant a deep bed polisher for applications other than those listed below:


High-pressure condensate system with oxygenated treatment.
High-pressure system with high conductivity cooling water.
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Either precoat or deep bed polishers can be used in most applications. Low-pressure systems
usually do not require polishers. Plants with frequent shutdowns or cycling operations would
benefit from polishers to reduce startup time.
8.2.5
System Operation
The following is a list of operational aspects of a condensate polisher that need to be considered as
part of the system design:





When media is removed from the precoat polisher, there is a rapid release of air and water
that can cause issues with the receiving sump and people in the area. The receiving sump
should have a lid to prevent water spray. The lid vent should be sized to relieve the air
without any lift in the lid manway or the lid itself.
For proper operation of a deep bed or precoat filter, the condensate temperature should be
kept below 140° F (60° C). If high temperatures are encountered, the polisher should be
bypassed to prevent resin damage.
Polishers are removed from service upon high differential pressure or by an analytical
method detecting ammonia, conductivity, and/or pH. Consideration should be given to how
resin exhaustion would be detected based on either hydrogen or ammonia cycle operation.
If there is no flow through the precoat polisher vessel and the hold pump stops, the filter
should be backwashed and recoated.
If powdered resin precoat is mixed too long, the anion resin can be exhausted by carbon
dioxide in the air. The powdered resin should not be mixed until ready for operation of the
precoat process.

It is common to have problems separating the cation and anion resin during the first
regenerations because the resins tend to clump. One approach to getting a good separation
is to wash the entire resin bed with dilute caustic and then try the separation.
8.3
References






Overpressure protection must be carefully considered for condensate polisher system
designs.
Electric Power Research Institute, Condensate Polishing Guidelines, September 1996.
Amberjet 1500 H Resin Product Data Sheets, April 2007.
Amberjet 4400 OH Resin Product Data Sheets, February 2008.
Colleen M. Layman and Lisa L. Bennett, “Condensate Polishers Add Operating Reliability
and Flexibility,” POWER magazine, August 15, 2008.
Deep Bed Condensate Polishing Calculation (Found through the Industrial Water Treatment
Community page).
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9.0
9.1
Degasification
Purpose and Applicability
Dissolved gases such as oxygen and carbon dioxide are typically removed from water by
degasification. Carbon dioxide can be removed by chemical means or mechanical means using a
vacuum degasifier or forced draft degasifier, or through membrane degasification. Oxygen is
generally removed through either vacuum degasification or membrane degasification.
9.2
Approach
This section is intended to be used as a basis for the design of degasification equipment.
9.2.1
Overview
Degasification is most often seen in the power industry as part of the demineralization system.
Carbon dioxide is a dissolved gas that will pass through reverse osmosis (RO) membranes into the
permeate stream. Dissolved carbon dioxide adds ionic loading on electrodeionization (EDI) or ion
exchange systems downstream of the RO membranes. This leads to larger ion exchange and EDI
systems, increases in chemical cleaning/regeneration costs, and can cause operational problems.
Degasifiers can improve efficiency of downstream ion exchange by extending anion bed life. Carbon
dioxide can combine with hydroxide ions to form bicarbonate, which will be removed by ionexchange resin. The result is exhaustion of the resin and higher costs of operation.
The most common degasification method in a two-pass RO system is to feed caustic to the second
pass feedwater to raise the pH to approximately 8.2 to 8.4, which will convert the carbon dioxide to
bicarbonate which can then be removed by the RO membranes.
Depending on the amount of carbon dioxide in the feedwater, it may be more cost effective (from an
operating standpoint) to remove carbon dioxide by mechanical means rather than chemical means.
Membrane degasifiers can also be used for ammonia removal, carbonation, nitrogenation, and
water injection; however, these are not common in water treatment applications.
9.2.2
Vacuum Degasifier
A vacuum degasifier can be used to remove oxygen and carbon dioxide from a water source. A
vacuum degasifier can have one to three stages of packing in a tower configuration. Water is
sprayed at the top of the tower and passed through the packing stages where gases are removed. A
vacuum is drawn at each stage to pull the gases out of the water. The vacuum can be created by a
vacuum pump or steam eductor. A vacuum degasifier is a large piece of equipment. Each of the
stages is typically 10 feet long (top to bottom), and below the last stage there is a storage chamber a
minimum of 15 minutes of throughput volume which serves as a pump surge tank. Since the entire
assembly is operating at nearly full vacuum, that storage chamber must be located close to 20 feet
above the center line of the forwarding pumps to prevent significant cavitation issues associated
with the forwarding pumps, which typically provide feed to the remaining demineralization
equipment. As a result, the overall structure can easily reach 60 feet in elevation (and even higher
if the degasifier is a three-stage version). The vacuum producing equipment is also quite complex.
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Since the objective is to accomplish maximum degasification, very large vacuum pumps are used to
produce the vacuum. As an enhancement to the overall operation of the vacuum pumps, ejectors
are generally installed on the suction side of the pumps to get the overall vacuum as close to perfect
vacuum as possible.
Vacuum degasifiers are pressure vessels constructed of rubber lined carbon steel that operate at
near perfect vacuum conditions. The packing material is typically polypropylene or other
corrosion-resistant material, typically no larger than 2 inch (50 mm) nominal size. Degasified
water is collected in the bottom of the degasifier (in the integral surge tank) and is pumped to the
next treatment process.
A vacuum degasifier calculation is included in the reference section that determines the tower
design required to meet the effluent water quality. The calculation template is stored in the
department intranet page as indicated in the reference.
A vacuum degasifier reduces the carbon dioxide to between 5 to 10 parts per million (ppm) in the
effluent. Other volatile gases are also removed, most notably oxygen, which will be reduced to
20 parts per billion (ppb) or below. The vacuum pump exhaust airflow must be discharged
outdoors because of the water vapor in the exhaust. The outside exhaust must be carefully
designed and located when the installation is in frigid climates because ice formation is a significant
issue. In addition, the design of the building’s heating, ventilating, and air conditioning (HVAC)
system must be closely coordinated with other design disciplines because of the significant air
volume that is required by the degasifier and that is exhausted outdoors. This design places a
significant replacement air volume demand and an associated heat load on the ventilation system.
9.2.3
Forced Draft Degasifier
A forced draft degasifier is a packed tower where water is sprayed down the tower column and the
carbon dioxide is removed by air that is blown up the column using blowers. The forced draft
degasification design is based on saturating the water with air.
The packing material is polypropylene or other corrosion-resistant material no larger than 2 inch
(50 mm) nominal size. The degasifier tower is typically constructed of fiberglass reinforced plastic
(FRP) and sits above an FRP surge tank or underground water tank. The degasified water is
collected in the surge tank and is then pumped to the next treatment process.
A forced draft degasifier calculation template is included in the reference section that determines
the required tower height based on water flow rate, air and water temperatures, and carbon
dioxide concentration to be removed. The calculation template is stored in the department intranet
page as indicated in the reference.
A forced draft degasifier can reduce the carbon dioxide to less than 10 ppm in the effluent. The
effluent from the degasifier will be saturated with oxygen that is significantly different than the
effluent from a vacuum degasifier. An indoor forced draft degasifier is shown on Figure 9-1. While
the degasifier itself is commonly located indoors, it is always recommended to exhaust the
degasifying air, which will be saturated with water, to the outside. The outside exhaust must be
carefully designed and located when the installation is in frigid climates because ice formation is a
significant issue. In addition, design of the building’s HVAC system must be closely coordinated
with other design disciplines because of the significant air volume that is required by the degasifier
and that is exhausted outdoors. This design places a significant replacement air volume demand
and an associated heat load on the ventilation system.
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Figure 9-1
9.2.4
Forced Draft Degasifier Storage Vessel
Membrane Degasification
Membrane degasification is the process of removing dissolved gases, especially carbon dioxide and
dissolved oxygen, from water and occurs when a gas stream has contact with a water stream
through a hydrophobic, hollow fiber, microporous membrane. Degasification can be used as a step
in producing demineralized water, and for reducing dissolved gases in boiler makeup water.
Membrane contactors allow an aqueous stream to interface with a gaseous phase, which supports
the mass transfer of gases between the phases. The liquid stream flows through the shell side, and
the gas stream flows countercurrent through the hollow membrane fibers supported on a baffle.
This provides a maximum transfer area while minimizing the pressure drop through the contactor.
A typical membrane contactor is shown on Figure 9-2.
Figure 9-2
Illustration of a Membrane Contactor, Courtesy of Liqui-Cel
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The driving force of the mass transfer is the diffusion of the carbon dioxide and oxygen to reach
equilibrium according to Henry’s law, where the gas concentration of the species in the aqueous
stage is proportional to the partial pressure of the gas. To drive the dissolved carbon dioxide and
oxygen from the aqueous stage, the partial pressure of the species in the gas phase is lowered. The
partial pressure can be lowered either by lowering the total pressure of the gas phase (as in
vacuum degasifier operation), or by flowing a “stripping gas” or “sweep gas” of inerts (similar to a
forced draft degasifier in principle), or a combination of vacuum and sweep gas. The hydrophobic
membrane allows contact between the aqueous and gaseous stream without dispersion.
9.2.5
Design
Mechanical deaeration is most effective at low pH levels (4.5 and below) because the highest
concentration of the dissolved carbon dioxide in the water is present as free carbon dioxide gas.
Membrane contactors can reduce carbon dioxide below 1 ppm.
9.3
References

Wiesler, Fred, “Membrane Contactors: An Introduction to the Technology,” Ultrapure Water,
May/June 1996.



Dang, Tri, “Using Membrane Contactors for CO2 Removal to Extend Resin Bed Life,”
Ultrapure Water, July/August 2003.
Vacuum Degasifier Calculation template (found through the Energy Chief Engineers
Community page).
Forced Draft Degasifier Calculation template (found through the Energy Chief Engineers
Community page).
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10.0 Cycle Chemistry
10.1
Purpose and Applicability
This section describes the different cycle chemical treatment methods and provides design criteria
that can be used to design chemical feed equipment.
10.1.1
Overview
Cycle chemistry is impacted by many factors, all of which must be controlled to achieve satisfactory
operation of the cycle. Important factors include proper selection of cycle materials, use of highpurity cycle makeup, proper steam generator and cycle chemical conditioning, and proper noncondensables control.
Chemical conditioning is the addition of chemicals to provide a selected chemical environment in
the portion of the system being conditioned. Chemical conditioning is practiced for both the steam
generator water and the water in the steam-condensate-feedwater system. In addition,
maintenance of proper cycle chemistry requires surveillance of cycle parameters through the use of
a water quality control system that is a part of an established water quality control program for the
entire power plant.
One important purpose of cycle chemistry is to minimize the amount of contaminants that enter the
cycle. Typical means of contaminant ingress include condenser leaks (both air and water) and poor
quality makeup water. Other contaminant ingress can occur from maintenance activities (paints,
solvents, cleaning compounds) and from chemical feed contaminants. In modern day power cycles,
the portion of the cycle most sensitive to contamination is the steam turbine. In general,
contaminants concentrate in certain areas of the turbine because the solubilities of the
contaminants in the steam decrease as the steam temperature and pressure decrease. Usually, if
chemistry and cycle fluid purity are acceptable for the steam turbine, the remainder of the cycle
components are also protected. The exceptions are those contaminants, primarily corrosions
products (crud), that deposit in the steam generator. Typical turbine steam purity requirements
recommended by various sources are given in Table 10-1.
Figure 10-1 shows the basic steam cycle and describes many of the steam cycle areas that are
impacted by water chemistry. A multitude of different forms of damage can occur to a steam cycle
as a result of inappropriate cycle chemistry. For the boiler, these include caustic attack, hydrogen
damage, and stress corrosion cracking. Chemical attack in the feedwater system also includes
stress corrosion cracking, flow-accelerated corrosion, and erosion corrosion.
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Table 10-1
Typical Turbine Steam Purity Requirements
CONSTITUENT
GENERAL
ELECTRIC
SIEMENS
ELECTRIC POWER
RESEARCH INSTITUTE
Cation Conductivity, µS/cm
< 0.1
< 0.2
≤ 0.2
Chloride, µg/L
<3
Sodium, µg/L
Silica, µg/L
<3
< 10
Sulfate, µg/L
<3
Iron, µg/L
Copper, µg/L
Total Dissolved Solids, ppb
Total Organic Carbon, ppb
< 50
<5
< 20
<20
≤2
≤ 10
≤2
<3
< 100
µS/cm = MicroSiemen per centimeter = Micromho.cm
µg/L = Micrograms per liter
ppb = Parts per billion
Figure 10-1
≤2
≤ 100
Chemical Transfer in the Conventional Drum Boiler System
(From Sargent & Lundy for the Electric Power Research Institute [EPRI]. Used with
Permission of EPRI.)
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10.1.2
Chemical Conditioning
Chemical conditioning is divided into two different areas: steam generator conditioning and cycle
conditioning. Steam generator conditioning can be accomplished by the addition of nonvolatile
chemicals. Cycle conditioning includes the turbine, the condensate system, and the feedwater
system up to the steam generator and generally requires the use of volatile chemicals.
10.1.2.1 Steam Generator Conditioning
Steam is generated in the steam generator circuits and routed to the turbine. The purity of this
steam is dependent on the appropriate conditioning of the steam generator water and the quality of
the feedwater. Feedwater is routed to the steam generator to be converted to superheated steam,
which is then ready for admittance to the turbine.
The approach to steam generator conditioning varies depending on the type of steam generator
used within the cycle. The approach must minimize corrosion of steam generator materials,
minimize deposition of feedwater contaminants, and provide steam of adequate purity for the
turbine.
Any solids in the feedwater are concentrated in the steam generator. Concentration beyond the
solubility of the solids results in deposition in the high heat flux areas of the steam generator. The
most common deposits are corrosion products from the condensate and feedwater systems.
Hardness constituents (calcium and magnesium), if present in the feedwater, are particularly
troublesome because of their property of inverse solubility; that is, these materials are less soluble
at higher temperatures than at lower temperatures. In addition, calcium forms particularly hard
scales. Scaling from any of these materials insulates the inside of the tubes in the steam generator.
This insulation reduces heat transfer and can result in overheating and failure of the tubes in the
steam generator. Corrosion of steam generator materials is undesirable because of the associated
material loss and the heat transfer resistance of the corrosion product oxides. The insulating effect
of the corrosion products on the steam generator tubes can result in tube failure caused by
overheating. In addition to insulating heat transfer, these deposits also participate in caustic attack
and other under deposit phenomena, all of which are detrimental to long-term service.
Maintaining steam purity affects both the levels of chemical additions allowed to the steam
generators and the required quality of feedwater to the steam generator. Steam generator
conditioning for both drum units and once-through steam generators is discussed in the following
subsections.
10.1.2.1.1 Drum Type Units
A primary function of the steam generator drum is to separate vapor from liquid. Feedwater routed
to the steam generator is heated to the point of vaporization within the steam generator. For drum
type units, a vapor and liquid mixture is generated in the tubes, collected, and separated in the
steam drum; the separated vapor is routed to the superheater and then to the turbine. This twophase separation causes concentration of the dissolved impurities in the remaining drum water
because of the preferential solubility of most impurities for the liquid phase.
Blowdown from the steam generator is used to control and remove solids. With proper feedwater
purity, blowdown can be limited to less than 1 percent of the feedwater flow rate. It is desirable to
minimize blowdown to limit both the heat loss and the use of high-purity makeup water.
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Another function of the drum is to provide proper steam purity to the turbine. The purity of the
steam is affected by both mechanical and vaporous carryover. Mechanical carryover is the physical
entrainment of drum water in the steam leaving the drum. This results in contamination of the
steam by the less pure drum water. Excessive mechanical carryover results in unacceptable
contamination of the drum water.
Vaporous carryover is a result of the volatilization of the chemical species in the drum water. This
volatilization of impurities contaminates the steam. The extent of volatilization depends on the
chemical species making up the contaminant, the drum pressure, and the concentration of the
contaminants in the drum water. Silica volatilization is a particularly difficult problem because of
its relatively high solubility in steam at intermediate steam generator pressures. Steam turbine
manufacturers have imposed steam purity limits that typically restrict the maximum silica
concentration in the steam to 10 µg/L or less. Figure 10-2 provides guidelines for allowable silica
in water.
Figure 10-2
Maximum Boiler Water Silica (SiO2) Concentration versus Drum Pressure at Different
Values of pH (10 µg/L SiO2 Limit in Steam)
(From J. Rios [Bechtel Power Corporation] and F.X. [Blood Union Electric Company].
Used with Permission.)
The concentrations of solids in the steam from both volatilization and mechanical carryover must
be limited to meet steam turbine manufacturers’ limitations. Since both are affected by steam
generator drum water, it is obvious that the concentrations in the drum water must be controlled.
Chemical conditions within the steam generator must be controlled to minimize corrosion within
the steam generator. This means maintaining pH at a minimum of 9.0 for high-pressure units and
higher values for some of the lower pressure units. For drum units, this is often achieved with the
addition of a sodium phosphate salt. Properly selected sodium phosphate solutions result in
alkaline solutions that elevate the pH of the steam generator water, and phosphate chelates or
combines with calcium to minimize the potential for the calcium deposit on the heat transfer
surfaces.
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Sodium orthophosphates are typically used to add phosphate ion to the steam generator water.
Sodium orthophosphates are monosodium phosphate (1.0 Na/PO4 ratio), disodium phosphate
(2.0 Na/PO4 ratio), and trisodium phosphate (3.0 Na/PO4 ratio). Originally, a coordinated
phosphate treatment method was used which kept the sodium to phosphate molar ratio at 3.0.
Facilities were still seeing corrosion issues, so this recommended ratio was changed to be below
2.6, and it was recommended to keep the pH high enough to maintain corrosion protection. This
treatment method is called congruent phosphate treatment (CPT). Some individuals believe this
ratio and pH range still cause corrosion issues, so the equilibrium phosphate treatment (EPT)
method was developed. This method feeds pure trisodium phosphate (3.0 NAPO4 ratio) along with
1 ppm of caustic (NaOH) and then allows the system to seek its own equilibrium. This method
operates in a higher pH range than CPT. Figure 10-3 shows the steam generator water pH versus
phosphate residual for various sodium to phosphate molar ratios. It should be noted that higher
pressure units use lower levels of phosphate. This is because higher pressure units transmit higher
levels of sodium phosphate to the turbine via volatilization; thus, lower levels are required for
steam purity targets. Any phosphate program that utilizes anything other than trisodium
phosphate should be reviewed by the Chemical Section Lead.
Phosphate hideout occurs when phosphate tends to disappear by precipitation or absorption under
high heat transfer or high load conditions. When the heat transfer or load is reduced, the phosphate
returns and results in higher than expected levels of phosphate. Therefore, the control of drum
phosphate concentrations is usually difficult during load changes, and care should be taken to avoid
“chasing” the phosphate levels since this is usually ineffective.
There are several other types of steam generator drum conditioning. Caustic is sometimes used
instead of or in addition to phosphates to maintain alkaline conditions in the steam generator. A
concern with the use of caustics is the potential for caustic gouging or caustic under deposit
corrosion. EPRI guidelines describe the conditions under which caustics should be used in drum
type steam generators. Chelants are sometimes used to maintain cleanliness in the steam
generator. Some difficulties have been experienced with control of the amount of chelant available,
and the chelants themselves sometimes cause corrosion damage to the steam generators. Allvolatile treatment, which is discussed in Subsection 10.1.2.2.1, is also applicable to drum type steam
generators.
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Figure 10-3
Boiler Water pH versus Phosphate Residual for Various Sodium to Phosphate Molar
Ratios
(From Betz Laboratories, Inc. Used with Permission.)
10.1.2.1.2 Once-Through Steam Generators
The schematic representation of the steam generator on Figure 10-1 is based on a drum type steam
generator. Steam generators may also be of the once-through type, without a drum. Steam is
generated within the tubes of the steam generator and collected in headers before being routed to
superheaters and then to the turbines. There is no area for collection of a vapor and liquid mixture,
and thus, no opportunity to concentrate solids or contaminants in a liquid phase for discharge.
Some of these once-through steam generators operate at supercritical conditions, meaning that
water has exceeded its critical point and beyond this point the water no longer exhibits a phase
change from liquid to vapor. In the subcritical or the supercritical steam generator, any impurities
that enter the steam generator either deposit on the steam generator surfaces or are passed
through the steam generator to the turbine. Because there is no separation of phases in the oncethrough units, the feedwater to the steam generator must be of high purity to meet turbine
requirements.
For preservation of the steam generator materials in the high purity water, a high pH is required to
minimize corrosion. Because there is no drum or phase separation, the use of nonvolatile solid
chemicals such as phosphates for steam generator conditioning is not acceptable. The solid
chemicals would deposit in the tubes in the high heat flux zones, resulting in tube failures.
Fortunately, an elevated pH can be maintained in the once-through steam generator with the amine
(generally ammonia) that is used to condition the cycle. This type of treatment is called all-volatile
treatment (AVT).
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The use of condensate polishing is required with once-through units because of the need for high
purity feedwater and because no additional conditioning chemicals can be fed to the boiler.
Condensate polishing is described in Section 8.0.
AVT may also be used with drum type steam generators.
10.1.2.2 Cycle Conditioning
Feedwater purity and conditioning are important factors in the maintenance of good cycle
chemistry. Cycle conditioning minimizes corrosion and subsequent transport of corrosion products
to downstream components and, ultimately, the steam generator. The most important function of
these corrosion control mechanisms is to minimize the transport of iron from erosion corrosion in
copper free cycles and to minimize the transport of both iron and copper in cycles with copper
alloys.
10.1.2.2.1 All-Volatile Treatment
AVT(R) - All Volatile Reducing Treatment
In the United States, for many years the approach to minimize erosion corrosion was to elevate
cycle pH in a reducing environment. It has since been determined that feeding reducing agents,
such as oxygen scavenger, to the cycle contributes to flow accelerated corrosion and is no longer
recommended by EPRI for normal operation of a plant.
To maintain a reducing environment, efforts are made to eliminate oxygen. Oxygen removal, as
well as removal of other noncondensables, occurs in both the condenser and the deaerator. In
addition, reducing agents or oxygen scavengers, such as hydrazine, are fed to eliminate any oxygen
that may have eluded physical methods used in both the condenser and the deaerator. This method
is referred to as all-volatile treatment – reducing (AVT-R). The water quality is maintained as
follows:



Oxygen levels should be ≤ 10 ppb.
pH should be between 9.0 to 9.3 if there is any copper present.
pH should be above 9.5 if no copper is present.
This reducing environment results in the formation of a protective layer of magnetite over steel
materials. To minimize the erosion corrosion of magnetite, it is necessary to select conditions that
minimize the solubility of magnetite in water. Figure 10-4 indicates the relative solubility of
magnetite as a function of pH. From this figure, it is apparent that minimum solubility and, thus,
minimum magnetite transport occurs when the cycle pH is maintained around 9.5. This is typically
accomplished with the addition of an amine such as ammonia. Other amines, such as morpholine or
cyclohexylamine, can be used in lower pressure cycles. These other amines break down in cycles
operating above 1,500 pounds per square inch gauge (10,340 kilopascals) and are not
recommended for use in higher pressure cycles.
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Figure 10-4
Effect of pH on Iron Concentration
(EPRI, 1994. Reprinted with Permission.)
AVT(O) - All Volatile Oxygenated Treatment
EPRI now recommends all-volatile treatment – oxygenated (AVT-O). AVT-O promotes an oxidizing
environment to control corrosion. This is done by eliminating the reducing agent feed (oxygen
scavenger). Not feeding an oxygen scavenger allows a film of ferric oxide hydrate (Fe2O3·H2O) to
form over the base magnetite protective layer on the piping. This occurs naturally over time. Ferric
oxide hydrate is also the basis of oxygenated treatment which is described next. AVT-O can only be
used in cycles that are copper free (most newer power plants). If there is any copper-based tubing
in the feedwater heaters, the cycle chemistry must be AVT-R.
For AVT-O, the pH level is elevated in the feedwater by ammonia addition. No oxygen is added to
the system. The dissolved oxygen in the cycle is controlled by mechanical deaeration of the
feedwater only. The water quality is maintained as follows:


Oxygen levels should be between 10 ppb ≤ 20 ppb.
pH should be between 9.2 to 9.6.
10.1.2.2.2 Oxygenated Treatment
Oxygenated treatment (OT) is an alternate treatment method that was developed in Germany in the
early 1970s for the treatment of once-through steam generators. Although the primary history of
OT is for once-through units, OT has also seen limited use in drum units.
In this treatment, oxygen or another oxidizer is fed to an all-ferous cycle for cycle conditioning. In
an oxidizing environment, a different protective layer is formed over the steel materials. This
protective corrosion layer, ferric hydrate oxide, covers a base layer of magnetite. Figure 10-5
shows the relative solubilities of both magnetite and ferric hydrate oxide. Reports from Germany
and the former Soviet Union indicate that plants using this type of treatment have operated for
significantly longer periods than AVT steam generators without the necessity of chemical cleaning
to remove iron deposits in the steam generator.
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Figure 10-5
Solubility of Iron Hydrate Oxides
(EPRI, 1994. Reprinted with Permission.)
In OT, oxygen is fed to the condensate system downstream of the condensate polisher, by the boiler
feed pump suction piping, or via both methods. Oxygenated treatment can be practiced
satisfactorily over a large pH range. An all-ferrous condensate and feedwater system is required.
Copper materials are acceptable for the condenser tubing. Any copper materials downstream of the
condensate polisher will result in an unacceptably high rate of copper transport in the cycle.
OT requires high purity water for successful operation, therefore condensate polishing is required.
OT specifications for the boiler feedwater include the following:


Oxygen levels between 30 to 150 ppb for once-through units and between 30 to 50 ppb for
drum units.
pH between 8.0 to 8.5 for once-through units and 9.0 to 9.4 for drum units.
To use a traditional OT, the following parameters must be consistently maintained in the feedwater:


All ferrous metallurgy.
Cation conductivity ≤ 0.15 microSiemens per centimeter (µS/cm) at 25° C in condensate,
feedwater, and steam.
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If the cation conductivity is above 0.15 µS/cm at 25° C, the corrosion rate accelerates quickly, which
is why it is critical to maintain the feedwater conductivity below this point to operate with this type
of treatment.
Figure 10-6 shows a comparison between AVT conditioning and OT conditioning.
Figure 10-6
10.1.3
Comparison between AVT Conditioning and OT Conditioning (for Once-Through Units)
(EPRI, 1994. Reprinted with Permission.)
Conditioning Chemicals
10.1.3.1 Ammonia
Ammonia is fed to the cycle water to raise pH in order to maintain corrosion passivity in the cycle.
Ammonia is fed to the cycle immediately downstream of the condensate polisher connection, when
provided, or to the condensate pump discharge when a polisher connection is not provided. If
directed by the client, proprietary volatile amines may be considered.
Because of its odor, ammonia should be fed using a closed feed system. The preferred feed system
utilizes a tote and is shown on Figure 10-7. Alternatively, a closed solution tank could be used
which includes a gasketed and bolted chemical charging door and a vapor seal around the mixer
shaft where it enters the solution tank. All vents from the ammonia feed system shall be discharged
outdoors away from normal traffic areas. Ventilation in the ammonia feed areas should be
designed to prevent recirculation of air to other indoor plant areas. Exhaust air from the ammonia
areas should be directed outdoors.
The ammonia feed pumps should be designed to maintain the pH of the condensate and boiler
feedwater at a desired level. Ammonia will be lost through cycle losses, condenser exhaust, and by
ion exchange in a condensate polisher. Typically, each feed pump should be sized to maintain an
ammonia residual of up to 2.0 parts per million (ppm) at the boiler feed pump suction for nonHRSG units and 4.0 ppm for HRSG units, assuming a 1 to 2 percent ammonia solution in the solution
tank. If ammonia is provided in totes (19 percent aqueous ammonia concentration is commonly
used), the pump sizing should be adjusted to accommodate the concentration to be provided. The
ammonia feed should be continuous and automatically adjusted with the use of a variable speed
motor with a manual or automatic stroke positioner. A variable speed motor together with a stroke
positioner provides 1:100 pump turndown ratio. During continuous normal operation, ammonia
will be recovered and a significant amount of ammonia is recirculated, which makes the ammonia
pumps operate around 30 percent of the pump design capacity. Therefore, a high turndown ratio
pump is more applicable for ammonia feed pumps.
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For systems with condensate polishing, extra attention should be taken to ensure that the ammonia
feed system is properly sized and designed for operation of a polisher system that functions in both
hydrogen and ammonia cycles.
Figure 10‐7
Ammonia Feed System
10.1.3.2 Phosphate
Trisodium phosphate and/or caustic are fed to adjust and buffer the pH of boiler water and to react
with any residual hardness to form a nonscaling precipitate that is more easily removed by boiler
blowdown. Trisodium phosphate and caustic are fed to the cycle of drum units at the economizer
inlet, boiler drum(s), or into the suction line of the circulation pumps in forced circulation boilers.
Phosphate cannot be fed to low‐pressure heat recovery steam generator (HRSG) drums if the drum
is used for the feedwater that is used as desuperheating water because the desuperheating water is
fed directly into the steam.
Phosphate can be supplied as a dry chemical in bags or in a tote. A solution tank is typically
provided to allow the client flexibility in the type of chemical used over time. Proprietary
phosphate products may already contain some caustic to help control the boiler pH (e.g., trisodium
phosphate + 1 ppm caustic). Each phosphate feed pump should be sized to increase the phosphate
residual in the boiler water from 0 to 5 milligrams per liter (mg/L) within 1 hour with a 3 percent*
phosphate solution. During normal operation, the feed pumps should be capable of metering at a
dosage rate of 4 mg/L, based on the boiler blowdown rate, with a 1 percent* phosphate solution.
The phosphate feed pumps do not require automatic feed controls. Feed is usually intermittent to
build up the phosphate residual. Therefore, the feed rate should be manually adjustable with a
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manual stroke adjustment micrometer mounted on the pump. For neat solutions, the chemical
supplier should be consulted to confirm if a dilution system is needed to prevent crystallization of
the phosphate in the chemical feed lines. Figure 10‐8 presents a traditional phosphate feed system.
*Note that the appropriate phosphate dilution concentration should be discussed with the chemical
supplier if the Owner has a specific phosphate specified for use. Feeding phosphate that is too
concentrated will result in precipitation in the chemical feed line at the HRSG drum. The more
dilute the phosphate solution and the more flow through the line, the less potential for the line
plugging over time.
Figure 10‐8
Traditional Phosphate Feed System
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Some clients specify feeding phosphate with an automated makedown module. This method
includes a small, low-pressure pump that feeds a precise amount of concentrated chemical to a
pipeline where the concentrated chemical mixes with an amount of demineralized water that
dilutes the concentrated chemical to the desired solution strength. This dilute solution then feeds
high-pressure diaphragm metering pumps that pump the diluted solution to the HRSG drums. A
representation of this method is shown on Figure 10-9.
Figure 10-9
Phosphate Makedown Module Feed System
10.1.3.3 Hydrazine
Hydrazine (an oxygen scavenger) is fed to cycle water to reduce oxygen concentration in the
condensate and boiler feedwater. Hydrazine is no longer recommended to be fed during normal
operating conditions as it has been shown to contribute to flow-accelerated corrosion. Hydrazine
feed systems are sometimes requested by clients for use during startup, but most HRSG
manufacturers do not recommend the use of hydrazine. If hydrazine is fed at any time to the cycle,
the cycle chemistry is no longer considered AVT-O, and the cycle materials of construction must be
selected to reduce the potential for flow accelerated corrosion (FAC). When hydrazine is used, it is
fed to the cycle immediately downstream of the condensate polisher connection, when provided, or
to the condensate pump discharge when a polisher connection is not provided.
Hydrazine should be fed using a closed feed system because of its odor. A typical hydrazine feed
system is shown on Figure 10-10. A closed solution tank is required, which includes a gasketed and
bolted chemical charging door and a vapor seal around the mixer shaft where it enters the solution
tank. All vents from the hydrazine feed system should be discharged outdoors away from normal
traffic areas. Ventilation in the hydrazine feed areas should be designed to prevent recirculation of
air to other indoor plant areas. Exhaust air from the hydrazine areas should be directed outdoors.
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Type 304 stainless steel is recommended for the concentrated chemical transfer piping and valves
for the hydrazine feed system. The transfer piping and the valves should be Type 304 stainless
steel whenever practical. Other stainless steel alloys may contain molybdenum, which acts as a
decomposition catalyst for hydrazine. The bell-up for the hydrazine tank overflow and drain
should be sealed to prevent the escape of hydrazine vapors. The hydrazine feed pump suction and
discharge piping and valves should also be of Type 304 stainless steel.
Each hydrazine feed pump should be designed to maintain a hydrazine residual of 0.03 mg/L at the
economizer inlet and to continuously feed 0.1 mg/L of hydrazine to the condensate system with a
1 percent solution. The hydrazine feed should be continuous and automatically adjusted with the
use of an automatic electronic stroke positioner or variable speed motor.
Hydrazine is a suspected carcinogen, which is often a concern to clients. This should be a
consideration on any project that utilizes hydrazine.
Figure 10-10
Hydrazine Feed System
10.1.3.4 Oxygen
Oxygen is fed only when utilizing oxygenated treatment. Oxygen is fed to the condensate pump
discharge and/or the boiler feed pump suction. The oxygen feed creates an oxidizing environment
in the condensate/feedwater, as opposed to the reducing environment created by removing the
oxygen. This is the preferred cycle chemistry for supercritical boilers, but may also be used for
subcritical drum boilers and HRSGs.
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10.2
Approach
The chemical feed system design should be dependent on the chemicals to be fed; contractual
requirements; client preferences; and federal, state, and local regulations governing the safe
storage and handling of the chemicals.
Reliability is an important factor in the design of a chemical feed system. Redundancy improves the
system reliability by providing duplicates of those items of equipment that possess the greatest
potential for failure or malfunction. All chemical feed systems should include two 100 percent
capacity feed pumps.
10.2.1
Equipment Design
10.2.1.1 Chemical Storage
10.2.1.1.1 Solution Tank Design
Solution tank capacity is based on the projected feed rate of the chemical solution over a 1 day
period. In cases where the tank size required exceeds 100 US gallons, higher chemical
concentrations should be considered to balance the chemical quantity demands with the common
tank sizes and reasonable feed pump capacities. The chemical concentration used for design
purposes should always remain substantially below the solubility limit of the chemical being used
throughout the potential operating temperature range for the chemical solution.
The solution tanks should be fabricated of a material compatible with the intended service. Each
tank should be furnished with a charging door, mixer, nameplate, liquid level rule, and piping and
instrumentation connections. If a chemical is purchased in the solid form, a dissolving basket
should be provided. Even though liquid chemicals would not need a dissolving basket to aid in
solution preparation, a basket may be specified to allow for the use of a solid chemical in the future.
10.2.1.1.2 Chemical Supplier Totes
Proprietary chemical supplier storage totes or semi-bulk containers may be used in lieu of solution
tanks. Feeding directly from totes is preferred in many cases because of the simplicity of the design
and reduction in operator attention associated with making dilute solutions in a solution tank.
During the initial phases of the project, it should be determined whether interconnecting hoses and
quick connects for totes are to be supplied with the chemical feed system. To properly design the
system, the chemical supplier should be contacted for available solution strengths.
10.2.1.1.3 Solution Tank Mixers
Solution tank mixers should be provided with a bolted tank mounting bracket for mounting onto
the solution tank. The mixer should enter the solution tank at a 15 degree angle. This geometry
aids the solution mixing process. The mixer should have a chemical duty motor. The wetted parts
of the mixer should be constructed of stainless steel or rubber coated carbon steel. The mixer shaft
should extend within 6 inches (150 mm) of the bottom of the solution tank. A single propeller with
a diameter of approximately 4 inches (100 mm) should be adequate for most applications. If a solid
chemical is used, the mixer enhances dissolution of the chemical. If a liquid chemical is used, a
short period of agitation by the mixer ensures a homogeneous chemical solution.
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For hydrazine and ammonia applications, the mixer entry to the tank must be sealed to prevent
escape of harmful or nuisance odors.
10.2.1.1.4 Solution Tank Local Indication
A gauge glass level indicator with scale should be used with a stainless steel or opaque solution
tank. A scale should be provided on translucent tanks. This will allow operating personnel to
monitor the liquid level in the solution tank and anticipate when a fresh solution needs to be
prepared.
10.2.1.1.5 Calibration Column
A calibration column should be used in any chemical feed system to reduce personnel exposure and
spillage of the chemical encountered with test connections. The calibration column should be used
to check the chemical feed pumping rates. The calibration column should be constructed of
transparent acrylic plastic or translucent polypropylene. The columns should be sized to take at
least 60 seconds to pump down, based on the design flow of the pump. The calibration column
should be vented back to the storage/solution tank, or a “candy cane” type vent should be added
with the open end of the vent at an elevation at least 6 inches (150 mm) higher than the top of the
associated bulk storage tank to avoid personnel exposure if the calibration column is overfilled.
10.2.1.1.6 Measuring Tank
If required, a measuring tank should be provided for measuring the proper amount of liquid
chemical for solution preparation. The measuring tank should be constructed of translucent plastic
or polypropylene. The measuring tank should be graduated in 1/10 gallon (0.5 liter) increments as
illustrated on Drawing 81113-DC-0010 (included at the end of this section). The measuring tank
should be sized to hold 2 gallons (8 liters) of liquid.
10.2.1.1.7 Chemical Pot Feeder
A chemical pot feeder, as shown on Drawing 81116-DC-0001 (included at the end of this section),
should be used to feed liquid chemicals to closed cycle cooling water systems. Standard off-theshelf type chemical feeders may also be used.
10.2.1.2 Chemical Feed Pumps
Chemical feed pumps are typically positive displacement, hydraulically actuated diaphragm type or
solenoid driven pumps. These types of pumps discharge a precise volume of liquid at a specific
stroke length and stroking speed over a wide range of discharge pressures. Diaphragm type pumps
are generally more expensive and are repaired rather than replaced. Solenoid driven pumps are
cheaper but typically are replaced rather than repaired. In some cases, other styles of pumps, such
as gear pumps or peristaltic pumps, are utilized.
Chemical feed pumps should be selected so that there are two full-capacity pumps, one serving as a
spare. Hydraulically actuated diaphragm metering pumps should be used for most applications.
The hydraulically actuated feed pumps should contain an internal pressure relief valve. Pumps
with discharge pressure below 800 psig (5,516 kilopascals gauge [kPag]) should have suction and
discharge check valves. Pumps with discharge pressure above 800 psig (5,515 kPag) should have
double suction and discharge check valves. Each feed pump should be furnished with a chemical
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duty motor. The feed pump stroking mechanism should be designed for continuous service and be
capable of stroke length adjustments regardless of pump operating status. Local stroke adjustment
capabilities should be included for any automatic stroke adjustment equipment. All wetted parts of
the feed pump should be of materials compatible with the intended service. Variable speed drive
motors with local control capabilities can also be used for pump capacity control. Stroke length
adjustment will give 10:1 turndown of the pump. For applications where greater than 10:1
turndown is required, a combination of stroke adjustment (typically manual but could be
automatic) and variable speed drives should be considered.
10.2.1.3 Chemical Transfer Pumps
A drum pump is required to transfer chemicals purchased in drums to the chemical measuring tank.
Specifically, the hydrazine and ammonia feed systems require a drum pump if solution tanks are
utilized for those feed systems. The drum pump should be equipped with a 2 inch (50 mm) bung
adapter to prevent vapor escape from the drum and a drainback feature to prevent spillage when a
drum change is required. Double shutoff quick-connect fittings should be considered to connect the
drum pump discharge to the flexible hose on the transfer line. This allows the chemical drum to be
changed easily. A single shutoff quick-connect should be considered to connect the vent line to the
chemical drum. The shutoff portion of the quick-connect should be mounted on the vent piping,
because hydrazine vapors are heavier than air.
The drum pump should be sized with sufficient discharge head to deliver the chemical to the
measuring tank and a capacity such that the volume of the chemical in the measuring tank can be
controlled accurately by the operator.
In some instances, hydrazine may be purchased in shipping containers other than drums. Transfer
of hydrazine from the shipping container under nitrogen pressure is an acceptable alternative
when the shipping container is designed for such transfer.
10.2.1.4 Piping and Valves
10.2.1.4.1 Materials
The piping and valve materials should be selected on the basis of compatibility with the anticipated
chemical environment.
The typical materials used in B&V’s common applications are listed as follows:

Aqueous Ammonia:
●
●

ASTM A312, Type 316 Stainless Steel, seamless
ASTM A213, Type 316 Stainless Steel, seamless
Phosphate:
●
●
ASTM A312, Type 316 Stainless steel, seamless
ASTM A213, Type 316 Stainless steel, seamless
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
Hydrazine:
●
●

ASTM A312, Type 304 Stainless steel, seamless (Type 316 should not be used
because Type 316 contains molybdenum, which acts as a decomposition catalyst for
hydrazine.)
ASTM A213, Type 304 Stainless steel, seamless
Oxygen:
●
ASTM A213, Type 316 Stainless steel
10.2.1.4.2 Sizing Criteria
The piping diameter should be selected for an average fluid velocity no greater than 7 feet per
second (2.1 meters per second). However, because of the usual feed rates encountered with these
chemicals, the minimum pipe diameter allowed to be used on a project may be larger than the
calculated size. The engineer should refer to the Project Design Manual for the minimum pipe sizes
that can be used. For most installations, 1 inch (25 mm) diameter suction piping and 1/2 inch
(15 mm) diameter discharge piping are sufficient. Piping or tubing can be used for this service, but
consideration must be given to how tubing will be supported. Piping size calculations must also
take into account the fact that positive displacement feed pumps pump in a pulsating manner; this
can have a significant impact on the proper selection of the piping system. The pipe schedule
should be selected with consideration of the pressure ratings of the system being fed and the
maximum discharge pressure of the feed pump. The piping design must follow the Overpressure
Protection Procedure (link is provided in the references), which requires the pump suction piping
to be designed to meet the pump discharge pressure, unless a relief valve is installed in the suction
line. This is especially important in the phosphate feed piping because of the high pump pressures.
If a relief valve is not installed in the suction line, the maximum allowable pressure of the flexible
hose between the chemical tote and chemical skid shall be higher than the maximum discharge
pressure.
10.2.1.4.3 Pulsation Dampeners
Pulsation dampeners are used to even the flow to a process and to reduce the size of pipe that is
needed. A pulsation dampener should be installed in pump discharge piping for pumps 2 gallons
per hour (7.5 liters per hour) and larger. The pulsation dampener should be located as close to the
pump discharges as practical. The pulsation dampener selected must be able to handle the
maximum system pressure. Pulsation dampeners should not be used on high-pressure phosphate
feed systems.
A pulsation dampener may be required on longer pump suction lines to minimize suction line
losses, especially on more viscous fluids such as sulfuric acid. The engineer must evaluate this on a
case-by-case basis.
The Metering Pump Handbook (refer to Section 10.3) contains equations for calculating the
pressure drop for metering pump systems.
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10.2.1.4.4 Relief Valves
A relief valve should be installed on the discharge of each pump, upstream of the discharge isolation
valve. The relief valve should be set for the design pressure of the system for overpressure
protection. The outlet of the relief valve should be routed to a local chemical drain, with an air gap
to allow the operator to recognize when the valve is relieving. Alternatively, the outlet of the relief
valve can be routed back to the bulk storage tank.
Suction piping that cannot be rated for the same pressure as the discharge should also be protected
by a relief valve. This is to protect the suction piping in the event the check valves in the system
leak and pressurize an isolated suction line.
10.2.1.4.5 Back-Pressure Valves
In low-pressure applications (less than 50 psi [345 kPa] back pressure), back-pressure valves
should be installed, if required, at the discharge of the feed pumps, downstream of the pulsation
dampener, to ensure sufficient back pressure for proper operation of the pumps’ integral suction
and discharge check valves. Back-pressure valves should be set in accordance with the pump
manufacturer’s recommendations. Back-pressure valves should not be used in applications where
the operating pressure experienced by the valves exceeds the maximum valve pressure rating.
10.2.1.4.6 Strainers
A strainer should be installed downstream of the supply tank outlet isolation valve. This location
allows servicing of the strainer without draining the tank. The strainer should be constructed of a
material compatible with the pumped chemical and system piping. The material most frequently
used is Type 316 stainless steel; however, Monel, polyvinyl chloride (PVC), chlorinated polyvinyl
chloride, and carbon steel may be considered for specific applications. Clear PVC strainers should
be considered to provide a visual indication that the strainer needs to be cleaned. The strainer
should be equipped with a blind cap and 100 mesh perforations in the strainer screen.
10.2.1.5 Physical Arrangement Considerations
The physical arrangement of the equipment varies significantly from one installation to the next.
The following factors should be considered when designing the equipment arrangement.
10.2.1.5.1 Skids
Chemical feed systems should be skid mounted unless project specifics dictate otherwise. Skid
mounting each feed system reduces overall installation schedules and costs. Skid mounting also
generally provides for more compact designs. Individually mounting the equipment requires a
higher level of control and coordination by the design engineer during the design and fabrication of
the equipment. Along with the higher level of detail required of the engineer, the installation of the
equipment is generally more complicated and, therefore, more costly.
The access and maintenance required for the components on each skid should be considered during
skid and plant arrangement design.
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10.2.1.5.2 Pump Net Positive Suction Head Requirements
The net positive suction head (NPSH) requirements of the feed pumps may make the location of the
solution tank, relative to the feed pumps, an important consideration. Generally, the feed pumps
can operate accurately at pressures as low as 10 pounds per square inch absolute (70 kPa), if
relatively nonvolatile materials are in the solution being pumped. Consequently, it is generally
acceptable to mount the feed pumps at the base of the associated solution tank. The NPSH
requirements, however, should be checked for each installation.
10.2.1.5.3 Drain Design
Unsealed drainlines, such as floor drains, should not be connected to ammonia, hydrazine, or other
oxygen scavenger drainlines. The ammonia and hydrazine solution tank drainlines and the cycle
chemical area floor drains should be kept separate from other plant drainlines to prevent vapors
from entering other plant areas. The ammonia and hydrazine drainlines should be trapped and
terminated under the normal water level of the receiving sump.
10.2.1.5.4 Access Requirements
Chemical feed area locations must be considered with respect to access. Areas using bulk storage
must have road access for delivery. Space must be provided to allow forklift delivery of the
chemical totes and other portable containers. Forklift delivery will require that the tote be placed
on an equipment pad or surface at least as high as the containment curb and will require a
minimum of 12 feet (3.7 meters) of clearance to back the forklift out after placing the tote.
Alternately, totes can be located alongside the outside wall of the chemical feed building, with rollup doors to allow tote delivery. Additional height clearance should also be considered for totes
because totes are often refilled by elevating a “fill” tote above the “main” tote with filling of the main
tote by way of gravity. Space considerations for bulk storage tank platforming and/or ladders
should also be considered.
10.2.1.6 Controls and Instrumentation
10.2.1.6.1 General
The controls and instrumentation involved with chemical feed systems should include solution tank
level interlocks and alarms, feed pump motor control, and feed pump stroke controls. A level
switch should be used to indicate a low solution level and provide a low-low level interlock to stop
the feed pumps. If totes are used, the control system should consider the capability of having a low
level switch from a tote for pump interlock. Level switches provided with solution tanks should be
probe electrode, diaphragm, ultrasonic, or float type. Pump motor controls should be provided
locally with provisions for remote control. Control of the feed pump stroke should be accomplished
with an automatic electronic stroke positioner or a manual stroke adjustment micrometer.
Generally, phosphate feed pumps are adjusted manually and ammonia and hydrazine feed pumps
are adjusted automatically. However, the extent of the use of automatic controls should be
evaluated for each installation.
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10.2.1.6.2 Control Overview
The control philosophies discussed in this subsection (concerning the automatic feed rate controls)
involve control instrumentation not often purchased with the chemical feed systems. The feed rate
controls should be included in a water quality control system or should be part of a distributed
control system. Drawing 81116-DC-0013, included at the end of this section, identifies the symbols
used in the logic diagrams.
10.2.1.6.3 Ammonia Control
The ammonia solution feed rate should be automatically controlled in proportion to the specific
conductance of the condensate downstream of the injection point. The feed rate may alternatively
be automatically controlled on the basis of the condensate flow rate biased by the specific
conductance of the condensate downstream of the ammonia feed point. A typical ammonia feed
control logic diagram is shown on Drawing XXXXX-DC-0014 (included at the end of this section).
The desired ammonia concentration is related to condensate specific conductance and pH as
indicated on Figure 10-11. The desired system pH is dependent on the operating pressure and
materials contained in the main cycle. The optimum pH should be determined for each application.
Figure 10-11
Ammonia - Conductivity - pH Curve
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10.2.1.6.4 Hydrazine Control
The hydrazine feed rate should be automatically controlled in proportion to the condensate flow
with a bias signal from the hydrazine residual at the economizer inlet. A typical hydrazine feed
control logic diagram is shown on Drawing XXXXX-DC-0015 (included at the end of this section).
The hydrazine concentration should be maintained in the range of 0.01 to 0.03 mg/L at the
economizer inlet. For some projects, the use of a hydrazine analyzer may not be justifiable. In
these cases, the control logic should be modified to eliminate the biasing signal from the hydrazine
analyzer or use a dissolved oxygen input from a point downstream of the deaerator. The result
would be the removal of the hydrazine residual signal processing instrumentation and the
multiplier that combines the condensate flow signal with the hydrazine residual signal.
10.2.1.6.5 Phosphate Control
The phosphate feed rate should be manually controlled to feed phosphate, as required. Phosphate
is normally maintained in a specific range relating to the boiler operating pressure. The engineer
should determine the specific requirements of the steam generator on each project.
10.2.1.6.6 Oxygen Control
The oxygen feed should be automatically controlled in proportion to the condensate flow rate. The
oxygen concentration should be maintained in the range of 30 to 150 micrograms per liter (ppb) in
the feedwater for once-through units and from 30 to 50 ppb for drum units. A dissolved oxygen
analyzer should be provided to measure the oxygen concentration in the boiler feedwater at the
economizer inlet.
10.3
References

Robert H. Perry and Don Green, eds., Perry’s Chemical Engineers’ Handbook, Sixth Edition,
McGraw-Hill Book Company, 1984.









National Institute for Occupational Safety and Health, Criteria for a Recommended Standard:
Occupational Exposure to Hydrazines, June 1978.
George Gibson, “The Basics of Phosphate-pH Boiler Water Treatment,” Power Engineering,
February 1978.
Pulsatrol Pulsation Dampener, Pulsafeeder Products Catalog No. 210, May 1987.
Storage and Handling of Aqueous Hydrazine Solutions, Olin Chemicals, Olin Corporation,
1980.
Electric Power Research Institute (EPRI), Cycle Chemistry Guidelines for Fossil Plants:
Oxygenated Treatment, March 2005.
EPRI, Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators
(HRSGs), March 2006.
EPRI, Comprehensive Cycle Chemistry Guidelines for Fossil Plants, December 2011.
Robert E. McCabe, Phillip G. Lanckton, and William V. Dwyer, eds., Metering Pump
Handbook, Second Printing, Industrial Press Inc., 1984.
Overpressure Protection Procedure.
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11.0 Circulating Water Chemical Feed
11.1
Purpose and Applicability
This section describes the different chemical treatment methods for circulating water and provides
design criteria that can be used to design chemical feed equipment. This handbook section is
applicable to all fossil fuel power projects with circulating water systems.
11.1.1
Overview
Circulating water is chemically treated to prevent or minimize scaling and corrosion of the
condenser tubes and the cooling water side of the condenser. Scaling of the condenser reduces the
efficiency of the condenser, and of the overall plant. Circulating water chemical feed systems also
provide control of bacterial fouling and algae that can affect heat transfer, impair flow distribution
at the cooling tower, and cause deterioration of materials.
11.1.2
Circulating Water Treatment Chemicals
11.1.2.1 Biocides
The most common biocide for circulating water treatment is sodium hypochlorite. Sodium
hypochlorite is commercially available in 10 to 15 percent solutions. Hypochlorite should be fed to
the circulating water intake structure or to the cooling tower basin near the circulating water
intake structure for biological control in circulating water systems. Sodium bromide solution may
also be fed in conjunction with sodium hypochlorite for increased biofouling control. Bromide
handling and feed systems are designed similar to inhibitor handling and feed systems except the
feed rate control is manual.
A typical feed system is shown on Figure 11-1. Nonmetallic piping should be used for hypochlorite
service. Solvent welded chlorinated polyvinyl chloride (CPVC) should be used for hypochlorite
service in most installations. If additional structural strength is desired, lined carbon steel may be
used. Acceptable lining materials include Kynar, polypropylene, and Teflon. The most significant
disadvantage with lined piping systems is that flanges must be used, and leaks at flanges subject the
carbon steel in the piping to the corrosive hypochlorite. Valves within a hypochlorite feed system
should also be constructed of CPVC.
If the chlorine demand of the circulating water makeup cannot be determined prior to design, the
pumps should be sized to deliver 5 parts per million (ppm) minimum of free chlorine, based on the
use of a 10 percent hypochlorite solution to the circulating water. The pumps should be designed to
shock feed three times a day for 20 minutes each shock. Adjustable timers should be provided
either locally or in the distributed control system (DCS) for automatic feed. For positive
displacement hydraulic pumps, the feed rate should be manually adjustable by a manual stroke
adjustment micrometer mounted on the pump. If sodium hypochlorite is fed at high dosing rates,
gear pumps may be considered as a more cost-effective alternative. Chlorine feed rate should be
manually adjusted. Circulating water should maintain a free available chlorine residual of 0.1 to
0.5 milligram per liter (mg/L).
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Figure 11-1
Circulating Water Sodium Hypochlorite Feed System, Inhibitor Feed System, and Acid Feed System
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Closed feed systems should be used for hypochlorite due to inhalation hazards and objectionable
odors. Providing a closed solution tank requires modifications that include a gasketed and bolted
chemical charging door and a vapor seal around the mixer shaft where it enters the solution tank.
All vents from the hypochlorite system should be discharged outdoors away from normal traffic
areas. Ventilation in the hypochlorite feed area should be designed to prevent recirculation of air to
other indoor plant areas. Exhaust air from the hypochlorite feed area should be directed outdoors.
11.1.2.1.1 Biocides for Potable Water
Hypochlorite should be fed upstream of a potable water head tank or pressure tank (sized to
provide a minimum of 30 minutes contact time) to disinfect the water for potable water uses.
Hypochlorite may be in the form of sodium hypochlorite or calcium hypochlorite.
Each hypochlorite feed pump used for potable water should be designed to maintain a 0.3 mg/L
concentration of free chlorine throughout the potable water distribution system. It is generally not
possible to calculate the exact chlorine feed design rate on account of variations in potable water
use rates and chlorine demand in the raw water. However, a design feed rate of 3 to 5 mg/L of free
chlorine, based on the use of a 10 percent solution, may be used. The hypochlorite solution should
be fed continuously to a head tank or pressure tank during automatic refill operations of the tank
whenever possible. The feed rate should be manually adjustable with a manual stroke adjustment
micrometer mounted on the pump. If hypochlorite must be fed directly to a distribution system, an
automatic electronic stroke positioner or variable speed drive motor should be used, and the
hypochlorite should be fed in proportion to the potable water usage. Low volume hypochlorite feed
pumps should be provided with a degassing valve or similar mechanism.
11.1.2.2 Sulfuric Acid
Sulfuric acid is fed to reduce the M-alkalinity of the circulating water. This reduces the scaling
potential of the circulating water and allows for a cooling tower to operate at higher cycles of
concentration. Sulfuric acid is typically fed into the cooling tower basin. Care must be taken with
the feed piping design because dense acid can sink to the bottom of the cooling tower and corrode
the basin if not well diluted. Refer to Section 22 for sulfuric acid feed system design, including
details on acid mixing and diffusers.
11.1.2.3 Scale Inhibitors
Scale inhibitors, or antiscalant, is fed to circulating water to reduce the scale potential of the water.
Inhibitors should be fed into the circulating water makeup water line or directly into the circulating
water pump discharge. If the inhibitor is fed to the tower basin, a mixing trough or diffuser should
be used, or it should be fed directly into the point of makeup.
Typical corrosion inhibitors include molybdates, polyphosphates, and zinc compounds. Scale
inhibitors are typically organic phosphates. Proprietary scale and corrosion inhibitors are
commonly used.
The inhibitor feed pumps should be designed to maintain the desired residual of the specific
inhibitor being used; however, the actual inhibitor usually has not been established at the time of
design. In the absence of more specific information, each inhibitor feed pump should be sized to
maintain an inhibitor concentration of 30 mg/L in the circulating water with a 1 percent inhibitor
solution. The inhibitor feed should be continuous and automatically adjusted with the use of an
automatic electronic stroke positioner or variable speed drive motor mounted on the pump.
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Inhibitor concentration should be maintained in accordance with plant operating experience and
the particular inhibitor used.
11.1.2.4 Dechlorination Agents
Dechlorination agents may be fed to the cooling water system blowdown stream prior to discharge
or to the inlet of cycle makeup treatment systems, if required. The dechlorination agent removes
residual chlorine from the water to allow discharge to the environment or to protect ion exchange
resin or reverse osmosis membranes from oxidation damage. Dechlorination agents that are
normally used include sodium bisulfite or sodium sulfite.
Each dechlorination feed pump should be sized to feed 2 mg/L of dechlorination agent for each
milligram per liter of total chlorine expected in the water supply. The dechlorination agent should
be fed in proportion to the flow rate of the water being treated. Depending on the application, the
feed rate may be manually adjustable with a manual stroke adjustment micrometer mounted on the
pump or automatically adjusted with the use of an automatic stroke positioner mounted on the
pump.
11.2
Approach
The chemical feed system design should be dependent on the chemicals to be fed; contractual
requirements; client preferences; and federal, state, and local regulations governing the safe
storage and handling of the chemicals.
Reliability is an important factor in the design of a chemical feed system. Redundancy improves the
system reliability by providing duplicates of those items of equipment that possess the greatest
potential for failure or malfunction. All chemical feed systems should include two 100 percent
capacity feed pumps.
11.2.1
Equipment Design
11.2.1.1 Chemical Storage
11.2.1.1.1 Solution Tank Design
Solution tank capacity is based on the projected feed rate of the chemical solution over a 1 day
period. In cases where the tank size required exceeds 100 US gallons, higher chemical
concentrations should be considered to balance the chemical quantity demands with the common
tank sizes and reasonable feed pump capacities. The chemical concentration used for design
purposes should always remain substantially below the solubility limit of the chemical being used
throughout the potential operating temperature range for the chemical solution.
The solution tanks should be fabricated of a material compatible with the intended service. Each
tank should be furnished with a charging door, mixer, nameplate, liquid level rule, and piping and
instrumentation connections. If a chemical is purchased in the solid form, a dissolving basket
should be provided. Even though liquid chemicals would not need a dissolving basket to aid in
solution preparation, a basket may be specified to allow for the use of a solid chemical in the future.
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11.2.1.1.2 Chemical Supplier Totes
Proprietary chemical supplier storage totes or semi-bulk containers may be used in lieu of solution
tanks. During the initial phases of the project, it should be determined whether interconnecting
hoses and quick connects for totes are to be supplied with the chemical feed system.
11.2.1.1.3 Solution Tank Mixers
Solution tank mixers should be provided with a bolted tank mounting bracket for mounting onto
the solution tank. The mixer should enter the solution tank at a 15 degree angle. This geometry
aids the solution mixing process. The mixer should have a chemical duty motor. The wetted parts
of the mixer should be constructed of stainless steel or rubber coated carbon steel. The mixer shaft
should extend within 6 inches (150 mm) of the bottom of the solution tank. A single propeller with
a diameter of approximately 4 inches (100 mm) should be adequate for most applications. If a solid
chemical is used, the mixer enhances dissolution of the chemical. If a liquid chemical is used, a
short period of agitation by the mixer ensures a homogeneous chemical solution.
For hypochlorite, the mixer entry to the tank must be sealed to prevent escape of harmful or
nuisance odors.
11.2.1.1.4 Solution Tank Local Indication
A gauge glass level indicator with scale should be used with a stainless steel or opaque solution
tank. A scale should be provided on translucent tanks. This will allow operating personnel to
monitor the liquid level in the solution tank and anticipate when a fresh solution needs to be
prepared.
11.2.1.1.5 Bulk Liquid Storage
Bulk storage is required where the quantity of chemical being handled prohibits daily preparation.
Because of the quantities required, a bulk liquid chemical storage tank should generally be used for
storing circulating water inhibitor chemicals, acid, pretreatment coagulants, and sodium
hypochlorite. The tank capacity should be sufficient for 15 to 30 days of storage at the design feed
rates. The bulk storage tanks should be constructed of materials compatible with the chemical
being stored.
The bulk storage tanks should be located within containment areas and with convenient road
access. Delivery truck unloading pumps are not typically required for domestic locations, but may
be required for international sites. Containment design is described in the Oil and Chemical
Containment Procedure.
Acid storage tank design is covered in Section 22.
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A bulk sodium hypochlorite (10 percent to 15 percent concentration) storage tank should be of
fiberglass reinforced plastic (FRP) construction. The sodium hypochlorite FRP tank should be
specified as follows:
Resin:
Derakane 411 or Hetron 922 (both are from Ashland manufacturer)
Surfacing Veil :
Two ply Nexus veil or double C-glass (requires resin manufacturer’s
confirmation)
Post Cure :
Required
Cure :
UV inhibitor:
BPO/DMA
Required
11.2.1.1.6 Calibration Column
A calibration column should be used in any chemical feed system to reduce personnel exposure and
spillage of the chemical encountered with test connections. The calibration column should be used
to check the chemical feed pumping rates. The calibration column should be constructed of
transparent acrylic plastic or translucent polypropylene. The columns should be sized to take at
least 60 seconds to pump down, based on the design flow of the pump. The calibration column
should be vented back to the storage/solution tank, or a “candy cane” type vent should be added
with the open end of the vent at an elevation that is at least 6 inches (150 mm) higher than the top
of the associated bulk storage tank to avoid personnel exposure if the calibration column is
overfilled.
11.2.1.1.7 Measuring Tank
If required, a measuring tank should be provided for measuring the proper amount of liquid
chemical for solution preparation. The measuring tank should be constructed of translucent plastic
or polypropylene. The measuring tank should be graduated in 1/10 gallon (0.5 liter) increments as
illustrated on Figure 11-2. The measuring tank should be sized to hold 2 gallons (8 liters) of liquid.
11.2.1.2 Chemical Feed Pumps
Chemical feed pumps should be positive displacement, hydraulically actuated diaphragm type. This
type of pump discharges a precise volume of liquid at a specific stroke length and stroking speed
over a wide range of discharge pressures.
Chemical feed pumps should be selected so that there are two full-capacity pumps, one serving as a
spare. Hydraulically actuated diaphragm metering pumps should be used for most applications.
The hydraulically actuated feed pumps should contain an internal pressure relief valve. Pumps
with discharge pressure below 800 pounds per square inch gauge (psig) (5,516 kilopascals gauge
[kPag]) should have suction and discharge check valves. Pumps with discharge pressure above
800 psig (5,515 kPag) should have double suction and discharge check valves. Each feed pump
should be furnished with a chemical duty motor. The feed pump stroking mechanism should be
designed for continuous service and be capable of stroke length adjustments regardless of pump
operating status. Local stroke adjustment capabilities should be included for any automatic stroke
adjustment equipment. All wetted parts of the feed pump should be made of materials compatible
with the intended service. Variable speed drive motors with local control capabilities can also be
used for pump capacity control. For applications where greater than 10:1 turndown is required, a
combination of automatic stroke adjustment and variable speed drives should be considered.
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Figure 11-2
Liquid Chemical Measuring Tank
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11.2.1.3 Chemical Transfer Pumps
A drum pump is required to transfer chemicals purchased in drums to the chemical measuring tank.
The drum pump should be equipped with a 2 inch (50 mm) bung adapter to prevent vapor escape
from the drum and a drainback feature to prevent spillage when a drum change is required. Double
shutoff quick-connect fittings should be considered to connect the drum pump discharge to the
flexible hose on the transfer line. This allows the chemical drum to be changed easily. A single
shutoff quick-connect should be considered to connect the vent line to the chemical drum.
The drum pump should be sized with a discharge head sufficient to deliver the chemical to the
measuring tank and a capacity such that the volume of the chemical in the measuring tank can be
controlled accurately by the operator.
11.2.1.4 Piping and Valves
11.2.1.4.1 Materials
The piping and valve materials should be selected on the basis of compatibility with the anticipated
chemical environment.
11.2.1.4.2 Sizing Criteria
The piping diameter should be selected for an average fluid velocity no greater than 7 feet per
second (2.1 meters per second). However, because of the usual feed rates encountered with these
chemicals, the minimum pipe diameter allowed to be used on a project may be larger than the
calculated size. The engineer should refer to the Project Design Manual for the minimum pipe sizes
that can be used. For most installations, 1 inch (25 mm) diameter suction piping and 1/2 inch
(15 mm) diameter discharge piping are sufficient. Piping size calculations must also take into
account the fact that positive displacement feed pumps pump in a pulsating manner; this can have a
significant impact on the proper selection of the piping system. The pipe schedule should be
selected with consideration of the pressure ratings of the system being fed and the maximum
discharge pressure of the feed pump. The piping design must follow the Overpressure Protection
Procedure, which requires the pump suction piping to be designed to meet the pump discharge
pressure, unless a relief valve is installed in the suction line.
11.2.1.4.3 Pulsation Dampeners
Pulsation dampeners are used to even the flow to a process and to reduce the size of pipe that is
needed. A pulsation dampener should be installed in pump discharge piping for pumps 2 gallons
per hour (7.5 liters per hour) and larger. The pulsation dampener should be located as close to the
pump discharge as practical. The pulsation dampener selected must be able to handle the
maximum system pressure.
A pulsation dampener may be required on longer pump suction lines to minimize suction line
losses. The engineer must evaluate this on a case-by-case basis.
The Metering Pump Handbook contains equations for calculating the pressure drop for metering
pump systems.
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11.2.1.4.4 Relief Valves
A relief valve should be installed on the discharge of each pump, upstream of the discharge isolation
valve. The relief valve should be set for the design pressure of the system for overpressure
protection. The outlet of the relief valve should be routed to a local chemical drain with an air gap
to allow the operator to recognize when the valve is relieving.
11.2.1.4.5 Back-Pressure Valves
In low-pressure applications (less than 50 psi [345 kPa] back pressure), back-pressure valves
should be installed, if required, at the discharge of the feed pumps, downstream of the pulsation
dampener, to ensure sufficient back pressure for proper operation of the pumps’ integral suction
and discharge check valves. Back-pressure valves should be set in accordance with the pump
manufacturer’s recommendations. Back-pressure valves should not be used in applications where
the operating pressure experienced by the valves exceeds the maximum valve pressure rating.
11.2.1.4.6 Strainers
A strainer should be installed downstream of the supply tank outlet isolation valve. This location
allows servicing of the strainer without draining the tank. The strainer should be constructed of a
material compatible with the pumped chemical and system piping. The material most frequently
used is Type 316 stainless steel; however, Monel, polyvinyl chloride (PVC), CPVC, and carbon steel
may be considered for specific applications. Clear PVC strainers should be considered to provide a
visual indication that the strainer needs to be cleaned. The strainer should be equipped with a
blind cap and 100 mesh perforations in the strainer screen.
11.2.1.5 Physical Arrangement Considerations
The physical arrangement of the equipment varies significantly from one installation to the next.
The following factors should be considered when designing the equipment arrangement.
11.2.1.5.1 Skids
Chemical feed systems should be skid mounted unless project specifics dictate otherwise. Skid
mounting each feed system reduces overall installation schedules and costs. Skid mounting also
generally provides for more compact designs. Individually mounting the equipment requires a
higher level of control and coordination by the design engineer during the design and fabrication of
the equipment. Along with the higher level of detail required of the engineer, the installation of the
equipment is generally more complicated and, therefore, more costly.
The access and maintenance required for the components on each skid should be considered during
skid and plant arrangement design.
11.2.1.5.2 Pump Net Positive Suction Head Requirements
The net positive suction head (NPSH) requirements of the feed pumps may make the location of the
solution tank, relative to the feed pumps, an important consideration. Generally, the feed pumps
can operate accurately at pressures as low as 10 pounds per square inch absolute (70 kPa), if
relatively nonvolatile materials are in the solution being pumped. Consequently, it is generally
acceptable to mount the feed pumps at the base of the associated solution tank. The NPSH
requirements, however, should be checked for each installation.
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11.2.1.5.3 Access Requirements
Chemical feed area locations must be considered with respect to access. Areas using bulk storage
must have road access for delivery. Space must be provided to allow forklift delivery of the
chemical totes and other portable containers. Forklift delivery will require that the tote be placed
on an equipment pad or surface at least as high as the containment curb and will require a
minimum of 12 feet (3.7 meters) of clearance to back the forklift out after placing the tote.
11.2.1.6 Controls and Instrumentation
11.2.1.6.1 General
The controls and instrumentation involved with chemical feed systems should include solution tank
level interlocks and alarms, feed pump motor controls, and feed pump stroke controls. A level
switch should be used to indicate a low solution level and provide a low-low level interlock to stop
the feed pumps. If totes are used, the control system should consider the capability of having a low
level switch from a tote for pump int erlock. Level switches provided with solution tanks should be
probe electrode, diaphragm, ultrasonic, or float type. Pump motor controls should be provided
locally with provisions for remote control. Control of the feed pump stroke should be accomplished
with an automatic electronic stroke positioner or a manual stroke adjustment micrometer.
Generally, hypochlorite and bromide feed pumps are adjusted manually, and inhibitor and
dechlorination feed pumps are adjusted automatically. However, the extent of the use of automatic
controls should be evaluated for each installation.
11.2.1.6.2 Control Overview
The control philosophies discussed in this subsection (concerning the automatic feed rate controls)
involve control instrumentation not often purchased with the chemical feed systems. The feed rate
controls should be included in a water quality control system or should be part of a distributed
control system. Figure 11-3 identifies the symbols used in the logic diagrams.
Acid feed rate control will be based on the cooling tower makeup water flow biased by feedback
from pH of the circulating water. The acid feed pumps will be interlocked with the circulating water
pumps to assure acid will not be fed unless a circulating water pump is operating.
The inhibitor feed should be automatically controlled in proportion to the cooling water blowdown
flow rate. A typical inhibitor feed control logic diagram is shown on Figure 11-4.
Feed of chlorination agents such as sodium bisulfite should be controlled based on the flow rate of
the water being treated and biased by feedback from a chlorine analyzer.
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Figure 11-3
Logic Diagram Symbol Legend
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Figure 11-4
Inhibitor Feed Control Logic Diagram
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11.3
References

Robert H. Perry and Don Green, eds., Perry’s Chemical Engineers’ Handbook, Sixth Edition,
McGraw-Hill Book Company, 1984.




Pulsatrol Pulsation Dampener, Pulsafeeder Products Catalog No. 210, May 1987.
Robert E. McCabe, Phillip G. Lanckton, and William V. Dwyer, eds., Metering Pump
Handbook, Second Printing, Industrial Press Inc, 1984.
Oil and Chemical Containment Procedure.
Overpressure Protection Procedure.
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12.0 Sampling and Analysis
12.1
Purpose and Applicability
This section provides design criteria for sampling and analysis systems installed in all Energy
power projects. This section provides specific design criteria for steam cycle sampling, circulating
water sampling, and wastewater sampling.
12.2
Approach
This section is intended to be used as a basis for the design of sampling and analysis systems.
12.2.1
Overview
The function of the sampling and analysis system is to provide a means to monitor the performance
and operation of the steam-condensate-feedwater cycle, to monitor the quality of circulating water
and/or wastewater, and to provide sufficient data to operating personnel for detection of any
deviations from control limits so that corrective action can be taken.
The steam cycle sample panel provides temperature and pressure conditioning and performs
certain automatic analyses of the samples.
The sample conditioning section of the steam cycle sample panel provides the following functions:










Regulation of flow of all samples.
Secondary sample coolers for all samples.
Pressure control and indication for all samples.
Temperature indication for all samples.
Measurement of specific conductance, cation conductivity, degassed cation conductivity,
and pH of selected sample streams.
Control and indication of sample flow rates to each analyzer.
Grab samples for each sample.
High temperature protection of all analyzers by the use of high temperature shutoff valves.
Drainage to waste for all sample streams and discharges from all analyzers.
Demineralized flush water for all analyzers/probes during a plant shutdown or for analyzer
calibration.
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The analyzer section of the steam cycle sample panel provides the following functions:


Contains the analyzers that receive samples from the sample conditioning section of the
steam cycle sample panel. The measurement signals from these analyzers are routed
through the dry section for subsequent transmittal to the distribution control system (DCS).
Sample sequencers, capable of controlling and varying the sequence schedule
independently to each analyzer, may be provided for samples sharing analyzers. No more
than four samples per analyzer, unless requested by client, should be sequenced because of
lag time related to sharing analyzers.
Cooling water for samples is generally provided from the closed cycle cooling water system.
Circulating water sample panels and wastewater sample panels typically include one sampling
location. This sample includes pressure, temperature, and flow indication. Circulating water
samples typically analyze pH, specific conductivity, and chlorine. Wastewater samples typically
analyze pH and chlorine. These are typically provided when requested by the client or required to
monitor discharge points.
12.2.2
System Design
12.2.2.1 Piping and Tubing Design
Sample system piping and tubing should be designed in accordance with the latest edition
(including the latest addenda, interpretations, and cases) of the American Society of Mechanical
Engineers (ASME) Power Piping Code, ASME B31.1, unless specific code and standard dates are
required by the contract. ASME B31.1 lists specific guidelines that should be used when designing
sample system piping and tubing for power stations. This handbook uses ASME B31.1 guidelines
and presents the Black & Veatch (B&V) standard method of design for the various piping and tubing
pressure and temperature conditions normally present in a sample system. ASME B31.1 should
govern if there is a conflict between ASME B31.1 and this handbook.
Tubing is preferred over piping for sample systems, but certain conditions may dictate the use of
pipe. Through-the-plant tubing or pipe should mean any tubing or pipe that is outside the sample
panel boundaries.
For the purposes of this handbook, two distinctions are made with regard to the materials that are
commonly available in the industry. Type 316 stainless steel materials that have a carbon content of
greater than 0.04 percent carbon may be purchased as Type 316 stainless steel with material
certification sheets indicating the minimum carbon content, as materials designated as
Type 316/316H, or as materials designated as Type 316H. Type 316 stainless steel materials that
do not have a guaranteed carbon content may be purchased as Type 316 stainless steel without
certification sheets or Type 316/316L. Type 316L material should not be used for sample tubing.
Distinctions with the same considerations as above are also made for the usage of Type 304
stainless steel materials.
It should be noted that using any material with less than 0.04 percent carbon content at
temperatures above 1,000° F (538° C) will have significantly higher minimum wall thickness
requirements and may not be suitable for some high pressure, high temperature applications.
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These designations should allow greater flexibility in aligning the engineering design with material
availabilities and options for the tubing and piping.
Tubing should be American Society for Testing and Materials (ASTM) A213 with either minimum or
average wall thickness designation. Average wall thickness A213 may be designated with
A213/269 dual stamp, or A213 stated with average wall. Average wall thickness tubing may also be
designated as ASTM A213EAW (Except Average Wall). Average wall thickness A213 is the most
common and readily available tubing. Sample system piping should be ASTM A312.
The material for piping or tubing should be TP304, TP316, TP316/316L, TP316/316H, or TP316H
(U designation is not allowed). The Rockwell Hardness for tubing should be specified as HRB80 or
less. If HRB80 tubing or less is not available, pre-swaging tools may need to be used for proper fitup. If tubing design is based on allowable stress values on the basis of the minimum carbon content
tubing, Certified Material Test Reports (CMTRs) should be obtained for all tubing or piping (unless
the material is TP316/316H or TP316H, which is by definition certified to have a minimum carbon
content above 0.04 percent) to verify that the minimum carbon content has been met. Additionally,
CMTRs should be obtained to confirm that all tubing meets the maximum hardness requirement.
12.2.2.2 Minimum Wall Thickness
A calculation template is included in the reference section for tubing minimum wall thickness that
uses the following guidelines. It is strongly recommended that the calculation template that is
stored on the intranet be used for all sample tubing calculations.
ASME B31.1 provides the following formula for calculating the minimum wall thickness required
for a given pressure, temperature, and tube outside diameter (OD) for straight runs of tubing:
where:
tm = ( P * Do ) / ( 2 * [ SE + P * y ] ) + A [ASME B31.1, Section 104.1.2]
tm
P
Do
SE
y
A
=
=
=
=
Minimum wall thickness, inches,
Internal design pressure, psi,
Outside diameter of tube or pipe, inches,
Maximum allowable stress value for a given
material at a given design temperature, psi (refer
to Table A-3 of ASME B31.1 for values),
= Coefficient having values as given in Table
104.1.2(A) of ASME B31.1. Refer to note (b) of
Table 104.1.2(A) for design temperature of
900° F and below, and
= An additional thickness to allow for material
removed in mechanical operations, such as
threading or grooving or for corrosion-erosion
allowance, inches. The Mechanical Section should
be consulted for A factors used on sample system
piping. The A factor value should be 0 for tubing.
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The resulting tm value does not take into account tube wall thinning when tubing is bent. The
sample tubing calculations required to determine minimum tube wall thicknesses when bending is
employed are complex and require several additional calculations and the application of tube wall
bend thinning factors. While the B31.1 code does identify tube bending thinning allowances to be
applied, they are not the appropriate allowances to be applied for the types of bends that would
normally be made during field installation activities. The standard field bending process is the
“Roary Draw Bending Method.” The wall thickness adjustment factors for this tube bending
method are identified in PFI-ES-24 (Pipe Fabricators Institute, Engineering Standards). The tube
bending factor associated with the tube bends of three tube diameter bends should be used for
tubing calculations associated with this standard, and specifications should state that tube bends
should be made at no less than three tube diameters. If any design indicates a requirement for wall
thicknesses of greater than 0.083 inches (14 GA), contact the chief engineers group. There are
many factors besides the wall thickness identified that must be evaluated. It is very likely that if the
wall thickness requirements require wall thicknesses above 0.083 inches that tube fittings will be
used for all changes in directions rather than tube bending.
Pipe bending is also acceptable for sample piping. The factor for six pipe diameter bends (which is
also from the PFI standard) should be used for piping wall thickness calculations associated with
this handbook.
When nominal or average wall thickness tubing is used as the basis for design, the resulting
minimum wall thickness from the above calculation should be less than or equal to the nominal wall
thickness minus the wall thickness variation allowed by the A213 specification, repeated as follows:

tm ≤ (nominal or average wall thickness) - (A213 wall thickness variation allowance).
The same requirement applies for pipe (A312), which is commonly purchased as nominal wall:

tm ≤ (nominal or average wall thickness) - (A312 wall thickness variation allowance).
12.2.2.3 Sample Panel Components
The recommendations within this section are limited to sample lines within a sample panel.
A high temperature shutoff valve should be installed just upstream of the sample rate set valve for
all samples that have a design temperature above 120° F (49° C) to protect downstream analyzers
in the event of loss of sample cooling water. The shutoff valve must be rated for service at the full
design pressure of the sample line. A device that would alert operators that a thermal shutoff valve
has closed and sample flow has stopped should be considered.
Figure 12-1 shows a typical sketch of a sample line. The tubing sections depicted on Figure 12-1 are
defined in the following subsections.
12.2.2.3.1 Inlet Tubing
Tubing from the sample panel termination point to the sample pressure reducing element for high
energy samples (high temperature and/or pressure, typically downstream of the boiler feed pump)
or rate set valve for low energy samples (intermediate-low temperature and/or pressure, typically
upstream of the boiler feed pump) should be no smaller than 3/8 inch (9.5 mm) OD tubing. This
prevents sample tubing plugging. For high energy samples, confirmation should be provided by the
sample panel supplier that the primary sample cooler meets the design temperature and pressure
requirements.
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The required wall thicknesses for low energy samples in Subsection 12.2.2.2 are extremely small
when calculated by the ASME B31.1 formula. To maintain durability, and at the same time minimize
plugging and material costs, 0.065 inch (1.7 mm) wall thickness tube should be specified for low
energy sample tubing.
Figure 12-1
Typical Sample Line
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12.2.2.3.2 Sample Trunk Line Tubing
Sample trunk line tubing, including the common branch header, from the sample rate set valve for
low energy samples and from the pressure reducing element for high energy samples to the
analyzer branchline tubing should be 0.049 inch (1.2 mm) wall thickness stainless steel tubing.
Normally, 3/8 inch (9.5 mm) OD tubing should be used; however, if the sample pressure drop is
excessive, 1/2 inch (12.7 mm) OD tubing may be used. The 0.049 inch (1.2 mm) wall thickness
provides acceptable durability and at the same time minimizes material costs and friction losses.
Some vendors may propose 1/4 inch (6.4 mm) thinner wall tubing for this application. This may be
acceptable if adequate sample flow and pressure can be maintained. Fluid velocities through the
tube are normally adequate to prevent the settling of suspended solids in the sample lines.
The maximum sample pressure in this portion of the sample line is dependent on the safety relief
valve selection. It is the responsibility of the sample panel supplier to select the proper valve to
handle the worst possible condition that may be encountered, without exceeding the capabilities of
the recommended tubing.
12.2.2.3.3 Analyzer Branchline Tubing
The analyzer branchline tubing extends from the sample trunk line to each analyzer, conductivity
cell, or pH cell that may be required for a sample. The tubing also extends from the analyzer or cell
to the drainline.
Analyzer branchline tubing should be 0.035 inch (0.89 mm) wall thickness tubing. This selection, in
general, will allow adequate analyzer flows, while minimizing friction losses in the tubing. Cases
where required analyzer flows are greater than 500 mL/min or where samples must be piped to
analyzers located in a remote sample panel will probably require modifications to this tubing size
recommendation. When calculating friction losses for tubing between the sample table and the
sample panel (if separate panels are provided), it should be assumed that there will be
approximately 200 feet (60 meters), plus the lineal distance between the panels, of tubing required.
To calculate friction losses for tubing within a sample table, it should be assumed that there would
be approximately 150 feet (45 meters) of tubing run within the table. The resulting pressure drops
may require that 3/8 inch (9.5 mm) tubing with an appropriate wall thickness be used to achieve
acceptably low friction losses.
12.2.2.3.4 Blowdown Tubing
Tubing downstream of the blowdown valve for all samples should be designed in accordance with
the pressure and temperature conditions identified in ASME B31.1, Section 122.2, Blowoff and
Blowdown Piping in Nonboiler External Piping. All blowdown sample lines should be designed for
the highest pressure/temperature sample connected to the panel, unless a separate low-pressure
blowdown header is provided for these low-pressure samples. If a separate low-pressure/low
temperature blowdown header is provided, it should be designed for the highest
pressure/temperature sample that is routed to that header.
12.2.2.3.5 Internal Panel Friction Loss
Figures 2, 3, 4, and 5 from the Swagelok Tube Fitter’s Manual, may be used when calculating
pressure drops through 3/4 inch (19.1 mm), 1/2 inch (12.7 mm), 3/8 inch (9.5 mm), or 1/4 inch
(6.4 mm) OD tubing, respectively, to ensure that the sample panel supplier has properly sized its
tubing.
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12.2.2.3.6 Through-the-Plant Sample Lines
All through-the-plant sample system tubing should be 3/8 inch (9.5 mm), 1/2 inch (12.7 mm), or
3/4 inch (19.1 mm) OD, unless otherwise required by the client.
Through-the-plant tubing should have nominal wall thicknesses of 0.049 inch (1.2 mm), 0.065 inch
(1.7 mm), or 0.083 inch (2.1 mm), depending on the process design conditions (refer to
Subsection 12.2.2.2 for calculation of required wall thickness). If a larger required thickness tubing
is needed, 1/2 inch (12.7 mm) pipe should be considered because material supply of tubing
thicknesses larger than 0.083 inch (2.1 mm) is typically uneconomical and difficult to find. This is
particularly true for 316H or 316 sample lines that are required to meet the minimum 0.04 percent
carbon content.
Frequently, through-the-plant tubing for sample systems is purchased with tubing used by the
Instrumentation and Control (I&C) Section. The I&C Section typically uses 1/2 inch (12.7 mm) OD
tubing with wall thicknesses of 0.049 inch (1.2 mm), 0.063 inch (1.6 mm), or 0.083 inch (2.1 mm).
When the tubing is purchased together, the sizing selections for chemical sample lines should be
coordinated with the I&C Section to ensure that the proper selections are made and to minimize the
overall number of sizes/configurations purchased. Doing so should provide the most economical
approach for tubing management on-site.
Early in the design, the mechanical team should be consulted to determine all factors, including
support and routing, which may affect selection of pipe, tube, and tray materials. The tubing wall
thickness calculations do not routinely incorporate any additional margin to mitigate additional
stresses as a result of routing or supports. In addition, sample lag times should be taken into
consideration. Lag time requirements are dependent on the sample conditions and the type of
analysis to be performed. Normally, sample piping should be designed for lag times of 5 minutes or
less from the process takeoff point to the sample table. It should be noted that sample velocities
resulting from the recommended lag times should be considered. Velocity conditions may require
that lag times be increased or decreased as required to obtain acceptable pressure losses or to
prevent suspended solids from settling.
Sample lines should be routed via the shortest route possible and to avoid traps, dead legs, and dips
upstream of the sample stations. Lines should be sized to maintain turbulent flow with a Reynolds
number greater than 8,000 at the minimum required velocity of 6 feet per second (1.8 m/s) for
each sample line. Sample lines should be routed and supported so that expansion and contraction
caused by thermal conditions will not impose excessive stress on any portion of the routed piping.
The minimum sample purge flow for any line should be 500 mL/min (0.13 gal/min) at 100° F
(38° C).
Heat tracing, insulation, and tray type should be considered when determining the type of tubing to
be purchased. Personnel protection for sample lines may be needed. Insulation or insulation and
heat tracing should be used if the sample lines have the potential to freeze during a plant shutdown
and do not drain to the sample panel. Insulation may also be required if samples exceed the
recommended tray material temperatures (refer to the Technical Paper Series referenced in
Section 12.3). Typically, aluminum tray has been used in previous B&V designs. The tray may
include a blanket of insulation to protect the tray from samples that exceed the tray design
temperature. Anchoring of tubing and/or allowance for expansion and contraction complicates the
tubing selection. Pre-insulated or pre-insulated and heat traced tubing coils may be used to address
the above concerns. The design engineer should work with the mechanical and I&C teams early in
the project to determine the most economical approach before a selection is made.
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When the above recommendations are appropriate, it must be stressed that there needs to be very
close coordination between the chemical design engineer and the mechanical engineer, mechanical
designer, and the I&C engineer. The coordination effort must be initiated at the very early stages of
the project so that chemical input is provided when project decisions regarding tube selections take
place and the chemical requirements can be taken into account. Also, mechanical design
procedures do not include detailed routing of tubing, either for sample line applications or for I&C
applications. As a result, the only method available for sample line routing interface is by a process
where the tubing support trays are routed. This process requires very close coordination between
the chemical engineer and the mechanical designers. It should also be noted that the mechanical
design procedures are documented in the intranet document “2.1 AG Pipe Routing Guidelines.”
(http://communities.bv.com/sites/EnergyChiefEngineers/Manuals/Engr Tech
Handbook/MC/PowerGen/2.1 Above Grade Piping/2.1 AG Pipe Routing Guidelines.doc). The
chemical engineer must be familiar with all details regarding the sample tubing tray that supports
the sample tubing. The complete process from the tubing selection process through ensuring that
all necessary tray detail drawings are shown on all appropriate construction drawings must be
coordinated and reviewed. In addition, the chemical engineer should follow up with construction
activities to ensure that the field installation matches the design.
Blowdown lines should be routed to the plant blowdown tank or a sample panel blowdown tank if
the plant blowdown tank elevation does not allow a free flowing, gravity drain (no water pockets or
“looped” sections) to the blowdown tank. Hot drains from a sample system blowdown tank should
be sealed and designed of materials suitable for 212° F (100° C).
12.2.2.3.7 Sample System Tubing and Piping Specifications
Construction specifications should be developed to require that all tubing materials, fabrication,
erection, and application of materials be in accordance with the latest applicable requirements of
ASME B31.1 and all federal, state, and local regulations, where applicable.
The specifications should require that fittings for the tubing be either socket-welded or Codeapproved flareless type tube fittings. Fittings for tubing with wall thicknesses greater than
0.083 inch (2.1 mm) should be butt-welded or socket-welded fittings. It should be noted that for
high-pressure applications where greater than 0.083 inch (2.1 mm) wall thickness is required, the
fitting rating may not always meet or exceed the rating of the tubing. Individual fitting styles often
have different ratings from each other. The designer should verify that the fitting design and rating
meet or exceed the tubing design for all applicable cases. If flareless type tube fittings are used for
applications exceeding 0.083 inch (2.1 mm) wall thickness, the designer should consult with the
Chief Engineers group (Mechanical and I&C disciplines) to ensure proper fitting selection and
design, and correct materials usage.
The specifications should state that specified tube wall thicknesses are based on three tube
diameter bends. Tube diameter bends less than three are not identified in PFI-ES-24; therefore,
bends tighter than three diameters should not be allowed.
The specification should require that the tubing be routed and supported so that expansion and
contraction of the tubing will not impose any excessive stress on the tubing. In addition, all valves
and components mounted in the tubing should be supported from the sample table or rack to
eliminate superimposed loads on the tubing.
The specifications should also state that any tubing damaged during bending or installation must be
replaced and that all tubing must be hydrostatically tested at 1.5 times the design pressure for a
period of not less than 10 minutes. If any leaks are detected, the joint or connection must be
repaired. No detectable leakage at test conditions should be allowed.
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12.2.3
System Operation
Each sample line should be flushed manually with sample water through the grab sample line. All
analyzers should be isolated during this flush. Sample lines should be flushed for a minimum of
15 minutes at each cold startup to ensure that debris does not foul sample panel components. After
flushing, normal operation includes manual adjustment of sample block valves, adjusting pressure
reduction and backpressure valves to set sample flow and pressure, adjusting closed cycle cooling
water flows to provide required temperature reductions, and adjustment of rate set valves for
analyzers. After setup, the system continuously monitors and transmits analytical data from the
various samples of the steam-condensate-feedwater cycle to the DCS. The process measurements
that are monitored by the steam cycle sampling and analysis system are displayed on the DCS operator stations.
12.2.4
Calculation and Documentation
The following documents and calculations should be prepared and stored in project files:




Sample system piping and instrumentation diagrams (P&IDs).
Sample system pipeline list.
Project sample tubing specification.
Sample tubing wall thickness calculation.

Sample tubing sizing calculation.
12.3
References






Sample lag time calculation.
ASME Power Piping Code, ASME B31.1.
F. J. Callahan, Tube Fitter’s Manual, Swagelok Company, Solon, Ohio, 1998, pp. A7-A10.
ASTM A213 / A213M-15b, Standard Specification for Seamless Ferritic and Austenitic AlloySteel Boiler, Superheater, and Heat-Exchanger Tubes, ASTM International, West
Conshohocken, PA, 2015, www.astm.org.
Cooper B-Line Sales Engineering Technical Paper Series, Cable Tray Use at High
Temperatures - Materials and Selection (found through the Industrial Water Treatment
Community page).
Sample tubing minimum wall thickness calculation (found through the Industrial Water
Treatment Community page).
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13.0 Evaporative Wastewater Treatment
13.1
Purpose and Applicability
This section provides design criteria for evaporative wastewater treatment systems installed in all
Energy power projects.
13.2
Approach
This section is intended to be used as a basis for the design of evaporative wastewater treatment
equipment. It is important to note that evaporative treatment is quite diverse and that this section
should only be considered as a starting point. Additional research on the treatment technologies is
warranted when a project has identified the need to evaporate wastewater.
13.2.1
Overview
Evaporative treatment is the process of evaporating water from a wastewater stream to
concentrate the salts into either a dry solid product or a smaller wastewater volume. Depending on
the evaporative treatment technology, the evaporated water may be recovered and reused within
the facility. Typically, evaporative processes are used to achieve zero liquid discharge (ZLD) at the
facility. Evaporative technologies may be required to meet specific discharge permit requirements
or to provide water recovery in water scarce locations. Depending on the technology, evaporative
treatment may have high capital and operating costs and is typically used for wastewater treatment
only when required.
13.2.2
Evaporative Treatment Technologies
Many different evaporation technologies are currently available, including brine concentrators
(BCs), crystallizers, evaporation ponds, and spray dryers. The type of wastewater will determine
pretreatment requirements for each of the technologies. With the exception of evaporation ponds,
evaporative technologies require power, chemicals, manpower, and maintenance. Project
objectives, costs, operability, pretreatment requirements, wastewater characteristics, and client
preferences should be considered during evaporative technology selection.
13.2.2.1 Brine Concentrator
BC technology refers to the process of partially evaporating water from the waste stream, thereby
concentrating the dissolved solids. There are two primary categories of evaporators used in the
wastewater treatment industry: thin film and forced circulation. Most BCs in operation are thin
film evaporators configured to use a mechanical vapor compression (MVC) vertical tube
evaporation process capable of 90 to 99 percent recovery efficiencies, depending on the feedwater
chemistry. A typical BC flow diagram is shown on Figure 13-1.
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Figure 13-1
Process Flow of Brine Concentrator (courtesy of Power Magazine)
Feed to the BC typically passes through an inlet heat exchanger to bring the feed temperature near
its atmospheric boiling point by recovering heat from the BC distillate. From the heat exchanger,
the feed is deaerated to remove carbon dioxide (CO2) and other noncondensable gases, enters the
bottom portion of the BC, and is mixed with concentrated slurry. The concentrated slurry is
continuously pumped via recirculation pumps to the top of the BC, where it is distributed as a thin
film to the inside wall of a vertical tube heat exchanger. Good distribution of the recirculated
stream is critical to ensure efficient and reliable operation. As the thin film of slurry passes down
the tube, water is evaporated. The remaining slurry is collected at the bottom sump within the BC
and again recirculated via the recirculation pump. The evaporated water is collected, sent to the
vapor compressor to increase its pressure and condensation temperature, and then used as the
heating medium on the shell side of the vertical heat exchanger. The vapor condenses, is pumped
through the inlet heat exchanger, and can then be collected for plant reuse. The recovered water is
a high quality water source that can be reused within the plant.
A portion of the recirculated concentrated slurry stream is removed as blowdown to maintain a
total dissolved solids concentration within the BC, typically around 200,000 to 300,000 parts per
million (ppm). Generally, a BC serves as a volume reduction step because the blowdown stream
cannot be discharged directly; the process requires a final treatment step such as crystallization,
evaporation ponds, or some type of solidification process such as fly ash blending. This process has
a high electrical consumption for the vapor compressor. An estimated power requirement is 80 to
90 kilowatt-hour per kilogallon (kWh/kgal).
An alternative MVC technology is available that utilizes a core containing the recompressed vapor
that is submerged in the brine solution in lieu of a thin film vertical heat exchanger within the BC
vessel. As the recompressed vapor condenses to provide heat to the surrounding brine solution,
the condensed solution is collected as distillate, and vapor from the brine bath is collected and sent
to the vapor compressor. This design is intended to reduce operating costs by simplifying cleaning
and to increase reliability by having the flexibility to remove and replace the submerged cores.
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Pretreatment requirements upstream of the BC depend on the type of wastewater and required
downstream treatment technologies. Generally, only suspending solids removal is required to
prevent the inlet heat exchanger and deaerator from fouling. Few chemical feeds are required
within the BC process. Acid feed is required to the inlet wastewater to remove carbonate hardness
and reduce scaling. Caustic feed may be required for pH control within the BC.
Wastewaters being treated typically contain constituents that will precipitate from solution within
the BC when heated, adhering to the evaporator surface. Antiscalants and/or a seeded slurry
process are used to help reduce scaling. A seeded slurry system utilizes crystals, such as calcium
sulfate, as a precipitation surface for low solubility salts. Although this slurry system can reduce
precipitation on tube walls, scaling cannot be completely eliminated, and periodic cleanings are
required.
13.2.2.2 Crystallizers
A crystallizer evaporates water from a previously concentrated waste stream, further concentrating
the waste to a point where it can be dewatered into a solid product suitable for landfill.
Crystallizers can be driven either by an external steam supply or by a vapor compressor. Because
of the amount of energy required, flexibility to vary heat input, and reliability considerations, steam
is the preferred choice. Electrical energy requirements for a vapor compressor are high,
approximately 250 kWh/kgal. A typical steam driven crystallizer flow diagram is shown on
Figure 13-2.
Figure 13-2
Process Flow of Steam Driven Crystallizer (courtesy of Veolia)
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The brine feed to the crystallizer is sent to the suction of a recirculation pump where it is mixed
with the crystallizer slurry from the crystallizer vapor body. The slurry is continuously recirculated
via the recirculation pump through an external shell and tube heat exchanger. The slurry is
circulated through the tube side of the exchanger, and saturated steam from an external source is
applied to the shell side. The slurry is heated past its atmospheric boiling point temperature, but
kept below the boiling point of the tube side pressure. Once heated, the slurry is fed into the
crystallizer vessel where it flashes. The evaporated water from the crystallizer exits the top of the
vessel, is scrubbed, and either feeds a vapor compressor or is condensed (steam driven crystallizer)
into distillate. The recovered water is a high quality water source that can be reused within the
plant.
The process for an MVC type crystallizer is similar to that described for a steam driven crystallizer,
except that the evaporated water from the crystallizer body is collected and sent to a vapor
compressor, to increase its pressure and condensation temperature, and then used as the heating
medium on the shell side of the external heat exchanger in lieu of a steam supply. The vapor
condenses and is collected for plant reuse. Figure 13-3 shows the flow through an MVC type
crystallizer.
Figure 13-3
Process Flow of MVC Crystallizer (courtesy of Power Magazine)
A portion of the recirculated slurry stream is removed as blowdown to purge solids from the
process. The blowdown stream is sent to a dewatering device such as a centrifuge, belt filter, or
filter press. An antifoam chemical feed is often required to control foaming within the crystallizer.
Additional chemical feeds for pH control may be required depending on the application.
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Because of the high salinity and corrosive nature of the slurry stream within the crystallizer, more
exotic metals are required. Specifying the correct materials is a critical step for ensuring long-term
operation of the system. Materials such Inconel 625, Hastelloy C276, or similar metals are typically
for piping and equipment construction, while titanium is used for the heat exchanger tubes. These
materials lead to higher capital costs compared to those for a BC. Because of these high capital and
energy costs, reducing the volume of wastewater feeding the crystallizer is critical to making this a
viable option. Typical volume reduction steps upstream of the crystallizer include a BC or
membrane concentration.
Depending on the type and makeup of the wastewater stream, additional pretreatment beyond a
volume reduction step can be required. Calcium chloride and magnesium chloride based salts,
typical in flue gas desulfurization (FGD) wastewater, are highly soluble, corresponding to a high
boiling point. The high boiling point makes it difficult to evaporate to a solid state because of
equipment constraints and uneconomical equipment design. Sodium chloride salts have a lower
boiling point and are more suitable for evaporation. Therefore, when calcium chloride and
magnesium chloride based salts are predominate in the wastewater, lime and soda ash softening
upstream is required to convert to sodium chloride based salts. Refer to Section 5.0 for additional
information on softening. This pretreatment requirement adds to both the cost and complexity of
the system.
Crystallizers can be prone to foaming from constituents in the water such as organics. A foam
inhibitor feed should be included in the crystallizer design. Another good practice is to include a
viewing window in the crystallizer vessel. This window can be used to visually confirm foaming, or
a closed circuit camera can be used through this window to monitor foaming from a remote
location.
13.2.2.3 Evaporation Ponds
Evaporation ponds rely on disposal through solar evaporation of wastewater in an open pond,
leaving sludge and a concentrated slurry in the pond. The evaporation rates will need to exceed the
average rainfall for the area to be a feasible treatment solution. Evaporation data for a specific area
can typically be found through state department websites such as the department of agriculture or
the state water board, or through the United States Geological Survey (USGS). Evaporation rates
are presented as either a pan or lake evaporation rate. Pan evaporation rates are usually higher
than evaporation from a body of water; therefore, when sizing evaporation ponds, the lake
evaporation rate should be used. Alternately, pan evaporation rates can be used with an
appropriate adjustment factor.
Additional factors affecting the feasibility of solar evaporation include solids (dissolved and
suspended), land availability, and environmental regulations. The solids content of the wastewater
impacts pond sizing through sludge accumulation and by reduced evaporation rates with increasing
pond salinity. Pond life needs to be taken into account during the design phase. In addition, ponds
will typically require freeboard space, a double liner, and a leak detection system. Environmental
regulations specific to the project need to be reviewed to ensure that the design meets all
requirements.
Estimated evaporation pond sizes can be determined using the Evaporation Pond Calculations
(found through the Industrial Water Treatment Community) by inputting the aforementioned
design factors. Typically, evaporation ponds are sized based on annual average wastewater
production.
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13.2.2.4 Spray Dryers
Spray dryer technology refers to the process of fully evaporating water from the waste stream,
leaving only dry salt crystals. The evaporated water from this process is not recovered. The salts
formed are removed in a solids removal device such as a baghouse or electrostatic precipitator
(ESP). Spray dryer technology has been used for many years, particularly in the power industry for
FGD or to make specific products for resale. The spray dryer technology discussed within this
section is specific to wastewater treatment applications. Spray dryers are getting significant
interest for treating FGD wastewater because of the spray dryer’s ability to produce a solid crystal
product from the high solid, highly corrosive wastewater without the extensive pretreatment salt
conversion step discussed in Subsection 13.2.2.2, all while only requiring carbon steel for the vessel
materials.
The spray dryer technology is a relatively simple process. A hot, unsaturated gas stream is used as
the heat source to evaporate the wastewater. This can be either a high temperature gas produced
by fuel gas combustion or, at a coal fired power plant, the flue gas itself. When using the flue gas, a
slipstream is taken downstream of the boiler and selective catalytic reduction system (if installed).
Collected wastewater is pumped into the spray dryer vessel as a mist. The wastewater is
evaporated by the hot gas to produce a humidified gas stream. The atomizers and vessels are
designed so that before the mist droplets reach the wall of the vessel, the hot gas source evaporates
the droplets to a dry waste. The solid waste formed remains suspended in the humidified gas
stream. When using flue gas, the humidified flue gas stream is returned downstream of the air
preheater. Figure 13-4 shows a simplified process flow diagram of a spray dryer treating FGD
wastewater utilizing the flue gas stream.
Figure 13-4
Process Flow Diagram of Spray Dryer Treating Flue Gas Desulfurization Wastewater
The dried solids formed in the gas stream are collected and removed in the existing particulate
removal system (baghouse or ESP). When designing a spray dryer system, the additional solids
loading from the wastewater, along with the impact to fly ash quality, needs to be evaluated. Spray
dryers can be provided with a separate baghouse; however, because of the additional pressure
drop, a booster fan will be required to return the flue gas slip stream to the main flue gas duct.
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This process has a low electrical demand that is limited to atomizers and any feed pumps. One
important point to consider is that, because some of the flue gas is bypassing the air preheater,
there is an impact to the heat rate that needs to be evaluated. Depending on the volume of
wastewater being evaporated, this can range from 0.5 to 1 percent. When using a slip stream of flue
gas for heating, the volume of wastewater that can be processed is limited. The flue gas
temperature upstream and downstream of the air preheater, the pressure drop across the air
preheater, and the volume of flue gas need to be considered to determine this limit.
When spray dryers are installed at coal plants, the spray dryers should be located near the flue gas
train to minimize ducting and pressure drop. When spray dryers are installed at locations with
multiple units, the relative location of the units will help determine whether a common spray dryer
can be used. If a common spray dryer is being installed with the intention of operating on multiple
units, isolation dampers will be required so that flue gas from multiple units is not being mixed,
which would likely violate permit requirements.
Since atomizers are designed to handle slurry applications, pretreatment of the wastewater is not
required. Chemical feeds are also not required within the spray dryer process.
13.2.3
Conceptual Design
When possible, a complete water chemistry evaluation should be done on the wastewater.
Historical wastewater quality data should be used to establish an appropriate design water quality
range. Wastewater quality data are critical information for designing an evaporative wastewater
treatment system; wastewater quality affects pretreatment requirements, equipment sizing, and
equipment materials. If the system is being designed for a new plant and wastewater quality data
are not available, a complete water chemistry evaluation should be performed on raw water along
with establishing system operating limits for the plant (i.e., cooling tower operating limits) to
determine accurate wastewater quality. Establishing these limits will help to properly specify flow
rates, pump sizing, chemical applications, sump/tank capacities, and required metallurgy. When
sizing the system it is important to account for all plant operating scenarios such as one unit
off-line, startup, shutdown, cycling operation, etc. Downtime of the evaporative treatment system
for maintenance cleaning also needs to be taken into account.
It is important to establish a commissioning plan, including testing criteria for major equipment
when designing evaporative treatment systems. During the commissioning phase, testing of
evaporative treatment systems can be challenging if the plant is not yet operational and
representative wastewater is not yet available. This can lead to commissioning the system and
passing any performance guarantees on a lower total dissolved solids water, which would mask any
difficulties the system may have when in full operation.
For the evaporative treatment systems dealing with a corrosive brine solution, it is critical to
choose high quality materials during the design phase. In addition to corrosion resistance, the
materials also need to be able to handle the high temperature environment.
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13.3
References

T. Cannon, V. Como, and M. Mueller, Operating a ZLD – What Does it Take?, 74th Annual
International Water Conference, 2013.



Aquatech, Zero Liquid Discharge: Drivers, Concepts & Technology Trends in Brine
Concentrate Management, June 2013.
William A. Shaw, “Benefits of Evaporating FGD Purge Water,” Power Magazine, HDR Inc.,
March 2008.
Veolia, Water Reuse and ZLD Technologies for the Power Generation Industry – HPD
Evaporation and Crystallization, May 2014.
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14.0 Seawater Desalination
14.1
Purpose and Applicability
This section provides design criteria for seawater desalination systems installed in all Energy
power projects.
14.2
Approach
This section is intended to be used as a basis for the design of seawater desalination equipment.
14.2.1
Overview
Seawater desalination can be utilized to produce water for industrial or potable water use.
Although desalination is fairly rare on power generation projects, the industry trend is toward
greater utilization of this technology because of fresh water supply issues in various geographical
areas. The installation of a desalination system is almost exclusively triggered by client
requirements because of the high installation and operating costs associated with desalination.
Typically, a groundwater or surface water supply would be utilized in lieu of seawater desalination
because of economic reasons.
Desalination systems consume a large amount of power and, therefore, are often paired with a
power generation facility even if a large percentage of the water is exported off-site. Several
different desalination technologies have distinct advantages and disadvantages that must be
carefully considered. Metallurgical selection is critical to the design of a desalination system
because of the corrosive nature of the high dissolved solids seawater. Permitting limitations
associated with the systems have the potential to significantly impact the desalination system
design and must be understood.
14.2.2
Seawater Quality
Seawater typically has a salinity of approximately 35,000 mg/kg (3.5 percent). Variability in the
salinity from 3.2 percent to 4.0 percent is due to dilution by fresh water from rivers, evaporation,
freezing, and thawing. Salinity maps are available that show the typical salinity levels for different
areas. Table 14-1 shows the major dissolved solids species for seawater at 3.5 percent salinity. At
different salinity levels, the ratios of the dissolved solids stay nearly the same, which implies that
water dilution and evaporation effects are the most critical with respect to estimating the seawater
quality.
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Table 14-1
Typical Seawater Quality at 3.5 Percent Salinity
CONSTITUENT
CONCENTRATION (PPM AS SUCH)
Chloride, Cl
19,400
Sulfate, SO4
2,700
Sodium, Na
10,800
Magnesium, Mg
1,290
Calcium, Ca
411
Potassium, K
392
Bicarbonate, HCO3
145
Bromide, Br
67
Borate, BO3
27
Fluoride
13
Strontium, Sr
8
Silica, SiO2
6
The specific gravity of 3.5 percent salinity seawater is 1.0255 at 60° F (16° C). The specific gravity
increases with higher salinity and lower temperatures.
The pH of seawater is typically between 7.9 and 8.2. Coastal seawater typically has higher
variations with the pH being as low as 7.3 inside deep estuaries or as high as 8.6 in productive
coastal plankton blooms or 9.5 in tide pools.
14.2.3
Desalination Technology
Many different desalination technologies are currently available, including reverse osmosis,
mechanical vapor compression, thermoscompression, multiple effect distillation, and multi-stage
flash (MSF). Owner preferences, along with project objectives and limitations, should be
considered during desalination technology selection.
14.2.3.1 Reverse Osmosis
Reverse osmosis (RO) technology reduces dissolved solids from seawater by utilizing a
semipermeable membrane. The membrane has a high permeability to water and a low
permeability to dissolved solids. The seawater is pumped to a high pressure and fed to the
membranes. Approximately 35 to 40 percent of the water passes through the membrane and is
collected as product water. The remainder of the water is concentrated and rejected as a brine
stream.
Figure 14-1 shows a flow diagram of a desalination system that utilizes RO technology for potable
water production. Although the RO membranes are the core portion of the technology, proper
pretreatment and posttreatment are essential features. RO membranes are intolerant to suspended
solids and oxidizers (e.g., chlorine). Scaling and biological fouling of the membranes can also be
problematic and should be mitigated by proper pretreatment. The treated water from the RO
system is often too pure for drinking purposes, which requires remineralization by either blending
or chemical addition.
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Figure 14-1
Reverse Osmosis Based Desalination Flow Diagram
When compared to brackish water reverse osmosis (BWRO) systems, seawater reverse osmosis
(SWRO) systems cannot achieve as high of a recovery rate because of a higher level of dissolved
solids in the RO feedwater. BWRO systems can typically achieve 75 to 80 percent recovery rates
while SWRO recovery rates are typically less than 50 percent for a single-stage system and less than
60 percent for a two-stage system. Furthermore, the RO booster pump pressure is significantly
higher for a SWRO application when compared to BWRO because of the higher osmotic pressure of
the RO feedwater.
RO membranes used for desalination are typically 8 inch or 16 inch diameter seawater thin film
composite spiral wound membranes. One supplier, Koch, also makes an 18 inch diameter
membrane. The larger diameter membranes significantly reduce the number of membrane
housings and associated piping, which reduces the cost of larger systems. RO membrane flux rates
are generally lower for SWRO (8 to 10 gal/ft2/day) when compared to BWRO (<14 gal/ft2/day)
because of capital and operating cost factors that are primarily driven by the differences in the
osmotic pressure of the feedwater.
Unlike smaller RO systems that are utilized to produce demineralized water for a power generation
facility, the larger flows associated with a desalination system make the use of an energy recovery
device more feasible. The energy recovery device increases the pressure of the RO feedwater by
decreasing the pressure of the RO reject water. Although this device adds some complexity and
capital cost, the energy savings are typically much greater for a large desalination system.
RO membranes are not very effective at removing boron from seawater, which can make meeting
drinking water boron limits challenging. Membrane manufacturers may have options available to
improve the boron removal rate that should be considered.
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RO is the lowest capital and operating cost desalination technology available. It is preferred for
small scale and decentralized installations. Disadvantages are that it requires extensive
pretreatment to prevent fouling, is sensitive to water chemistry upsets, and may have poor
reliability if operated improperly.
14.2.3.2 Electrodialysis Reversal
Electrodialysis is an electrochemical process where ions are transferred through ion exchange
membranes that are driven by electrical potential maintained through the application of direct
current (dc) voltage. The removal of ions is achieved by placing a series of alternative cation and
anion transfer membranes as shown in Figure 14-2.
Figure 14-2
Electrodialysis Schematic
Electrodialysis reversal (EDR) is similar to electrodialysis except that the polarity is reversed
periodically to clean the membrane. When the polarity is reversed, the demineralized water and
concentrate outlets are reversed requiring automatic valves to switch the destination of the two
streams. Refer to Figure 14-3 for a schematic of this process.
Figure 14-3
Electrodialysis Reversal Schematic
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EDR is typically suitable for treating streams that have less than 2,000 parts per million (ppm) of
total dissolved solids (TDS). Seawater typically has much higher TDS and, therefore, may not be
practical for this technology.
EDR has an advantage over RO when silica is limiting the recovery of an RO. EDR does not remove
silica and, therefore, silica precipitation is not a concern. EDR also does not remove uncharged
species, including particles, pathogens, and weakly charged organics.
EDR requires approximately 2 kilowatt-hours per thousand gallons (kWh/kgal) of energy to
remove 1,000 milligrams per liter (mg/L) of salt.
14.2.3.3 Mechanical Vapor Compression
Mechanical vapor compression (MVC) typically utilizes a falling film evaporator or spray dryer to
evaporate a portion of the seawater. The water vapor is compressed and returned to the
evaporator or dryer where it is condensed to produce the distillate product. The condensation of
the water vapor provides heat for continued evaporation of the seawater.
This technology features high electrical consumption for the vapor compressor. The technology is
used extensively for small preengineered installations and in marine applications but is not
economical for large installation.
14.2.3.4 Thermal Vapor Compression
Thermal vapor compression (TVC) is similar to MVC in that a falling film evaporator or a spray
dryer is typically used. However, a steam jet ejector is used as the driving force of the process in
lieu of a mechanical compressor. A substantial amount of medium-pressure steam is required to
operate the ejector. Unlike MVC, multiple effects (stages in series with a pressure reduction from
stage to stage) are required to achieve reasonable efficiencies.
This technology features high steam consumption and has limitations on the capacity of individual
modules.
14.2.3.5 Multiple Effect Distillation
Multiple effect distillation (MED) utilizes multiple effect evaporators. Low-pressure steam is
supplied to the first effect to vaporize a portion of the seawater feed. The water evaporated from
the previous effect is condensed in the next effect to form distillate water and vaporize an
additional portion of the seawater. The vapor from the final effect is condensed in a heat exchanger
to preheat the incoming seawater. Refer to Figure 14-4 for a flow diagram of an MED system.
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Figure 14-4
Multiple Effect Distillation Desalination Flow Diagram
MED technology is slightly lower in capital and operating cost than MSF evaporation. This
technology features smaller nominal unit size availability compared to the MSF technology,
resulting in many more units that complicate maintenance and operations.
14.2.3.6 Multi-Stage Flash
MSF technology utilizes a series of flash chambers. The seawater is heated by steam in the brine
heater. The heated seawater is fed into the first flash chamber where a small portion of the water
vaporizes. The water vapor is then condensed and collected as distillate water. The seawater
leaves the first flash chamber at a lower temperature and higher salinity than when it entered.
Therefore, the pressure of the second flash chamber is reduced compared to the first chamber so
that the lower temperature higher salinity brine will flash when it enters the second stage. The
pressure is reduced from chamber to chamber, which results in progressive partial vaporization of
the seawater in each chamber. Figure 14-5 shows a simplified flow diagram for a typical MSF
system.
Figure 14-5
Multi-Stage Flash Desalination Flow Diagram
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The MSF process requires a heating source to partially vaporize the seawater and a cooling source
to condense the vapor as distillate. The heat source is steam that heats the seawater prior to
entering the first flash chamber. Theoretically any cooling medium that is moderately cooler than
the water vapor could be used to condense the vapor. The most economical choice for a cooling
medium is to use the relatively cool seawater feed to the MSF prior to heating it in the brine heater.
The first advantage of this approach is that less steam is required in the brine heater because the
seawater is heated by condensing water vapor in the flash chambers. The second advantage is that
an additional cooling system (e.g., cooling tower, refrigeration) is not required.
The cooling requirements of the MSF are typically not met fully by the seawater flow that
eventually feeds the first flash chamber. Therefore, additional cooling water is used in the rejection
section of the MSF. The additional cooling water provided supplements the cooling capacity of the
MSF but is discharged back to the sea rather than entering the brine heater. A flash chamber in the
reject section utilizes this additional cooling water while the flash chambers in the recovery section
do not.
The seawater that is flashing flows countercurrent to the flow of the seawater that is used for
cooling. The coldest seawater (from the seawater intake structure) is fed to the last chamber (the
lowest temperature chamber). This configuration is similar to that of a countercurrent heat
exchanger where the coldest shell side fluid is in contact with the coldest tube side fluid.
The available modular size for the MSF technology is significantly greater than other technologies
resulting in fewer modules, The MSF process unit is configured as either a cross tube (X-tube) or a
long tube (L-tube) design. The flow of the seawater used for cooling (inside of the tubes) is
perpendicular to the flow of the seawater that is being partially evaporated (outside of the tubes) in
the X-tube configuration. The flow of the seawater used for cooling is parallel (but in the opposite
direction) to the seawater that is being partially evaporated in the L-tube configuration.
The L-tube configuration can be advantageous over the X-tube configuration because of the reduced
number of water boxes and associated piping and valves that are required. The L-tube design
requires only two water boxes, whereas the X-tube design requires two water boxes for every
stage. The reduction in water boxes typically results in a significant reduction in capital cost.
14.2.4
Materials of Construction
Seawater is corrosive because of its high salinity. Typically, either high grade metals or nonmetallic
components are required. Table 14-2 gives an indication of typical material of construction
requirements for an MSF unit. SWRO provides a distinct advantage when compared to other
technologies because large metallic equipment is not needed. Careful consideration must be given
to the material selection for all systems, especially those that utilize large metallic equipment
components. Furthermore, the volatility of material pricing should always be carefully considered
for projects because the material prices could dominate the economics of the project.
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Table 14-2
Typical Materials of Construction for a Multi-Stage Flash Unit
COMPONENT
MATERIALS
Tubing
Reject section
Recovery section
Brine heater
Water boxes
Rejection section
Recovery section
Tube support plates
Brine heater
Rejection section
Recovery section
Brine heater
Piping
Pressure < 100 pounds per
square inch gauge (psig)
Pressure > 100 psig
Condenser section
Walls, floors
Tube support plates
Pumps
Recycle, makeup, and blowdown
2.
70/30 copper-nickel
Temperatures to 180° F (82° C), 90/10 copper-nickel
Temperatures above 180° F (82° C), 70/30 copper-nickel
70/30 copper-nickel
Plastic material
CS clad with 90/10 copper-nickel for large diameter piping and
316L stainless steel (SS) for small diameter piping
CS clad with 316L SS
70/30 and 90/10 copper-nickel
Bronze
Monel
Casings
Impellers/shafts
316 SS
316 SS
References
1.
Carbon steel (CS) clad with 70/30 copper-nickel
Temperatures to 180° F (82° C), CS clad with 90/10 coppernickel
Temperatures above 180° F (82° C), CS clad with 70/30 coppernickel
Casings
Impellers/shafts
Distillate and condensate
14.3
70/30 copper-nickel
Temperatures to 180° F (82° C), 90/10 copper-nickel
Temperatures above 180° F (82° C), 70/30 copper-nickel
70/30 copper-nickel
J. F. Anthoni, “The Chemical Composition of Seawater,” 2006,
<http://www.seafriends.org.nz/oceano/seawater.htm>.
V. Veerapaneni, “Desalination,” presented to Black & Veatch Water College,
February 20, 2008, <http://communities.bv.com/sites/LearningLibrary/Water
Treatment/6. Desalination (Veerapaneni)/Desalination.ppt>.
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15.0 Heavy Metals Reduction
15.1
Purpose and Applicability
This section provides design criteria for heavy metals reduction systems installed in all Energy
power projects.
15.2
Approach
This section is intended to be used as a basis for the design of systems utilized to reduce the
concentration of heavy metals. It is important to note that the nature and treatment for the various
heavy metals is quite diverse and that this section be considered as a starting point. Additional
research on the treatment technologies is warranted when a project has identified the need to treat
for a particular heavy metal.
15.2.1
Overview
Aluminum (Al), antimony (Sb), arsenic (As), barium (Ba), cadmium (Cd), chromium (Cr), cobalt
(Co), copper (Cu), iron (Fe), lead (Pb), manganese (Mn), mercury (Hg), molybdenum (Mo), nickel
(Ni), selenium (Se), silver (Ag), thallium (Tl), vanadium (V), and zinc (Zn) constitute the more
common heavy metals of concern for power plant water and wastewater streams. These elements
most commonly occur as positively charged cations in solution, but some of them, most notably
selenium, can combine with oxygen, sulfur, or other compounds and exist as negatively charged
anions. Heavy metals can also form complexes with organic and inorganic substances. Even at low
concentrations, heavy metals can be problematic to equipment performance, discharge limits, and
drinking water requirements.
15.2.2
Sources of Heavy Metals
Heavy metals exist in most raw water sources but, in most cases, at concentrations lower than what
may impact water treatment equipment or water treatment users. Some of the more common
sources of raw water heavy metals concerns are as follows:



Iron. Ferrous iron (Fe2+) is water soluble and can be removed by softeners or can often be
handled by using dispersants as part of the reverse osmosis (RO) feed. Ferric iron (Fe3+) is
not water soluble and can cause fouling in an RO system. Ferrous iron will convert to ferric
iron in the presence of air.
Manganese. Similar to iron, manganese is soluble in oxygen free water. It becomes
insoluble in an oxidized state and usually exists as a black manganese dioxide (MnO2)
precipitant. Manganese can lead to fouling in an RO system, and at lower levels can be
controlled with dispersants.
Strontium. Strontium can be found in some well waters and can cause strontium sulfate
precipitation in an RO system.
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Heavy metals can also be introduced or concentrated in a power plant as follows:









15.2.3
Chemical addition, such as aluminum-based and iron-based coagulants, can introduce heavy
metals into a system. The coagulants typically precipitate out as metal hydroxides and are
captured and removed by a clarifier and solids dewatering equipment. However, a small
residual quantity of the heavy metal may exist after coagulant dosage, and gross
overfeeding of coagulant may result in higher heavy metal concentrations.
Evaporative cooling in a cooling tower will cycle up the feedwater concentration of all
constituents, including heavy metals. This is potentially problematic where there is not
much of a difference in the heavy metals concentration of the source water when compared
to the discharge destination limitations.
Although once-through cooling does not concentrate the constituents in the water supply,
there may be circumstances where the limits on the discharge are as strict or even stricter
than those in the raw water supply. This issue is not easily resolvable because of the high
flowrates associated with once-through cooling leading to prohibitively high water
treatment costs.
Treated sewage plant effluent, or other recycled water supplies, may have heavy metals
concentration at higher levels than what is typical for a raw water source.
Runoff from coal, ash, or gypsum piles will have a tendency to leach heavy metals into the
rainwater that falls on them. The water may need to be treated to remove certain heavy
metals prior to discharge or reuse.
Water used for ash sluicing will leach out some heavy metals from the ash and may require
treatment prior to discharge or reuse.
A portion of the heavy metals in the coal supply will eventually work its way into the flue
gas desulfurization (FGD) wastewater stream. The regulatory trend is to require specific
treatment of FGD wastewater for heavy metals prior to discharge or combination with other
wastewater streams.
Boiler chemical cleaning wastewater can contain significant amounts of heavy metals. Most
notably, the chromium content of the wastewater often determines if it is considered a
hazardous waste. In most cases the chemical cleaning wastewater is disposed of off-site.
Other metal cleaning activities, including rinsing, could generate wastewaters that may
require treatment or disposal.
Alternate fuel supplies, such as biofuels, oils, and supplemental fuels (i.e., waste
incineration), may introduce additional heavy metals into the system that may subsequently
introduce heavy metals into the wastewater.
Estimating Heavy Metals Concentration Prior to Treatment
Although having a good set of analytical data or good predictions of heavy metal concentrations is
extremely useful for determining the need for treatment, this information is typically not available
and is not easily estimated. Design analysis data should be obtained from currently operated
systems, if available, or obtained directly from the client. In other cases it may be possible to obtain
analysis data from the Original Equipment Manufacturer (OEM) that has or will supply equipment
that will generate wastewater.
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A secondary source of data will be to gather and use similar data from other similar projects or
industry reports. Some of these data can be found in the sources listed in the references section.
Care must be taken to consider these data to be indicative instead of predictive since there are
many factors (e.g., coal supply, water supply, power plant design/operation) that will cause the
actual heavy metal concentrations to deviate from the referenced values. This is especially true on
international projects since much of the similar data that are available are based on domestic
power plants with domestic coal supplies. It is highly advisable to work closely with the client and
OEMs concerning the use of indicative data to establish appropriate margins and/or adjustments to
the data. Contract guarantees based on indicative data can be problematic since it is likely that the
actual data will vary from the indicative data.
15.3
Heavy Metals Treatment Methods
Heavy metals can be reduced by many different treatment methods. The following subsections
highlight some of the more common treatment methods.
15.3.1.1 Hydroxide Precipitation
Either sodium hydroxide or lime is added to elevate the pH and hydroxide content of the
wastewater stream. The heavy metals combine with the free hydroxides to form insoluble heavy
metal hydroxides.
Many of the heavy metals are amphoteric in that they can react with both bases and acids. For
example, zinc oxide can react in the presence of an acid or a base to form various compounds as
follows:
In acid: ZnO + 2H+ → Zn2+ + H2O
In base: ZnO + H2O + 2 OH− → [Zn(OH)4]2−
The amphoteric nature of many of the heavy metals results in their solubility reaching a minimum
at a specific pH (refer to Figure 15-1); therefore, a specific pH should be targeted to increase the
removal of a specific heavy metal. If the removal of multiple heavy metals is desired, a pH has to be
selected to optimize the removal of all of the heavy metals in question or multiple process steps
with varying pH levels should be considered.
Consideration should also be given to softening and calcium sulfate precipitation that will occur
along with the heavy metals reduction that will increase reagent utilization and solid waste
generation/characterization.
Prior to the precipitation of heavy metals such as hydroxides, complexing agents that can keep the
heavy metals in solution must be removed. Most notably, cyanide salts form strong complexes with
heavy metals and typically must be removed by way of oxidation with chlorine under alkaline
conditions.
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Figure 15-1
Solubility of Metal Hydroxides and Metal Sulfides as a Function of pH
15.3.1.2 Sulfide Precipitation
Metal sulfides are very insoluble even when compared to metal hydroxides (refer to Figure 15-1).
Sulfides can be introduced into the wastewater stream from hydrogen sulfide, sulfide salts, or
organosulfides. Organosulfides are specialty chemicals that are organic in nature but have sulfide
groups on the organic molecules. Because of the difficulty in handling hydrogen sulfide and sulfide
salts, organosulfides are typically a better alternative.
Sulfide salts undergo hydrolysis as follows:
S-2 + H2O <---> HS- + OH-
HS- + H2O <---> H2S + OH-
A very high pH of around 14 is required to force the equilibrium to S-2, resulting in sulfide
precipitation. H2S can also be generated if an alkaline pH is not maintained. Sulfide precipitation is
rather insensitive to the presence of chelating agents. Sulfide solids tend to form colloidal particles
requiring the use of coagulants to increase the particle size to aid in settling. Although sulfide solids
are typically easier to dewater than hydroxide solids, sulfide solids are more prone to oxidation and
subsequent resolubilization.
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Because of the difficulties associated with handling and using sulfide salts and hydrogen sulfide,
organosulfides have gained popularity to the extent that a design utilizing a sulfide other than an
organosulfide would be unusual. Organosulfides utilize an organic backbone with sulfide functional
sites to capture heavy metals. Dugussa TMT, Nalmet 1689, and Nalmet 8072 products are examples
of the more common organosulfides. Organosulfides tend to remove heavy metals in a preferred
order, so the dosage may or may not be impacted by the other heavy metals that are in the
wastewater. For example, NALMET 1689 removal preference is
Hg>Ag>Cd>Cu>Pb>Zn=Ni>Co+2>Fe+2>Mn+2. It is important to note that organosulfides are specialty
chemicals and may or may not need supplemental polymer addition to aid in coagulation. The
chemical supplier should be contacted directly to determine appropriate dosage requirements,
heavy metal reduction capabilities, and any limitations on the system design (e.g., clarifier rise
rate).
15.3.1.3 Carbonate Precipitation
Some metals, such as cadmium, lead, and nickel, can form insoluble precipitants with carbonates.
Caustic and/or soda ash can be used to elevate the pH and levels of carbonate to the point where
precipitation will occur. It is likely that some metals will also precipitate out as hydroxides when
the pH level is increased. Carbonate precipitants tend to settle and dewater better than
corresponding hydroxide precipitants.
15.3.1.4 Coprecipitation
Iron or aluminum salts can be added to form a precipitated floc where heavy metals can
coprecipitate. Coprecipitation is effective at reducing the concentration of many heavy metals but
typically not down to very low levels.
15.3.1.5 Biological Treatment
Biological systems, such as the GE ABMet®, utilize microbes to reduce soluble contaminants to
insoluble precipitants. The systems typically consist of a series of bioreactors where the microbes
are attached to a fixed media. Nutrients such as molasses are used to supplement the wastewater
to allow for the efficient removal of heavy metals to low levels. Sludge is removed from the
bioreactors once every several months and is typically returned to a pretreatment solids removal
system as opposed to having a dedicated solids dewatering system. Biological treatment systems
are becoming more common on the back end of FGD wastewater physical/chemical treatment
systems to remove heavy metals down to fairly low limits. It is also important to note that
biological systems will also remove nitrates that will need to be considered as part of the design.
Other unique design considerations, such as influent temperature limitations, must also be factored
into the design.
15.3.1.6 Ion Exchange
Although there are specialty ion exchange resins designed to target specific heavy metals, this type
of treatment has not gained much market share for power plant wastewater streams. The need to
regenerate or dispose of the exhausted resin can cause difficulty or be cost-prohibitive. The resin
may also remove other constituents that were not targeted for treatment. Furthermore,
wastewater quality can vary and often presents difficulties relating to resin fouling.
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15.3.1.7 Reverse Osmosis
With appropriate pretreatment, RO can be utilized to reduce the volume and subsequently
concentrate a wastewater stream. An RO system will generate a lower volume waste stream that
must typically be treated further. In some cases, an RO system is a more economical choice for
volume reduction in front of a crystallizer when compared to a brine concentrator; however, there
are typically many constituents in a wastewater stream that could be problematic to an RO system
if not properly handled by way of pretreatment.
Forward osmosis is an emerging technology that may be promising for some wastewater streams.
A forward osmosis system consists of a forward osmosis loop and an RO loop. A highly saline water
loop passes through the RO loop where water is extracted from the saline water stream. The
concentrated saline water stream from the RO loop is then sent to the forward osmosis loop where
it extracts water from the wastewater stream. The wastewater stream is only in direct contact with
the low-pressure forward osmosis membranes, and therefore, fouling issues are mitigated.
15.3.1.8 Zero Liquid Discharge
Heavy metals will be removed from a wastewater stream as part of a zero liquid discharge
configuration. These systems typically include a brine concentrator or RO system for volume
reduction followed by a crystallizer (refer to Figure 15-2). These systems are fairly expensive from
a capital and operating cost perspective and are typically considered a last resort option if other
treatment methods are available. These systems typically require a large amount of power to drive
the brine concentrator vapor compressors or RO booster pumps. They also typically require some
auxiliary steam to drive the crystallizer.
In some cases a flue gas spray dryer may be an alternative to a crystallizer-based system. The
wastewater is sprayed into the flue gas, which then evaporates the water and forms dry crystals
that are removed in the downstream baghouse or electrostatic precipitator. Although a spray dryer
does not require steam and only requires a small amount of power, it does impact the net plant heat
rate significantly and must be installed as part of the boiler flue gas system instead of installing the
spray dryer remotely.
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Figure 15-2
Process Flow Diagram of Brine Concentrator and Crystallizer
15.3.1.9 Constructed Wetlands
A wetlands system can be established that preferentially absorbs heavy metals in the vegetation.
Constructed wetlands require a considerable amount of site footprint, and their performance may
be difficult to predict and control. Because of the current regulatory environment, it is fairly
unlikely that constructed wetlands will be a feasible treatment option for the majority of, or
perhaps all, power generation projects.
15.3.1.10 Solidification/Stabilization
Solidifying/stabilizing a wastewater stream can be accomplished by blending it with a solid to form
a solid waste product that can be sent to a landfill. Although this approach has not been widely
used in the power generation industry, it does show promise especially in cases where there is a
low volume waste that would otherwise require extensive treatment such as thermal evaporation.
It may be possible to utilize the fly ash at the site with some additives to solidify and stabilize a
waste stream.
15.3.1.11 Metal Complexation
It is important to note than many transition metals (Cd, Co, Cu, Fe, Hg, Ni, Zn) can form complexes
with different ligands such as chlorides, cyanides, hydroxides, sulfides, and EDTA
(ethylenediaminetetraacetic acid). These complexes increase the solubility of the heavy metals and
must be broken up. This is often accomplished by using an oxidant such as chlorine, sodium
hypochlorite, or ozone.
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15.3.1.12 Disposable Sorbent Media
Disposable sorbent media are available and may be a viable option for a temporary or permanent
heavy metals removal system. The media can be placed in vessels to be used until exhaustion
where the media is removed and replaced. In some cases it may be practical to add sorbent media
directly to a wastewater pond and allow the spent media to settle on the bottom of the pond
without removal. The use of sorbent media will likely not be economical in cases where the
wastewater flow rate is high or the heavy metals concentration reduction is significant. Sorbent
media may also remove heavy metals that are not required to be removed, thus accelerating the
usage rate of the sorbent. Disposable sorbent media can be used to remove most of the different
heavy metals species.
15.3.2
Heavy Metal Characteristics
Each heavy metal has characteristics that should be understood to design a system with optimal
removal efficiency. The following subsections highlight the unique characteristics of each heavy
metal.
15.3.2.1 Aluminum (Al)
Aluminum salts are frequently used as coagulants in water treatment processes. Insoluble
aluminum hydroxide is formed leaving only a small residual of dissolved aluminum that is typically
around 0.05 parts per million (ppm). Further reduction of aluminum is possible by the use of ion
exchange resins.
15.3.2.2 Antimony (Sb)
Iron coprecipitation at a pH between 4.5 and 5.5 is most efficient at removing antimony. Some
antimony removal is obtained over a wider pH range of 4.0 to 10.0. Sb3+ is more easily removed
than Sb5+, with Sb5+ removal efficiencies as high as 98 percent being possible with an optimal pH.
Approximately 30 to 60 percent removal of Sb3+ and 80 percent removal of Sb5+ can be achieved
with RO. Antimony can also be removed with selective ion exchange resin.
Biological processes can also be utilized to reduce antimony to low levels.
15.3.2.3 Arsenic (As)
Arsenic typically occurs as arsenite (AsO43- where arsenic exists as As+3) or arsenate (AsO33- where
arsenic exists as As+5). Arsenite may need to be oxidized to arsenate prior to removal by using an
oxidant such as chlorine, potassium permanganate, ozone, or hydrogen peroxide.
Arsenic can typically be reduced down to 0.05 ppm with the use of sodium sulfide or hydrogen
sulfide. Arsenic can also be reduced down to 0.005 ppm by coprecipitation with ferric chloride.
Manganese greensand filters are also effective at removing arsenic.
Strong base anion exchange resins can be used to achieve up to 95 percent arsenate removal;
however, arsenate acts in a similar fashion to a sulfate anion, and therefore, ion exchange can be
inefficient since other common ions may be removed as well. The regeneration wastes from an
anion exchange process may also pose a disposal problem because of the corrosivity and high levels
of arsenic. Arsenite removal is often achieved by oxidation to arsenate prior to the ion exchange
process.
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RO and nanofiltration can provide arsenic removal efficiencies of 95 percent and 90 percent,
respectively. The disadvantage of these technologies is the low recovery rates resulting in large RO
reject or nanofiltration reject, which must be handled.
Biological processes are also capable of removing As+3 and As+5 to low levels as arsenic sulfide.
Disposable media such as Bayoxide® E33 can also be utilized to remove As+3 and As+5 down to low
levels.
15.3.2.4 Barium (Ba)
Barium can be removed by adding a sulfate source since the solubility of barium sulfate is 1.4 ppm.
The barium concentration can be reduced to concentrations of around 0.5 ppm if excess sulfate ions
are present. Lime softening with ferric sulfate coagulation is also effective at removing barium. Ion
exchange can also be used to remove barium to low levels.
15.3.2.5 Cadmium (Cd)
Cadmium can be removed as a hydroxide precipitant to 1 ppm (pH 8) or 0.05 ppm (pH 11).
Cadmium levels can be reduced to around 0.008 ppm by utilizing coprecipitation with ferric
chloride at a pH of 6.5. Sulfide precipitation can reduce cadmium levels down to 0.05 ppm.
Cadmium can form insoluble precipitants with carbonates at a pH of 7.5 to 8.5 with removal levels
similar to hydroxide precipitation. The presence of cyanides interferes with these removal process
and therefore, cyanide must be removed as part of pretreatment.
Biological processes can also be utilized to remove cadmium to low levels.
15.3.2.6 Chromium (Cr)
Chromium speciation is fairly complex and should be investigated as part of any treatment
program. Hexavalent chromium (Cr+6) is typically reduced to trivalent chromium (Cr+3) by using
ferrous sulfate, sodium bisulfite, or sulfur dioxide; low pH (<3). Cr+3 is then removed as Cr(OH)3 by
precipitation with lime at a pH of 7.5. An effluent chromium level of 0.2 ppm can be achieved.
Biological processes can also be utilized to reduce chromium to low levels.
15.3.2.7 Cobalt (Co)
Cobalt concerns are more common at nuclear power plants because of the production of Cobalt-60
as a byproduct of typical nuclear power plant operation. Cobalt-60 is radioactive and is typically
removed by using ion exchange resins.
Cobalt is rarely of prime concern with regard to non-nuclear power plant wastewater streams.
Technologies that are effective at removing other heavy metals may also be effective at removing
cobalt.
Biological processes can also be utilized to reduce cobalt to low levels.
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15.3.2.8 Copper (Cu)
Copper can be removed as cupric oxide (solubility of 0.01 ppm as cupric oxide) with hydroxide
precipitation at a pH of 9 to 10.3. Copper can also be removed to 0.01 to 0.02 ppm (as Cu) by
precipitation as a sulfide at a pH of 8.5. Cyanide and ammonia may interfere with the precipitation
processes. Copper cyanide can be removed by utilizing activated carbon.
Black & Veatch was involved in the design of the Appalachian Power Company – Clinch River Plant
copper reduction process (refer to Figure 15-3 and the References section). The process utilized
iron coprecipitation by feeding ferrous sulfate and caustic to precipitate out ferrous hydroxide at a
pH of 8.0 to 8.5. At this pH range, copper would coprecipitate out with the ferrous hydroxide. Air is
added prior to the solids removal to convert the ferrous hydroxide to ferric hydroxide.
Figure 15-3
Clinch River Plant Copper Reduction Process
Sulfides and biological processes can also be utilized to remove copper to low levels.
15.3.2.9 Iron (Fe)
Iron exists as either ferrous (Fe+2) iron or ferric (Fe+3). Ferrous iron is soluble in water at any pH;
ferric iron forms an insoluble orange/yellow precipitant when the pH is higher than 3.5. Ferric iron
can be removed by filtration; ferrous iron requires conversion to ferric iron by using an oxidizing
agent prior to filtration. Ferrous iron can be removed by utilizing ion exchange; ferric iron cannot.
Greensand filters are also effective at removing iron and manganese. Potassium permanganate
produces manganese dioxide on the surface of the greensand, which readily oxidizes iron and
manganese to form insoluble precipitants that are then filtered out.
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15.3.2.10 Lead (Pb)
Lime can be used at a pH of 11.5 to remove lead as a hydroxide down to a concentration of 0.02 to
0.2 ppm. Lead can also be removed as a carbonate at a pH between 7.5 to 8.5, with similar
reduction levels as obtained with hydroxide precipitation. Lead can also be removed by sulfide
precipitation at a pH of 7.5 to 8.5 or iron coprecipitation at a pH of 8.0 to 8.5.
15.3.2.11 Manganese (Mn)
Manganese can oxidize in many states but is most commonly oxidized as Mn+2. Oxidation of Mn+2
yields Mn+4, which is insoluble and will precipitate as MnO2.
Greensand filters are also effective at removing manganese. Potassium permanganate produces
manganese dioxide on the surface of the greensand, which readily oxidizes iron and manganese to
form insoluble precipitants that are then filtered out.
15.3.2.12 Mercury (Hg)
Mercury removal in plant wastewater streams, including FGD wastewater, is becoming more
important because of the very low levels of mercury allowed in the treated wastewater in many
cases. The allowed amount of mercury in the treated wastewater can be in the parts per trillion
range, which can be difficult to detect and even more difficult to treat. Special care should be taken
to select a treatment program that can consistently reduce mercury concentrations to acceptable
limits.
Mercury can be removed with the use of sodium sulfide or hydrogen sulfide at near neutral pH.
Precipitation efficiency declines significantly at a pH above 9. Because of handling issues, it is far
more likely that organic sulfides would be utilized to remove mercury when compared to inorganic
sulfides.
Mercury can also be removed by coprecipitation with alum or ferric chloride but typically not to
levels as low as when a sulfide is used. Filtration following precipitation may be utilized to facilitate
mercury removal to low levels. Disposable media, including activated carbon, can be effective at
removing mercury.
Mercury can also be removed to low levels by utilizing a biological process.
The use of ion exchange for mercury removal has been historically limited to anion resins used to
treat industrial wastewater that contains inorganic mercury in the complex mercuric chloride form.
The chloride content of the wastewater must be high such as found in wastewater streams
generated from chlor-alkali plants. Cation exchange of mercury may be effective if the anion
content of the wastewater is low. Specialized resins may have an affinity toward mercury removal
when compared to other constituents.
15.3.2.13 Molybdenum (Mo)
Molybdenum can be present in many oxidative states, including -2, 0, +1, +2, +3, +4, +5, and +6.
Molybdenum removal techniques often include adding a reducing agent at a low pH to modify the
molybdenum into a more suitable valence state for downstream iron coprecipitation or sulfide
precipitation.
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15.3.2.14 Nickel (Ni)
Nickel can be removed to 0.12 ppm with precipitation as a hydroxide at a pH of 10 to 11. Nickel can
also be removed by precipitation as a sulfate or carbonate. Cyanide may interfere with nickel
precipitation and may need to be removed in pretreatment.
Biological processes can also be utilized to reduce nickel to low levels.
15.3.2.15 Selenium (Se)
Selenium removal in plant wastewater streams, such as FGD wastewater, has recently become more
common because of proposed changes in the effluent guidelines. Selenium is more difficult to treat
because of its many oxidation states that result in selenium acting more like an anion. The more
common oxidation states are as follows:
Se(VI)
SeO42-
Selenate
Se(O)
Se0
Elemental selenium
Se(IV)
Se(-II)
SeO32HSe-
Selenite
Selenide
Selenium may also combine with sulfur or organic molecules to form other species; however,
selenate and selenite are the most common forms found in plant wastewater streams.
Biological processes such as the ABMet and Envirogen systems have recently become more
prevalent to remove selenium. These processes can remove selenium down to the parts per trillion
levels required by the new Effluent Limitation Guidelines (ELG) limits. The regulatory trend is, to
some extent, preventing other treatment methods from being considered in most cases because of
the low level treatment limits that are required. Selenium is difficult to treat for because of the
speciation as an anion. The biological systems tend to remove selenium fairly well, but
temperature limits and nitrate/nitrite removal must be considered. In most cases, pretreatment
prior to the biological process is needed to remove suspended solids. In some cases, it may be
prudent to design for the future addition of a biological system to a wastewater treatment system
that may not currently require a biological system.
Iron coprecipitation at a pH range of 4 to 6 is effective at removing a portion of selenium from
wastewater streams but typically not down to low levels. Iron coprecipitation will remove selenite
but not selenate. A two-step reduction oxidation process can be incorporated into a coprecipitation
process to remove both selenite and selenate under reducing conditions at a pH of 8 to 9.
15.3.2.16 Silver (Ag)
Hydroxide and carbonate precipitation of silver is often ineffective at reducing silver to discharge
limits. Silver concentrations can be reduced to 0.1 ppm using phosphate precipitation and even
lower using sulfide precipitation. Silver removal can also be achieved by ion exchange or by
utilizing a media filter in a reducing environment.
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15.3.2.17 Thallium (Tl)
Thallium ionizes mainly as Tl+1 and is fairly soluble as a hydroxide in water. Although thallium can
be removed by iron coprecipitation, most of the adsorption type data is based on thallium
adsorption on manganese dioxide. Tl+1 becomes oxidized to Tl2O3 when it precipitates on
manganese dioxide. Ion exchange can also be used to remove thallium.
15.3.2.18 Vanadium (V)
Common oxidation states of Vanadium are V+2, V+3, V+4 (as VO2+), and V+5 (as VO3- or VO2+).
Vanadium can be precipitated with the use of lime, caustic, sulfide, or, to a lesser extent, soda ash.
Ferric sulfate can be used to remove vanadium as a ferric metavanadate. Vanadium can also be
removed by the use of selective ion exchange.
15.3.2.19 Zinc (Zn)
By far the most common oxidation state of zinc is Zn+2, while zinc may also ionize as Zn+1. Zinc can
be precipitated as a hydroxide or sulfide. Zinc can also be removed by utilizing iron coprecipitation.
Biological processes can also be utilized to reduce zinc to low levels.
15.4
References

Armenante, P. M., Precipitation of Heavy Metals from Wastewaters, New Jersey Institute of
Technology, 1997.






Electric Power Research Institute (EPRI), Flue Gas Desulfurization (FGD) Wastewater
Characterization, December 2006.
Environmental Protection Agency (EPA), Steam Electric Power Generating Point Source
Category: Final Detailed Study Report, EPA 821-R-09-008, October 2009.
C. H. Fritz, L. R. Latta, and J. F. Saunders, Appalachian Power Company Clinch River Plant –
Copper Reduction by the Iron Coprecipitation Process, 55th Annual International Water
Conference, 1994.
EPA, Treatment Technologies for Mercury in Soil, Waste, and Water, August, 2007.
Iron and Manganese Removal, National Drinking Water Clearinghouse Tech Brief,
September, 1998.
T. Sandy and C. DiSante, Review of Available Technologies for the Removal of Selenium from
Water, Prepared for the National American Metals Council, June, 2010.
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16.0 Laboratory Design
16.1
Purpose and Applicability
This section provides design criteria for laboratory facilities and provides recommendations, as
well as specific criteria, for system design.
16.2
Approach
This section is intended to be used as a basis for the design of laboratory facilities.
16.2.1
General Design Considerations
Laboratory facilities are used in electric generation stations to perform the necessary analytical
requirements to support the plant. At a minimum, the laboratory will include space and utility
stub-outs to support startup and performance testing.
The type of laboratory depends on the generating station and the scope of the prime contract with
the owner. It is recommended to discuss requirements early in the project to determine scope; in
some instances, only space allocation and suggested arrangement is required.
16.2.1.1 Location
Laboratories should be capable of a low noise level (less than 80 dBA), be located in an area in
which vibration requirements for all analytical equipment can easily be met, and be aesthetically
pleasing yet functional. Laboratories contain fragile, expensive equipment and chemicals;
therefore, they should be considered as areas secured from general traffic. Flow traffic should flow
past the laboratory rather than through. Laboratories should be well ventilated and conditioned.
The lab should be under positive pressure with respect to the surrounding areas and air from the
lab area should not be recycled. Fume hood ventilation should be considered when choosing a
room location.
16.2.1.2 Walls, Ceiling, and Soffits
The walls in the laboratory should be constructed of fire retardant materials. It is good practice to
use 8 inch block construction for the walls without using furring strips and wallboard covering. A
viable alternative to block construction is dry wall over stud. Wall materials and finishes should be
coordinated with the Architectural Section.
The ceiling should use flame retardant suspended acoustical panels. It is recommended to use an
8 foot ceiling height.
Soffits should be constructed above all wall cabinets and closed-top water quality control panels to
prevent the accumulation of dust. Accumulated dust can create a fire hazard and can contaminate
samples in the laboratory.
The Fire Protection Section should review the laboratory for compliance to applicable codes.
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16.2.1.3 Flooring
The flooring surface for the laboratory should be acid and alkali resistant and also resistant to
skids, even when wet. Vinyl composition tile flooring is frequently used because it is economical
and chemical resistant. Quarry tile or coated concrete are other flooring options.
16.2.1.4 Cabinets
Cabinets should be of metal construction with a suitable chemical resistant coating. An example of
a common specification for the base and wall cabinets is sheet metal construction of bonderized
carbon steel. The finish should be two coats of baked enamel, which is resistant to acids, alkalis,
and solvents.
Base cabinet worktops should be impregnated stone or solid resin construction. Worktops should
have all exposed edges and vertical corners rounded on a 1/4 inch radius. They should include a
4 inch high integral backsplash on all perimeter areas.
Wall cabinets should be installed between 15 to 18 inches above the base cabinet worktop.
Cabinets should be provided with a sliding glass door front. Cabinet glass should be clear double
strength “A” quality.
All hardware should be anodized cast aluminum with satin polish finish or chromium-plated steel.
Base molding should be of polyvinyl chloride (PVC) construction.
16.2.1.5 Arrangement
The laboratory arrangement should maximize storage space. The lab should include, at a minimum:
a fume hood, sink, desk with chair, base cabinets, upper cabinets, and a full height wall cabinet. The
base cabinets should contain several different configurations of drawers and doors. In general, a
mix of 60 percent drawers and 40 percent doors is ideal. When selecting base configurations pay
special attention to the surrounding equipment. For example, long deep drawers should be used in
areas where major instrumentation will be located. Kewaunee is a manufacturer of laboratory
furniture and its catalog can be referenced for cabinet sizing, etc., for development of laboratory
layouts.
Blank wall spaces should be included to accommodate equipment that would extend higher than
the bottom of the wall storage units. A typical lab arrangement would include approximately 7 feet
of blank wall space.
When possible, the laboratory should have two exits, and the doors should swing outward unless
the swing would impede hallway traffic. Doorways that dead-end are not acceptable. Local code
requirements should be reviewed and followed.
For laboratory equipment that may be deeper than the standard 22 inches allowed on a wall
mounted cabinet, a center island should be furnished.
Pegboard units should be installed close to the sink to allow glassware to dry.
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Any laboratory that could possibly have corrosive fumes should have a fume hood with PVC lined
exhaust ductwork. A fume hood should be provided for every 300 square feet of laboratory floor
space, not to exceed two hoods in one room. If possible, the fume hood should not be located next
to a door and should be placed at one end or the other of a line of cabinetry. It is recommended to
locate the fume hood on an outside wall or other location that would allow for proper venting.
Fume hoods extend approximately 6 inches beyond the normal working surface. Figure 16-1
shows a typical fume hood. The fume hood will often set on top of a base cabinet that matches the
laboratory cabinetry. When the fume hood assembly comes as one piece, it may be too large to fit
through a normal sized doorway. Special provisions should be made in the construction sequence
to place the fume hood in the laboratory. The Electrical project engineer should be advised that
motor starters will be required for each supply and exhaust fan associated with the fume hood. The
switch on the fume hood should start both the supply and exhaust fans simultaneously.
Figure 16-1
Fume Hood
Air, water, and drain piping should be routed behind cabinetry rather than through a wall. The
laboratory layout should allow 6 inches behind base cabinets for routing of these services. Refer to
Subsection 16.2.1.6 for more details.
A detailed laboratory arrangement drawing should be prepared including plan and elevation views.
Refer to Figure 16-2 for a sample Water Chemistry Laboratory arrangement drawing. The
arrangement drawing should show the location of the faucets, safety shower/eye wash, fume hood,
compressed air/vacuum/gas fixtures (if there are any), and electrical receptacles. The CAD files for
typical laboratory furniture and example lab layouts can be found through the Industrial Water
Treatment Community under the Laboratory Layout and Design section.
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Figure 16-2
Example Lab Arrangement Drawing
16.2.1.6 Utilities
Location of utilities should be considered when laying out the cabinetry. On projects where the
only requirement is to provide a space for the laboratory, stub-outs for potable water, natural gas,
air, and drains are to be provided. Projects that include the entire laboratory should have
demineralized water and a vacuum provided. Utilities for air, vacuum, and propane/natural gas
should be provided for every 10 to 12 foot length of worktop in the lab, when required. In labs
where a vacuum is provided, a switch or push button that starts and stops the vacuum pump should
be located in a central location. The lab arrangement drawing should indicate the location of the
vacuum pump switch and receptacle. The vacuum pump should be located in a storage room or
closet to reduce the noise in the working area. Combined cycle projects should use a benchtop
vacuum pump rather than a permanent pump.
All sinks should be tin lined and trapped, and include a hot and cold water mixing faucet, except in
the fume hood. The hot and cold potable water service and demineralized water piping should be
completely isolated with backflow preventers.
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A wall mount type deionizer should be provided when demineralized water is required. The sink
should have a separate faucet for demineralized water. The deionizer should manually discharge to
an overhead water storage tank. This will provide water to all demineralized water faucets in the
laboratory.
Regulated power supply receptacles should be provided, as needed, in addition to the normal
(unregulated) power receptacles. Unregulated power receptacles are normally placed every 5 feet
along all walls within the laboratory. It is recommended that the electrical receptacles be double
duplex design when cabinet or wall mounted.
16.2.1.7 Safety Equipment
Safety considerations within the laboratory should include, but not be limited to, the following:
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Safety showers and eyewashes.
Multiple exits based on life safety review (refer to the Egress Procedure).
Safety equipment and protective clothing storage.
Flammable liquid storage.
Acid storage.
Emergency ventilation.
Electrical switches, outlets, and lighting fixtures (hazardous area classification in
accordance with the Hazardous Area Classification for Electrical Equipment Procedure).
Backflow prevention.
Compressed gas storage and use.
Safety Showers and Eyewashes
Free-standing combination safety shower and eyewash units should be provided and should be
located within 10 feet of unimpeded travel distance from any corrosive material hazard. Safety
showers are typically located near the fume hood. All safety showers should comply with ANSI
Z358.1 and use potable water. A floor drain should be located directly below each safety shower
and be sized for the maximum flow. Safety showers and eyewashes can be purchased with the
laboratory equipment; however, it is recommended to purchase all of the plant safety
showers/eyewashes with a separate procurement.
Storage
If a flammable liquid storage cabinet is required, it should be separately vented to the outdoors and
have a door with a fusible latch. The cabinets are usually colored red with yellow labels. Any acid
storage cabinets should be PVC lined and vented through the fume hood exhaust system.
Flammable and acid storage cabinets are often used as the base unit for the fume hood.
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16.2.2
Laboratory Types
There are four main types of laboratories: Water Chemistry, Coal Analysis, Coal Sample
Preparation, and Scrubber Testing. The type of laboratory required depends on the type of
generating station and the prime contract with the owner.
16.2.2.1 Water Chemistry Laboratory
The Water Chemistry Laboratory is the most common and includes major analytical
instrumentation for raw water, pretreatment water, cycle water, cycle makeup water, bulk
chemicals, cooling water, wastewater, and fuel oil. The specific equipment will depend on the type
of testing required by the plant. The room should be no less than 300 square feet of floor space and
should include, at a minimum, one auxiliary air fume hood, deionizer, sink, desk, and storage. The
lab area may include the water sampling and analysis panel.
This is the only laboratory typically needed in an engineering, procurement, and construction (EPC)
combined cycle project. The lab is normally located in the Steam Turbine Building, Water
Treatment Building, or other centrally located building.
Special Considerations
Several pieces of instrumentation and equipment should be included in the lab design if required by
the prime contract. These items include the following:
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Biochemical oxygen demand (BOD) incubator.
Refrigerator.
Atomic absorption spectrophotometer (AAS) or an inductively coupled plasma (ICP)
spectrophotometer.
Ion chromatography unit.
Gas chromatograph.
Ultraviolet-visible spectrophotometer.
Centrifuge.
Muffle furnace.
Glassware washer.
Some of this equipment requires 120 volt ac power and some requires 240 volt. Equipment
placement should be considered when locating electrical receptacles. The glassware washer and
refrigerator will normally be installed underneath the laboratory worktop. An electrical receptacle
should be provided underneath the counter in the plumbing space.
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16.2.2.2 Coal Analysis Laboratory
The Coal Analysis Laboratory is used for coal and coal ash. This lab is typically located adjacent to
the Water Chemistry Laboratory. The purpose of the Coal Analysis Laboratory is to contain the
major instrumentation that is associated with coal analysis. The lab is typically no less than
200 square feet of floor space and includes, at a minimum, one auxiliary air fume hood and a sink.
Special Considerations
Several pieces of instrumentation and equipment should be included in the lab design if required by
the prime contract. These items include the following:
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Moisture oven.
Calorimeter (may require water hookup).
Sulfur analyzer with small exhaust hood.
Balance.
Ash fusion furnace.
Ashing furnace.
Carbon-Hydrogen-Nitrogen (CHN) analyzer.
Wall mounted deionizer (if not located near the Water Chemistry Laboratory).
If analyzing fuel oil, the following equipment may be required:
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Flash point apparatus.
Viscosimeter.
Centrifuge.
Infrared spectrophotometer.
Gas chromatograph.
Coking furnace.
Some of this equipment requires 120 volt ac power and some requires 240 volt. The moisture oven
will require a 480 volt power supply. Equipment placement should be considered when locating
electrical receptacles. All electrical switches, outlets, and lighting fixtures should be dust-tight. A
center island with a flat top may be required due to larger pieces of equipment.
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16.2.2.3 Coal Sample Preparation Room
The Coal Sample Preparation Room contains the equipment required for size reduction, gradation,
and preliminary moisture determinations obtained from the coal samples. The room is located
near the Coal Dumper Building, Coal Crusher Building, or the Coal Transfer Building, and is typically
200 square feet. An enclosed storage space may be required to handle approximately 3 to 6 months
of bulk samples. The storage space should be located adjacent to the preparation room and is
typically 60 to 80 square feet.
Special Considerations
Several pieces of instrumentation and equipment should be included in the lab design if required by
the prime contract. These items include the following:
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Hammer mill.
Large sieve screen device.
Platform scale and ball mill.
Deep tub cleanup sink.
Central vacuum system hookup (or industrial grade vacuum).
Any floor mounted equipment should have 2 foot clearance on three sides. Some of this equipment
requires 120 volt ac power and some requires 240 volt. The hammer mill typically requires a
480 volt, three-phase power supply. Equipment placement should be considered when locating
electrical receptacles.
All electrical switches, outlets, and lighting fixtures should be dust-tight. The heating, ventilating,
and air conditioning (HVAC) system should be designed for total exhaust because of all the dust
generated. The design should include a way to remove the dust before exhausting to the outside.
Specific state code requirements should be checked early in the design process. Safety inspectors in
some states have required explosion-proof fixtures or that the Coal Sample Preparation Room be a
separate structure.
16.2.2.4 Scrubber Test Station
The Scrubber Test Station provides analysis for scrubber solids, scrubber waters, and scrubber
additives to monitor, control, and troubleshoot the flue gas scrubber system. The room is located in
the Scrubber Building and is typically no less than 250 square feet of floor space. It usually includes
a compressed air and vacuum source, fume hood for hydrochloric acid use, and wall mounted
deionizer (if not located near the Water Chemistry Laboratory).
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Special Considerations
Several pieces of instrumentation and equipment should be included in the lab design if required by
the prime contract. These items include the following:
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Oven.
Muffle furnace (requires special HVAC consideration).
Crusher.
Spectrophotometer.
Fume hood .
Some of this equipment requires 120 volt ac power and some requires 240 volt. The crusher
typically requires a 480 volt, three-phase power supply. Equipment placement should be
considered when locating electrical receptacles.
16.2.3
Design Coordination
Detailed Design
At the beginning of the project, an overall plan should be developed and agreed to by the owner
before detailed design. The overall plan should consider the type of testing that will be performed
by the owner and what equipment will be needed. This dictates the type of laboratories that will be
required. The purchase of the laboratory furniture is typically through a separate laboratory
furniture specification, with installation as part of the general construction specification.
Piping
Hot and cold potable water, compressed air, and vacuum service piping should be copper. Pipe
sizing for vacuum service should be the minimum diameter possible to reduce the required
drawdown time in the system. The vacuum pump will evacuate approximately 20 to 40 gallons per
minute (gpm) down to the required vacuum of 4 x 10-6 inches of mercury absolute (“HgA).
Demineralized water piping should be Type 304 or 316 stainless steel and a minimum of 1/2 inch.
Stainless steel tubing may be used in lieu of piping. No PVC or copper alloy should be used for
demineralized water piping.
If propane is required, the storage should be located outdoors, and the piping system should be
coordinated with the rest of the design. The fire marshal should review the storage tank location.
Natural gas should be used in place of propane whenever possible due to safety considerations.
If acetylene is required, the storage should be located as close to the atomic absorption
spectrophotometer as possible. Materials should be steel and wrought iron. Unalloyed copper,
silver, or mercury should not be used in the piping system.
Flammable storage cabinet vent piping should be carbon steel. The piping should continue to the
roof line, with bug screens and weather protection provided.
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Floor Drains and Bell-Ups
Floor drains and bell-ups should be located as required for all sinks, fume hoods, safety
shower/eyewash station, and demineralizer. Depending on the use of the laboratory, the drains
should be routed to the chemical wastewater drainage system or the sanitary system. Traps should
be provided on all sinks, drains, and bell-ups. If a glassware washer is provided, it should have a
dedicated bell-up. If a demineralized water storage tank is provided, the overflow line should go
straight to a floor drain.
Heating, Ventilating, and Air Conditioning
The HVAC design will require heat loads for the lab and any major analytical equipment located in
the room. The fume hood type and exhaust fans will also be required. It is recommended to use Vbelt driven, forward inclined blades for the exhaust fans. The exhaust fan should be able to produce
at least a 100 foot per minute airflow across the entire face when the sash is open. The fan should
be remotely located to reduce the noise level in the laboratory. The switch located on the fume
hood should start the auxiliary air supply fan and the hood exhaust fan. Fume hood discharge vents
must be separated from the plant ventilation system due to potentially corrosive air.
A snorkel or elephant trunk type ventilation hood is required if the laboratory includes an atomic
absorption spectrophotometer, an inductively coupled plasma spectrophotometer, a muffle
furnace, sulfur analyzer, or a gas chromatograph. If a snorkel or elephant trunk type hood is used, it
should have sufficient face velocity and be of sufficient size to completely capture vapors emitted at
a distance of 2 inches or less from the snorkel opening.
Lighting
A reflected ceiling lighting plan should be created based on the laboratory arrangement drawing.
The lighting plan should be checked for interferences with soffits, fume hoods, and fume ductwork.
Lighting in the Coal Sample Preparation Room, Coal Analysis Laboratory, or Scrubber Test Station
area should be dust-tight. The need for emergency lighting should be discussed during the design
process.
Power Supply
The Electrical group should be advised of which of the following voltage sources are required for
each laboratory:
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480 volts ac, three-phase.
240 volts ac, three-phase.
240 volts ac, single-phase.
120 volts ac, nonregulated power supply.
120 volts ac, regulated power supply.
No more than three receptacles should be allowed per 120 volt circuit because of the high
amperage demand of the laboratory equipment.
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If a demineralizer is provided, the electrical receptacle should be located close to the point of
installation. Laboratory demineralizers typically only have a 3 foot pigtail power cord.
16.3
References
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Occupational Safety and Health Administration, 29 Code of Federal Regulations, 2000
Edition, Sections 1910.35-38, 94, 95, 101-106, 111, 120, 133, 134, 141, 145, 151, 157, 307,
1000, 1200, 1450.
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National Fire Protection Association, National Fire Codes, NFPA 45, Latest Edition.
International Conference of Building Officials (ICBO), Building Officials and Code
Administrators International (BOCA), and Southern Building Code Congress International
(SBCCI).
W. R. Ferguson, Practical Laboratory Planning, Wiley, New York, 1973.
Manufacturing Chemists’ Association, Guide for Safety in the Chemical Laboratory, Second
Edition, Van Nostrand Reinhold Company, New York, 1972.
National Research Council, Prudent Practices for Handling Hazardous Chemicals in
Laboratories, National Academy Press, Washington, D.C., 1981.
National Fire Protection Association, National Fire Codes, NFPA 101, Latest Edition.
Egress Procedure.
Hazardous Area Classification for Electrical Equipment Procedure.
ANSI Z358.1-2009, American National Standard for Emergency Eyewash and Shower
Equipment.
Laboratory Layout and Design section of the Industrial Water Treatment Community page.
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17.0 Safety Showers and Eyewashes
17.1
Purpose and Applicability
This section provides design criteria for Safety Showers and Eyewashes (SS/EW) and provides
recommendations as well as specific criteria for system design.
17.2
Approach
The Black & Veatch Safety Shower/Eyewash System Design white paper summarizes US standards
that dictate SS/EW requirements and provides Black & Veatch’s recommendations on where
SS/EW are to be placed and the type required to comply with these standards. The white paper
should be reviewed at the start of every project and used in conjunction with this handbook section.
17.2.1
Overview
SS/EW are required throughout facilities where there is a possible exposure for any employee to
come in contact with a corrosive or hazardous material. Quantity and locations should be discussed
with the other disciplines early in the project. SS/EW should be supplied with potable quality
water, however, the equipment and accessories do not have to comply with NSF-61 unless defined
otherwise by the contract/client requirements.
SS/EW are purchased through a system integrator and not directly from a Supplier. The package
can be a stand-alone contract or purchased as part of the mechanical construction package.
17.2.2
Safety Shower Design
SS/EW assemblies should be designed as combination units in accordance with ANSI Z358.1. The
SS/EW should be located within 10 seconds of the identified hazard or approximately 55 feet. The
SS/EW station should be located on the same level as the hazard and the path of travel should be
free of obstructions. The area should be well lit and identified with a highly visible sign. The
combination unit should be capable of operating simultaneously and should be positioned so that
both the safety shower and eyewash may be used simultaneously by the same user.
The drench showerhead should be constructed of plastic and located 82 to 96 inches above the
surface of the floor. It should be tested to deliver a minimum of 20 gallons per minute (gpm). The
apparatus should be designed so that the flushing flow remains on without the use of the operator’s
hands. The eyewash portion should be designed to deliver a controlled flow to both eyes
simultaneously at a velocity low enough to not cause injury. The flow path of the water should be
33 to 53 inches from the floor and a minimum of 6 inches from the wall. The eyewash should be
designed to remain operating without the use of the operator’s hands. A strainer should be installed
on the waterline to prevent any debris from reaching the eyewash.
The waterline and valves should be constructed of materials that will not corrode when exposed to
water for long periods of time. Materials that are considered acceptable for the purpose of SS/EW
stations include brass, galvanized steel, and many types of plastic (ABS, nylon, etc.). For maximum
durability, epoxy-coated galvanized steel, epoxy-coated brass, stainless steel, and polyvinyl chloride
(PVC) should be considered.
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SS/EW stations can be located inside or outside. All showers should include alarms and flow
switches. If the SS/EW water is supplied by a tempering skid loop or instantaneous heater, a scald
protection valve should be provided. Outdoor SS/EW should be freeze protected and heat traced,
including an anti-freeze valve. These features are typically optional and do not come standard on
the SS/EW.
An all-weather, fully-enclosed SS/EW booth can be considered in extremely cold climates where a
SS/EW cannot be located inside a building. The booth allows the user to enter a climate controlled
area before activating the SS/EW. In remote, cold climate locations where water supply is not
available, a SS/EW enclosure with overhead water storage tank can be considered. Water in the
storage tank is heated with an immersion heater and ready for use to supply the SS/EW. Periodic
chemical treatment is required for disinfection of the stored water. These systems are expensive
and should only be used when it is not feasible to use an instantaneous heater or include the SS/EW
on the continuous tempering skid loop.
In the case of temporary hazard exposure, eyewash only or temporary units may be used.
17.2.2.1 Safety Shower Flow Switch
All SS/EW assemblies should be supplied with a flow switch and terminal block for power and flow
switch connections. The flow switch should allow flow through the anti-freeze and anti-scald valve
without annunciations and alarm. A proximity switch can be used to avoid anti-scald and antifreeze valves from activating the flow switch. The specification must clearly state which contract
will be supplying and installing the flow switch.
17.2.3
Tempered Water Design
Water delivered by the SS/EW should be tepid with temperatures between 60° F and 100° F. Two
common methods are used to produce tepid water: a circulating continuous loop with a tempered
water skid or an instantaneous heater located as close as possible to the shower. Unless there are
client-specific requirements, the default design basis is two SS/EW stations operating
simultaneously for the design of heaters and/or tepid water loops.
17.2.3.1 Continuous Loop
A continuous loop is implemented where there is a high number of showers in the system. A
tempering skid is used to produce tepid water and consists of a water heater, storage tank, mixing
valve, and recirculation pump. Depending on the number of safety showers and their locations,
multiple tempering skids/loops may be required. Continuous loops are a designed system requiring
calculations by the responsible engineer or the tempering skid supplier.
Hot water is generated by an immersion heater and stored in a storage tank located on the
tempering skid. Hot water from the storage tank and cold potable water are mixed on skid to
provide tepid water. To maintain the correct temperature during periods when the showers are
not in use, a recirculation pump moves water through the SS/EW loop. Each tempering skid should
include high temperature shutoff or dump valves. Heat losses throughout the recirculation loop
should be considered when sizing the heater.
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Tempering skids should have the capacity to provide tepid water at 30 to 90 pounds per square
inch gauge (psig) for two 23 gpm SS/EW for 15 minutes unless defined otherwise by the
contract/client requirements. The potable water supply pressure must be enough to overcome the
pressure loss through the skid and the SS/EW loop. A potable water booster pump may be
required.
Figure 17-1 shows an example of the tempering skid piping and instrumentation diagram.
Figure 17-1
Tempering Skid Piping and Instrumentation Diagram
17.2.3.1.1 Electrical Requirements
Tempering skids should be furnished with junction boxes, equipment, and devices for a complete
control system (flow switches, thermostats, local control switches, motor starters, etc.). Each skid
typically requires a single 208 volts alternating current (VAC), three-phase, three-wire power feed
where the service is below 30 amps. Where feeds exceed 30 amps, a single 480 VAC, three-phase,
three-wire power feed will be required for each skid. The skid should be furnished with a fused
disconnect switch for connection to the plant power feed.
A common tempering skid alarm to indicate skid malfunction is typically furnished for remote
monitoring by the plant distributed control system (DCS). One normally open and one normally
closed contact are provided for the common alarm.
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17.2.3.1.2 Equipment Location
Tempering skids should be located indoors and such that the shortest recirculation loop is
required.
17.2.3.1.3 Required Information
Tempering skid equipment sizing depends on loop length, pipe size, number of showers and other
factors. Once a supplier is chosen, the following information should be provided to properly size
the equipment:
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Number of showers in the loop.
Number of simultaneous showers required.
Pipe material, schedule, and diameter.
Pipe insulation type and thickness.
Length of indoor and outdoor piping.
Length of underground and aboveground piping.
Potable water supply temperature and pressure.
Ambient temperature (consider ground temperature for underground piping).
Elevation difference between tempering skid and highest SS/EW.
Diagram of the system.
Certain suppliers are able to provide a more engineered system capable of handling many SS/EW
on the continuous loop. Other suppliers provide their standard system that can typically handle
fewer SS/EW assemblies.
17.2.3.2 Instantaneous Heaters
Instantaneous heaters or electric tankless water heaters are employed for efficiently and precisely
delivering immediate tepid water for SS/EW assemblies. The newest models draw enough energy
to hold the outlet temperature at the setpoint within 1° F. These units should be equipped with
built-in anti-scald features. Some heaters can offer overshoot purge protection which can
automatically purge excess hot water when necessary.
17.2.3.2.1 Electrical Requirements
Instantaneous heaters should be furnished with three-phase 208V to 600V electrical configuration
with three live connections and one ground connection. A photoionization detector (PID)
temperature controller should be installed to adjust the electrical output to achieve the desired
setpoint temperature.
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17.2.3.2.2 Equipment Locations
Instantaneous heaters should be located close to the SS/EW and be wall-mounted within a NEMA 4
or NEMA 4X cabinet when possible.
17.2.4
SS/EW Locations
The general ANSI and OSHA guidelines for the location of SS/EW assemblies are included in the
Safety Shower/Eyewash System Design white paper. The following sections are the most common
types of chemical exposure and areas that may require an SS/EW. Specific guidelines and
recommendations for each area are provided herein.
17.2.4.1 Storage Tank Containment
SS/EW stations should be installed outside curbed or walled areas because of a high risk of
continued chemical exposure in that area. Storage tanks should be designed so that most, if not all,
maintenance can be completed without going into the containment area.
17.2.4.2 Ammonia Area
For SS/EW recommended locations in aqueous and anhydrous ammonia systems, refer to the
Ammonia Storage and Handling Procedure.
17.2.4.3 Chemical Feed Areas
SS/EW stations should be located in close proximity to any chemical storage tanks and pump skids.
SS/EW should be located outside of the pump skid curbed area. Safety showers are not required
near the chemical injection point.
17.2.4.4 Silos
When required by client requirements/contract, SS/EW for chemicals stored in a silo should be
located on the platform just outside the door.
17.2.4.5 Enclosures
When there is space, the SS/EW should be located inside the same enclosure as the hazard. If space
is not available, the SS/EW should be placed outside of the enclosure at the same level of the hazard
to avoid any obstructions. The enclosure door should open in the same direction of travel and be
equipped with a closing mechanism that cannot be locked.
17.2.4.6 Laboratories/Sampling Area
A SS/EW should be included in the laboratory and near the sample panel. If space is limited in the
laboratory, a sink mount eyewash/face wash system can be considered with the addition of a
separate drench shower. For both areas, the SS/EW should be located within the same enclosure or
room as the laboratory and sampling area and provide no obstructions.
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17.2.4.7 Battery Rooms
The decision to locate a SS/EW or portable eyewash in a battery room is specific to each project and
must be reviewed on a case-by-case basis. This is typically determined by client preference.
Common problems are suitable drainage that is typically not available for a full shower and use of a
water shower in an area where there is a high risk of exposure to electrical equipment should be
avoided.
Occupational Safety and Health Administration (OSHA) STD 01-08-002 is a guideline regarding
eyewash and body flushing facilities required for immediate emergency use in electric storage
battery charging and maintenance areas. This guideline essentially requires a combination SS/EW
to be used where potential exposure to hazardous storage battery electrolytes exist (if dry cell
batteries are used, showers are not required). In areas where the extent of possible exposure to
electrolyte is small (e.g., auto garages, service stations, and in certain industrial and construction
situations), a specially designated pressure-controlled and identified water hose equipped with a
proper face and body wash nozzle which will provide copious amounts of low velocity potable
water, or an appropriate portable eyewash device containing not less than 1 gallon of potable water
that is readily available and mounted for use, is considered to provide minimum employee
protection when proper personal protective equipment is used. OSHA 29 CFR 1926.441(a)(6)
requires that facilities for quick drenching of the eyes and body shall be provided within 25 feet of
battery handling areas.
17.3
References

Safety Shower/Eyewash System Design White Paper. Revision 0, September 15, 2017.
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ANSI Z358.1-2014, American National Standard for Emergency Eyewash and Shower
Equipment.
Ammonia Storage and Handling Procedure.
OSHA 29 CFR 1926.441(a)(6).
OSHA STD 01-08-002.
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18.0 Chemical Cleaning
18.1
Purpose and Applicability
This section provides design criteria for chemical cleaning of the condensate-feedwater piping
systems. This includes the boiler drum and boiler tubes as well. Cleaning of the condensatefeedwater-steam piping systems prior to initial operation is required before actual steam
production is started by the facility.
18.1.1
Summary
Chemical cleaning minimizes the damage to the pipe and equipment caused by debris and coatings
left in the system from the manufacturing of equipment and from plant construction. Chemical
cleaning removes dirt, debris, rust, mill scale, and other materials that build up as deposits in the
boiler, feedwater, and condensate system. If not removed, these deposits can insulate the heat
transfer into the boiler water, impacting plant performance and eventually causing overheating
failures.
Chemical cleaning could potentially enhance the plant in the following ways:
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18.2
Remove internal manufacturing coatings.
Maximize heat transfer.
Maximize plant performance.
Meet cycle water quality requirements and minimize chemistry holds during plant startup.
Minimize startup time.
Reduce the number of steam (or air) blows and, consequently, the quantity of
demineralized water used to support steam blow.
Reduce carry-over from the condensate and boiler feedwater systems into the boiler that
could result in tube failures.
General Project Considerations
The following list of activities is performed in the early stages of a project prior to the development
of a chemical cleaning design specification:
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Development of the Cleanliness Control Guide (refer to Handbook Section 19).
Identification of the post-installation cleaning method for each applicable system.
Development of the chemical cleaning piping and instrumentation diagrams (P&IDs) or flow
diagrams.
Identification of the chemical cleaning connections on the applicable P&ID’s prior to release
for routing (developed with responsible Mechanical design engineer).
Receipt of the heat recovery steam generator (HRSG) or boiler manufacturer’s cleaning
guideline.
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The Cleanliness Control Guide will establish the cleanliness standards applicable to each system for
all phases of the project. The guide will also include a summary table where the post-install
cleaning method is identified. This document is built with input from the project team and client.
Identifying which systems and subsystems are to be cleaned and how they are cleaned is very
important. Below is a summary of systems that should be considered for chemical cleaning, if
applicable to the project:

Preboiler Systems:
●
●
●
●
●

Condensate and Feedwater Piping.
Condensate Polishing.
Combustion Gas Reheat Piping.
Air Preheater Piping.
Feedwater Heater Shells and Drain Piping.
Boiler Systems and Auxiliary Boiler Systems:
●
●
●
●
●
Superheater.
Spray Piping.
Economizer, Evaporator, Drums, and Downcomers.
Reheater.
Steam Piping.
18.3
Approach
18.3.1
Cleaning Techniques and Procedures
The cleaning technique chosen depends largely on the level of cleanliness control maintained
during fabrication and installation. There are several options for the chemical cleaning of a
condensate-feedwater-steam cycle. Cleaning techniques may include any or a combination of the
following:





High purity water flushes.
Hydrolazing.
Surfactant (degreasing) cleaning.
Alkaline boilout (degreasing).
Solvent (chelant/acid) cleaning:
●
●
Ethylenediaminetetraacetic acid (EDTA).
Citrate (5 percent citric acid buffered with either ammonium hydroxide or sodium
hydroxide [caustic]).
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
Acid Cleaning:
●
●
Inorganic acid cleaning (hydrochloric acid, hydrofluoric acid).
Organic acid cleaning (hydroxyacetic/formic acid).
Degreasing is used for all feedwater, boiler, and preboiler systems; and solvent (chelant/acid)
cleaning is needed for operating pressures greater than 1,500 pounds per square inch gauge (psig).
18.3.1.1 High Purity Water Flushes
Treated demineralized water is preferred for all high purity water flushes. Demineralized water is
typically defined as high purity water with less than 1 part per million (ppm) total dissolved solids
that is free of suspended solids. Demineralized water is typically treated with an aqueous ammonia
solution to maintain a water pH of 9.2 to 9.6.
Refer to the project Cleanliness Control Guide (Section 19) for specific high purity water
requirements and alternatives. High purity water or demineralized water flushes are the least
labor intensive and provide the bare minimum of cleaning. This type of cleaning should be used
with low temperature and low-pressure (LP) systems, i.e., demineralized water storage and
transfer.
18.3.1.2 Hydrolazing, Hydroblasting, or Hydromilling
Hydrolazing will be the term used for hydrolazing, hydroblasting, and hydromilling. Hydrolazing
may be an acceptable cleaning technique for certain piping systems with a high number of piping
dead legs, or in piping sections where sufficient velocity cannot be maintained during a chemical
cleaning. Examples include the condensate and LP feedwater systems.
The purpose of the hydrolaze is to water jet the interior of the pipe to achieve an SP12 white metal
finish cleaning. During the hydrolaze process, a rotating nozzle travels along the inside wall of the
piping in a spiral pattern down the length of the pipe. As it travels along the pipe, the water jet
shears mill scale from the pipe surface. In addition, the high-pressure jet cuts up debris and other
foreign materials within the pipe. The process also flushes the removed materials down the pipe to
the entry point. Because of limitations with the physical hydromilling equipment and the routing of
the pipe to be cleaned, several access points may be required.
18.3.1.3 Surfactant (Degreasing) Cleaning
Chemical degreasing, or surfactant cleaning, is the process step to remove the dirt, shop oil, and
other light metalworking fluid particulates that remain following the manufacturing process.
Typically, the cleaning circuit is filled with demineralized water and brought to a temperature of
approximately 140° F up to 200° F. A proprietary surfactant is added to maintain a 0.1 percent to
0.5 percent concentration. In general, these types of chemicals have a moderate 6 to 8 pH range.
Surfactant molecules have two ends: an oil loving (hydrophobic) end and a water loving
(hydrophilic) end. The hydrophobic end will attach itself to the oil droplet while the hydrophilic
end remains dissolved in the cleaning solution. The oils are then removed as the system is rinsed
and drained. Figure 18-1 provides an illustration of this process. This adsorption cleaning
mechanism is effective with typical light oils, such as water-soluble oils and mill oil. Heavier oil and
grease removal may require a more aggressive precleaning such as an alkaline boilout.
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A foam inhibitor can be introduced, as required. A corrosion inhibitor can be introduced in this
step to help mitigate any corrosive effects due to the relatively low pH circulating through the
system.
Refer to Table 18-1 for critical parameters.
Surfactant
Oil
Iron Oxides
Iron Oxides
Base Metal
Base Metal
Figure 18-1
Chemical Degreasing Surfactant Addition
Table 18-1
Chemical Degreasing/Cleaning Critical Parameters
CRITICAL PARAMETERS
Temperature Range:
140° F to 200° F
Circulation Time:
Minimum 12 hours
Concentration:
Velocity:
18.3.1.4 Alkaline Cleaning
0.1 percent to 0.5 percent
1 to 2 ft/sec
Heavier oils, grease, and temporary protective coatings can remain after the system is erected.
Surfactant degreasing may not be able to clean the system effectively and if so, an alkaline cleaning
may need to be considered. Loose mill scale may be removed like dirt, but phosphate will not
“dissolve” mill scale.
Utilizing a similar treated demineralized water filling and circulating process, the circuit is brought
up to a temperature range of 140° F to 200° F. A disodium and trisodium phosphate alkaline
cleaning solution (normally purchased in its hydrated form) is typically used and consists of the
following chemicals mixed together:


Disodium phosphate (as Na2HPO4) - 1,500 mg/L.
Trisodium phosphate (as Na3PO4) - 2,500 mg/L.
A foam inhibitor can be introduced, as required. Caustic or soda ash can also be utilized to bring the
pH of the system up to a 10 to 12 range. Sodium sulfite is occasionally used to prevent oxygen
corrosion.
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The alkaline cleaning step is to be done separately from the acid cleaning step and should be
completely rinsed and drained before proceeding.
Refer to Table 18-2 for critical parameters.
Table 18-2
Alkaline Cleaning Critical Parameters
CRITICAL PARAMETERS
Temperature Range:
140° F to 200° F
Circulation Time:
Minimum 12 hours
pH Range:
Velocity:
18.3.1.5 Solvent Cleaning – Chelant/Acid
10 to 12
1 to 2 ft/sec
18.3.1.5.1 Chemistry and Function
The function of the tubeside cleaning is to provide a clean internal surface for passivation. The
solvent or chelant (pronounced key-lant) cleaning step represents the bulk of the chemical cleaning
process. The purpose of solvent cleaning is to dissolve all oxide layers from the boiler and boiler
tube surface, leaving the carbon steel “active.” If left alone, this active steel surface is prone to
immediate oxidation (rusting). However, raising the pH of the cleaning solution neutralizes and
keeps the metal ions chelated. After neutralization, an oxidizing agent is introduced that forms a
thin magnetite (Fe3O4) layer with reducing chemistry. With oxidizing chemistry, the layer formed
with chemical feed is ferric oxide hydrate. These layers passivate the steel. This passive layer is
temporary; but by maintaining good cycle chemistry, relatively high pH values, and sufficient
blowdown, this passive layer should remain intact for 5 to 10 years or until heat transfer is
impacted, at which time, another chemical cleaning would be required.
Solvent cleaning will adsorb metal ions iron and copper into the solution through the process of
chelation. The solvent is referred to as the chelant. Chelation is the process by which an organic
compound forms two or more bonds with a metal ion surrounding it. Under mildly acidic
conditions, iron oxides that make up the mill scale or deposits dissolve into the cleaning solution.
Once in the solution, they are chelated to remain in the solution. This process will continue until
either all of the scale is dissolved, or the chelant is used up. For this reason, the concentration of
“free,” unattached chelant is monitored. The minimum concentration of free chelant is 0.5 percent
to ensure that all of the deposit is removed. If the concentration drops below this value, additional
chelant should be added. A critical parameter of solvent cleaning is the solution velocity. The
solution must be kept in a turbulent mode to ensure mixing of free chelant throughout the tube
diameter. Descriptions and uses for common solvent cleaning reagents are as follows:

Citric Acid (Citrate). One of the most common iron removal solvents, this is typically a
moderate temperature process utilizing a 2 to 5 percent citric acid solution buffered with
either ammonium hydroxide (ammonium citrate) or caustic (sodium citrate). With
corrosion inhibitors, the pH is typically maintained between 3.5 to 4.0. This is an
inexpensive option compared to EDTA; however, its affinity to holding the iron molecule in
solution is not as great.
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
EDTA. This method is used similarly to citric acid, but it is less prone to releasing the iron
molecule. The cleaning process and handling operations are similar to citric acid and
generate minimal wastewater. This is typically a moderate temperature process utilizing a
2 to 5 percent solution. With corrosion inhibitors, a pH range of 5.0 to 6.0 is typically
maintained.
Both EDTA and citric acid are weak organic acids, as opposed to mineral acids such as hydrochloric
or sulfuric acid. Mineral acids will directly react with deposits, mill scale, and the base metal
surface itself during the cleaning process, whereas EDTA and citric acid are both chelants. One
benefit of solvent/chelant cleaning over a mineral acid cleaning is the retainage of the iron in
solution with minimal precipitation and sludge formation, which are common with mineral acids.
Figure 18-2 shows EDTA chelating a metal ion. The solvent cleaning process step is sometimes
referred to as the “iron stage.”
Figure 18-2
EDTA Chelation
18.3.1.5.2 Chelation Differences
Despite the similarities, there are differences between the two chemicals that should be considered.
The first is the chelating strength. EDTA has more bonding locations in its chemical structure,
which give it a stronger hold on the metal atom than citric acid. It holds the metals in solution
throughout the cleaning so that the internal surfaces are “spotless” after the cleaning. Citric acid,
while a chelating agent, is not as strong, and it is common for iron to precipitate out and drop onto
horizontal surfaces, such as the drum sides or economizer inlet header. These will then oxidize to a
bright red when the drum is opened for restoration. Although it may appear that the steel is
rusting, it has been Black & Veatch’s (B&V) experience that the red dust can be wiped or rinsed off,
and the surface beneath is clean and passivated. During initial operation, the iron is blown down,
but, if needed, it can be wiped down during drum restoration.
18.3.1.5.3 Process and Handling
The equipment and staffing required to execute either cleaning is identical: a circulating pump and
backup, heat exchanger, temporary boiler, chemical feed pump, backwash pump, chemical storage
tanks, and wastewater storage tanks.
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Neither chemical is considered toxic. The personal protection equipment (PPE) for handling either
chemical in concentrated form consists of long-sleeved shirt, gloves, pants, safety shoes, hard hat,
goggles, and face shield.
If an alkaline cleaning/degreasing stage precedes the solvent cleaning, the alkaline solution is to be
completely drained from the system and refilled with treated demineralized water, as it will inhibit
the dissolution of the iron.
If utilizing a low impact surfactant for the degreasing stage, the chelant can be injected directly into
the circuit after the degreasing stage. A corrosion inhibitor should be injected as well. Once all the
chemistry is injected, the circuit should be heated to 180° F to 200° F. The surfactant/inhibitor/acid
“cleaning solution” is to be circulated for at least 8 hours at 180° F to 200° F. Samples are taken to
monitor the chemistry, which is to be maintained between 3.5 to 4.0 pH, with 0.5 percent minimum
concentration of “free chelant.” As long as there is free chelant in the solution reading, the cleaning
is continued and the minimum cleaning time included as long as the EDTA concentration is
restored. This is due to the fact that the iron removal will continue as long as either free chelant or
iron oxide is present.
The iron removal stage is over when the iron concentration levels off to +/- 10 percent for at least a
4 hour period. Once the iron stage is complete, the system will need to be neutralized and then
passivated to form the protective magnetite or ferric oxide hydrate layer.
Refer to Table 18-3 for critical parameters.
Table 18-3
Solvent Cleaning (Iron Stage) Critical Parameters
CRITICAL PARAMETERS
Temperature Range:
180° F to 200° F
EDTA Concentration:
5 percent initial dose; maintain at least 1 percent
throughout iron stage
Circulation Time:
Citric Acid Concentration:
Equalized Iron Level:
Velocity:
Minimum 8 hours
2 to 4 percent: maintained throughout
+/- 500 ppm for at least 4 hours
2 to 3 ft/sec
The solvent/chelant cleaning process is illustrated on Figure 18-3.
Ferrous [Fe(II)] Chelant ]
Chelant
Iron Oxides
Base Metal
Figure 18-3
Base Metal
Solvent/Chelant Cleaning
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Refer to Table 18-4 for dissolution reactions for solvent cleaning.
Table 18-4
Dissolution Reactions for Solvent Cleaning
EDTA (low pH)
Citrate (low pH)
18.3.1.5.4 Disposal
4EDTA-4 + 8H+ + Fe3O4 + Fe
4Fe(II) EDTA + H2O
4NH4H2 Citrate + Fe3O4 + Fe
4NH4Fe(II) Citrate + 4H2O
While the chelating strength of the EDTA minimizes iron precipitation during the cleaning, it
creates a wastewater that may be more difficult to dispose of. Industrial treatment facilities
typically use alkaline treatment of wastewater to precipitate and separate metals. While this works
with citric acid wastewaters, EDTA wastewaters will not precipitate and meet normal discharge
limits so the presence of EDTA may limit disposal options and increase the disposal cost. Refer to
Table 18-9 for approximate chemical cleaning wastewater characterization.
18.3.1.5.5 Cost
The other difference between the two chemicals is cost. EDTA usually costs approximately
40 percent more than an equivalent amount of citric acid. However, since the cost of the chemicals
is just one part of the contractor’s chemical cleaning cost, the final total chemical cleaning cost
difference between the two chemicals is usually approximately 10 percent.
18.3.1.6 Mineral Acid Cleaning
Mineral acid cleaning processes (hydrochloric acid [HCl], hydrofluoric acid [HF],
hydroxyacetic/formic acid [HAF]) use strong acids to react with the iron and other cations in
deposits. These are all effective, but they have serious safety concerns that limit their use. HCl is an
economical, aggressive chemical that does not require circulation, but is used in a “fill and soak”
method. HCl should be considered whenever there are concerns with circulation, such as drum type
boilers. Concerns with HCl include the following:



HCl is not compatible with chrome, so if there are pH elements, HCl must not be used.
HCl will not hold iron in solution, and a sludge will drop out in the lower headers. A citric
acid rinse is used to remove the sludge after the acid stage.
HCl has serious hazards and should only be handled by experienced personnel.
Other forms of acid have been used as well:


HAF is used in supercritical boilers where chromium is used.
HF is commonly used in Europe, but rarely in the United States due to safety concerns.
Refer to Table 18-5 for dissolution reactions for mineral acid cleaning.
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Table 18-5
Acid
Dissolution Reactions for Mineral Acid Cleaning
Acid + Fe3O4
Fe+2 + 2Fe+3 + 4H2O + Neutralized Acid Anion
Fe + 2Fe+3
3Fe+2
Acid + Fe2O3
18.3.1.7 Corrosion Inhibitors
2Fe+3 + 3H20 + Neutralized Acid Anion
Corrosion inhibitors, as manufactured by Rodine or Cronox, must be added to all cleaning solutions
before the acid removal stage. The inhibitors protect the base metal from the acids, while allowing
them to dissolve scales and deposits.
18.3.1.8 Superheater Backfill
In most cleanings, the superheater is backfilled with demineralized water containing enough
ammonia to raise the pH to 10. This acts as a water block to prevent chemical carryover into the
superheaters. Chemical cleaning the superheaters is an alternative option. Although it can be
expensive, it can significantly reduce steam blows during startup, possibly eliminating the need to
rent expensive mobile water treatment trailers.
18.3.2
Neutralization and Passivation Stages
After the initial cleaning where the iron oxide layers have been stripped from the tube surface, the
base metal is active and is still prone to oxidation (rusting). To stop this “flash rusting,” the base
metal is passivated by the formation of a layer of magnetite (Fe3O4) that inhibits the flow of ions to
the base metal. To accomplish this passivation step, the pH of the solution needs to be increased.
This serves to neutralize the solution and keep the metal ions chelated. After neutralization, an
oxidizing agent is introduced that reacts with the iron in the solution. This oxidized iron then reacts
with the base metal to form the thin magnetite layer passivating the steel.
18.3.2.1 Passivation with EDTA Solvent
Once the iron stage is complete, heat to the system should be decreased, and the circuit should be
allowed to cool to 150° F and maintained for the neutralization stage. Ammonia or another alkali is
added to raise the pH up to a range of 8.8 to 9.5. An oxidant, either sodium nitrite, pure gaseous
oxygen, or hydrogen peroxide, is injected into the solution and circulated for 4 hours to passivate
the metal surfaces. This oxidizes the ferrous [Fe(II)] chelant to ferric [Fe(III)] chelant. The
oxidation-reduction potential (ORP) of the solution should be less than -220 millivolts (mV). The
solution is then drained to the frac tanks, and the circuit rinsed with demineralized water several
times.
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18.3.2.2 Passivation with Citrate Solvent
The passivation stage of the citrate solvent cleaning is similar to that of ammoniated EDTA. When
the citrate solvent iron stage is complete, heat to the system should be decreased and the circuit
should be allowed to cool to 150° F and maintained. Ammonia or another alkali is added to raise
the pH up to a range of 8.8 to 9.5. Excess citric acid and alkali should be applied as insurance
against iron precipitation (citric acid is a weaker chelant than EDTA).
The use of oxygen or hydrogen peroxide will not work as an oxidant with ammonium citrate.
Sodium nitrite is utilized and is injected into the solution and circulated for 4 hours to passivate the
metal surfaces. This oxidizes the Fe(II) chelant to the Fe(III) chelant. The ORP of the solution
should be less than -220 millivolts. The solution is then drained to the frac tanks, and the circuit
rinsed with demineralized water several times.
Refer to Tables 18-6 and 18-7 for critical parameters.
Table 18-6
Neutralization Stage Critical Parameters
CRITICAL PARAMETERS (NEUTRALIZATION STAGE)
Temperature Range:
140° F to 160° F
pH Range:
8.8 to 9.5
Circulation Time:
Velocity:
Table 18-7
Minimum 1 hour
1 to 2 ft/sec
Passivation Stage Critical Parameters
CRITICAL PARAMETERS (PASSIVATION STAGE)
Temperature Range:
140° F to 160° F
ORP:
<-220 mV
Circulation Time:
Velocity:
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Figure 18-4 illustrates the passivation process.
Ferrous [Fe(II)] Chelant ]
NH4OH
NH4OH + Ferric [Fe(III)] Chelant ]
NH4OH + Ferric [Fe(III)] Chelant +
Reduced Oxidant
Oxidant
Oxidation
Magnetite (Fe3O4)
Base Metal
Base Metal
Figure 18-4
Passivation
Refer to Table 18-8 for passivation reactions for solvent cleaning.
Table 18-8
Passivation Reactions for Solvent Cleaning
EDTA (high pH)
Ammonium Citrate
(high pH)
18.3.3
Fe(II)EDTA + NH4OH + O2
NH4OH Fe(III) EDTA
NH4OH + 2(NH4)Fe(II) Citrate + NaNO2
2(NH4)Fe(III) Citrate OH + NaNO + NH3
Draining, Rinsing, and Lay-up
Once the ORP has maintained less than -220 mV after at least 4 hours of circulation, the cleaning
solution is then drained from the system. The cleaning solution is typically drained to frac tanks
but can be sent to other well or storage locations depending on the client’s requirements and the
National Pollutant Discharge Elimination System (NPDES) regulations for metal cleaning waste.
After the cleaning solution has been drained, the system should be rinsed with demineralized water
until the conductivity indicates all residual chemicals are removed. The rinse solution should be
transferred to the same storage or injection location as the cleaning solution. Refer to
Subsection 18.3.4. Refer to Table 18-9 for approximate chemical cleaning wastewater
characterization.
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Table 18-9
Approximate Characterization of Chemical Cleaning Wastewater
COMPONENT
CLEANING
SOLUTION
Surfactant
0.2
%
Corrosion
Inhibitor
0.1
%
Antifoam
Citric Acid
Ammonia
Iron
Chromium
200
3
0.8
1,500 - 2,500
3
FIRST RINSE
50
mg/L
<2
mg/L
25
mg/L
<1
mg/L
mg/L
<5
%
750
%
mg/L
mg/L
SECOND RINSE
mg/L
mg/L
200
mg/L
< 60
< 100
mg/L
mg/L
<0.1
< 20
<5
<2
<2
mg/L
mg/L
mg/L
mg/L
mg/L
Notes:
Surfactant, corrosion inhibitor, citric acid, and ammonia levels based upon normal chemical cleaning
requirements.
Iron and chromium levels based upon similar cleanings.
First and second rinse dilution based upon 2 1/2 percent (about 2,000 gal) of the solution remaining in the lower
headers at the end of the drain. This will vary based upon how thorough the contractor is during the drain.
18.3.4
Post Cleaning Inspection and Lay-up
Upon completion of the cleaning, the steam drum should be opened up for inspection after the final
rinse. The metal should have a grey “gun metal” finish indicating a passive magnetite layer. Refer
to Figure 18-5. To maintain the integrity of the magnetite layer until operation, the system should
be laid up to prevent additional flash rust after exposure to atmosphere, using one of the following
methods:



Nitrogen blanket – Purge all of the oxygen from the system with nitrogen. Maintain a
5 to 10 psig nitrogen pressure on the boiler.
Dry air – Circulate dry air through the boiler. When the air exiting the boiler is dry, the
boiler is closed up.
Wet lay-up – Fill the boiler with demineralized water containing enough ammonia to raise
the pH to 10, and 200 ppm can be hydrazide or equivalent.
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Figure 18-5
Boiler Drum Internal
18.4
Process Considerations
18.4.1
Manufacturer’s Procedures
Prior to choosing a chemical cleaning process, the manufacturer of the HRSG or boiler is consulted
to verify that the chemical cleaning process will not void the equipment warranty or damage the
equipment. Any requirements of the manufacturer will be determined prior to cleaning (such as
removal of steam separators from the drum, etc.).
This should be addressed early in the project stages during the development of the Cleanliness
Control Guide.
18.4.1.1 Manufacturing Processes
To ensure that the systems are cleaned adequately, it is important to consider the manufacturing
processes for the equipment and piping to be cleaned. For example, lubricants that are used to roll
the tubes of the boiler need to be water soluble. In addition, excess lubricant should be removed
from the system. Once in place, excess lubricant can be hard to remove from the system. If the
manufacturer has placed any desiccants in the HRSG or boiler, it is important that these are
identified and removed prior to chemical cleaning.
This should be addressed early in the project stages during the development of the Cleanliness
Control Guide.
18.4.2
Construction Practice
Field cleanliness practices have a definite impact on construction and startup, including chemical
cleaning. To minimize schedule impacts on construction and startup, a cleanliness control
specification for each project must be developed during design and followed.
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18.4.3
Disposal Options
If the chromium content of the wastewater exceeds 5 mg/L, the wastewater is classified as
hazardous, and disposal costs can quadruple. Disposal of the waste produced by chemical cleaning
can cost as much as, if not more than, the chemical cleaning procedure itself. As early in the
planning process as possible, all components in the cleaning circuit containing chromium should be
identified. The available disposal options should be considered when evaluating the different
cleaning processes. If steam piping is cleaned, the chrome content of the waste will increase and is
likely to be hazardous. Some of the available waste disposal options are as follows:






Transfer to an evaporation pond on-site. Nonhazardous unless permitted.
Transfer to a local city wastewater plant (local sewer). Nonhazardous only.
Truck off-site (expensive). Nonhazardous and hazardous.
Retain on-site and co-combust in a permitted boiler (may be limited by low disposal rates).
Nonhazardous and hazardous if permitted.
On-site treatment, including neutralization and/or heavy metals removal, using the plant
wastewater treatment system. Nonhazardous, unless the treatment plant is permitted as a
treatment, storage, and disposal (TSD) facility.
Owner disposal (contract may not allow). Nonhazardous and hazardous.
Each of the above methods has its advantages and disadvantages, which will vary depending on the
city, county, state, or country where the plant is located. Federal, state, and local regulations and
permits must be reviewed when selecting a chemical cleaning waste disposal and/or treatment
method, especially when on-site treatment is being considered, because on-site treatment may be
prohibited or require additional permits. Discharge to a local sewer facility usually requires
maintaining strict limits on quantities, discharge rates, and waste constituents.
Typically, the waste is trucked off-site. High concentrations of chrome may cause the waste to be
classified as “hazardous,” greatly increasing the disposal cost. The chemical cleaning contractor for
the project can typically be used to assist in finding a waste disposal site or be paid to dispose of the
waste and to characterize the waste for disposal.
18.4.4
Demineralized Water Capacity
Most chemical cleaning procedures require a large volume of demineralized water. If sufficient
demineralized water is not available for the procedure, a mobile demineralizer or other options will
be required. The storage/makeup system should be evaluated to determine if a mobile
demineralizer or other options are required.
18.4.5
Construction/Startup Schedule
The construction/startup schedule is typically the driving force behind the chemical cleaning
schedule. If the schedule is aggressive, chemical cleaning of steam piping, superheaters, and
reheater may be considered as a means of reducing the steam blow duration. It should be noted
that, even in the case of an aggressive plant schedule, chemical cleaning will minimize steam or air
blow time, strainer cleaning during startup, and other aspects of plant startup required to ensure
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that the plant is operating properly. If the plant schedule is more flexible and/or if there are
significant liquidated damages associated with the startup, a more conservative and more
expensive two-step chemical cleaning process (both alkaline and acidic) may be considered.
18.4.6
Mobilization and Cleaning Schedule
Once the chemical cleaning process has started it will continue until the final rinsing step taking
several days and nights to complete one HRSG or boiler. Sufficient time should be built into the
schedule to allow the following:
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Mobilization of the cleaning vendor (or B&V if self-performing):
7 to 10 days
Removal of all strainers and orifice plates in circuit:
2 to 4 days
Control and check valve internal removal:
Installation of orifice plates in HRSG or boiler downcomers:
2 to 4 days
2 to 4 days
“Rig Up” installation of pumps, heat exchanger, and temporary piping:
5 to 10 days
“Rig Down” removal of all temporary piping and equipment:
5 to 10 days
Execution of the chemical cleaning and rinsing process:
Restoration of all control and check valve internals:
Nitrogen lay-up:
5 to 10 days
2 to 4 days
1 to 2 days
The number of days for each activity is typical for one HRSG or boiler. Durations can be different
based on drum volumes and other considerations. Most of the site preparation and restoration
activities can be completed in parallel. If cleaning multiple HRSGs, it is wise to rig up a second
HRSG during the cleaning phase of the initial HRSG. Planning the circuit path and work is key to a
well-executed cleaning.
18.4.7
Site Considerations
When a chemical cleaning specification is prepared, several issues require definition for the
chemical cleaning contractor, taking into account site conditions.
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Temporary Interface Piping and Valves--It should be determined who will provide
and install the interface piping and valves between the permanent plant piping and
the chemical cleaning equipment. It is typically most efficient to have the site
construction staff install these materials.
On a packed system, all temporary piping and components installed in the
circulation loop should be rated for the maximum static head, plus the shutoff head
of the chemical cleaning pump. Because of the elevations of some components on
large units, this may preclude the use of flexible hoses.
For units that are not packed (i.e., where the unit is vented and a constant level is
maintained), all temporary piping and components installed on the discharge of the
chemical cleaning pump should be rated for the maximum static head provided by
the maintained liquid level, plus the shutoff head of the chemical cleaning pump. All
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temporary piping and components installed on the suction of the chemical cleaning
pump should be rated for the maximum static head provided by the liquid level.
Because of the elevations of some components on large units, this may preclude the
use of flexible hoses on the discharge of the chemical cleaning pump, but may
reduce cost by allowing flexible hoses to be used on the suction.
Consideration may be given to installing a pressure relief device (relief valve or
rupture disk) on the discharge of the chemical cleaning pump to reduce the pressure
rating required for the temporary piping and components. If provided, the pressure
relief device should be installed between the chemical cleaning pump discharge
flange and the first isolation valve downstream of the pump. The pressure relief
device is routed directly to a temporary wastewater storage device such as a frac
tank. No valves should be installed on this relief line. If a valve is installed on this
line (such as a valve directly on the temporary wastewater storage device), it must
be locked open. If a pressure relief valve is provided, the valve must be tested by a
certified third party immediately prior to installation. If a rupture disk is provided,
the rupture disk must be in new and unused condition, and a minimum of one spare
rupture disk provided to minimize down time following a relief scenario. Depending
on lead time, more than one spare rupture disk may be required. Relief
valve/rupture disk materials need to be checked to be sure that they are compatible
with the cleaning chemistry. Materials containing copper are not permitted.
Flexible hoses, if permitted, are automatically derated by 25 percent of the stamped
design pressure rating because of hose failures. Due to recent issues with flexible
pipe failures it is strongly recommended that the project proceed with hard
temporary piping for all piping greater than 2 inches.
All temporary piping and components furnished, including flexible hoses (if
permitted), are rated for continuous operation at a temperature exceeding that
required by the selected chemical cleaning process or intended service (steam,
condensate, etc.) but not less than 212° F (100° C). It should be noted that this is a
design basis, not operational limit.
All temporary piping, pumps, components, flexible hoses, etc., are inspected prior to
installation on-site by the responsible project or startup engineer. Any component
that is visibly damaged, appears to have been poorly maintained, or whose integrity
is otherwise in question, is flagged, tagged, and is not permitted to be installed.
Hoses for vents and drains should be 1 inch (25 mm) hoses with threaded swivel
hose ends, except where a larger process vent or drain connection requires the use
of a larger hose. Flanged hoses should be avoided whenever possible because they
are generally heavier and shorter and by nature increase the cost and time
associated with installation. The number and length of hoses potentially needed
during chemical cleaning should not be underestimated. It is not unreasonable to
foresee the need for 1,000 feet (305 meters) or more of 1 inch (25 mm) hose in
random lengths.
Pre-Cleaning Flush--A high velocity flush of the systems to be chemically cleaned should be
performed prior to chemical cleaning to remove gross debris from the chemical cleaning
path. The flow path of the flush should be such that debris is prevented from being flushed
into the boiler or HRSG. If the condensate feed pumps can be commissioned prior to
chemical cleaning, they should be used for this process because they can typically generate
higher velocities than can be obtained by a temporary pump. If the condensate feed pumps
are not available, a temporary flush pump should be provided to flush the cleaning path. To
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reduce the amount of water used for the pre-cleaning flush, a circulation loop that
incorporates a weir tank, pot filter, or basket strainer may be used.
Chemical Cleaning Procedure--The following information, as a minimum, is included in the
chemical cleaning procedure issued for review:
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A complete description of the chemical cleaning system, including flow diagrams,
piping and equipment drawings, and locations of all temporary cleaning
components.
Chemical cleaning pump sizing calculations (flow and pressure).
Estimated chemical cleaning procedures (detailed, step-by-step).
Chemical quantities to be used for cleaning, neutralization, and passivation.
Anticipated water consumption.
Anticipated schedule.
Waste handling and disposal description.
Safety Data Sheets (SDSs) for all chemicals proposed, including analytical reagents.
Flow Paths--Flow paths are reviewed by both office and site personnel. The chemical
cleaning contractor (if used) might know a more efficient way to clean the system based on
experience. The site startup manager authorizes all final cleaning methods.
Heat Source--The majority of chemical cleaning processes require heat input. It may be
required to supply a temporary external boiler, if an existing heat source is not available.
The need for a heat source, or an attempt to minimize heat source requirements, may
govern the schedule of the chemical cleaning process. Depending on the boiler code of the
state, an external heat source may be required for hydrostatic testing. If an external heat
source is needed, requiring the chemical cleaning temporary boiler at the site early for
hydrostatic testing should be addressed in the cleaning specification. Federal, state, and/or
local regulations may require additional permits or inspections of a temporary boiler prior
to its operation.
Leak Testing--Hydrostatic testing of all permanent piping to be chemically cleaned is
completed prior to the start of chemical cleaning operations. Temporary piping is inspected
for leaks after heating but prior to the introduction of chemicals into the cleaning circuit.
During the chemical cleaning process, all permanent and temporary piping are checked for
leaks on a frequent routine basis.
Personnel Protection--The site has a safe work plan in place prior to chemical cleaning.
Hazards include exposure to cleaning chemicals and acids, and contact with hot uninsulated
pipes (the cleaning solution will be heated to 180 to 200° F [80 to 90° C]). Provisions are
made to quickly neutralize and clean up any chemical spills and to protect personnel from
exposure to the chemicals. Safety showers and eyewash stations are functioning and readily
accessible within 10 seconds of all chemical exposure areas. Protective face shields and
protective clothing for the chemical cleaning personnel are provided. Safety tape is strung
around the boiler and other components to warn of chemicals and high temperatures. Red
tape is strung around the chemical storage and injection areas and other areas, deemed as
necessary, to prohibit unauthorized entry.
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18.4.8
Temporary Waste Storage--In most locations, temporary waste storage equipment needs to
be provided to allow the waste to be temporarily stored onsite before it is permanently
disposed. This may reduce trucking costs and provide a cushion for capacity surges
required at neighboring wastewater facilities. These needs are thoroughly examined with
waste disposal options. Temporary waste storage equipment usually consists of multiple
frac tanks that are manifolded together. A rubber secondary containment curb should be
provided for each frac tank.
Site Coordination--The chemical cleaning contractor must submit all necessary
documentation required to function as a subcontractor onsite.
Boiler Insulation and Gas Path--In order to maintain proper cleaning temperatures, heat
loss from the boiler must be minimized. The boiler typically has at least one batt of
insulation installed at the time of cleaning. In addition, dampers are closed or a temporary
barricade erected to minimize draft through the boiler or HRSG to the stack. Other openings
and manways that, if left open, could increase draft through the boiler or HRSG also have a
temporary barricade erected to reduce heat loss.
Flow Path Determination
Care should be taken to have the largest manageable cleaning circuit(s) possible when determining
the flow paths for a system.
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Circulated Cleanings--When the chemical cleaning flow path is planned, the boiler or HRSG
design should be reviewed. Many HRSG designs require that the drum or drums be filled
with solution (i.e., packed) to ensure circulation through the evaporators. If cleaning with
packed drums, it is mandatory that the superheaters be backfilled to prevent chemical
carryover into the superheaters. Also, when the drums are packed, the flow rates can be
increased and multiple drums can be cleaned simultaneously.
If the HRSG drums are not packed, it is difficult to keep the boiler drum levels steady if more than
two drums are being cleaned at the same time, without stationing a person to continuously monitor
the drum levels.
When air blows are used, the superheaters must also be cleaned, which will affect the circuit layout.
During the planning stage, the following require evaluation:
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Piping and Instrumentation Diagrams (P&IDs)--If B&V is responsible for the design of the
temporary chemical cleaning pipe, P&IDs are required. If the chemical cleaning contractor is
responsible for the design of the temporary pipe, a flow diagram that clearly shows the
preferred flow paths and relative locations of chemical cleaning connections is sufficient, if
agreed upon by both the mechanical and chemical project engineers.
Velocity--Citric acid and EDTA cleaning solutions depend on maintaining a velocity gradient
across the surface of materials to provide a proper cleaning. It is important to keep the
minimum velocity in the condensate header at 2 to 3 feet per second (0.61 to 0.91 meters
per second), and the velocity in the waterwall tubes as high as practically possible.
Typically, in HRSGs, it is most difficult to maintain velocity in high- and low-pressure (HP
and LP) evaporators because of the number of tubes. In most drums, temporary orifice
plates are required to be installed in the drum downcomers to ensure a sufficient cleaning
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velocity through the evaporator tubes. The orifice should be sized with an opening
equivalent to one evaporator or waterwall tube.
Size and Location of Connections--The location and size of the chemical cleaning
connections are critical to the success of the chemical cleaning. Typical locations include the
following:
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Discharge of the condensate pumps.
Suction and discharge of the boiler feed pumps (locations may coincide with the
start and end points of a cleaning circuit).
Equipment bypasses around boiler feed pumps, deaerators, and in-line instruments
or devices that cannot be removed for cleaning.
Boiler/HRSG chemical cleaning connections (water and steam piping).
Desuperheater sprays.
Steam turbine area chemical cleaning connections (main, cold reheat, hot reheat,
and LP steam).
Superheater backfill connections.
Areas where a dead leg could occur.
18.5
Design and Specification Preparations
18.5.1
Design
Chemical cleaning specifications are either separate specifications or are included within the
mechanical construction specifications and are based on subcontractor performance of work
on-site. The chemical cleaning specifications typically include the following system design
information:
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Chemical cleaning system P&IDs and/or flow diagrams.
Number, size, class, and location of all anticipated interfaces (flanged, welded, Grayloc, etc.)
between temporary and permanent plant pipe.
Number, size, class, and location of any blanking or spectacle flanges that may be required.
Plant arrangement drawings with marked locations of major temporary equipment.
Volume of preboiler piping requiring cleaning.
Volume of the deaerator, if chemical cleaning is required.
Estimated volume of any temporary chemical cleaning pipe.
Volume of the feedwater heater shells requiring alkaline degrease (thermal plant).
Volume of feedwater heater drain piping requiring alkaline degrease (thermal plant).
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18.5.2
Condenser hot well volume, if cleaning through the condenser or if the condensate pumps
are used for a pre-cleaning flush.
Volumes of the boiler drum and water circuits requiring chemical cleaning. Include volumes
of separator drains, blowdown tanks, deaerators, etc., that are part of the chemical cleaning
circuit.
Volumes of superheaters, steam headers, and steam piping requiring cleaning.
Volumes of superheaters to be filled and backflushed with treated demineralized water.
Boiler layout drawings showing pipe layouts for water and steam paths.
Piping isometric drawings for water and steam paths, if required.
System design parameters (pressure/temperature). Caution should be exercised to ensure
that the design pressure and temperature ratings of both the permanent and temporary
system components are not exceeded at any time during the chemical cleaning operation.
Special attention should be given to components subject to overpressure, such as feedwater
heaters, whose relief valves may be removed to allow attachment of temporary chemical
cleaning piping.
System materials compatibility. All permanent components in the cleaning circuit should be
reviewed to ensure that they are compatible with the selected cleaning reagents. This is of
particular concern when hydrochloric acid is used and on overseas projects where
hydrofluoric acid or ammonium bifluoride are commonly used in the cleaning process.
Specification Scope of Work
The following temporary equipment, division of responsibilities, and services are considered when
developing the specification:
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2x100 percent circulating water pumps.
Temporary boiler (if required) and heat exchanger required for heating demineralized
water and cleaning solutions.
All necessary chemical injection pumps and demineralized water feed pumps.
All chemicals required for chemical cleaning, including, but not limited to, citric acid,
oxygen, aqueous ammonia, antifoam, corrosion inhibitor (Rodine or equivalent), and a
surfactant/degreasing chemical. Safety data sheets should be provided to Environmental,
Safety, Health, & Security for approval.
Fuel and fuel supply to all necessary equipment, including the temporary boiler and
circulating pumps.
All frac tanks necessary to hold cleaning solution wastewater, plus two complete rinses of
one HRSG/feedwater unit, as well as additional frac tanks for margin and immediate
rollover to second HRSG/feedwater unit should be included. The frac tanks should include
a common header system, spill containment, and associated piping and valves to fill and
drain the frac tanks. The location of these tanks should be coordinated with site.
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Contractor should take the necessary steps to evenly distribute chemical cleaning drains
through all frac tanks, if possible.
A mobile laboratory and the analytical services to determine the process and completion of
flushing and chemical cleaning operations and to determine wastewater properties should
be provided. One of the instruments should be an atomic absorption spectrometer utilized
for monitoring the chrome content within the cleaning solution. The contractor’s staff
should include a chemist trained and experienced in running all tests on a 24 hour per day
basis.
All safety equipment required for the contractor’s personnel, including, but not limited to,
fall protection, boots, hard hats, goggles, face shields, chemical suits, gloves, safety harness,
and portable shower/eyewash stations.
All necessary chemical spill cleanup materials, containment berms, and temporary pipe drip
pans.
All temporary flow meters, pressure gauges, and temperature meters necessary to complete
the chemical cleaning.
In-line strainers, including pressure gauges and strainer isolation valves, should be
provided for use during the course of all flushing and chemical cleaning operations. The
services performed should include periodic cleaning of the strainers.
All temporary barricades and other safety devices necessary to limit access in the
hazardous areas during chemical cleaning operations.
All temporary piping.
Figure 18-6 depicts the chemical cleaning circulating pumps.
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Figure 18-6
18.5.3
Chemical Cleaning Circulating Pumps
System Sizing
The responsible mechanical engineer and the responsible chemical engineer work together to
produce a preliminary chemical cleaning P&ID and/or flow diagram. Systems that require chemical
cleaning or hydromilling have the chemical cleaning and/or hydromilling connections located on
the P&ID prior to distribution for routing.
The chemical cleaning connections and temporary piping are sized to provide the required flow
rates necessary to support chemical cleaning, filling, flushing, and draining operations. The
responsible chemical engineer provides the flow rates required to maintain the velocity
requirements within both the permanent piping to be cleaned and the temporary piping. Piping
design interfaces to permanent piping should be in accordance with ASME B31.1 requirements,
unless otherwise approved by the Chief Mechanical Engineer. Temporary piping does not need to
meet all criteria of ASME B31.1, but is designed safely using B31.1 as a guideline. Carbon steel
piping is typically used for chemical cleaning temporary pipe. The responsible engineer is consulted
to determine the acceptability of the temporary materials.
18.5.3.1 Piping Connections
Wherever possible, removable spool pieces are suggested to aid in the effective cleaning and easy
connection of temporary interface piping to the main process pipe. Removable spool pieces are
especially effective in the cleaning of boiler feed pump piping, where the boiler feed pump has
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either a vertical suction or vertical discharge connection. The vertical connections will act as
collecting points for cleaning deposits/debris during the chemical cleaning process. Removable
spools will facilitate manual cleaning of these dirt collection locations.
During condensate and boiler feed system design, the physical layout is reviewed to make sure
removable spool pieces are easily accessible for removal and reinstallation. The physical layout of
other chemical cleaning connections are also reviewed to ensure that sufficient space is provided to
attach and make the transition to temporary chemical cleaning piping.
In areas where removable spool pieces cannot be provided, flanged chemical cleaning connections
on permanent piping upstream of the boiler feed pumps may be used. Temporary connections
downstream of the boiler feed pumps may be either welded or provided with Grayloc fittings and
hubs to eliminate a possibility of leaks.
The chemical cleaning contractor is normally required to supply adapter spools between the
permanent piping connections and temporary piping. Cut plate flanges may be a preferred option to
ASME flanges, particularly for large diameter HP flanges. All cut plate flanges must be approved by
the responsible chemical or mechanical engineer prior to their use.
18.5.3.2 Vents and Drains
Vents are used at all piping high points to allow the removal of trapped air in the piping during the
initial fill operations and to facilitate the draining operations after the chemical cleaning process is
completed.
Drains are used to allow complete drainage of all equipment and piping systems that were either
chemically cleaned or temporarily installed to support chemical cleaning. Drains are sized to allow
draining of system components within a reasonable time.
Temporary hoses are installed on all air vents, drains, and test connections to be used in the
flushing and cleaning operations. The hoses are routed to location(s) designated by the
construction manager. In some cases, in order to reduce the amount of hose to be installed, it may
be desirable to have a hose installed on one connection at a time and physically move that hose
from one connection to the next throughout the cleaning operations.
During the final rinse, all drains, vents, and dead legs are flushed until the fluid is visually clear, to
remove any pockets of chemicals. Fluid flushed from these lines is collected and disposed of with
the chemical cleaning rinse waste.
18.5.3.3 Routing
Temporary pipe routings should be as direct as possible, preferably without low points. If low
points cannot be avoided, they should be provided with drain connections.
18.5.3.4 Instrument Connections
Prior to chemical cleaning, all instruments in the chemical cleaning path should be disconnected as
close to the primary isolation valve as possible. If physically disconnecting the instrument is not
possible, the instrument should be isolated and protected from exposure to the chemical cleaning
fluid. Protection of a connected instrument can generally be accomplished by closing all primary
isolation valves, instrument shutoff valves, and equalization valves to the connected instrument and
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opening the instrument blowdown valve(s) so that the instrument blowdown serves as a telltale.
The instruments remain disconnected until after the completion of chemical cleaning.
During the final rinse, all instrument lines are flushed until the fluid is visually clear, to remove any
pockets of chemicals. Fluid flushed from these lines is collected and disposed of with the chemical
cleaning rinse waste.
18.5.3.5 Mechanical Accessory Equipment
Mechanical accessory equipment is installed or removed as follows:
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Strainers--Permanent strainer internals (baskets, screens, etc.) removal is on a case-by-case
basis. If the strainers can trap dirt or debris in the primary cleaning circuit (such as on
boiler feed pump [BFP] suction strainers), they should be removed. However, where the
strainer drain is used as a chemical cleaning connection (such as on spray line strainers),
retaining the strainer will help ensure that dirt and debris do not get lodged in the strainer
outlet where they could be transported downstream to a control valve. Any strainers kept in
the system during the cleaning process are removed and cleaned following chemical
cleaning.
Gauge Glasses--Temporary gauge glasses (or suitable clear plastic tubing) are installed on
the boiler drum water column, heater shells, or other locations that require monitoring of
the cleaning solution level. If the cleaning chemicals will not damage the permanent gauge
glasses, the permanent gauge glasses may be used instead of temporary gauge glasses.
Mist Eliminators--The mist eliminators can trap cleaning chemicals if the drum levels are
too high. The steam separators should be removed from the boiler drums during cleaning
and replaced following final inspection of the drums.
18.5.3.6 Valves
Permanent valves are addressed as follows:
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Globe body style control valves in systems that require chemical cleaning are either isolated
and bypassed, or have their internal trim components removed. The manufacturer of a
control valve can usually provide a temporary cleaning adapter to be used in lieu of the
trim, if the first two options are not feasible. The engineer identifies these valves prior to
procurement so that these adapters can be purchased upfront.
Check valve internals are removed or pinned open prior to chemical cleaning. Internals that
remain in the valves are checked for material compatibility with the chemical cleaning
solutions being used.
Extraction steam, cold reheat (CRH), hot reheat (HRH), and LP steam block valves are
closed, and provisions should be made to continuously drain, monitor, and collect all
downstream drip legs or piping sections.
Other valves may require special preparations prior to chemical cleaning and should be
evaluated on a case-by-case basis.
Temporary valves are addressed as follows:
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Gate, ball, and butterfly valves are typically used in temporary chemical cleaning pipe.
18.5.3.7 Flow Elements
Flow orifices that are in the chemical cleaning circuit are removed during chemical cleaning. System
engineers determine if flow elements are welded or flanged into the line, and will bypass the
chemical cleaning flow around welded flow elements if the manufacturer and/or the engineer
determines that chemical cleaning will impact the accuracy of the flow element.
18.6
Systems Requiring Chemical Cleaning
18.6.1
Combined Cycle Units
The following combined cycle systems and equipment may require chemical cleaning. For each of
these systems, consideration is given to the following items: manufacturer’s chemical cleaning
requirements for major equipment, system equipment that may need to be bypassed by the
chemical cleaning process, equipment requiring manual chemical cleaning, and system valves that
require either spare trim sets or internals removed prior to chemical cleaning.
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Condensate.
Boiler Feedwater.
Main Steam and Superheater.
Hot and Cold Reheat, if Superheater and Reheater.
LP Steam and Superheater.
Condenser--The condenser hot well is manually cleaned and is not used to store chemical
cleaning solutions.
External Deaerator--Where possible, the deaerator is bypassed during chemical cleaning
using temporary piping. Chemical cleaning connections for bypassing the deaerator are
located as close to the deaerator as possible, to maximize the piping to be chemically
cleaned. The deaerator and storage tank are manually cleaned and are not used to store
chemical cleaning solutions. If it is not possible to bypass the deaerator, the trays should be
removed prior to cleaning. If the deaerator is included in the chemical cleaning circuit, the
deaerator should be inspected following the chemical cleaning process. This inspection
determines if additional manual cleaning is required.
Condensate Pumps--Temporary chemical cleaning pumps are used to chemically clean the
preboiler systems and boiler. It is recommended that the condensate pumps be isolated and
not be used for any chemical cleaning operation, with the exception of distributing treated,
demineralized water or for an initial high velocity piping flush of the condensate and boiler
feedwater systems.
Boiler Feed Pumps--BFPs are bypassed using temporary spool pieces, or the pump internals
are removed during chemical cleaning. Bypassing the pumps is the preferred method,
because the pump internals would not have to be removed, and because solids will settle
out within the pump during chemical cleaning, despite the initial flushing process. Solids
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within the pump must be removed manually, prior to reinstalling the pump internals.
Removing and reinstalling pump internals is expensive.
HRSGs--The engineer should evaluate best cleaning flow paths through the HRSG drums by
referring to the manufacturer’s recommended chemical cleaning practices. Steam
separators and integral deaerator internals may need to be removed for chemical cleaning
in accordance with the manufacturer’s directions. This may be affected by the selection of
steam or air blows and the scope of the cleaning operations. The manufacturer’s materials
of construction should be reviewed to determine if there are any components containing
chromium in the flow path. If so, or if the superheaters and steam pipe are cleaned, the
wastewater may have a significant chrome concentration.
Boiler Circulation Pumps--In forced circulation boilers, the boiler manufacturer should be
consulted early on to determine if the boiler circulation pumps can be used during chemical
cleaning to aid in the circulation of the boiler. If permitted to be used by the manufacturer,
the boiler circulation pumps will greatly improve the chemical cleaning velocities achieved
within the boiler tubes and overall quality of chemical cleaning. If not permitted by the
manufacturer, the boiler circulation pumps are isolated and bypassed using temporary
spool pieces.
Rotor Air Cooler--The engineer will evaluate if the rotor air cooler should be cleaned.
Typically, the cooler is bypassed during chemical cleaning.
Fuel Gas Heater--The fuel gas heater is bypassed.
Other separate items that may need to be addressed include the following:
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Flow elements (annubar type).
Orifice plates.
Check valves.
Control valves.
Relief valves.
Steam jet air ejector inter/aftercooler.
Gland steam condenser.
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18.6.2
Thermal Units
The following thermal unit systems and equipment require chemical cleaning. For each of these
systems, consideration is given to the following items: manufacturer’s chemical cleaning
requirements for major equipment, system equipment that may need to be bypassed by the
chemical cleaning process, equipment requiring manual chemical cleaning, and system valves that
require either spare trim sets or internals removed prior to chemical cleaning. Steam systems are
usually cleaned only if air blows will be used:
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Hot and Cold Reheat.
BFP Turbine Drive Steam.
Makeup Water.
Condensate.
Boiler Feedwater.
Main Steam.
Boiler--The boiler manufacturer provides temporary cleaning piping connections and caps,
as well as typical chemical cleaning requirements and recommendations for their
equipment.
It is becoming more common within the industry to chemically clean both the water and steam
circuits of a boiler. If the accepted chemical cleaning procedure does not include cleaning of the
boiler steam circuits, and/or the superheaters do not have drains, then the superheater is
backflushed to prevent chemicals from entering the superheater. If the superheaters are drainable,
they may be included in the chemical cleaning circuit. Field personnel should be consulted to
determine if cleaning through the superheaters is advantageous to the project. Cleaning through the
superheaters will affect the wastewater quality because of the additional chrome pipe. If chromium
concentration is a concern in the wastewater, cleaning through the superheaters may not be
advantageous.
Superheaters that cannot be drained are rinsed or backflushed with treated demineralized water to
prevent corrosion until the boiler is fired. Treated demineralized water consists of demineralized
water with enough ammonia to raise the pH above 10. If there is an extended period following
cleaning until the boiler will be fired, consideration should be given to adding 50 ppm of hydrazine,
or an equivalent dosage of another oxygen scavenger, to the treated demineralized water.
Typical chemical cleaning requirements and recommendations should be obtained from the boiler
manufacturer. The boiler manufacturer should be informed of, and be in agreement with, the
desired chemical cleaning method that will be used to clean the boiler and protect boiler
components. Care should be taken to follow the boiler manufacturer’s recommendations for
equipment removal (e.g., steam separators). It is strongly recommended that the boiler
manufacturer review and accept the cleaning procedure.
18.7
References

Example chemical cleaning procedures (found through the Industrial Water Treatment
Community page).
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19.0 Cleanliness Control
19.1
Purpose and Applicability
Each power project will need a Cleanliness Control Guide developed by the chemical design
engineer and tailored to the project. The process steps to develop a thorough Cleanliness Control
Plan are outlined in Table 19-1.
Table 19-1
Cleanliness Control Project Checklist
ACTION
RESPONSIBLE PARTY
1
Set Cleanliness Control meeting for
project.
Project Manager (PM)
3
Develop Cleanliness Control Plan.
PM/Project Discipline
Engineer (PDE)-Chem
Include in Project Design
Manual (PDM) when complete.
Develop design/procurement plan
related to cleanliness.
PM/PDEs
Finalize Appendix A for project.
Develop construction plan related to
cleanliness.
PM/Construction Manager
(CM)
2
4
5
6
7
8
9
10
11
12
13
14
15
Determine extent project will utilize
standard.
Review heat recovery steam
generator (HRSG) and steam turbine
generator (STG) specs or contract for
water quality and steam purity.
Develop quality plan related to
cleanliness inspections.
Develop startup plan related to
cleanliness.
Develop plan for hydrostatic testing
water.
Determine if project will use steam
blow or air blow.
Develop plan for short- and long-term
HRSG lay-up.
Develop plan for cleanliness related
field engineering support for startup.
Develop plant water chemistry
guideline.
Determine scope of analytical
equipment used in startup.
Develop hydro/chemical cleaning
waste disposal plan.
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PDE-Chem
PM/Quality Assurance (QA)
/Quality Control (QC)
NOTES
Develop Cycle Chemical Feed
Plan.
PM/Start-Up Manager
(SUM)
PM/PDE-Chem
PM/PDEs
PDEs/CM/SUM
If air blow, Step 6 becomes
more involved.
PM/PDE-Chem
PDE-Chem
PDE-Chem/SUM
PM/PDE-Chem
19-1
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Table 19-2, at the end of this section, contains the recommended cleanliness control guidelines for
each system. This table will need to be edited based on the project requirements and included in
the project Cleanliness Control Guide.
19.2
Approach
This guide addresses the design, procurement, fabrication, construction, and commissioning phases
of the project.
19.3
Overview
The five main phases of the project where cleanliness control needs to be considered are:



Design and procurement.
Fabrication.
Construction.

Commissioning.
19.4
Provisions for Cleanliness Control During Design and Procurement

Initial operation.
Cleanliness control affects design and procurement in the following activities:

Preparation of design documents, such as pipeline lists.

Preparation of equipment procurement specifications.
19.4.1
Preparation of Design Documents – Pipeline Lists

Preparation of mechanical construction specifications.
The pipeline lists contain an available input field to identify the required level of cleanliness and
method of corrosion inhibition following fabrication and prior to erection. This input field should
be used to provide consistent and clear direction to the piping fabricator and the piping erector
regarding the required level of cleanliness for each piping system of the project. There are five
established interior cleaning methods, based on The Society for Protective Coatings (SSPC)
standards, available for assignment to a pipeline:





NO - No special cleaning required.
SP3 - Power tool cleaning.
SP6 - Commercial blast cleaning.
SP8 - Pickling.
WJ1 - Water jetting in the field to SP12, WJ1 cleanliness.
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There are also six established interior coating options that can be applied to each pipeline:






1001 - Vapor phase corrosion inhibitor (water soluble).
1002 - Oil soluble preservative.
1003 - Consumable (weldable) coating.
2314 - Epoxy coal tar.
CP - Coating prohibited.
NONE - Coating not required (manufacturer’s standard coating system).
Power tool cleaning, identified by cleaning method SP3, is typically applied to water and oil systems
requiring only a minimal level of cleaning, such as well water and fuel oil. There is no preservative
or coating for this type of cleaning, and it should be identified as coating option, NONE.
Commercial blast cleaning, identified by cleaning method SP6, is typically applied to water and
steam piping systems requiring a higher level of cleaning. The proper preservative or coating for
this type of cleaning and ultimate service is the water soluble preservative, identified by coating
option “1001.” Certain piping systems with a higher concentration level of solids may require a
different interior coating, such as an epoxy coal tar, identified by coating option 2314.
Pickling, identified by cleaning method SP8, is typically only required for piping systems that
contain oil, such as turbine lube oil. The proper preservative for this type of cleaning and ultimate
service is the oil soluble rust preventative, identified by coating option 1002. (It should be noted
that the fluid for the steam turbine electrohydraulic control [EHC] may not be compatible with
Black & Veatch’s [B&V] applicable oil and oil soluble preservatives. The final interior cleaning
method and coating system will be identified by the Project Mechanical Engineer on the pipeline
list.)
Water jetting to SP12 requires a high- or ultra high-pressure to prepare a surface for recoating,
using pressure above 10,000 pounds per square inch (psi) (690 bar). To obtain the WJ1 condition
for clean to bare substrate quality, the surface should be free of all previously existing visible rust,
coatings, mill scale, and foreign matter and have a matte metal finish. This type of cleaning is
typically applied to prefinished metals, plastics, and/or previously painted surfaces. There is no
preservative or coating for this type of cleaning, and ultimate service should be identified by
coating option CP.
The Materials Application Section Head and the Project Chemical Engineer should be consulted
before additional interior coatings are identified as a pipeline interior coating or preservative.
Stainless steel piping should not be internally cleaned or coated with a preservative.
Machined surfaces of weld-end preparations should be coated with consumable rust-preventative
coating identified by coating option 1003.
Refer to Table 19-2, at the end of this section, for a summary of the cleanliness levels that should be
followed for various piping systems.
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19.4.2
Preparation of Design Documents – Pipeline Design
During the design phase of a project, consider the following aspects that impact cleanliness control:
1.
2.
Pipe routings and plant equipment arrangements should avoid dead legs, nonvalved bypasses, and inaccessible or non-flushable piping sections where
contaminants can collect and reside.
When inaccessible pipe routing cannot be avoided, the following provisions can be
considered to permit direct visual or borescopic inspection, mechanical cleaning, air
blowing, vacuum cleaning, water flushing, high-pressure lancing, and/or chemical
cleaning of the affected area(s):





3.
Removable caps or plugs.
Flanged or piping connections.
Removable flanged piping connections.
Additional permanently valved high and low point vent and drain
connections.
Accessibility to manways and handholes for equipment and ductwork.
Early in the design process, piping connections should be identified, located, and
designed into the piping systems for chemical cleaning operation access. Connection
sizes should be selected to allow a flow velocity of 2.0 to 3.0 feet per second in the
main piping of the condensate and feedwater systems during cleaning operation.
Size and number of cleaning connections in vendor package equipment (such as the
boiler) should be specified in the procurement package.
4.
Connections should be located and designed in the condensate system to allow for
the use of a portable condensate polishing or condensate filter system.
6.
The Materials Applications Section reviews the selection of materials of
construction and protective coatings and linings.
5.
7.
Equipment internal pipe bracing and other support members should be designed or
provided with drain holes to preclude stagnant non-flow areas and water
accumulation, corrosion products, grit blasting materials, and other contaminants
that could impair cycle cleanliness. Such supports can be found in steam surface
condensers, deaerators, and similar equipment.
The use of an air-cooled condenser presents an additional concern for cycle
contamination with regard to the buildup of corrosion products. This concern is
primarily based on the vast amount of carbon steel surface area that an air-cooled
condenser exposes to condensate. The operating regime of the facility will have a
significant bearing on the impact that an air-cooled condenser cycle has on
cleanliness. There are baseloaded facilities that have successfully operated without
the addition of a condensate polishing system or a condensate filter system to
control corrosion product transport. However, it is highly recommended that any
facility with an air-cooled condenser be provided with a permanent condensate
polishing or condensate filter system for operating cycle cleanliness control.
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8.
19.4.3
Stainless steel piping materials should be considered for certain sections of the
condensate and feedwater pipelines and for equipment exposed to condensate and
feedwater where the cycle makeup supply could contribute significant
concentrations of dissolved oxygen to portions of the cycle before proper deaeration
can be performed, unless the high purity requirements of oxygenated treatment can
be consistently achieved. An example of this is a cogeneration plant with a large
percentage of cycle makeup using non-deaerated demineralized water. Stainless
steel should also be considered when the normal use of neutralizing amines, such as
ammonia, is not possible due to unusual situations (e.g., cogeneration where steam
contact with food products prohibits amine usage).
Preparation of Equipment Procurement Specifications
The Chemical PDE reviews the steam generator and steam turbine specifications for feedwater
quality and steam purity.
All procurement specifications require that fabricators submit a quality manual and an inspection
and test plan. Several OneSpec master specifications contain language to address the required
cleanliness for fabrication, shipment, and onsite storage of equipment and materials. These
specifications include, but are not limited to:










Deaerator.
Surface/Single Pressure/Dual Pressure Condenser.
Boiler Feed Pump.
Feedwater Heaters.
Shop Fabricated Piping.
General Service Piping.
Shop Fabricated Tanks.
Field Erected Tanks.
Steam Generator.
Steam Turbine.
Specifications can be added to or removed from this list depending on the specific project
requirements. Topics covered in these master specifications include the following:




Packaging.
Shop coating.
Rust-preventive compounds.
Painting.
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







Preservative coatings.
Protection (during shipment, handling, and storage).
Cleaning solvents for austenitic stainless steel components.
Mechanical cleaning of austenitic stainless steel components.
Marking of austenitic stainless steel components.
Tapes for sealing austenitic stainless steel components.
Inspection and testing (of fabricated piping assemblies).
Cleaning, painting, and marking of interior surfaces. Master specifications on cleaning cover
the following:
●
●
●
●
19.4.4
Power tool cleaning.
Blasting material specifications (refer to the Coating System and Blast Media
Selection Procedure).
Pickling.
No special cleaning required.
Preparation of Mechanical Construction Specifications
The following OneSpec master specification section addresses the required level of cleanliness
intended for fabrication, shipment, and onsite storage of equipment and materials:

Section 15921, Piping Erection.
The following OneSpec supplemental specifications also address cleanliness control:


M801, Mechanical Equipment Erection.
M802, Piping Erection.
These specifications address requirements pertinent to cleanliness control, including the following:






Mechanical Equipment and Systems--testing, checkout, and calibration.
Pre-Operational Testing and Startup.
Equipment Erection.
Piping Erection--pressure testing of pipe, instrumentation and control (I&C) tubing tests,
leakage tests, and underground water pipelines.
Cleaning of Pipe--blowing out steam piping and chemical cleaning.
Sterilization of Equipment and Piping.
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19.5
Provisions for Cleanliness Control During Fabrication
Cleanliness control during fabrication covers both fabrication of equipment in a fabricator’s shop
and packaging of equipment for shipment. The equipment supplier should provide a written quality
assurance plan with a test and inspection outline. This written plan is reviewed for cleanliness
control provisions by the QA engineer and Chemical PDE.
19.5.1
Fabrication of Equipment
Requirements for cleanliness control during equipment fabrication are primarily covered in design
documents and the equipment procurement specifications, as previously discussed in Section 2.1.
Additionally, the equipment supplier or fabricator is required, by purchase specification
requirements, to submit its QA manual and a quality plan that includes tests and inspections to be
performed for project approval prior to start of fabrication.
19.5.2
Shop Verification of Equipment Cleanliness
Condensate-feedwater-steam cycle equipment is required to be inspected during appropriate
fabrication stages to verify that the specified cleanliness control has been achieved and has been
documented. The inspections are identified in the project inspection and test plan.
The inspection points for cleanliness control may be the same as established inspection points for
verification of other contract requirements. The inspection points for cleanliness control of all shop
fabricated equipment are established based on the specific equipment involved. An important goal
of the inspection and verification program is to verify the exclusion of foreign materials, lubricating
oils, and other contaminants, such as blasting materials, from the internal surfaces and spaces of
the equipment at each appropriate stage of the fabrication process.
The final piece of equipment should be sealed in a dried condition and packaged in accordance with
B&V specifications.
19.5.3
Packaging of Equipment
Requirements for cleanliness control during equipment packaging are primarily governed by the
design documents and the equipment procurement specifications, as previously discussed in
Section 2.1. The specifications include requirements for factory assembly, consolidated shipments,
packaging and identification of spare parts, special shipping requirements, protection (equipment),
and protection during shipment (shop fabricated piping). The supplier or fabricator packaging
plans should be reviewed for comprehensiveness.
19.6
Provisions for Cleanliness Control During Construction
Cleanliness control during construction includes the following activities:




Receipt and unloading.
Storage prior to erection.
Equipment erection.
Storage prior to commissioning.
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19.6.1
Receipt and Unloading
The following activities need to be performed for condensate-feedwater-steam cycle piping and
equipment upon receipt at the project site:
1.
2.
Identification of any damage to condensate-feedwater-steam cycle piping and
equipment packaging, which may have occurred during shipment and handling, that
could directly impact the internal cleanliness of that equipment.
If inspection reveals that the piping and equipment’s internal cleanliness has been
compromised, immediate action should be taken by the Construction Manager to
correct the situation before the equipment is stored prior to erection.
Specific corrective actions are addressed in the Field Instructions Manual and Field Quality Control
Manual.
19.6.2
Storage Prior to Erection
In general, it is preferable for equipment and piping to be stored prior to erection in the same type
of packaging as it was received, if not the original packaging materials. This packaging includes pipe
and valve caps and covers, nitrogen blanketing, desiccants, and similar requirements. The integrity
of these storage measures should be maintained in accordance with equipment specifications and
Supplier recommendations.
The Construction Manager is responsible for verifying and documenting proper storage. Any
discovered incidents of contamination should be corrected prior to equipment erection. To
summarize, the following storage measures should be accomplished:



All protective covers, caps, and moisture controlling measures should be maintained in
place throughout the storage period.
The equipment and materials should be stored indoors or on pallets, as appropriate, for
protection from precipitation and from windblown dust and sand.
The rust inhibitor applied to components, equipment connections and weld ends should be
replenished, as appropriate.

The equipment and materials should be stored in accordance with the manufacturer’s
recommendations.
19.6.3
Equipment Erection

Nitrogen blanketing and inhibitors should be replenished, as appropriate.
The erection phase of a project subjects the internal surfaces of the condensate-feedwater-steam
cycle equipment and piping to more potential contamination than any other phase of the project.
Construction debris, hard hats, gloves, welding rods, drink cans, paper or plastic cups, sand, dirt,
insulation, etc., may inadvertently enter piping and connections on equipment during assembly or
prior to welding or flange bolting after caps and covers have been removed. Temporary caps,
covers, or similar methods of protection should be in place during suspended work periods such as
shift changes, weekends, etc. Cleanliness practices are to be part of the site QC procedures, and
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routine inspections and corrective actions need to be established in advance of erection activities.
The construction management team is responsible for documenting all inspections during the
erection phase.
Nitrogen blanketing and other corrosion control measures will need to be temporarily suspended
during the erection phase, but these measures should be reinstated as soon as practical following
erection.
19.6.4
Storage Prior to Commissioning
Storage of installed equipment and systems prior to commissioning should be based on factors such
as equipment manufacturers’ requirements, industry standards and guidelines, anticipated storage
duration, corrosion control, and practicality.
In general, equipment and piping systems should be kept dry and closed until it is necessary to
open them and begin commissioning operations.
19.6.5
Blast Media for Steam Cycle Service
Given the high purity steam quality requirements, the blasting media used shall contain no more
than 1.2 percent complexed silica and 0 percent free silica. Refer to the Coating System and Blast
Media Selection Procedure and the specific project Q301 supplemental.
Blasting media used by projects where steam cycle silica contamination might occur shall be limited
to aluminum oxide (pink or white grade), cut steel wire (Society of Automotive Engineers [SAE]
J441, Cut Wire Shot), or steel grit, as identified on Blast Media Data Sheet B1. Please note that some
blast media may be noted as “100% aluminum oxide” which can be “black in color” and not the
product commercially known as “Black Beauty®.”
Blasting media product data sheets shall be submitted to the MAS and Chemical PDE for review and
acceptance before use. Product data sheets shall include an ultimate analysis of the product that
indicates elemental and free silica content. Black Beauty®, Starblast®, slags, sand, or other materials
not meeting the criteria are prohibited from use.
19.7
Provisions for Cleanliness Control During Commissioning
Cleanliness control activities during commissioning include the following:





Piping and equipment cleaning and flushing.
Hydrostatic testing.
Verifying cleanliness of inaccessible and nonflushable areas.
Chemical cleaning and blowing of steam piping.
System and equipment outages.
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19.7.1
Piping and Equipment Cleaning and Flushing
This phase of the project should adhere to the requirements established in the Mechanical
Construction and Chemical Cleaning specifications. Refer to the post-installation cleaning column
in Table 19-2 for flushing water quality requirements.
A chemical engineer and/or plant chemist is required at this phase to coordinate chemical cleaning
and water chemistry, as a minimum. This can be accomplished by telephone communications or
visits to the site. The inspections need to be documented in an inspection report. The inspection
report should include the inspections and verifications of the following items at the completion of
installation and/or at the beginning of the commissioning phase of the project:
1.
2.
3.
4.
5.
6.
19.7.2
All pump suction pits and strainers should be free of trash, mud, silt, and debris.
All cooling and sealing water circuits should be flushed and checked for proper
operation.
All equipment should be verified as clean and should be visually inspected to be free
of loose debris prior to initial operation. Condensers and deaerators must be
thoroughly cleaned prior to initial operation.
Pump suction strainers should be checked periodically for clogging. These strainers
should be kept in service during initial operation and should be cleaned, as required,
to minimize pressure drop due to clogging. Whenever equipment is shut down due
to strainer clogging, the strainer should be cleaned immediately, regardless of the
time of day, to ensure equipment availability. New gaskets should be installed after
each cleaning operation. After initial operation, when strainer loading no longer
occurs, temporary strainers should be removed from the piping. Spacers should be
furnished and installed where temporary cone type strainers have been removed.
Branch lines and dead legs should be opened and flushed.
Consideration should be given to nonmetallic piping to ensure that proper flushing
is achieved. Some pipe joining methods, such as fusion joining for high density
polyethylene (HDPE), may form a larger than desired internal bead that may
prevent proper flushing. Internal beads may be trimmed for demineralized water
makeup and condensate HDPE piping prior to flushing if the project determines that
adequate flushing cannot be achieved. A bead trimmer, as manufactured by R&L
Manufacturing or acceptable equal, should be used.
Hydrostatic Testing
During this phase of commissioning activities, the use of an inappropriate water supply for
hydrostatic testing or the failure to adequately protect the system from corrosion following the
testing can contribute to system contamination. In the absence of the manufacturer’s hydrostatic
test procedures, the following water supply requirements should be used for all hydrostatic testing
of condensate-feedwater-steam cycle components and piping:

Treated demineralized water is preferred for all hydrostatic testing. Demineralized water
should have less than 5 parts per million (ppm) total dissolved solids and be free of
suspended solids. Sufficient ammonia should be fed to maintain final pH in the range of 9 to
10.
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The actual water supply used may need to be modified due to such considerations as the piping
materials exposed to the water, the availability of the water, or any waste disposal concerns with
the treated water. In the event that demineralized water is not available, clean service water may be
substituted. Treated demineralized water is required for hydrostatic test water.

Service water should be of potable water quality:
●
●
●
●
●
< 500 milligrams per liter (mg/L) total dissolved solids (TDS)
< 1 mg/L total suspended solids (TSS)
< 250 mg/L chlorides
< 250 mg/L sulfates
pH 6 - 9.
These water requirements are intended to be used for the testing of all carbon steel piping and
equipment normally encountered in condensate, feedwater, and steam systems. If treated
demineralized water is not used for hydrostatic testing, the equipment and piping should be
drained and later flushed with treated demineralized water prior to operation. It should also be
used as a guide for hydrostatic testing water used in systems that provide water to the steam cycle
(e.g., makeup water supplies and condensate return lines).
Coated carbon steel demineralized water storage tanks and condensate storage tanks should be
hydrotested with service water or potable water prior to being internally cleaned and coated.
19.7.3
Verification of Cleanliness of Inaccessible and Non-flushable Areas
As indicated in Subsection 2.1.1, the cleanliness of any inaccessible and nonflushable areas should
be verified at the appropriate times during hydrostatic testing, flushing, chemical cleaning, and
steam blowing of steam cycle piping and equipment.
19.7.4
Chemical Cleaning and Blowing of Steam Pipe
Adequate cleaning of the condensate-feedwater-steam piping prior to initial operation is an
important cleanliness control measure that should be performed before actual steam production by
the facility. Refer to Section 18.0, Chemical Cleaning. Typically, this last cleaning step is a
combination of chemical cleaning and steam blows. There are several options for the chemical
cleaning of a cycle. Cleaning techniques may include any or a combination of the following:






High purity water flushes.
Hydroblasting.
Chemical degreasing or alkaline cleaning.
Chelant solvent cleaning (EDTA).
Organic acid cleaning (citric acid or hydroxyacetic/formic acids).
Inorganic acid cleaning (hydrochloric acid).
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The extent of the cleaning needs to be carefully considered in conjunction with the operating
pressure of the cycle and the steam purity requirements of the receiving equipment. Some form of
degreasing should be used for all boiler and preboiler systems, and acid/solvent cleaning is needed
for operating pressures greater than 1,500 pounds per square inch gauge (psig) (100 bar). Lower
operating pressures would require progressively less cleaning, and higher operating pressures
would require progressively greater degrees of cleaning. If the project cleanliness control program
has been effective, the degree of chemical cleaning may be reduced without an impact on the
commissioning operations. However, if there is any doubt regarding the cycle cleanliness, it is
recommended that the degree of chemical cleaning be increased rather than run the risk of an
extended cycle cleanup period once initial operation has begun. Chemical cleaning prior to
operation saves significant time and operation costs when compared to a shutdown and cleaning.
During the chemical cleaning selection process, consideration should be given to manufacturer’s
recommendations and any wastewater discharge permits previously obtained for the project.
Blowing steam through the piping system at high velocities is a standard method to clean steam
piping. Precleaning the steam piping by hydroblasting or solvent cleaning prior to steam blows can
significantly decrease the number of steam blows and, correspondingly, the time required to
adequately clean the steam piping. The decision to preclean the steam piping should be based on
the following considerations:




Effectiveness of the cleanliness control program up to this point in the project.
Amount of steam piping involved.
Ability to adequately drain the cleaned piping sections of the solvent.
Final steam purity requirements of the receiving equipment or processes.
The decision to hydroblast should be made early in the design process in order to design access into
the piping. Typically, a minimum connection size of 4 inches (100 mm) is needed to allow adequate
space for the jetting hose as well as drainage. Connections for hydroblasting should be located on
the bottom of the pipe and as low as possible in the piping system to facilitate proper drainage. In
addition, the number of points is dependent upon the pipe size and the number of bends.
Air blow cleaning is not a generally recommended method for cleaning steam cycle piping. The level
of cleanliness control required during shop fabrication, delivery, storage, handling, erection, and
startup is extremely high for the air blow method. A high level of QC is required to ensure that the
cleanliness requirements are followed. The decision to use air blows should be made as early in the
project as possible so that the stringent quality requirements can be planned for.
19.7.5
System and Equipment Outages
It is important to watch out for cleanliness concerns during system and equipment outages,
especially when steam cycle equipment is opened and entered, to minimize the possibility of
introducing contamination and corrosion.
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There are two typical approaches to cycle layup: wet layup and dry layup. In the absence of specific
manufacturers’ layup procedures, observe the following:
The use of wet layup is preferred if the period of downtime is a few days or weeks. The
manufacturer’s wet layup procedures should be followed where provided. In the absence of
manufacturer’s wet layup procedures, the water that is remaining in the system following normal
operation should be dosed with an oxygen scavenger that contains no organic materials
(to 200 ppm), or a proprietary oxygen scavenger that may contain organic materials, if cycle
chemistry requires, at the manufacturer’s recommended concentration and ammonia. Ammonia
should be fed to a pH of 10.0 for noncopper bearing systems. Wet layup should be avoided if the
system cannot be adequately protected from freezing. If proprietary oxygen scavengers (which may
contain organic materials) are used for wet layup after chemical cleaning, then prior to operation
the equipment and piping need to be drained and filled with an oxygen scavenger that contains no
organic materials.
The steam cycle should be stored in a dry layup condition if the shutdown is anticipated to last
more than a few weeks or if freezing is a possibility. A dry layup is performed by draining the cycle
while it is still hot from operation and then purging with nitrogen until dry. The cycle should then
be sealed with a nitrogen blanket until operations resume. If entry into the system is needed during
the outage, the effected sections of the steam cycle can be opened as needed and purged with clean,
oil-free air prior to entry. An alternative dry layup method involving circulation of warm dry air is
also acceptable for long-term storage. The equipment supplier should also be consulted regarding
recommended dry layup procedures for extended shutdown periods.
19.8
Considerations for Cleanliness Control During Initial Operation
Once the facility has begun initial operation, potential operating conditions that can contribute to
inadequate cycle purity include the following:



Poor quality cycle makeup water.
Condenser tube leaks.
Operator’s chemical feed selection.

Contaminated process condensate return.
19.8.1
Poor Quality Cycle Makeup Water

Inadequate deaeration.
Poor cycle makeup water quality can originate from inadequate removal of dissolved solids, silica,
or organic compounds with the treatment process used. These potential problems should be
thoroughly investigated to determine if treatment equipment is operating properly or if makeup
water quality has changed significantly from design, or otherwise addressed during the early stages
of the project.
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19.8.2
Condenser Tube Leaks
Condenser tube leaks (or seepage due to poor tube-to-tubesheet seals) can occasionally occur, and
it is important that this potential contamination source be quickly identified and the appropriate
tubes be isolated or the tube joints be resealed, to avoid extensive delays during startup operations.
19.8.3
Operator’s Chemical Feed Selection
Many owners have taken the approach, in recent years, of contracting chemical supplier services,
e.g., Nalco, GE Betz, Chem Treat, etc., for all their facility chemical needs. Identifying the chemical
supplier and receiving chemical Safety Data Sheets (SDSs) early in the design phase would be
beneficial to the project. SDSs shall be submitted to the Chemical PDE for review and acceptance
before use.
Refer to Section 10.0, Cycle Chemistry for further details on cycle chemical feed design.
The use of oxidizing all-volatile treatment (AVT[O]), with ammonia or amine addition is the
preferred oxidizing treatment in B&V power plant projects. Standard CS piping materials and
components can be utilized with the use of AVT(O) to manage and/or prevent FAC failures in
single-phase flow services. The use of reducing agents (oxygen scavengers such as hydrazine) is
not a recommended design practice at B&V. The use of any reducing agent shall be reviewed and
approved by the Chemical PDE and Engineering Manager.
The use of amines other than ammonia and the use of oxygen scavengers that contain organic
materials could result in contaminants being introduced into the condensate-feedwater-steam
cycle. Such contaminants add to cation conductivity values and can result in the inability to meet
the turbine manufacturer’s steam purity requirements. Meeting steam purity is a requirement of
maintaining the steam turbine manufacturer’s warranty.
If B&V is responsible for startup operations and liquidated damages (LDs) are involved, contracts
with clients must exclude boiler additives that contain any organic materials. Otherwise, the owner
or operator should understand that it risks voiding the turbine warranty. The owner should
negotiate with the turbine manufacturer to allow the use of the alternate chemicals and appropriate
cycle chemistry limits that allow the use of alternate chemicals.
One effective way of dealing with this potential is to use specific non-carbon dioxide contributing
chemicals for startup operations. Following turnover of the facility to the owner, the chemical
supplier-preferred chemicals could then be used. If proprietary chemicals that contain organic
materials are used, the project should consider the purchase of a sample reboiler or a nitrogen
stripping column to determine cation conductivity measurements of degassed samples. One such
instrument is the Martek dissolved carbon dioxide analyzer. This could be used as evidence that the
carbon dioxide decomposition products of the chemicals being fed to the cycle are causing
exceedingly high cation conductivity measurements.
The oxygenated chemistry program AVT(O) does not require the use of oxygen scavengers during
the startup and commissioning periods nor during the initial hours of boiler operation. B&V, in
keeping with Electric Power Research Institute (EPRI) recommendations, does not recommend use
of an oxygen scavenger at any time for units that are operating oxygenated chemistry programs.
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19.8.4
Contaminated Process Condensate Return
The potential for contaminated process condensate return should be considered when the facility
produces steam for off-site process services. Contamination of returned condensate needs to be
carefully monitored especially during initial operation. Limits for contamination levels should be
clearly defined in the contract.
19.8.5
Inadequate Deaeration
Inadequate deaeration can also impact cycle water/steam quality. Proper mechanical deaeration of
the feedwater should be verified during initial operation.
19.8.6
Special Considerations for Joint Venture EPC Projects and Consortia
When B&V is a member of a joint venture or a consortium involved in an Engineering, Procurement,
and Construction (EPC) project, B&V’s experience and recommendations on cleanliness control
may not be adopted by other joint venture partners or consortium members for their portion of the
project. In order to avoid problems, it is essential to provide for and manage cleanliness control of
any part of the project not under the direct control of B&V when such control may have a direct
impact on the success of the project.
The following measures are suggested to mitigate the risk associated with cleanliness control for
EPC turnkey projects:


The Chemical PDE should educate joint venture partners on our cleanliness control
standards.
The Chemical PDE can clearly define the cleanliness control responsibilities of each party of
each participant’s scope of supply. This should also address the consequences of failure to
provide adequate cleanliness control with regard to commissioning activities.
The Chemical PDE can include provisions that cover the impacts of selected cycle chemicals.
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Table 19-2
Cleanliness Control Guidelines for Various Piping Systems
SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.0201
Bottom/Bed Ash
Low
NO
NONE
Not Applicable
00.0203
Boiler Hopper/Economizer Ash
Low
NO
NONE
Not Applicable
SYSTEM
FILE
NUMBER
00.0202
00.0204
00.0205
00.0206
00.0207
00.0601
Fly Ash
Pulverizer Rejects
Flue Gas Desulfurization (FGD)
Solids
Combustion Waste Storage
Ash Pelletizing
Auxiliary Steam Supply
Low
Low
Low
Low
Low
High
NO
NONE
NO
NONE
NO
NONE
NO
NONE
NO
NONE
SP6
1001
00.0602
Auxiliary Boiler Fuel
Low
NO
NONE
00.0604
Process Steam Supply
(Cogeneration)
High
SP6
1001
00.0603
00.1001
00.1002
00.1003
Auxiliary Boiler Chemical Feed
High
NO
CP
FGD Reagent Receiving
Low
NO
NONE
FGD Reagent Preparation
Low
NO
NONE
FGD Reagent Storage and Reclaim
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Low
NO
NONE
19-16
POSTINSTALLATION
CLEANING(3,4, 5)
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Not Applicable
Not Applicable
Service Water
Flush
Not Applicable
Not Applicable
Chemical
Cleaning or
Steam Blow
Service Water
Flush
Demineralized
Water Flush
Chemical
Cleaning or
Steam Blow
Not Applicable
Post-installation cleaning
may not be needed for all
services.
Air dry immediately
following flush.
Post-installation cleaning
may not be needed for all
services.
Not Applicable
Service Water
Flush
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SYSTEM
FILE
NUMBER
SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
POSTINSTALLATION
CLEANING(3,4, 5)
00.1004
Limestone Receiving, Storage, and
Preparation
Low
NO
NONE
Not Applicable
00.1801
Station Air
Low
NO
NONE
Air Blow
00.1005
00.1802
00.1803
00.2001
00.2002
00.2003
00.2004
00.2005
Cured Pellet Storage and Reclaim
Control Air
Soot Blowing Air
Hydrogen Storage
Carbon Dioxide Storage
Chlorine Storage
Nitrogen Storage
Ammonia Storage
Low
High (SS)
High (CS)
Low
Low
Low
Low
Low
Low
NO
NONE
NO (SS)
SP6 (CS)
NO
NO
NONE (SS)
1001 (CS)
NONE
NONE
NO
NONE
NO
NONE
NO
NONE
NO
NONE
Not Applicable
Air Blow
Air Blow
Air Blow
Air Blow
Air Blow
Air Blow
Service Water
Flush or Air Blow
00.2006
Sulfur Dioxide Storage
Low
NO
NONE
Air Blow
00.2211
Construction Fire Protection
Low
NO
NONE
Service Water
Flush
00.2202
00.2601
Construction Water
Condensing
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Low
High
NO
NONE
SP6
1001
19-17
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Aqueous ammonia supply
lines between the storage
tank and the vaporizer
skid should be air dried
after hydrotesting or
flushing with water.
Service Water
Flush
Chemical
Cleaning or
Hydrolaze
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SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.2602
Condenser Air Extraction
Low
NO
NONE
Service Water
Flush
00.2605
Circulating Water Chemical Feed
High
NO
CP
Service Water
Flush
SYSTEM
FILE
NUMBER
00.2603
00.2606
00.2607
00.2801
00.2802
00.2803
00.2804
00.3201
00.3202
00.3401
00.3402
Circulating Water
Condenser Cleaning
Vacuum Priming
Generation Building Drains and
Plumbing (Coal)
HRSG/Piperack Area
Drains/Plumbing
Control Center Building
Drains/Plumbing
Administrative Building Drains and
Plumbing
Auxiliary Cooling Water
Closed Cycle Cooling Water
Boiler Feed
Boiler Feed Pump Injection
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Medium
Low
Low
Low
Low
Low
Low
Low
Medium
High
High
NO (SS)
NO (concrete)
NO
NONE (SS)
2314 (concrete)
NONE
NO
NONE
NO
NONE
NO
NONE
NO
NONE
NO
NONE
NO
NONE
SP3
NONE
SP6
1001
SP6
1001
19-18
POSTINSTALLATION
CLEANING(3,4, 5)
Service Water
Flush
Water Flush
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Consult Chemical PDE for
materials.
Service Water
Flush
Service Water
Flush
Service Water
Flush
Service Water
Flush
Service Water
Flush
Service Water
Flush
Service Water
Flush
Chemical
Cleaning
Demineralized
Water Flush
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SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.3403
Condensate and Condenser
High
SP6
1001
00.3404
Condensate Polishing
High
NO
CP
00.3405
Cycle Chemical Feed
High
NO
CP
Demineralized
Water Flush
00.3407
Process Condensate Return
High
SP6
1001
Chemical
Cleaning or
Hydrolaze
SYSTEM
FILE
NUMBER
00.3406
Cycle Makeup and Storage
High
NO
CP
00.3601
Generation Building Fire Protection
(Coal)
Low
NO
NONE
00.3603
Control Center Building Fire
Protection
Low
NO
NONE
00.3602
00.3604
00.3801
00.3802
Air Quality Control Building Fire
Protection
Administration Building Fire
Protection
Fuel Gas Supply
Burner Gas Supply
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Low
Low
High
Medium
NO
NONE
NO
NONE
SP6
1001
SP3
NONE
19-19
POSTINSTALLATION
CLEANING(3,4, 5)
Chemical
Cleaning or
Hydrolaze
Demineralized
Water Flush
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
In accordance with
manufacturer’s
recommendations.
Consult Chemical PDE for
materials.
Service Water
Flush
Service Water
Flush
Service Water
Flush
Service Water
Flush
Pigging (below
grade)
Air Blow (above
grade)
Air Blow
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Chemical Engineering Handbook
SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.4001
Fuel Oil Receiving and Storage
Low
SP3
NONE
Air Blow or Oil
Flush
00.4801
Chemical Cleaning
Low
NO
NONE
Not Applicable
SYSTEM
FILE
NUMBER
00.4002
00.4802
00.4803
00.5202
00.5203
00.5204
00.5205
00.5206
00.5407
00.5801
00.5802
Fuel Oil Supply
Shutdown Corrosion Protection
Vacuum Cleaning
FGD Liquids Sampling and Analysis
Water/Steam Cycle Sampling and
Analysis
Circulating Water Sampling and
Analysis
Water Supply Sampling and Analysis
Plant Effluent Sampling and Analysis
Site Fire Protection
Steam Generator
Combustion Turbine
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Medium
Low
Low
Low
High
Medium
Medium
Medium
Low
High
SP3
NONE
NO
NONE
NO
NONE
NO
NONE
NO
CP
SP3
NONE
SP3
NONE
SP3
NONE
NO
NONE
SP6
1001
High
19-20
POSTINSTALLATION
CLEANING(3,4, 5)
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Air Blow or Oil
Flush
Air Blow
Not Applicable
Service Water
Flush
Demineralized
Water Flush
Consult Chemical PDE for
materials.
Service Water
Flush
Consult Chemical PDE for
materials.
Service Water
Flush
Service Water
Flush
Consult Chemical PDE for
materials.
Fire Water Flush
Chemical
Cleaning or
Steam Blow
In accordance with
manufacturer’s
recommendations.
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SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.5803
First Stage Air Preheat
High
SP6
1001
Demineralized
Water Flush
00.5805
Ignitor Fuel
Medium
SP3
NONE
Air Blow
SYSTEM
FILE
NUMBER
00.5804
00.5806
00.5807
Second Stage Air Preheat
Boiler Vents and Drains
Main Steam/High-Pressure Steam
High
Low
High
SP6
1001
NO
NONE
SP6
1001
00.5809
Soot Blowing
Medium
SP3
NONE
00.5811
Cold Reheat Steam
High
SP6
1001
00.6001
High-Pressure Extraction
High
SP6
1001
00.6002
Low-Pressure Extraction
High
SP6
1001
00.6003
Extraction Drains
High
SP6
1001
00.5810
00.6004
Hot Reheat Steam
High-Pressure Heater Drains
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High
High
SP6
1001
SP6
1001
19-21
POSTINSTALLATION
CLEANING(3,4, 5)
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Demineralized
Water Flush
Not Applicable
Chemical
Cleaning or
Steam Blow
Air Blow
Chemical
Cleaning or
Steam Blow
Chemical
Cleaning or
Steam Blow
Chemical
Cleaning or
Steam Blow
Chemical
Cleaning or
Steam Blow
Demineralized
Water Flush
Demineralized
Water Flush
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SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.6005
Low-Pressure Heater Drains
High
SP6
1001
00.6201
Steam Turbine
High
SYSTEM
FILE
NUMBER
00.6006
Heater Vents and Miscellaneous
Drains
High
SP6
1001
POSTINSTALLATION
CLEANING(3,4, 5)
Demineralized
Water Flush
Demineralized
Water Flush
00.6203
Turbine Seals and Drains
High
00.6204
Turbine Lube Oil (Carbon Steel)
High
SP8
1002
Fluid Flush
00.6205
Generator Cooling and Purge
Low
NO
NONE
Air Blow
00.6204
00.6401
00.6402
00.6403
00.6601
00.6602
00.6603
Turbine Lube Oil (Stainless Steel)
Chemical Waste Drainage and
Treatment
Sanitary Drainage and Treatment
Wastewater Collection and
Treatment
Surface Water Supply
Well Water Supply
Service Water
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High
Low
Low
Low
Medium
Medium
Medium
NO
CP
NO
NONE
NO
NONE
NO
NONE
SP3
NONE
SP3
NONE
SP3
NONE
19-22
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Fluid Flush
Service Water
Flush
Service Water
Flush
In accordance with
manufacturer’s
recommendations.
In accordance with
manufacturer’s
recommendations.
No preservative for EHC.
Consult Chemical PDE for
materials.
Service Water
Flush
Raw Water Flush
Well Water Flush
Service Water
Flush
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SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
00.6604
Potable Water
Medium
SP3
NONE
Service Water
Flush
00.6605
Fire Protection Water Supply and
Storage
Low
NO
NONE
Fire Water Flush
00.6607
FGD Makeup Water
Low
NO
NONE
Service Water
Flush
SYSTEM
FILE
NUMBER
00.6606
00.6608
00.6801
00.6802
00.6803
00.6804
00.6805
00.6806
Ash Sluice Water
NOx Injection Water
Circulating Water Makeup
Treatment or Service Water
Pretreatment for Combined Cycle
(CC) Plants
Low - High Solids
High
Medium
NO
NONE
NO
CP
SP3
NONE
POSTINSTALLATION
CLEANING(3,4, 5)
Demineralized
Water Flush
Service Water
Flush
Medium
SP3
NONE
Service Water
Flush
Cycle Makeup Treatment
High
NO
CP
Demineralized
Water Flush
Combustion Turbine Injection Water
Treatment
Process Condensate Return
Treatment
September 2017 - Rev. 1
BLACK & VEATCH Proprietary and Confidential
Medium
High
High
SP3
NONE
NO
CP
NO
CP
19-23
Disinfect in accordance
with American Water
Works Association
(AWWA) standards.
Service Water
Flush
Service Water Treatment
Potable Water Treatment
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Service Water
Flush
Demineralized
Water Flush
Disinfect in accordance
with AWWA standards.
Consult Chemical PDE for
materials.
Demineralized
Water Flush
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SYSTEM
FILE
NUMBER
SYSTEM NAME
SYSTEM
CLEANLINESS
RATING
PIPING
FABRICATION
CLEANING
METHOD(1)
POSTFABRICATION
PIPING
PRESERVATIVE
OR COATING
OPTION(2)
POSTINSTALLATION
CLEANING(3,4, 5)
SPECIAL REQUIREMENTS
/ RECOMMENDATIONS
Notes:
(1)Piping Fabrication Cleaning Methods:
NO – no special cleaning required.
SP3 – power tool cleaning.
SP6 – commercial blast cleaning.
SP8 – pickled.
WJ1 – water jetting in the field to sp-12, wj1 cleanliness.
(2)Post-Fabrication Piping Preservative or Coating Options:
1001 – vapor phase corrosion inhibitor (water soluble perservative).
1002 – oil soluble preservative.
2314 – epoxy coal tar.
CP – coating prohibited.
NONE – manufacturer’s standard coating system or no internal coating require.
(3)Service water and demineralized water flushes should be performed with treated water as defined by the guide.
(4)Hydroblasting may be an appropriate alternative to chemical cleaning and steam blowing for certain applications, depending on piping length and accessibility.
(5)Air blow post-installation cleaning should be performed with clean, dry air.
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19-24
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Chemical Engineering Handbook
20.0 Startup Water Chemistry
20.1
Purpose and Applicability
This section provides the startup water chemistry guidelines applicable for all fossil fueled power
plant projects.
It is anticipated that the information in this section will be used as a guide to produce projectspecific startup water chemistry guidelines according to the contract required chemistry program.
This guide is then used to support the site startup personnel with chemistry limits, sampling and
analysis requirements, corrective actions, and procurement and handling of chemicals from steam
blow through startup and commissioning of the steam cycle components.
20.2
Approach
This section defines the type of information to be included with the startup water chemistry
guidelines and outlines the water chemistry program to be followed during the startup and initial
operation.
20.3
Overview
The startup water chemistry guidelines establish chemical limits and monitoring requirements for
critical startup and commissioning activities. The goals for establishing these criteria are as follows:








Expedite the startup process by minimizing contaminant entry into the steam and water
cycle during startup and commissioning.
Minimize the potential for impacts to steam cycle components from chemistry excursions
during startup and commissioning.
Provide criteria to recognize and quickly correct chemical excursions.
Maintain cycle cleanliness during startup and commissioning, ensuring long-term efficient
heat transfer in the heat recovery steam generator (HRSG).
Produce steam of the purity necessary for admission to and normal operation of the steam
turbine according to the manufacturer’s requirements, as well as to ensure compliance with
all warranty validation restrictions.
Protect the auxiliary cooling water system from scale, corrosion, and biological attack.
Protect the circulating water system from biological attack.
Provide guidelines for purchasing and handling steam cycle related chemicals.
The cycle chemistry program outlined in this section is appropriate to provide long-term, reliable
operation of the plant cycle. This section provides information for several different chemical feed
systems and all may not apply to a project. The program should be based on the cycle chemistry
program defined in the project contract. Most recent projects are based on using all-volatile
treatment oxidizing (AVT[O]) chemistry with ammonia feed.
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20-1
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The steam cycle startup chemistry program is based on the use of generic chemicals. If the Owner
requires any changes to this program during startup, the Project Startup Manager should
immediately contact the Project Chemical Engineer and/or the Startup Group Chemical Cleaning
Specialist to review and approve the Owner’s request. The use of proprietary chemicals, as offered
by water treatment chemical suppliers (e.g., Nalco Holding Company, GE Betz, or other vendors),
requires review. These chemicals often contain constituents that add carbon dioxide (that can alter
the cation conductivity of the steam samples), which affects the compliance to the steam turbine
manufacturer steam quality limits.
The startup water chemistry guidelines should contain information for the following subjects:






Hydrostatic test water.
Steam blow chemistry.
Steam cycle chemistry.
Corrective actions.
Cycle startup chemistry.
Lay-up of the cycle.

Circulating water chemistry.
20.4
Responsibilities

Auxiliary boiler chemistry.
The Project Chemical Engineer develops and issues the project water chemistry guide and monitors
its implementation through the startup and commissioning of the plant.
The Project Chemical Engineer and Startup Chemical Cleaning Specialist review and monitor the
execution of the project chemistry program and provide technical support for chemistry issues to
site startup personnel.
The Project Startup Manager is responsible for the implementation of the project chemistry
program at the site.
The Client will provide facilities and qualified personnel to perform the required analyses and
chemical control under the oversight of the Project Startup Manager.
20.5
Hydrostatic Test Water
These guidelines should be used in conjunction with the project Cleanliness Control Plan and the
steam turbine generator (STG) supplier’s recommendations. Consultation with the STG supplier or
its on-site representative may be necessary to resolve any differences between these guidelines and
their recommendations.
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During hydrostatic testing, the primary concern is to maintain system cleanliness by selecting the
most appropriate quality of water for testing and to prevent corrosion of system components after
hydrostatic testing. To this end, it is recommended that treated demineralized water be used for
hydrostatic testing of high purity components, including condensate-feedwater-boiler components,
steam piping, demineralized and condensate water storage tanks, makeup water supply lines, and
condensate return lines.
Treated demineralized water is defined as demineralized water containing less than 5 mg/L of total
dissolved solids (TDS) and 0 mg/L of total suspended solids (TSS). Aqueous ammonia should be
added to the demineralized water to give a final pH in the range of 9.5 to 10.0. The steam generator
hydrostatic test water should have a final pH of 10.3. An oxygen scavenger shall not be used as it
creates wastewater disposal concerns and is of little benefit for short-term exposure of the
hydrostatic test water.
To prevent potentially severe corrosion, the testing water should be drained from the system
within 48 hours of the completion of the hydrostatic testing. Catastrophic failures have occurred
from long-term exposure to stagnant, corrosive hydrostatic test water. Systems or components that
are susceptible to freezing should be considered for immediate draining.
Hydrostatic test water should be disposed of according to the mechanical construction contract and
adhere to the client’s National Pollutant Discharge Elimination System (NPDES) permit if disposing
to the cooling reservoir. This is to be reviewed and determined for each project.
20.6
Steam Blow Chemistry
This section should be used in conjunction with the STG supplier’s recommendations. Consultation
with the STG supplier or its on-site representative may be necessary to resolve differences between
these guidelines and its recommendations.
During steam blow, the primary water concerns are to keep the steam blow progressing, to
maintain the system cleanliness achieved during chemical cleaning and subsequent flushing, and to
minimize the corrosion of system components during steam blow. To this end, it is recommended
that demineralized water be used as makeup to the system during steam blow.
Demineralized water makeup is supplied by the Cycle Makeup Treatment System and may be
augmented by temporary (mobile) demineralizers, if required. The quantity of makeup water
depends on the unit configuration and blow philosophy. The quality of makeup water is defined in
Subsection 20.6.1.
It is recommended that the HRSGs be drained and stored under a nitrogen blanket during the
restoration period following steam blow. Refer to Section 20.7 for lay-up and draining
recommendations.
20.6.1
Steam Blow Chemical Feed
Chemical conditioning of the makeup water or condensate is recommended to offset the corrosive
nature of the high purity makeup water. Chemical feed using the Cycle Chemical Feed System
(FWE) is recommended.
It is recommended to adjust pH, as noted in Table 20-1, using aqueous ammonia (amine). Oxygen
scavenger feed shall not be used.
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Table 20-1
Steam Blow Demineralized Water Quality After Chemical Feed Parameters
ANALYSIS
FREQUENCY
PREFERRED
ACCEPTABLE
Specific Conductance
Continuous
10 to 15 µS/cm
< 20 µS/cm
Silica
Per 8 hour shift
< 10 ppb
10 to 30 ppb
pH
Continuous
9.5 to 9.8
µS/cm = microsiemens per centimeter
ppb = parts per billion
20.6.2
9.2 to 9.5
Steam Blow Makeup Water Quality and Monitoring
Makeup water for steam blow is used to maintain the boiler level as steam is exhausted to the
atmosphere. Although the purity of the steam for steam blows is not as critical as steam to the
turbine, demineralized water makeup is required to prevent damage to the steam generator. (Refer
to Table 20-2 for the preferred makeup water quality.) Makeup water quality is not as critical in
this step, which may permit the use of demineralized water trailers, if required.
Table 20-2
Steam Blow Makeup Water Quality Parameters
ANALYSIS
FREQUENCY
PREFERRED
ACCEPTABLE
Specific Conductance
Continuous
≤ 0.10 µS/cm
< 0.50 µS/cm
Silica
≤ 10 ppb
Continuous
10 to 30 ppb
Continuous monitoring of the cycle makeup water via the Water Quality Control System sample
panel or Cycle Makeup Treatment System effluent analyzers is recommended. Most demineralized
water trailers can be equipped with silica and specific conductance instrumentation for continuous
monitoring of the trailer effluent water quality; however, care should be taken to ensure that the
instrumentation is operating correctly. Alternatively, grab samples from the demineralized water
storage tank or Cycle Makeup Treatment System effluent can be collected and analyzed during each
8 hour shift.
Continuous monitoring of the condensate after chemical feed via the Water Quality Control System
sample panel is also recommended. Grab samples can be collected and analyzed during each 8 hour
shift.
20.7
Startup Steam Cycle Chemistry
The following subsections include a description of the cycle chemistry (normal operation, startup,
boiler setup/lay-up), cycle monitoring requirements, and corrective actions. The cycle chemistry
program outlined below is based on the Electric Power Research Institute (EPRI) TR-1010438,
Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators, dated March
2006. These are provided as a guideline only and must be confirmed for project-specific design. It
should be noted that the limits given in the following sections do not apply to steam blows; please
refer to Section 20.6 for those requirements.
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20.7.1
Cycle Chemistry
The cycle chemistry program is based on a Black & Veatch reference unit consisting of two
combustion turbine/HRSG trains to a common condensing reheat steam turbine/condensate cycle.
Each HRSG train will include low-pressure (LP), intermediate-pressure (IP) and high-pressure (HP)
drum boilers. The condenser tubes are stainless steel (or titanium) and the cycle is free of copper.
Oxygen and other noncondensable gases are removed in the deaerating portion of the condenser to
a level of 7 ppb of oxygen. The Cycle Chemical Feed System (FWE) provides the feed of
condensate/boiler chemicals necessary to maintain proper cycle chemistry.
20.7.1.1 Condensate/Feedwater
An aqueous ammonia solution is injected into the condensate pump discharge (downstream of the
condensate polisher exchangers, if applicable) to maintain the condensate/feedwater pH between
9.4 and 9.8. The aqueous ammonia is fed from a chemical storage tote located (insert projectspecific location here). The tote contains 19 percent aqueous ammonia. The aqueous ammonia
feed rate is automatically adjusted by the main plant distributed control system (DCS), according to
the specific conductance of the condensate after chemical feed.
The ammonia is fed in the condensate system to minimize the amount of corrosion products
introduced into the steam generator and to continue to protect the steam generator piping up to the
turbine.
20.7.1.2 Boiler Water
A phosphate or caustic solution, if chemical feed equipment is provided for the project for these
chemicals, is injected into the HP and IP drums to maintain the boiler water pH and to prevent scale
formation on the boiler tube surfaces. Sodium hydroxide (caustic) may also be added up to 1 mg/L
to assist with pH adjustment.
The phosphate solutions can be purchased preblended from a chemical supplier. The preblended
chemicals are delivered in totes and can be fed directly using the phosphate solution feed pumps or
fed neat with the neat feed pumps and makedown module.
The dry phosphate can also be purchased from a chemical supplier and made into a solution on-site
in a solution tank. A description of the method required by project contract should be included in
the project guide.
The phosphate feed method shall be acceptable to equipment suppliers.
The phosphate combines with hardness in the boiler feedwater to form a nonadhering precipitate
that can be easily blown down from the boiler. The phosphate feed also buffers the boiler water
from the pH excursions likely to occur during startup, often created by condenser leaks.
Both the HP and IP drum blowdowns are directed to the blowdown tank. This requires
confirmation based on project-specific water flow path.
Not all projects will have a phosphate or caustic feed system. In this case, pH is maintained using
the ammonia feed to the condensate/feedwater.
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20.7.2
Steam Cycle Parameters and Action Levels
Action levels are defined by EPRI as guidelines for maximum annual exposure to contaminant
conditions outside normal limits. These action levels also permit startup and flexibility during unit
upsets when preferred operating conditions may not be maintained. Immediate shutdown limits
are typically provided by the equipment supplier and will require confirmation for the project. The
action levels are defined as follows:





Normal. Operating range associated with long-term stability. A safety margin has been
provided to avoid concentration of contaminants on heat transfer surfaces. No remedial
action is necessary. Maintain water quality analysis schedule.
Action Level 1. Values present a potential for accumulation of contaminants and corrosion.
Return to normal values within 7 days. The cumulative operating time (per year) should not
exceed 336 hours for baseload conditions and 672 hours for cycling conditions.
Action Level 2. Values identify an accumulation of impurities, and corrosion may occur.
Operators should return to normal target values within 24 hours. The cumulative operating
time (per year) should not exceed 48 hours for baseload conditions and 96 hours for cycling
conditions.
Action Level 3. Values identify levels where rapid corrosion occurs. Implement corrective
actions immediately to return to normal conditions within 4 hours. If corrective actions are
not successful, immediately shut down the unit. The cumulative operating time (per year)
should not exceed 8 hours for baseload conditions and 16 hours for cycling conditions.
Immediate Shutdown. Low pH boiler water is aggressively corroding the tube metal.
Either add caustic soda to neutralize the acid within 30 minutes or shut down the boiler and
drain it as soon as it has cooled. The cumulative operating time (per year) should not exceed
1 hour for baseload conditions and 2 hours for cycling conditions.
It should be noted that before startup and during operation, care should be taken to ensure proper
calibration and operation of all testing and analytical devices. If needed, exhausted or defective
equipment and calibration standard solutions should be replaced.
The following is a brief discussion of the analyses to be performed during startup and
commissioning. These analyses support the troubleshooting and steam purity data necessary to
admit steam to the steam turbine. Continuous analyses of critical parameters are provided by the
sampling system sample panel. Grab samples can be obtained from the sample panel, but in that
case analysis has to be performed by off-line instrumentation.
20.7.2.1 Makeup Water
The two primary sources of cycle water contamination are makeup water treatment system
excursions and condenser leaks. Upsets in the Cycle Makeup Treatment System may release high
levels of silica and/or sodium to the demineralized water storage tank, which then enters the
condenser hot well and the condensate system. Table 20-3 provides recommended makeup water
quality parameters for steam cycle operation. These values require validation with the equipment
supplier recommendations.
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Table 20-3
Makeup Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Specific
Conductance
Continuous
≤ 0.10 µS/cm
0.1 to 0.15
µS/cm
> 0.15 µS/cm
--
> 0.20 µS/cm
Sodium
Continuous
≤ 3 ppb
Silica
Sulfate
Chloride
Total Organic
Carbon (TOC)
Continuous
Daily
As needed
Weekly
≤ 10 ppb
10 to 15 ppb
--
--
> 15 ppb
≤ 3 ppb
≤ 3 ppb
< 300 ppb
20.7.2.2 Condensate Pump Discharge
The other primary source of cycle contamination is via condenser tube leaks that draw external
contamination from the circulating water system. The relative purities of condensate and
circulating water mean that a very small leak can severely impact the steam cycle chemistry in a
short period of time. The condensate pump discharge sample provides the first indication of trouble
in the condenser. Table 20-4 provides the recommended condensate pump discharge quality
parameters. These values require validation with the equipment supplier recommendations.
Table 20-4
Condensate Pump Discharge Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Specific
Conductance
Continuous
5 to 15
µS/cm
15 to 20
µS/cm
20 µS/cm
--
--
pH
Continuous
9.0 to 9.4
8.8 to 9.0
> 9.8
--
< 8.8
< 8.0
Cation
Conductivity
Sodium
Dissolved
Oxygen (DO)
TOC
Silica
Continuous
Daily
Continuous
Weekly
Daily
≤ 0.2 µS/cm
≤ 3 ppb
≤ 7 ppb
≤ 200 ppb
≤ 10
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≤ 0.3 to 0.4
µS/cm
6 to 10 ppb
7 to 10 ppb
> 200
> 10
20-7
≤ 0.4 to
0.65 µS/cm
10 to 20
ppb
10 to 20
ppb
---
> 0.65
µS/cm
> 20 ppb
> 20 ppb
---
--
-----
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20.7.2.3 Condensate Polisher Effluent (if applicable)
The condensate polishers will help keep the system quality at the levels needed by removing ions in
the condensate and any solids that may be passed through from the condensers. The precoat
polishers have a limited fixed capacity for ion exchange. If the polishers reach their capacity during
operation, the polisher can reject previously removed ionic contaminants back into the
condensate/feedwater cycle.
Table 20-5 provides the recommended condensate pump discharge quality parameters. These
values require validation with the equipment supplier recommendations.
Table 20-5
Condensate Polisher Effluent
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Cation
Conductivity
Continuous
≤ 0.2 µS/cm
> 0.2
µS/cm
≤ 0.6 µS/cm
> 0.6 µS/cm
--
Silica
Continuous
≤ 10 ppb
> 10 ppb
--
--
--
Sodium
Continuous
≤ 3 ppb
≤ 6 ppb
20.7.2.4 Condensate After Chemical Feed
> 12 ppb
≤ 12 ppb
--
Analysis of the condensate after the chemical feed is used to control the aqueous ammonia feed to
the cycle. Table 20-6 provides the recommended condensate after chemical feed quality
parameters. These values require validation with the equipment supplier recommendations.
Table 20-6
Condensate After Chemical Feed Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Specific
Conductance
Continuous
10 to 15
µS/cm
15 to 20
µS/cm
> 20
µS/cm
--
--
pH
Continuous
9.2 to 9.6
20.7.2.5 Low-Pressure Drum
8.8 to 9.2
> 9.6
--
< 8.8
< 8.5
The LP drum is the feedwater source for the HP and IP drums, and the attemperation water for
main steam and reheat steam. Because the attemperation water is injected directly into the main
steam and reheat steam, the water quality has to comply with steam purity limits; therefore,
phosphate treatment is not permitted in the LP drum. AVT(O) using ammonia is used for LP boiler
water chemistry control. This paragraph requires confirmation on each project because there are
different configurations and flow paths.
Typically, 5 to 10 percent of the water entering the LP drum is converted to steam, which is
directed to the LP section of the steam turbine. Because the steaming rate is so low, dissolved solids
do not concentrate significantly in the drum; however, large portions of volatile chemicals, such as
ammonia, can flash into the LP steam, depressing the pH in the LP drum and the feedwater to the IP
and HP drums. Table 20-7 provides the LP drum water quality parameters.
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Table 20-7
Low-Pressure Drum Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
pH
Continuous
≥ 9.4
--
--
--
--
DO
Continuous
≤ 7 ppb
7 to 15
ppb
15 to 20
ppb
> 20 ppb
--
If applicable to the specific project, and phosphate feed equipment is provided, during upset
conditions and commissioning the LP drum has the capability to operate on phosphate treatment
(PT). During phosphate feed, the blowdown valve opening should be increased to discharge
additional impurities to the blowdown tank. Once the boiler and steam quality are stable, the drum
is converted to AVT(O) by turning off the phosphate and continuing to blow down excess amounts
of phosphate via the blowdown line. It should be noted that the transition from PT to AVT(O) could
take several weeks.
20.7.2.6 Intermediate-Pressure Drum
The IP drum receives feedwater from the boiler feed pump. Steam from the IP drum is
superheated and combined with cold reheat steam.
When feed equipment is provided on the project, phosphate or caustic treatment is used to
maintain the IP boiler water chemistry. If not, disregard the previous sentence. The IP drum is
blown down to the blowdown tank.
Table 20-8 provides the recommended water quality parameters for the IP boiler.
Table 20-8
Intermediate-Pressure Drum Water Quality Parameters
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
ANALYSIS
FREQUENCY
NORMAL
Specific
Conductance
Continuous
See curves of allowable specific conductance versus pressure
Phosphate, if provided
Per 8 hour shift
See curves of allowable phosphate versus pressure
Cation Conductivity
pH
Silica
Sodium
Chloride*
Sulfate*
Continuous
Continuous
Daily
Daily
As needed
As needed
See curves of allowable cation conductivity versus pressure
≥ 9.4
--
--
--
See curves of allowable silica versus pressure
--
See curves of allowable sodium versus pressure
See curves of allowable chloride versus pressure
See curves of allowable sulfate versus pressure
* Chloride and sulfate measurements suggested when hot reheat steam cation conductivity is high.
ppm = parts per million
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If applicable to the specific project, and phosphate feed equipment is provided, during upset
conditions and commissioning the IP drum has the capability to operate on PT. During phosphate
feed, the blowdown valve opening should be increased to discharge additional impurities to the
blowdown tank. Once the boiler and steam quality are stable, the drum is converted to AVT(O) by
turning off the phosphate and continuing to blow down excess amounts of phosphate via the
blowdown line. It should be noted that the transition from PT to AVT(O) could take several weeks.
20.7.2.7 High-Pressure Drum
The HP drum receives feedwater from the boiler feed pump. When feed equipment is provided on
the project, phosphate or caustic treatment is used to maintain the HP boiler water chemistry. The
HP drum is blown down to the blowdown tanks.
Table 20-9 provides the recommended water quality parameters for the HP drum.
Table 20-9
High-Pressure Drum Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
Specific
Conductance
Continuous
See curves of allowable specific conductance versus pressure
Phosphate, if
applicable
Per 8 hour shift
See curves of allowable phosphate versus pressure
Cation
Conductivity
pH
Silica
Sodium
Chloride*
Sulfate*
Continuous
Continuous
Daily
Daily
As needed
As needed
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
See curves of allowable cation conductivity versus pressure
≥ 8.7
--
--
See curves of allowable silica versus pressure
--
< 8.0
See curves of allowable sodium versus pressure
See curves of allowable chloride versus pressure
See curves of allowable sulfate versus pressure
*Chloride and sulfate measurements suggested when main steam cation conductivity is high.
20.7.2.8 Steam Purity
The main steam and reheat steam purity requirements are identical. The STG supplier’s
recommended steam purity requirements need to be inserted into the project startup water
chemistry guidelines. Steam purity limits set by the STG supplier supersede those in Table 20-9 if
the limits are more stringent. The recommended steam purity requirements are included in
Table 20-10.
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Table 20-10
Steam Purity Requirements
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Cation
Conductivity*
Continuous
< 0.15
µS/cm
< 0.25
µS/cm
< 0.45
µS/cm
< 0.45
µS/cm
--
Silica
Sodium
Continuous
10 to 20 ppb
2 to 40 ppb
> 40 ppb
--
Chloride**
Continuous
< 10 ppb
As needed
≤ 2 ppb
≤ 4 ppb
≤ 8 ppb
> 8 ppb
--
Sulfate**
TOC**
As needed
As needed
≤ 2 ppb
≤ 2 ppb
≤ 100 ppb
≤ 4 ppb
≤ 4 ppb
> 100 ppb
≤ 8 ppb
≤ 8 ppb
> 8 ppb
> 8 ppb
---
*Cation conductivity may be a degassed sample during startup; this is dependent on the steam cycle and drum treatment
method.
**Chloride, sulfate, and TOC analysis (as needed) when steam purity is in question.
20.8
Startup Steam Cycle Chemistry – Oxygenated Treatment
The following subsections include a description of the cycle chemistry on oxygenated treatment
(OT) and should be included in the project startup water chemistry guidelines if the cycle will be
operated on OT.
20.8.1
Cycle Chemistry
The cycle chemistry program is based on EPRI guidelines for the OT of drum units (EPRI TR102285). The condenser tubes are stainless steel, and the cycle is free of copper. Noncondensable
gases are removed in the deaerating portion of the condenser to a level of 7 ppb of oxygen. The
Cycle Chemical Feed System provides for the feed of cycle chemicals necessary to maintain proper
cycle chemistry.
A condensate polisher is required with this type of cycle chemistry program. Please refer to
Section 8.0 of the Chemical Engineering Handbook for further design details.
20.8.1.1 Condensate/Feedwater
An aqueous ammonia solution is injected into the condensate downstream of the condensate
polisher to maintain the condensate/feedwater pH between 9.0 and 9.6. The aqueous ammonia
feed rate is automatically adjusted by the plant DCS, in proportion to condensate flow biased by the
condensate pH.
Oxygen gas is injected to maintain an oxygen residual between 30 to 50 ppb from the condensate
polisher effluent to the economizer inlet. The oxygen feed rate is automatically adjusted based on
condensate flow, biased by oxygen residual, to achieve the desired oxygen concentration. The unit
is provided with two feed locations, as recommended by EPRI; the first feed location is downstream
of the combined condensate polisher effluent, and the second feed point location is downstream of
the deaerator.
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Oxygen reacts with the cycle piping to create a passive oxide layer on the cycle pipe that limits the
amount of corrosion in the cycle. The passive layer is formed by the following ferric iron reactions:
4Fe2+
Iron
+ O2
+ 2H+
=
4Fe3+
+ 2OH-
Fe(OH)+
+ H2O
=
FeO(OH)
+ 2H+
+ e-
+ 2 H2O
=
+ H+
+ e-
+ ½ O2
=
+ H2O
=
Oxygen
Iron Hydroxide
Fe3O4
2 Fe2+
Iron
Iron (III) Oxide
+ 2 H2O
Water
2 Fe3O4 +
Iron (III) Oxide
Hydrogen
Water
Water
Oxygen
Water
Iron
Iron OxideHydroxide
3 FeO(OH)
Iron OxideHydroxide
Fe2O3
Iron (II) Oxide
3 Fe2O3
Iron (II) Oxide
Hydroxide
Hydrogen
Hydrogen
+ 4 H+
Free Radical
Free Radical
Hydrogen
+ 2e-
Free Radical
At a pH above 7 and cation conductivity below 0.3 µS/cm, these reactions minimize the release of
iron corrosion products into the cycle from the pipe.
To protect the steam side of the feedwater heaters, the vents should be kept closed during normal
operation to ensure that sufficient levels of oxygen remain in the vessel. However, noncondensable
gases may also build up in the heaters and may need to be vented off.
The protection of the deaerator operates in a similar fashion to the feedwater heaters. The vents on
the deaerator should be kept closed during normal operation to ensure that the sufficient levels of
oxygen remain in the vessel. However, with the vents closed, other noncondensable gases are not
vented from the system. To remove the noncondensable gases, the deaerator vents may need to be
opened periodically.
The ammonia and oxygen fed in the condensate and feedwater systems minimize the amount of
corrosion products introduced into the steam generator and provide protection of the steam
generator steam piping to the turbine.
20.8.1.2 Boiler Water
A phosphate or caustic solution is injected (for emergency use only and for when feed equipment is
available on-site) into the HP and IP drums only in the event of low boiler water pH excursions.
These solutions prevent the depression of the boiler water pH and prevent scale formation on the
boiler tube surfaces. Sodium hydroxide (caustic) may also be added up to 1 mg/L to assist with pH
adjustment.
Both the HP and IP drum blowdowns are directed to the blowdown tank.
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20.8.2
Steam Cycle Parameters and Action Levels
Action levels are defined by the EPRI as guidelines for the maximum annual exposure to
contaminant conditions outside normal limits. These action levels also permit startup and flexibility
during unit upsets when preferred operating conditions may not be maintained. Immediate
shutdown limits are typically provided by the equipment supplier and will require confirmation for
the project. The action levels are defined as follows:





Normal. Operating range associated with long-term stability. A safety margin has been
provided to avoid concentration of contaminants on heat transfer surfaces. No remedial
action is necessary. Maintain water quality analysis schedule.
Action Level 1. Values present a potential for accumulation of contaminants and corrosion.
Return to normal values within 7 days. The cumulative operating time (per year) should not
exceed 336 hours for baseload conditions and 672 hours for cycling conditions.
Action Level 2. Values identify an accumulation of impurities, and corrosion may occur.
Operators should return to normal target values within 24 hours. The cumulative operating
time (per year) should not exceed 48 hours for baseload conditions and 96 hours for cycling
conditions.
Action Level 3. Values identify levels where rapid corrosion occurs. Implement corrective
actions immediately to return to normal conditions within 4 hours. If corrective actions are
not successful, immediately shut down the unit. The cumulative operating time (per year)
should not exceed 8 hours for baseload conditions and 16 hours for cycling conditions.
Immediate Shutdown. Low pH boiler water is aggressively corroding the tube metal.
Either add caustic soda to neutralize the acid within 30 minutes or shut down the boiler and
drain it as soon as it has cooled. The cumulative operating time (per year) should not exceed
1 hour for baseload conditions and 2 hours for cycling conditions.
It should be noted that before startup and during operation, care should be taken to ensure proper
calibration and operation of all testing and analytical devices. If needed, exhausted or defective
equipment and calibration standard solutions should be replaced.
The following is a brief discussion of the analyses to be performed during startup and
commissioning. These analyses support the troubleshooting and steam purity data necessary to
admit steam to the steam turbine. Continuous analyses of critical parameters are provided by the
sampling system sample panel. Grab samples can be obtained from the sample panel, but in that
case, analysis has to be performed by off-line instrumentation.
OT Additions - In addition to the aforementioned action levels, the following guidelines apply to
units operating on oxygen treatment:
1.
If the condensate/feedwater cation conductivity continues to rise regardless of the actions
taken to locate and reduce the contaminant ingress, operators should implement the actions
presented in Table 20-11.
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Table 20-11
Oxygenated Treatment Actions
FEEDWATER
CATION
CONDUCTIVITY
(µS/CM)
BOILER WATER
CATION
CONDUCTIVITY
(µS/CM)
< 0.15
< 1.5
Continue normal operations. Levels less than 0.10 µS/cm
(feedwater) and 1.0 µS/cm (boiler water) are preferred.
> 0.3
> 5.0
Terminate oxygen feed. Return to AVT(O).
> 0.2
2.
3.
> 3.0
ACTION REQUIRED
Increase boiler blowdown. Continue oxygen feed.
Loss of oxygen feed for a short time has a relatively minor impact on feedwater system
corrosion resistance, but efforts should be made to restore oxygen feed in a timely fashion.
An oxygen overfeed can result in the accelerated corrosion of the boiler if significant oxygen
reaches the downcomers or lower water walls when contamination is also present. If the
oxygen residual exceeds 10 ppb in the downcomer sample, the oxygen feed should be
discontinued immediately.
20.8.2.1 Makeup Water
The two primary sources of cycle water contamination are makeup water treatment system
excursions and condenser leaks. Upsets in the Cycle Makeup Treatment System may release high
levels of silica and/or sodium to the demineralized water storage tank, which then enters the hot
well and the condensate system. Table 20-12 provides recommended makeup water quality
parameters for steam cycle operation.
Table 20-12
Oxygenated Treatment – Cycle Makeup Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION LEVEL 1
ACTION LEVEL 2
ACTION LEVEL 3
Specific
Conductance
Continuous
≤ 0.10 µS/cm
0.10 to 0.15 µS/cm
> 0.15 µS/cm
--
Silica
Continuous
≤ 10 ppb
> 10 ppb
--
--
Sodium
Continuous
≤ 3 ppb
20.8.2.2 Condensate Pump Discharge
> 3 ppb
--
--
Condenser tube leaks or tubesheet weepage introduces contamination to the condensate from the
circulating water system. The relative purities of condensate and circulating water mean that a very
small leak can severely impact the steam cycle chemistry in a short period of time. The condensate
pump discharge sample provides the first indication of trouble in the condenser. Table 20-13
provides the recommended condensate pump discharge quality parameters.
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Table 20-13
Oxygenated Treatment – Condensate Pump Discharge Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION LEVEL 1
ACTION LEVEL 2
ACTION LEVEL 3
Specific
Conductance
Continuous
3 to 15 µS/cm
15 to 20 µS/cm
> 20 µS/cm
--
pH
Continuous
9.0 to 9.6
< 9.0 or > 9.6
--
--
Cation
Conductivity
Sodium
Silica
DO
TOC
Continuous
Continuous
Continuous
Shift
Weekly
< 0.30 µS/cm
≤ 3 ppb
≤ 10 ppb
< 20 ppb
< 200 ppb
> 0.30 µS/cm
> 3 ppb
> 10 ppb
--
> 200 ppb
20.8.2.3 Condensate Polisher System Effluent
---
---
--
--
--
--
--
--
The condensate polisher system will help keep the condensate/feedwater cycle water quality at the
levels needed for continuous OT by removing dissolved and suspended solids from the condensate.
The condensate polisher ion exchange resin has a fixed capacity for ion exchange and must be
periodically regenerated. If a condensate polisher exchanger reaches its ion exchange capacity
during operation, the exchanger can reject previously removed ionic contaminants back into the
condensate/feedwater cycle.
The condensate polisher system effluent provides the first sample downstream of the cycle
chemical feed injection points.
The recommended water quality parameters for the condensate polisher system effluent are
included in Table 20-14.
Table 20-14
Oxygenated Treatment – Condensate Polisher Effluent Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION LEVEL 1
ACTION LEVEL 2
ACTION LEVEL 3
Cation
Conductivity
Continuous
< 0.15 µS/cm
0.20 to 0.30 µS/cm
--
--
Silica
Shift
≤ 10 ppb
> 10 ppb
--
--
Sodium
DO
Shift
Continuous
20.8.2.4 Boiler Water
≤ 3 ppb
30 to 50 ppb
3 to 6 ppb
--
6 to 12 ppb
--
> 12 ppb
--
The boiler water sample point monitors drum boiler water chemistry to minimize deposition and
corrosion in the boiler tubes. Additionally, this sample point allows the control of boiler water
chemistry through blowdown and chemical feed and is the primary control point for steam purity.
The recommended water quality parameters for the boiler water are included in Table 20-15.
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Table 20-15
Oxygenated Treatment – Boiler Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION LEVEL 1
ACTION LEVEL 2
ACTION LEVEL 3
Specific
Conductance
Continuous
< 4.0 µS/cm
--
--
--
pH
Continuous
8.5 to 9.2
< 8.5 or > 9.2
--
--
Cation
Conductivity
DO
Continuous
Silica
Sodium
Shift
Chloride
Sulfate
Continuous
Shift
As needed
As needed
20.8.2.5 Steam Purity
< 1.5 µS/cm
5 to 10 ppb
< 100 ppb
< 0.70 ppm
< 30 ppb
< 30 ppb
> 3.0 µS/cm
> 10 ppb
100 to 250 ppb
0.70 to 1.5 ppm
30 to 55 ppb
30 to 55 ppb
> 5.0 µS/cm
--
250 to 500 ppb
1.5 to 3.0 ppm
55 to 100 ppb
55 to 100 ppb
---
> 500 ppb
> 3.0 ppm
> 100 ppb
> 100 ppb
The main steam and reheat steam purity requirements are identical. The STG supplier’s
recommended steam purity requirements need to be incorporated into the project startup water
chemistry guidelines.
20.9
Corrective Actions
A wide array of events can cause cycle water chemistry to deviate from expected values. The
following subsections outline common causes for these excursions and suggest typical corrective
actions. These subsections are not intended to be all-inclusive of every possible cause for a
chemistry excursion; however, they are intended to cover the common causes.
Some of the core parameters require immediate attention to prevent equipment damage or plant
shutdown. It is imperative that plant personnel be familiar with this section and implement a
quality assurance (QA)/quality control (QC) program to accommodate this risk.
In the event of a chemical excursion outside the aforementioned limits, the following actions should
be taken.
20.9.1
Makeup Water
High conductivity and silica levels indicate leakage through the Cycle Makeup Treatment System.
Possible causes of the leakage are as follows:



Change in raw water quality entering the Cycle Makeup Treatment System.
Failure of the Cycle Makeup Treatment System, including, but not limited to, the failure of
the reverse osmosis (RO) membranes causing overloading on the electrodeionization (EDI)
units and downstream mixed bed polishers.
Fouling of the RO membranes.
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


Improper regeneration of the ion exchangers.
Ion exchanger resin exhaustion.
Channeling through the ion exchanger resin, resin loss, fouling, or age.
If an effluent sampling system is provided, add the following language:
This leakage from the permanent plant treatment system will be mitigated by the presence
of sodium, silica, and conductivity analyzers at the system effluent, which will shut down
the system if the presence of any of these is detected. Grab samples should be taken
periodically to verify the accuracy of the analyzers.
The Cycle Makeup Treatment Equipment (65.1410) Instruction Manual should be used to
troubleshoot quality problems within the system.
20.9.2
Condensate
20.9.2.1 Specific Conductance
Specific conductance is a measure of the TDS in the condensate, including cycle conditioning
chemicals in the condensate after chemical feed. Within the condensate/steam cycle, specific
conductance is primarily the result of the ammonia added for pH control. The ammonia feed pump
should be checked to ensure that the proper amount of ammonia is being fed. Care should be taken
to check for condenser leaks and verify the proper operation of the Cycle Makeup Treatment
System.
Accurate measurement of specific conductivity is critical to cycle chemistry because the specific
conductivity is used to control the ammonia feed for pH adjustment.
High specific conductivity typically indicates the following:




Poor quality makeup water.
Condenser leaks.
Steam contamination from carry-over.
Overfeed of ammonia.
20.9.2.2 Cation (Acid) Conductivity
Cation conductivity is the conductivity measurement after the removal of the cationic portion of the
TDS, primarily sodium and ammonia. Consequently, cation conductivity is more sensitive to sulfate,
chloride, or carbon dioxide contamination (which would be indicative of condenser leaks).
High cation conductivity typically indicates contamination from the following:


Poor quality makeup water.
Condenser tube leak.
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


Carbon dioxide from air inleakage or organically based cycle chemicals.
Steam contamination from boiler carry-over.
Exhausted cation resin column in the sample panel.
Troubleshoot each of these contaminant sources to correct the excursion.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the resin columns or conductivity analyzers.
20.9.2.3 Sodium
In the event of high sodium in the condensate, the sodium concentration in the steam samples
should be checked. If both are high, the likely cause of the problem is contamination of the steam
through carry-over and/or volatilization of high sodium concentrations in the makeup water. The
boiler drum water quality and drum levels should be checked to verify that they are within limits.
If the sodium in the steam is within limits, the likely cause of the high condensate sodium is either
poor quality makeup water or a condenser tube leak (for condenser leaks, condensate cation
conductivity would also be elevated). The quality of the water in the demineralized water storage
tank should be checked. If the demineralized water is within limits, the contamination is likely
entering through a leak in the condenser.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the sodium analyzers.
20.9.2.4 pH
Abnormal condensate pump discharge pH is primarily the result of the ammonia added to the
condensate system for pH control. Either high or low pH is likely caused by a problem in the cycle
chemical feed system. The ammonia pump should be checked and adjusted as needed. If
condensate conductivity and the LP drum pH readings are normal, the accuracy of the condensate
pH reading should be verified.
20.9.2.5 Dissolved Oxygen
High DO content indicates either a failure of the condenser air removal system to remove the
noncondensables, or air inleakage into the condenser. The LP turbine back pressure should be
checked, and the proper performance of air removal system flow from the condenser should be
verified. If air removal system performance is not within limits, it should be adjusted as needed. If
air removal is not the cause, the condensate pump, condensate pump strainers, bypass system,
condenser, and turbine seals should be checked for excessive air inleakage. High DO at low
condenser duty can also be caused by the malfunction of the hot well sparging system.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the DO analyzers.
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20.9.2.6 Total Organic Carbon
TOC indicates contamination from one of the chemicals being fed to the cycle, a condenser tube
leak, makeup water contamination, or a dirty cycle. The cycle chemical feed system should be
checked for contamination and cleaned as needed. If the condensate cation conductivity and
sodium are also high, the condenser should be checked for leaks. If the condenser is not leaking, the
makeup water system should be checked. Possible sources of makeup water TOC include changes to
the raw water chemistry, fouled RO membrane, or a fouled demineralized water storage and
transfer system. High TOC can depress the pH of cycle fluids and increase corrosion rates.
Grab samples should be taken on a weekly basis and tested for TOC using Standard Methods 5310
or ASTM D5904.
20.9.3
LP Drum
The LP drum is assumed to produce only a small fraction (less than 5 percent) of the overall steam
to the steam turbine. As such, it is not considered a concentrating drum, and chemical conditioning
is not recommended. Additionally, the LP drum water is the source of desuperheating spray water
and cannot be contaminated by boiler water treatments associated with IP and HP drums;
therefore, LP drum water quality is maintained solely by condensate quality checks.
This paragraph may require revision based on the water flow path through the equipment.
20.9.3.1 pH
If the pH is outside the normal limits, the ammonia pump should be checked and adjusted as
needed.
20.9.3.2 Dissolved Oxygen
If the condensate has high DO, check the condenser for air inleakage or check if the air removal
system has failed.
20.9.4
Intermediate-Pressure Drum
Contaminants entering the IP drum circulate within the boiler until they are removed through
boiler blowdown. If allowed to concentrate too much, they may reach a level where they can carry
over or volatilize into the steam and impact steam purity. The level of carry-over is a function of
moisture separation within the drum and/or the drum pressure. Vaporous carry-over created by
high drum pressures is typically not an issue in the IP drum. The primary concern in the IP drum is
moisture (mechanical) carry-over with the steam.
When applicable, HP drum blowdown is cascaded to the IP drum. This allows the heat in the
blowdown to be recovered in the IP drum, but it also affects the IP boiler chemistry. Generally, this
impact benefits the IP drum, requiring less boiler chemical feed to the IP drum.
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20.9.4.1 Specific Conductance
Specific conductance measures the dissolved solids content of the boiler water. High boiler water
dissolved solids affect steam purity in the form of carry-over.
If the conductivity limit is exceeded, the drum blowdown rate should be increased. Overfeed of
drum chemicals can also lead to high specific conductance excursions.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the conductivity analyzers.
20.9.4.2 Cation (Acid) Conductivity
Cation conductivity is the conductivity measurement after the removal of the cationic portion of the
TDS, primarily sodium and ammonia. Consequently, cation conductivity is more sensitive to sulfate,
chloride, or carbon dioxide contamination (which would be indicative of condenser leaks).
High cation conductivity typically indicates contamination from the following:






Poor quality makeup water.
Condenser tube leak.
Carbon dioxide from air inleakage or organically based cycle chemicals.
Steam contamination from boiler carry-over.
Overfeed of drum chemicals.
Exhausted cation resin column in the sample panel.
Troubleshoot each of these contaminant sources to correct the excursion.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the pH analyzers.
20.9.4.3 Phosphate
Phosphate solution is added to the boiler to control boiler water pH and prevent scale formation on
the boiler surfaces. If the phosphate level in the IP drum is too high, the IP drum should be blown
down and the IP phosphate feed rates should be adjusted. If it is too low, additional phosphate
should be injected into the drum through the dosing pumps.
If the pH drops below 8.0, the water is corroding the boiler and immediate corrective action is
required. Sodium hydroxide (caustic soda) should be added to the drum, with the chemical feed
pump set to maximum outputs; the boiler pH should be monitored. If no improvement is observed
within 30 minutes or caustic cannot be fed, the HRSG has to be taken off-line immediately, then
drained and refilled with fresh makeup water and chemicals. (The pH instrumentation and
calibration should be checked prior to draining and refilling the HRSG.)
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Not all projects feed phosphate solution or they feed phosphate only in emergency situations and
not during normal operation. The following subsections are written for no phosphate feed during
normal operation.
20.9.4.4 pH
Boiler drum pH is controlled through condensate ammonia feed and blowdown. If the pH is too
high, the boiler is blown down and condensate ammonia feed is adjusted. If the pH is too low,
possible causes could be air or contaminant ingress. Increased ammonia dosing is required until
the pH is stabilized.
When phosphate feed equipment is provided and the pH is depressed by acid contaminants, the
unit should be started on phosphate feed.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should be used to
troubleshoot quality problems with the pH analyzers.
20.9.4.5 Silica
Silica enters the IP drum as contamination from the condensate/feedwater system and continuous
HP drum to IP drum blowdown. At the IP drum pressure, silica carry-over is very low, and it can be
allowed to concentrate to higher levels than in the HP drum.
If the silica level exceeds its limit, the steam silica levels should be checked and the IP drum should
be blown down. If the boiler requires excessive levels of blowdown, check for either condenser
leakage or poor makeup water quality.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should be used to
troubleshoot quality problems with the silica analyzers.
20.9.4.6 Sodium
If the sodium level exceeds its limit, care should be taken to blow down the drum and check for
either condenser leaks or makeup water treatment system function.
If phosphate solution is added, sodium is added to the boiler through a trisodium phosphate
solution. If the sodium level exceeds its limit, care should be taken to blow down the drum and
check for either a condenser leak, poor makeup water quality, or an overfeed of phosphate.
20.9.4.7 Chloride and Sulfate
Chlorides and sulfates enter the IP drum as either contamination from the condensate/feedwater
system or blowdown from the HP drum. Chlorides and sulfates should be checked when steam
cation conductivity is high.
If chloride and sulfate levels are high, the IP drum should be blown down. Care should be taken to
check for condenser leaks and makeup water treatment system function.
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20.9.5
High-Pressure Drum
Contaminants entering the HP drum concentrate within the drum until they are removed through
blowdown. If allowed to concentrate too much, the contaminants may reach levels where steam
purity may be affected by carry-over. Carry-over is a function of moisture separation and
volatilization of dissolved solids within the drum. The HP drum contamination limits are much
more stringent than those of the IP drum because of higher pressure and temperature operation.
20.9.5.1 Specific Conductance
Specific conductance measures the dissolved solids content of the boiler water. High boiler water
dissolved solids affect steam purity in the form of carry-over.
If the conductivity limit is exceeded, the drum blowdown rate should be increased.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should be used to
troubleshoot quality problems with the specific conductance analyzer.
20.9.5.2 Cation (Acid) Conductivity
Cation conductivity is the conductivity measurement after the removal of the cationic portion of the
TDS, primarily sodium and ammonia. Consequently, cation conductivity is more sensitive to sulfate,
chloride, phosphate, or carbon dioxide contamination (which would be indicative of condenser
leaks).
High cation conductivity typically indicates contamination from the following:






Poor quality makeup water.
Condenser tube leak.
Carbon dioxide from air inleakage or organically based cycle chemicals.
Steam contamination from boiler carry-over.
Overfeed of drum chemicals.
Exhausted cation resin column in the sample panel.
Troubleshoot each of the contaminant sources to correct the excursion.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the pH analyzers.
20.9.5.3 Phosphate
Phosphate solution is added to the boiler to control boiler water pH and prevent scale formation on
the boiler surfaces. If the phosphate level in the HP drum is too high, the HP drum should be blown
down and the HP phosphate feed rates should be adjusted. If it is too low, additional phosphate
should be injected into the drum through the dosing pumps.
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If the pH drops below 8.0, the water is corroding the boiler and immediate corrective action is
required. Sodium hydroxide (caustic soda) should be added to the drum, with the chemical feed
pump set to maximum outputs; the boiler pH should be monitored. If no improvement is observed
within 30 minutes or caustic cannot be fed, the HRSG has to be taken off-line immediately, then
drained and refilled with fresh makeup water and chemicals. (The pH instrumentation and
calibration should be checked prior to draining and refilling the HRSG.)
Not all projects feed phosphate solution or they feed phosphate only in emergency situations and
not during normal operation. The following subsections are written for no phosphate feed during
normal operation.
20.9.5.4 pH
Boiler drum pH is controlled through condensate ammonia feed and blowdown. If the pH is too
high, the boiler is blown down and the condensate ammonia feed is adjusted. If it is too low,
possible causes could be air or contaminant ingress. Increased ammonia dosing is required until
pH is stabilized.
When phosphate feed equipment is provided and the pH is depressed by acid contaminants, the
unit should be started on phosphate feed.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the pH analyzers.
20.9.5.5 Silica
Silica enters the HP drum as contamination from the condensate/feedwater system. In the HP
boiler drum, the silica concentration has to be monitored to minimize vaporous and mechanical
carry-over in the steam.
If the silica limits are exceeded, the drum should be blown down. Care should be taken to check for
either a condenser leak or poor makeup water quality.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the silica analyzers.
20.9.5.6 Sodium
In the HP boiler drum, the sodium concentration is controlled to avoid carry-over in the steam.
Sodium carry-over can cause stress corrosion cracking of the turbine blades.
If the sodium limits are exceeded, care should be taken to blow down the HP drum and check for
either a condenser leak, poor makeup water quality, or high phosphate feed rates.
The Steam Cycle Sampling and Analysis Equipment (65.1461) Instruction Manual should also be
used to troubleshoot problems with the sodium analyzers.
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20.9.5.7 Chloride and Sulfate
Chlorides and sulfates enter the HP drum as contamination from the condensate/feedwater system.
Chlorides and sulfates have to be checked when steam cation conductivity is high.
If the chloride or sulfate levels exceed limits, care should be taken to blow down the drum and
check for either a condenser leak or poor makeup water quality.
20.9.6
Steam
Steam purity is the driving parameter for all other chemistry limits and requires the most stringent
monitoring and QC.
Each steam turbine supplier has a unique set of steam purity requirements. The steam turbine
instruction manual should be consulted for site-specific purity requirements.
20.9.6.1 Cation Conductivity
Cation conductivity accentuates the anionic cycle contaminants, typically sulfates, chlorides,
phosphates, organics, and carbon dioxide.
High steam cation conductivity indicates anion carry-over in the steam. Sources of the anion carryover include chlorides and sulfates, phosphates, organics, and carbon dioxide.
If cation conductivity is out of range, the boiler water chloride, sulfate, and phosphate levels should
be checked and the drum’s blowdown rates and/or chemical feed rates should be increased as
necessary. Condenser air inleakage should be checked and the cycle chemical feed rates should be
verified.
20.9.6.2 Cation Conductivity (Degassed)
Degassed cation conductivity quantifies the carbon dioxide contribution to cation conductivity by
reboiling the sample or sparging with nitrogen to drive off carbon dioxide and then measuring the
condensate conductivity. The short-term effect of carbon dioxide on steam turbine materials is the
subject of some debate. The steam turbine manufacturer should be consulted on the acceptable
degassed cation conductivity levels during startup.
20.9.6.3 Silica
High steam silica concentrations are a result of a failure of the moisture separators in the boiler
drums, boiler foaming, or high boiler water silica that is vaporizing and carrying over into the
steam. Silica carried to the steam turbine deposits on the LP section turbine blades. These deposits
have a significant detrimental effect on turbine efficiency. Although some of the silica washes off the
blades when the unit comes off-line, the only means of completely restoring the steam turbine
efficiency is during a maintenance outage when the turbine can be removed and shotblasted.
If steam silica is high, the boiler water has to be immediately blown down to reduce the steam silica.
The makeup system should be checked for high silica levels.
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20.9.6.4 Sodium
High steam sodium is caused by high boiler water sodium that is carrying over or volatilizing into
the steam. The sodium can cause stress corrosion cracking and eventual turbine blade failure.
If sodium is high, the boiler water should be blown down to reduce the steam sodium. The water
treatment system operation should be checked for proper operation, the condenser checked for
leaks, and the cycle chemical feed system checked for excessive phosphate feed and/or caustic, if
applicable.
20.9.7
Condensate Polisher Effluent
20.9.7.1 Cation Conductivity
Cation conductivity is the conductivity measurement after removal of the cationic portion of the
TDS, primarily sodium and ammonia. High cation conductivity at the condensate polisher system
effluent sample point typically indicates contamination from one of the following:







Channeling through a condensate polisher exchanger.
Exhaustion of the condensate polisher ion exchange resins.
Condensate polisher resin loss, fouling, or age.
Improper transfer of condensate polisher resins to the external regeneration vessels.
Improper separation of the condensate polisher resins prior to regeneration.
Improper regeneration of the condensate polisher resins.
Exhausted cation resin column in the sample panel.
The Condensate Polisher System Instruction Manual should be used to troubleshoot quality
problems with the system effluent.
20.9.7.2 Sodium
High sodium at the condensate polisher system effluent sample point typically indicates
contamination from one of the sources identified in Subsection 20.9.7.1. The Condensate Polisher
System Instruction Manual should be used to troubleshoot quality problems with the system
effluent.
20.9.7.3 Silica
High silica at the condensate polisher system effluent sample point typically indicates
contamination from one of the sources identified in Subsection 20.9.7.1. The Condensate Polisher
System Instruction Manual should be used to troubleshoot quality problems with the system
effluent.
Table 20-16 summarizes the previously addressed parameters and the possible causes of
excursions.
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Silica
X
X
X
Chloride
Sulfate
pH
Cation/Specific
Conductivity
Dissolved
Oxygen
Total Organic
Carbon
Na/PO4 Ratio
Free Hydroxide
Ammonia
Phosphate
Iron
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
DI Resin Leakage
X
Feedwater pH Low
X
Feedwater
Dissolved Oxygen
High
Phosphate Feed
High/Low
X
Poor Deaerator
Function
Poor Makeup
Quality
X
Air Inleakage
Condenser Leak
Sodium
Parameter
Oxygen Scavenger
Feed High/Low
Insufficient
Boiler Blowdown
Cause
Troubleshooting Parameters
Ammonia Feed
High/Low
Table 20-16
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
The project startup water chemistry guide should include the sample analysis parameters as an
appendix for the condensate/feedwater/boiler chemistry. An example startup water chemistry
guide for a combined cycle plant operating on AVT(O) with phosphate treatment is included in
Table 20-17.
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Table 20-17
Example Startup Water Chemistry Guide
SAMPLE NAME
ANALYSIS
FREQUENCY
INSTRUMENT RANGE
NORMAL
OPERATION
ANNUNCIATION
Sample 1:
LP Drum Boiler Water
DO
Continuous
2 ppb to 20 ppm
≤ 7 ppb
High
Specific conductance
Continuous
0 to 20 µS/cm
10 µS/cm
High
Sample 2:
IP Drum Boiler Water
pH
Phosphate
Silica
pH
Sample 3:
HP Drum Boiler Water
Sodium
Specific conductance
Phosphate
Silica
Sodium
Sample 4:
LP Drum Saturated Steam
pH
Cation conductivity
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
2 to 12
200 ppb to 20 ppm
0.5 to 5,000 ppb
2 to 12
0.01 ppb to 10 ppm
0 to 20 µS/cm
200 ppb to 20 ppm
0.5 to 5,000 ppb
0.01 ppb to 10 ppm
2 to 12
0 to 10 µS/cm
9.2 to 10.2
2 ppm
≤ 1 ppm
9.2 to 9.6
≤ 5 ppb
10 µS/cm
2 ppm
≤ 250 ppb
≤ 5 ppb
9.2 to 9.6
≤ 0.2 µS/cm
High, Low
High, Low
High
High, Low
High
High
High, Low
High
High
High, Low
High
Sample 5:
IP Drum Saturated Steam
Cation conductivity
Continuous
0 to 10 µS/cm
≤ 0.2 µS/cm
High
Cation conductivity
Continuous
0 to 10 µS/cm
≤ 0.2 µS/cm
High
Sample 7:
Hot Reheat Steam
Cation conductivity,
degassed
Continuous
0 to 10 µS/cm
≤ 0.2 µS/cm
High
Sample 6:
HP Drum Saturated Steam
Sodium
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SAMPLE NAME
ANALYSIS
FREQUENCY
INSTRUMENT RANGE
NORMAL
OPERATION
ANNUNCIATION
Sample 8:
Superheated Steam
Silica
Continuous
0.5 to 5,000 ppb
≤ 10 ppb
High
Sample 17:
Cycle Water Makeup
Sodium
Specific conductance
Continuous
0.1 ppb to 10 ppm
≤ 5 ppb
High
Sample 18:
Condensate Pump Discharge
Cation conductivity
Silica
Cation conductivity
Sodium
DO
Specific conductance
pH
Sample 19:
Condensate After Chemical
Feed
Silica
Specific conductance
pH
DO = dissolved oxygen
HP = high-pressure
IP = intermediate-pressure
LP = low-pressure
ppb = parts per billion
ppm = parts per million
µS/cm = microsiemens per centimeter
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Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
0 to 10 µS/cm
0 to 10 µS/cm
0 to 5,000 ppb
0 to 10 µS/cm
0.01 ppb to 10 ppm
2 ppb to 20 ppm
0-10 µS/cm
2 to 12
≤ 0.2 µS/cm
0.1 µS/cm
≤ 10 ppb
≤ 0.2 µS/cm
≤ 5 ppb
≤ 7 ppb
0.1 µS/cm
0.5 to 5,000 ppb
≤ 10 ppb
2 to 12
9.2 to 9.6
0 to 20 µS/cm
20-28
5 to 8 µS/cm
High
High
High
High
High
High
High
High, Low
High
High
High, Low
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20.10 Startup
During startup, a condensate/feedwater/boiler chemistry program should be implemented, and
plant operators should be trained to recognize and react to chemistry excursions. Common areas of
concern include chemical additions, steam purity, and cycle chemistry. Operators unfamiliar with
managing cycle chemistry may need significant time to develop a sensitivity and full understanding
of the critical operating issues. It is recommended that a detailed training program be implemented
to address this area, possibly in conjunction with the owner’s chemical vendor.
As a reference, the general order for starting a combined cycle unit is as follows:
1.
2.
3.
For units with condensate polishing, ensure that the condensate polisher system is ready
for operation. All cycle water should be passed through the condensate polishers prior to
introduction into the cycle.
Fill the boilers from the condensate pump.
●
Fire the combustion turbine and HRSG.
●
●
●
4.
5.
6.
Ammonia is added to establish proper feedwater and boiler drum chemistry. When
phosphate feed equipment is provided, phosphate is fed to the HP and IP drums. It
should be noted that there may be a significant lag time in the chemical feed lines,
which will require the chemical feed pumps to be run for a duration of time just to
prime the chemical feed lines.
The HP, IP, and LP steam should be vented to the atmosphere and the HP and IP
drums should be blown down to the blowdown tank.
Makeup from the condenser is used to maintain HP and IP drum levels.
Ammonia is fed through the respective metering pumps.
Draw condenser vacuum.
Direct steam to the turbine steam seals and the bypass. Close the HP and IP drum vents, but
keep the LP drum vents open.
Roll the steam turbine once the drum silica and steam cation conductivity drop to an
acceptable level (generally defined as Action Level 1). Upon acceptance by the steam
turbine manufacturer (on-site representative), raise pressure and load as the silica and
cation conductivity permit.
20.10.1 Phosphate and Caustic (if applicable)
Once the boiler fill is complete, a phosphate solution is added to the HP and IP drums. The amount
should be as recommended by EPRI curves versus pressure. The pH should be checked and caustic
should be added to raise the drum pH to 9.8, if caustic feed is applicable to the site.
During startup, the blowdown valves open and the drum conditioning chemicals are lost. The HP
and IP boiler water pH and phosphate should be sampled and analyzed every 2 hours, and
phosphate and caustic should be added as needed.
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20.10.2 Oxygen (if applicable)
The oxygen feed system should be started when the condensate polisher system effluent cation
conductivity reaches 0.15 µS/cm, boiler water cation conductivity reaches 1.5 µS/cm, and both
continue to trend downward. Deaerator vents should then be positioned for oxygenated chemistry
treatment. The economizer inlet DO should be continuously sampled, and adjustments to the
oxygen feed automatic controls should be made, as required, to maintain normal economizer inlet
DO control limits.
20.10.3 Ammonia
The ammonia pump is started when the HRSG receives heat, and condensate is required to
maintain drum levels. The pump has on-line controls to adjust the pump feed rate based on the
specific conductivity of the condensate after chemical feed. The feedwater pH should be checked
periodically to ensure that the conductivity-based controls are working properly.
20.10.4 Silica
During shutdown periods when the boiler cycle is open to the atmosphere, silica can enter the
boiler cycle as particulate material in various forms, as dust or dirt in the air, residue from
shotblasting activities, or colloidal silica in the makeup water (not likely on a project with RO
treatment as a part of the Cycle Makeup Treatment System). The usual silica test does not detect the
particulate silica. Once in the boiler, the silica heats up and dissolves in the boiler water. It is
common practice to measure several ppm of silica in the boiler during startup when the makeup
water is showing less than 20 ppb of silica.
Silica concentrates in the boiler drums and carries over in the steam where it deposits on the
turbine blades. The amount of carry-over is dependent on the drum pressure; the higher the
pressure, the greater the carry-over.
During startup, the boiler drum blowdown valves are opened wide to flush as much water and silica
as possible. The drum pressure is raised to 1,000 pounds per square inch absolute (psia). At this
point, silica is tested every 2 hours. The unit pressure is raised in accordance with Table 20-18. As
the silica level drops, the unit can be raised to the corresponding pressure. Once the unit is at full
pressure, the boiler drum blowdown is continued until the silica drops to the normal range.
Steps that can be taken to minimize silica startup delays include the following:



Keep the boiler and condensate piping closed as much as possible during outages to prevent
dirt and dust contamination.
Perform blasting activities in accordance with Section 19.0, Cleanliness Control, of this
handbook.
Ensure adequate cleanout and/or flushing of the demineralized water system, condensate
system, condenser, and condenser hot well.
When provided, the condensate polishers will remove silica in the condensate to help with startup.
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Table 20-18
Boiler Pressure Versus Silica
MAXIMUM BOILER PRESSURE
(PSIA)
BOILER WATER SILICA
(PPM)
1,000
< 2.5
1,200
1.6
1,100
1,300
1,400
1,500
1.9
1.2
1.0
0.8
1,600
0.67
1,800
0.45
1,700
1,800; no blowdown
20.10.5 Cation Conductivity
0.56
0.3
The most common cause of cation conductivity in the steam is carbon dioxide. Carbon dioxide is
extremely difficult to remove from the boiler cycle, as it can take on several forms within the boiler
cycle. It is in gaseous form within the boiler and is carried over in the steam because it cannot be
blown down. As it passes through the turbine with the steam, a portion can combine with water to
form carbonic acid and condense on the turbine, causing corrosion. The remainder of the carbon
dioxide gas flows through to the condenser, where a portion is removed in the air removal section,
but the remainder combines with ammonia to form ammonium carbonate, which is soluble in
water and is not removed.
The key to reducing cation conductivity in the steam is minimizing carbon dioxide in the cycle.
Carbon dioxide can enter the cycle with the makeup water as the boiler is filled. Most of this is
removed through the drum vents as the unit is fired.
Additionally, the removal of carbon dioxide and subsequent reduction of cation conductivity can be
aided by continuing to vent the LP drum during initial operation.
20.10.6 Dissolved Oxygen
During the initial stages of startup, mechanical deaeration of the cycle water is normally not
available, so the fill water and makeup water may contain ppm levels of DO. The combination of
demineralized water and DO is very aggressive to the mild steel in the boilers.
During startup, the LP drum acts as a deaerator. The boiler drum vents are open, and the oxygen in
the water degasses and is vented to the atmosphere. This deaerates the water prior to entering the
HP and IP boilers.
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Once the steam is directed to the steam seals and bypassed to the condenser, a vacuum can be
pulled on the condenser. This deaerates the makeup water, and the LP drum vents can be closed.
During startup, the DO should be checked in the condensate, feedwater, and HP and IP boilers to
ensure that it is being removed from the cycle.
20.11 Lay-Up
During outage periods, if unprotected, oxygen can enter the cycle and cause oxidation (rust),
pitting, and corrosion in the boiler cycle. This type of corrosion requires oxygen and water together.
If exposed to just one item, the steel is not attacked. To prevent this corrosion, the following
strategies have been developed to isolate the water and oxygen:



Wet lay-up with ammonia dosing and low DO levels.
Dry air lay-up
Nitrogen blanketing.
20.11.1 Wet Lay-Up
In a wet lay-up, the boiler is closed up and filled with demineralized water treated with ammonia to
raise the pH to approximately 10.0. Closing up the boiler limits the entry of oxygen into the boiler,
while ammonia ensures that the water remains alkaline throughout the lay-up. The boiler can be
fired with the lay-up solution, but the excess ammonia has to be vented off.
A wet lay-up is only recommended for 48 to 72 hour periods. The wet lay-up is best following a
chemical cleaning or when the boiler can be bottled up and protected until it is needed again.
20.11.2 Dry Air Lay-Up
The dry air lay-up uses warm, dry air to evaporate and displace any water out of the boiler. Bags of
desiccant, such as silica gel, are set inside the drum and the boiler is bottled up. The desiccant
absorbs any humidity that may be remaining in the air so that it cannot condense in the boiler. The
drum should be opened every 2 months and the desiccant should be replaced to ensure that it has
not been exhausted. Prior to starting the unit, the desiccant MUST be removed.
The dry air lay-up is best suited for long outages when no work is to be performed on the boiler.
20.11.3 Nitrogen Blanketing
Nitrogen blanketing entails keeping a slight positive nitrogen pressure on the boiler (HRSG). This
prevents air from entering the boiler during the outage. To be successful, no air should be present
in the boiler when the blanket is applied. For boilers coming off-line, nitrogen is applied as the
boiler is cooled down and the pressure has dropped to between 5 and 10 pounds per square inch
gauge (psig). The boiler vents are closed, and nitrogen is admitted at a pressure of approximately
10 psig. As the boiler continues to cool and the steam collapses in the superheater and reheater,
nitrogen displaces the steam volume. Once the boiler has cooled down enough to drain, the
nitrogen displaces the water during the drain. The nitrogen pressure is maintained at about 5 psig
to prevent air from entering the boiler.
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Nitrogen blankets can also be used when the boiler is to be drained after a chemical cleaning.
Nitrogen blanketing is not recommended for boilers that have been drained and are open to the
atmosphere, such as after work has been performed inside the boiler. The air in each of the boiler
circuits has to be displaced with three to five volumes of nitrogen to eliminate the oxygen or the
blanket is ineffective in mitigating corrosion.
Caution: Nitrogen is not to be used during maintenance if personnel are entering the drum. Oxygen
deprivation or suffocation can occur if the drum is not properly vented. Proper confined space
entry procedures should be followed by certified professionals with guidance from the clients’
confined space entry plan.
20.12 Circulating Water Operating Chemistry
These subsections are not meant to be a comprehensive description of every complex chemical
phenomenon found in these systems, but are intended to provide the system operators enough
information for a basic understanding of system operating chemistry.
The project startup water chemistry guidelines shall include a description of the circulating water
chemistry and its parameters. The following subsection is an example of the possible chemical feed
requirements.
20.12.1 Circulating Water Chemical Feed
Chemical conditioning of the circulating water is required to minimize scaling, corrosion, and
biological fouling. The chemicals and intended use of each are described herein.
Regardless of the chemicals fed or operating practices of the circulating water system, it is
imperative that if the condenser is going to be shut down for any extended period of time (more
than 2 days), the condenser should be drained to prevent microbiological or chloride attack from
stagnant water conditions.
20.12.2 Sodium Hypochlorite
The Circulating Water Chemical Feed System (HRE) is designed to shock feed sodium hypochlorite
(NaOCl) to the cooling tower basin to minimize biological growth within the circulating water
system, including the cooling tower and condenser heat transfer surfaces.
When sodium hypochlorite is added to the circulating water, the following reactions occur:
NaOCl
Sodium
Hypochlorite
+ H2O
=
HOCl
+ NaCl
HOCl
=
H+
+ OCl-
Water
Hypochlorous
Acid
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Hydrogen Ion
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Hypochlorite Ion
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Hypochlorous acid (HOCl) and the hypochlorite ion (OCl-) will control biological growth, but HOCl
is more effective at biological control than OCl-. The dissociation of the HOCl into OCl- increases as
the pH of the system increases.
The circulating water sodium hypochlorite feed pumps are controlled manually. The circulating
water sodium hypochlorite feed pumps transfer sodium hypochlorite (10 to 15 percent) solution
directly from the circulating water sodium hypochlorite storage tank to the sodium hypochlorite
diffuser located in the cooling tower basin. Each circulating water sodium hypochlorite feed pump
is designed to deliver the required amount of hypochlorite solution to maintain a free chlorine
concentration at the condenser outlet during periods of shock chlorination. The dosage to achieve
this residual depends on chlorine demand, but is expected to range from 2 to 5 mg/L.
The sodium hypochlorite system is designed to shock the entire circulating water system three
times a day for 20 minutes per shock to control biological growth. Timers and feed rates are
manually adjusted in the DCS.
20.12.3 Sodium Hypochlorite and Sodium Bromide (if applicable)
Either combination of both oxidants are fed to the cooling tower to minimize the biofouling of heat
transfer surface within the circulating water system and to minimize the biological growth on the
tower fill and piping. Sodium bromide (NaBr) itself is not a biocide, but when fed in conjunction
with sodium hypochlorite (NaOCl), the bromide ions are oxidized to form hypobromous acid
(HOBr), which is an effective biocide. When sodium hypochlorite and sodium bromide are added to
the circulating water, the following reactions occur:
NaOCl
Sodium
Hypochlorite
HOCl
Hypochlorous
Acid
+ H2O
=
HOCl
+ NaCl
HOCl
=
H+
+ OCl-
+ NaBr
=
HOBr
=
Water
Hypochlorous
Acid
Sodium
Bromide
Hypobromous
Acid
Hypochlorous
Acid
Hydrogen Ion
HOBr
Hypobromous
Acid
H+
Hydrogen Ion
Sodium Chloride
Hypochlorite Ion
+ NaCl
Sodium Chloride
+ OBr-
Hypobromite Ion
Hypochlorous acid (HOCl) and the hypochlorite ion (OCl-) will control biological growth, but
hypochlorous acid is more effective at biological control than the hypochlorite ion. The dissociation
of the hypochlorous acid into hypochlorite ion increases as the pH of the system increases. The
same is true of hypobromous acid (HOBr) and the hypobromite ion (OBr-), but the dissociation of
the hypobromous acid into hypobromite ion occurs at a higher pH than hypochlorous acid;
therefore, the hypobromous acid is a more effective disinfectant at lower pH.
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The circulating water bromide and sodium hypochlorite feed pumps are controlled manually. The
circulating water sodium hypochlorite feed pumps transfer sodium hypochlorite (10 to 15 percent)
solution directly from the circulating water sodium hypochlorite storage tank to the first mixing
tee. Sodium hypochlorite is diluted with circulating water in the first mixing tee. The circulating
water sodium bromide feed pumps transfer sodium bromide (40 percent) solution directly from
the circulating water sodium bromide storage tank to the second mixing tee, where it is combined
with sodium hypochlorite solution from the first mixing tee. Finally the combined biocide solution
is injection into the biocide diffuser in the cooling tower basin. Each bromide feed pump is
designed to deliver the required amount of sodium bromide solution to maintain the proper mole
ratio of sodium bromide to sodium hypochlorite. Each circulating water sodium hypochlorite feed
pump is designed to deliver the required amount of hypochlorite solution to maintain residual
chlorine concentration at the condenser outlet during periods of shock chlorination. The dosage to
achieve this residual depends on chlorine demand, but is expected to range from 2 to 5 mg/L.
The biocide feed system is design to shock the entire circulating water system with time-controlled
automatic frequency and duration control from the plant DCS. Timers and feed rates are manually
adjusted.
20.12.4 Sulfuric Acid
Sulfuric acid is fed to the cooling tower to reduce the total alkalinity in the circulating water.
Reduction of the alkalinity allows the cycles of concentration in the tower to be increased while
controlling the scaling potential of the water. The sulfuric acid reduces the alkalinity in the water
by the following reaction:
H2SO4
Sulfuric Acid
+ Ca(HCO3)2
Calcium
Bicarbonate
=
CaSO4
Calcium
Sulfate
+ 2CO2
Carbon Dioxide
+ 2H20
Water
The circulating water acid feed pumps transfer sulfuric acid (93 percent) solution directly from the
circulating water acid storage tank to the mixing trough. The sulfuric acid is diluted with
circulating water in the mixing trough prior to entering the cooling tower basin. Each circulating
water acid feed pump is designed to deliver the required amount of sulfuric acid to maintain
between 50 to 150 mg/L M-alkalinity (as CaCO3) levels in the circulating water system over the
expected range of cooling tower cycles of concentration.
Sulfuric acid is fed continuously to the cooling tower basin.
20.12.5 Scale Inhibitor
A scale inhibitor is fed to the cooling tower basin as a sequestering agent to help inhibit scale from
building up in the condenser and reducing the efficiency of the plant.
The mechanism and dosing requirements for the inhibitor are dependent on the proprietary
chemical used. The chemical supplier dosing recommendations should be followed for proper
protection of the system. The circulating water scale inhibitor feed pumps feed neat (without
additional dilution) scale inhibitor solution directly from the circulating water scale inhibitor tote
to the cooling tower makeup line. Each circulating water scale inhibitor pump has automatic
controls to adjust the pump stroke in proportion to the makeup flow rate. Both scale inhibitor
pumps may be needed to expedite the increasing concentration of the scale inhibitor to the
appropriate levels in the circulating water system during startup.
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20.12.6 Corrosion Inhibitor
A corrosion inhibitor is fed to the cooling tower basin as a sequestering agent to help inhibit
corrosion in the condenser and to reduce the efficiency of the plant.
The mechanism and dosing requirements for the inhibitor are dependent on the proprietary
chemical used. The chemical supplier dosing recommendations should be followed for proper
protection of the system. The circulating water corrosion inhibitor feed pumps feed neat (without
additional dilution) corrosion inhibitor solution directly from the circulating water corrosion
inhibitor tote to the cooling tower makeup line. Each circulating water corrosion inhibitor pump
has automatic controls to adjust the pump stroke in proportion to the makeup flow rate. Both
corrosion inhibitor pumps may be needed to expedite the increasing concentration of the corrosion
inhibitor to the appropriate levels in the circulating water system during startup.
20.12.7 Sodium Bisulfite
Sodium bisulfite (NaHSO3) is fed to the cooling tower blowdown for the dechlorination of the
blowdown prior to the disposal to an outfall (if required to meet wastewater discharge
requirements). The sodium bisulfite reacts with the residual chlorine by the following formula:
NaHSO3
Sodium
Bisulfite
+ 2HOCl
Hypochlorous
Acid
=
Na2SO4
Sodium
Sulfate
+ 2HCl
Hydrochloric
Acid
+ H2O
Water
The circulating water bisulfite feed pumps feed neat (without additional dilution) sodium bisulfite
solution directly from the circulating water sodium bisulfite tote to the cooling tower blowdown
line. Each bisulfite feed pump delivers sodium bisulfite solution to reduce the free chlorine residual
in the cooling tower blowdown. Sodium bisulfite is automatically fed to the cooling tower
blowdown during and following biocide shock feed of the circulating water system. The initial
recommended feed time following shock chlorination is 1 hour. Timers and feed rates are manually
adjusted.
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20.12.8 Circulating Water Quality and Monitoring
Table 20-19 provides the recommended water quality parameters for the circulating water system.
Table 20-19
Circulating Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
pH (as pH units)
Continuous
7.5 to 8
Silica (as SiO2)
Shift
Calcium (as CaCO3)
Shift
< 900 ppm
Shift
150 to 200 ppm
Shift
< 0.5 ppm
10 minutes
following shock
0.2 to 0.5 ppm
Total alkalinity (as CaCO3)
Iron (as Fe)
Shift
Manganese (as Mn)
TSS
Free available chlorine
20.12.8.1 pH
< 150 ppm
< 3 ppm
Shift
< 50 ppm
The pH of the circulating water can provide information on the scaling or corrosive tendencies of
the circulating water. If the pH is outside the control limits for the tower, the acid feed should be
adjusted to compensate.
20.12.8.2 Calcium
The circulating water calcium level should remain at or below the normal control point to minimize
the scaling potential within the system. If the calcium limit is exceeded, the cooling tower
blowdown rate should be increased to bring calcium residual under control.
Certain scale inhibitors allow system operation with calcium limits higher than the recommended
normal limit. The supplier of the proprietary chemical used should be consulted for any
recommended modification to the calcium limit.
20.12.8.3 Silica
Silica can cause major scaling problems in the circulating water system if not properly monitored
and controlled. The circulating water silica level should remain at or below the normal control
point to minimize the silicate scaling potential within the system. If the silica limit is exceeded, the
cooling tower blowdown rate should be increased to bring silica residual under control.
Certain scale inhibitors allow system operation with silica limits higher than the recommended
normal limit. The supplier of the proprietary chemical used should be consulted for any
recommended modification to the silica limit.
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20.12.8.4 Total Alkalinity
High alkalinity in the circulating water system can cause scaling problems in the condenser. The
circulating water total alkalinity level should remain within the normal control range to minimize
the scaling potential within the system. If the total alkalinity control range is exceeded, the cooling
tower blowdown rate can be increased to bring alkalinity under control, or the sulfuric acid
addition rate can be temporarily increased to react with the high alkalinity within the system.
Certain scale inhibitors allow system operation with alkalinity limits higher than the recommended
normal control range. The supplier of the proprietary chemical used should be consulted for any
recommended modification to the alkalinity control range.
20.12.8.5 Iron and Manganese
High iron and/or manganese in the circulating water system can cause staining of concrete surfaces
and the cooling tower deck and can contribute to iron or manganese deposition in the condenser,
with resultant sites for promulgation of under-deposit corrosion or microbiological corrosion of the
condenser tubes. If the iron and/or manganese control limit is exceeded, the cooling tower
blowdown rate should be increased to bring iron and/or manganese residual under control.
20.12.8.6 Total Suspended Solids
Suspended solids will always be present in an open recirculating cooling water system from either
suspended solids in the makeup water source or wind-blown dust and dirt that enter the system.
The suspended solids can settle in low-flow areas throughout the system, creating a routine
maintenance issue and, in extreme cases, can provide a site for under-deposit or crevice corrosion.
If the TSS control limit is exceeded, the cooling tower blowdown rate should be increased to bring
TSS residual under control.
20.12.8.7 Chlorine
The free available chlorine residual should be monitored at the condenser outlet following a shock
chlorination period to monitor the effectiveness of the sodium hypochlorite chemical feed. If the
desired chlorine residuals are not present after shock chlorination, the chlorine demand within the
system (degree of biological activity) is higher than what the current shock feed can treat, and the
feed rate and/or duration should be increased to achieve the recommended control range.
20.13 Auxiliary Boiler Chemistry
The auxiliary boiler must be treated to minimize corrosion and scaling in the boiler and to produce
steam of a quality suitable for use as startup steam.
20.13.1 Steam Purity
The auxiliary boiler steam is introduced into the main cycle during startup and should meet the
limits of the main cycle steam.
The recommended steam purity requirements are included in Table 20-20.
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Table 20-20
Auxiliary Boiler Steam Purity Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Cation
Conductance
Continuous
≤ 0.2 µS/cm
≤ 0.4 µS/cm
≤ 0.8 µS/cm
> 0.8 µS/cm
> 1.0 µS/cm
Silica
Shift
≤ 10 ppb
10 to 20 ppb
20 to 40 ppb
40 to 50 ppb
> 50 ppb
Sodium
TOC
Chloride*
Sulfate*
Continuous
Weekly
Grab
Grab
≤ 2 ppb
≤ 100 ppb
≤ 2 ppb
≤ 2 ppb
≤ 4 ppb
> 100 ppb
≤ 4 ppb
≤ 4 ppb
≤ 8 ppb
--
≤ 8 ppb
≤ 8 ppb
*Chloride and sulfate analysis, as needed, when steam purity is in question.
> 8 ppb
--
> 8 ppb
> 8 ppb
> 20 ppb
----
20.13.2 Auxiliary Boiler Water Quality
The auxiliary boiler water quality should be suitable for the production of the steam quality
described in Table 20-20. The recommended boiler water requirements are included in
Table 20-21.
Table 20-21
Auxiliary Boiler Water Quality Parameters
ANALYSIS
FREQUENCY
NORMAL
ACTION
LEVEL 1
ACTION
LEVEL 2
ACTION
LEVEL 3
IMMEDIATE
SHUTDOWN
Specific
Conductance
Continuous
100 to 150
µS/cm
150 to 200
µS/cm
--
--
pH
Sodium
Continuous
9.0 to 9.2, > 9.8
8.0 to 9.0
< 4 ppm
4 to 8 ppm
8 to 15 ppm
> 25 ppm
< 8.0
Daily
12 to 25 ppm
--
Silica
Daily
9.2 to 9.8
> 200 µS/cm
> 15 ppm
--
Phosphate
Daily
20.13.3 Ammonia Feed
< 6 ppm
1 to 10 ppm
6 to 12 ppm
> 10 ppm
--
--
---
Ammonia is fed to the auxiliary boiler to raise the pH to levels where attack of the metal is
minimized. If the feed to the auxiliary boiler is provided by the condensate system, ammonia may
not need to be added to the auxiliary boiler chemical feed.
20.14 Inlet Air Chiller Chemistry
The inlet air chiller water quality must be monitored to minimize scaling and corrosion.
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20.14.1 Makeup Water Quality
The allowable concentrations in the makeup water supplied to the evaporative cooler are included
in Table 20-22.
Table 20-22
Inlet Air Chiller Makeup Water Quality Parameters
CONCENTRATION RANGE
(PPM)
ANALYSIS
Calcium Hardness (as CaCO3)
Total Alkalinity (as CaCO3)
Chlorides (as Cl)
Silica (as SiO2)
Iron (as Fe)
50 to 150
50 to 150
< 50
< 25
< 0.2
Oil and Grease
< 2.0
TDS
30 to 500
pH
6.0 to 8.5
Suspended Solids
<5
50 to 750 µS/cm
Conductivity
µS/cm = MicroSiemen per centimeter = Micromho/cm
The inlet air chiller makeup has a source from service water and demineralized water. The
operator will need to determine the amount of mixing required to maintain the quality.
20.14.2
Scaling Index
The determination of the maximum cycles of concentration (as defined in the ratio of the makeup
water flow to the blowdown flow) should be verified using a scaling index. For evaporative cooling,
it is desirable to maintain a slightly corrosive or scale dissolving index; however, water that is very
corrosive, such as demineralized water, can soften the media in the cooler.
The water at the operating conditions within the evaporative cooler shall be maintained so that the
scaling index lies within the ranges presented in Table 20-23. Although several indices are listed,
the Practical (Puckorius) Stability Index (PSI) is the preferred index of the media vendors.
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Table 20-23
Recommended Scaling Indices for Evaporative Cooling
INDEX
RECOMMENDED RANGE
Langelier Saturation Index (LSI)
0.25 to 0.75
Practical (Puckorius) Stability Index (PSI)
6.0 to 7.0
Ryznar Stability Index (RSI)
5.5 to 6.5
20.14.3 Chemical Additives
The use of chemical additives (of any kind) is not recommended to treat the water. Any use of
chemicals must be approved by the media vendor.
20.15 References


Electric Power Research Institute (EPRI), “Cycle Chemistry Guidelines for Combined
Cycle/Heat Recovery Steam Generators (HRSGs),” Technical Report 1010438, March 2006.
Colleen M. Layman, “Selecting a Combined Cycle Water Chemistry Program,” Power
Magazine, HDR Inc., March 2013.
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21.0 Flow Accelerated Corrosion
Later
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22.0 Sulfuric Acid Handling and Dilution
22.1
Purpose and Applicability
This section provides design criteria for concentrated sulfuric acid handling for ion exchange resin
regeneration, circulating water alkalinity adjustment (pH control), and other acid feed applications
installed in power projects, and provides recommendations, as well as specific criteria for system
sizing and design, for filtration equipment.
22.2
Approach
This section is intended to be used as a basis for the design of sulfuric acid handling and dilution
equipment.
22.2.1
Overview
Sulfuric acid handling and dilution equipment includes storage tanks, unloading stations, acid feed
pumps, dilution system (ion exchange regeneration), and circulating water alkalinity adjustment, as
well as auxiliary safety equipment necessary for the safe handling and feeding of sulfuric acid.
Sulfuric acid is typically provided as 66 degree Baumé (93 percent) commercial grade acid.
22.2.2
Sulfuric Acid Storage Tanks
22.2.2.1 Operating Conditions and Location
Sulfuric acid storage tanks should be designed for atmospheric storage of 66 degree Baumé
commercial grade sulfuric acid at ambient temperature. To minimize building costs and to facilitate
chemical delivery and unloading, the preferred location for storage tanks is outdoors. At plant sites
with an extremely cold winter climate (frequent temperatures less than 0° F [-18° C]),
consideration should be given to an indoor tank location.
Life safety and fire protection requirements must be considered when determining the final
location of the acid storage tanks. The paper listed in Section 22.3, Placement of Sulfuric Acid,
Oxidizer, and Corrosives, contains additional requirements regarding placement of acid storage
tanks.
22.2.2.2 Sizing
The preferred sizing for each tank should be 1.5 times the maximum delivery volume. Acid can be
delivered by railcar or truck. The volume of acid delivered by railcar ranges from approximately
6,000 to 18,000 gallons (22,700 to 68,140 liters). Acid volume delivered by truck is typically
3,000 to 4,000 gallons (11,360 to 15,140 liters). However, the tank should be sized to hold no
greater than a 6 month storage volume.
Table 22-1 shows the effective storage volumes of horizontal, cylindrical tanks with flanged and
dished heads. Effective volume is total volume less ineffective capacity. Ineffective capacity refers to
the volume occupied by the bottom 6 inches (150 mm) and the top 12 inches (300 mm) in the tank.
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Table 22-1
Effective Tank Capacities for Horizontal, Cylindrical Tank With Standard Dished Heads
TANK
DIAMETER
(IN)
EFFECTIVE CAPACITY IN US GALLONS
STRAIGHT SIDE LENGTH (FT)
10
11
12
13
14
15
16
17
18
19
72
1,950
2,100
2,300
2,500
2,650
2,850
3,000
3,200
3,400
3,550
84
2,800
3,050
3,300
3,550
3,800
4,050
4,300
4,550
4,800
5,050
78
90
96
102
108
114
120
2,350
3,250
3,750
4,300
4,900
5,550
6,200
20
2,550
3,550
4,100
4,700
5,350
6,050
6,750
21
2,750
3,850
4,450
5,100
5,800
6,550
7,300
22
3,000
4,150
4,800
5,500
6,250
7,000
7,850
3,200
4,450
5,100
5,850
6,650
7,500
8,400
3,400
4,750
5,450
6,250
7,100
8,000
8,950
3,650
5,000
5,800
6,650
7,550
8,500
9,500
3,850
5,300
6,150
7,050
8,000
9,000
4,050
5,600
6,500
7,400
8,400
9,450
4,250
5,900
6,800
7,800
8,850
9,950
23
24
25
10,050
26
10,600
27
11,150
28
72
3,750
3,900
4,100
4,300
4,450
4,650
4,800
5,000
5,200
84
5,300
5,550
5,800
6,100
6,350
6,600
6,850
7,100
7,350
78
90
96
102
108
114
4,500
6,200
7,150
8,200
9,300
4,700
6,520
7,500
8,550
4,900
6,800
7,850
8,950
5,150
7,100
8,150
9,350
5,350
7,400
8,500
12,400
12,900
13,400
13,900
14,350
10,600
11,050
29
30
12,800
31
13,300
32
13,850
72
5,350
5,550
5,700
5,900
6,100
84
7,600
7,850
8,100
8,350
8,600
90
6,400
8,850
6,650
9,150
6,850
9,450
7,050
12,800
13,200
10,550
10,900
11,200
108
13,200
13,650
14,100
14,550
114
120
11,650
14,850
16,600
12,050
15,350
17,150
12,450
15,850
17,700
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18,250
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11,450
14,400
11,900
14,950
12,350
15,500
12,800
16,050
7,300
10,050
10,200
102
33
9,750
96
9,850
11,250
12,250
78
9,550
8,550
10,900
10,950
11,700
9,200
8,250
6,200
10,500
10,450
120
8,850
7,950
6,000
10,100
10,150
11,900
7,700
5,800
9,700
9,700
11,450
5,550
11,550
14,950
16,800
18,800
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22.2.2.3 Construction
Each sulfuric acid storage tank should be a horizontal, cylindrical tank with standard flanged and
dished heads designed and constructed in accordance with ASME Boiler and Pressure Vessel Code,
Section VIII, Division 1. Vertical tanks may be used; however, they are not the preferred
configuration. Vertical tanks should be constructed in accordance with API 650. Each tank should
be provided with an access manhole, vent, overflow, and other appurtenances as required by the
design. The overflow connection and all tank connections above the maximum liquid level should
be flanged nozzle type. Tank connections below the maximum liquid level should be welded. A
typical sulfuric acid storage tank is shown on Figure 22-1.
The tank should be constructed of carbon steel (ASTM A-516, Grade 70), with a minimum wall
thickness of 1/2 inch (13 mm). The minimum wall thickness should take into account a 0.13 inch
(3.2 mm) minimum corrosion allowance. Carbon steel with a specified maximum tensile strength
exceeding 90 kips per square inch (ksi) (620 megapascal [MPa]) should not be used because of the
potential for hydrogen embrittlement.
Figure 22-1
Standard Drawing for Sulfuric Acid Storage Tank
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All welds, welding, and related operations performed on the storage tank should be in accordance
with the requirements of ASME Boiler and Pressure Vessel Code, Section VIII, Division 1. The shell
joints should be welded butt joints with complete penetration for the full length of the weld and
should be free from undercuts, overlaps, or abrupt ridges. All weld spatter should be removed by
grinding or wire brushing.
The tank fill nozzle should be located on the top of the tank along the longitudinal center line, away
from the tank heads and pump suction nozzle. This nozzle should extend inside the tank
approximately 6 inches (150 mm) to prevent the protective ferrous sulfate film on the tank walls
from being disturbed during tank filling.
One tank outlet nozzle should be located on the bottom of the tank along the longitudinal center
line, away from the fill nozzle. This nozzle should be constructed from Alloy 20 and should extend
inside the tank approximately 6 inches (150 mm) to prevent the protective ferrous sulfate film on
the tank walls from being disturbed when acid is withdrawn from the tank. The outlet nozzle
should be sized according to the pump suction piping, but should not be less than 1 inch (25 mm).
A manway should be located on top of the sulfuric acid storage tank along the tank longitudinal
center line. If requested by the client, manholes may be furnished with a light weight, quick-opening
roof manway cover assembly similar to Tyco Flow Control/Varec Model 220-24-32. Manway cover
assemblies of this type should have a carbon steel base and cast iron cover. Eyebolts, wing nuts,
cover stops, and all other parts of the manhole cover assembly should be carbon steel. Gasket
material should be acceptable for sulfuric acid service. An acceptable gasket selection is a Flexitallic
Style CGI with Alloy 20 inner ring, carbon steel outer ring, and polytetrafluoroethylene (PTFE
[Teflon®]) filler.
The tank should be supported by concrete pedestals formed to the shape of the steel saddle plates
as shown on Figure 22-1. Depending on the acid tank size and specific project requirements, it may
be preferable to include steel construction support legs with the tank.
An access platform may be provided, if required, complete with ladder and handrail in accordance
with specific project requirements.
22.2.2.4 Construction
The sulfuric acid storage tank exterior surfaces, including steel support legs, if furnished, should be
prepared and coated in accordance with the Coating System and Blast Media Selection Procedure.
A protective ferrous sulfate film will form on the bare carbon steel internal tank walls when the
tank is initially filled with sulfuric acid. As such, the interior surface of the tanks should be bare
carbon steel, prepared and coated with a vapor phase corrosion inhibitor in accordance with the
Coating System and Blast Media Selection Procedure. Refer to Figure 22-2.
Specialty coatings should not be provided on the interior of sulfuric acid storage tanks unless
explicitly required by the client in the prime contract or if an acid tank vent dryer is not provided. If
the interior surfaces of the acid storage tank are to be coated, the coating should be a high
temperature baked phenolic coating in accordance with the Coating System and Blast Media
Selection Procedure.
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Figure 22-2
Interior of Uncoated, Carbon Steel Acid Storage Tank
22.2.2.5 Level Transmitters and Indicators
The sulfuric acid storage tank should be furnished with an ultrasonic level transmitter with local
and remote level indication devices. The level transmitter nozzle should be located on the top of the
tank along the longitudinal center line, away from the tank heads and fill nozzle. This nozzle should
be flush with the inside of the tank. The nozzle diameter should be short in length and of sufficient
diameter to prevent interference with the transmitter beam. The level transmitter should be
suitable for flanged mounting directly to the tank nozzle and should have a narrow beam to
minimize interference from the tank nozzle and curvature of the bottom of the tank.
A local level indicator should be provided in the vicinity of the tank filling station such that the
unloading operators have a reasonable view of the display. The display on the remote level
indicator should be calibrated to read in percent full and directly in feet (or meters) and gallons (or
liters) of acid.
22.2.2.6 Tank Vent and Overflow Design
An acid tank vent air dryer should be used. The air dryer removes moisture from air entering the
tank, reducing the potential for condensation. Acid dilution from water condensation dilutes the
acid and increases corrosion on inside tank surfaces. If a vent dryer is used, the vent piping should
be separate from the fill piping, and a separate vent nozzle should be provided on the top of the
tank near the center. The vent nozzle should be flush with the inside of the tank.
Vent piping between the tank and vent dryer must be routed so that there is no possible way for
sulfuric acid to enter the piping and drain back into the vent dryer assembly. The open end of the
vent piping should be designed to prevent rainwater from entering the vent pipe and collecting in
the vent dryer.
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Because the vent dryer assembly requires periodic maintenance to change out the drying reagent,
the vent dryer must be located either on the acid tank access platform, if provided, or outside the
tank containment. The vent air dryer should be provided with a sight window and color changing
desiccant to indicate when the desiccant needs to be replaced and/or regenerated.
Tank overflow piping serves as a vent if a vent air dryer is not used. If a vent air dryer is used, a
check valve must be included on the overflow pipe. The overflow check valve should be a Viton
Tideflex® duckbill type check valve or acceptable equal. If another type of check valve is used, it
should be designed and oriented to prevent the ingress of air.
22.2.2.7 Filling Station Design
The sulfuric acid filling station design should include provisions for safe collection and drainage of
spills and drips, should ensure adequate operator accessibility to valves and instruments, and
should provide means to monitor tank level. The following criteria should be used in the design of
filling stations.
Acid tank fill piping should be laid out to minimize the quantity of piping required. All fill piping
should be sloped to drain into the acid storage tank to the extent possible. Piping not sloped to
drain to the tank should slope to the fill station to allow complete drainage of the acid fill piping.
Acid should be unloaded by a pump located on the delivery truck. Acid delivery trucks are assumed
to be equipped with pumps for unloading, but this should be verified if in question, or if the project
is located outside the United States. Acid suppliers in the vicinity of the plant site should be
consulted to determine if their delivery trucks are so equipped. If truck mounted unloading
equipment is not available for unloading, regulated service air should be provided at the unloading
area to accommodate truck unloading. If compressed air is used for unloading, it should be dry.
Acid suppliers in the vicinity of the plant site should be consulted to determine suitable fittings for
the acid fill connection. Typically, the acid fill connection will be a mating flange for a 2 inch
(50 mm) raised face flange or a quick-disconnect coupling. If the exact connection fitting type
cannot be ascertained, a 2 inch (50 mm) raised face flange by 2 inch (50 mm) male camlock adapter
should be provided as part of the unloading station. This adapter should be constructed from Alloy
20 or polyvinylidene fluoride (PVDF [Kynar®]).
22.2.2.8 Containment
Secondary containment for the acid tank and equipment should be designed in accordance with the
Oil and Chemical Containment Procedure.
Equipment that requires routine operator access or maintenance should be located outside the acid
tank secondary containment.
Acid pump skids should be installed on an equipment maintenance pad located in a curbed area
separate from the acid tank secondary containment. This curbed area should be designed in
accordance with Oil and Chemical Containment Procedure.
Below grade drainage piping from the containment drains or sump drain to an acceptable
treatment or disposal system, if included, should be constructed of premium fiberglass reinforced
plastic rated by the pipe manufacturer for concentrated sulfuric acid service, such as
Z-CORE (NOV FiberGlass Systems).
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Large containment areas that utilize below grade drainage piping to an acceptable treatment or
disposal system should be provided with a locked, closed isolation valve to prevent the treatment
or disposal system from overflowing and/or being overloaded, while still allowing for routine
drainage of minor spillage and accumulated rainwater. These valves should be located in a valve
box immediately outside of the containment area such that the length of upstream piping is
minimized. These valves should be flanged ball valves constructed from premium fiberglass
reinforced plastic and rated by the valve manufacturer for concentrated sulfuric acid service.
PureFlex 450/455 series valves are one such acceptable valve because they are manufactured with
the same Z-CORE resin as the pipe mentioned above.
If the containment location does not permit gravity drainage to an acceptable treatment or disposal
system, gravity drainage provisions may be omitted from the design, and instead, provisions should
be included to allow routinely scheduled use of portable scavenging equipment to remove
rainwater and spillage.
22.2.2.9 Sulfuric Acid Pumping Station
Sulfuric acid pumps should be hydraulically actuated diaphragm positive displacement pumps,
although mechanically actuated diaphragm pumps or gear pumps are also acceptable. Solenoid
driven diaphragm pumps should not be used. Hydraulically actuated diaphragm pumps should be
furnished with internal hydraulic pressure relief valves set as recommended by the pump
manufacturer. Hydraulically or mechanically actuated diaphragm positive displacement pumps
used in sulfuric acid service should have a maximum stroking speed of less than 72 strokes per
minute to ensure the proper fill of the pump cavity on the suction stroke at low temperatures.
Automatic control should be provided for acid feed pumps to allow acid flow control from a
4 to 20 milliampere (mA) direct current (dc) signal. Acid feed pumps should have either (1) an
electronic positioner for automatic stroke adjustment or (2) a variable speed drive motor and a
manual stroke positioner. Variable speed drives and manual stroke positioners are generally
preferred on the circulating water feed pumps because they allow for control over a broader range
of feed rates. A typical circulating water sulfuric acid feed system is illustrated on Figure 22-3.
Sulfuric acid pumps should be constructed with Alloy 20 or PVDF (Kynar®) heads and PTFE
(Teflon®) diaphragms.
A bleed valve should be installed on the discharge of each pump, upstream of the discharge
isolation valve. This valve provides a controlled means to depressurize the pump head before
maintenance.
A back-pressure valve should also be furnished and installed on the common discharge of the acid
pumps. The back-pressure valve should be factory set at the pressure recommended by the pump
manufacturer to ensure proper seating of the ball checks. Typically, 50 pounds per square inch
gauge (psig) is sufficient.
A pulsation dampener should be included on the common discharge of the acid pumps, upstream of
the back-pressure valve. Consideration should be given to also including a pulsation dampener on
the common suction to the acid feed pumps to help ensure the proper operation of the pumps at
low temperatures when the acid is highly viscous. Pulsation dampeners should be constructed of
Alloy 20 or PVDF (Kynar®) bodies and PTFE (Teflon®) or Viton bladders or diaphragms. A root
isolation valve and a bleed valve should be provided to facilitate maintenance of the pulsation
dampener.
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Figure 22-3
Typical Circulating Water Sulfuric Acid Feed System
A Y type strainer should be furnished on the common suction of the acid pumps. The strainer body
and screen should be constructed from Alloy 20. The flush port on the strainer should be valved.
A calibration column should also be provided. The calibration column should be constructed of
borosilicate glass with acrylic shielding and Alloy 20, PVDF (Kynar®), or PTFE (Teflon®) ends, or
other acceptable materials for concentrated sulfuric acid. Polyvinyl chloride (PVC) and chlorinated
polyvinyl chloride (CPVC) are not acceptable materials. The calibration column should be vented to
a level above the maximum liquid level in the storage tank.
Pump suction and discharge piping should be Alloy 20 stainless steel. The pump suction line
routing should ensure that no air pockets develop in the suction line.
The specifications (UN N08020) in Table 22-2 should be reviewed to identify the material to be
used.
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Table 22-2
Alloy 20 Material Specifications
B-366
Wrought fittings
B-463
Plate, sheet, strip
B-462
B-464
B-468
B-474
B-729
Forged parts
Welded pipe
Tubing
Electric fusion welded pipe
Seamless pipe
22.2.2.10 Sulfuric Acid Storage Totes
For applications where the volume of chemical being used does not warrant a permanent bulk
storage tank, sulfuric acid may be supplied in chemical totes. If chemical totes are to be used,
special attention to the arrangement, including hazardous area classification, must be considered
early on in the design process (refer to Placement of Sulfuric Acid, Oxidizer, and Corrosives in
Section 22.3).
If totes are to be used, the suction line on the acid pump skid should be furnished with a 1 inch
(25 mm) male camlock fitting. A flexible hose should be provided to connect the tote to the suction
connection on the pump skid. The flexible hose should be 1 inch (25 mm) diameter with sufficient
length to connect the tote to the permanent connection; however, the hose length should be kept at
a minimum to reduce potential chemical exposure and waste during tote replacement. Hoses
should be constructed from convoluted perfluoroalkoxy (PFA) hose with a braided polypropylene
or PVDF (Kynar®) cover and solid PVDF (Kynar®) female camlock fittings on each end. One such
acceptable hose is the ProFlex Series manufactured by PureFlex.
22.2.2.11 Piping
The following general criteria should be used for piping system design.
Concentrated acid piping should be seamless Alloy 20. Refer to Table 22-2 for more information on
Alloy 20 material specifications.
Flanged and threaded joints should be minimized in the concentrated acid piping to reduce the
potential for leakage. Piping with welded connections should be used to the maximum extent
practical. Where flanged and/or threaded joints are unavoidable, consideration should be given to
providing plastic covers around flanged and/or threaded joints, especially around flanged and/or
threaded joints outside of chemical containment areas or curbs, to protect against sprayed
chemicals.
A block and bleed valve arrangement should be provided where concentrated acid is injected
directly into a dilution line. The main purposes of the block and bleed assembly are to provide
indication if there is a leaking valve and to provide positive protection against water backflowing
into the concentrated acid piping and tank. The block valve located between the bleed valve and the
mixing tee should be located as close as practical to the check valve, with the check valve as close as
practical to the mixing tee to minimize the amount of Alloy 20 piping that is exposed to dilute acid.
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The upstream block valve should be located as close as possible to the branch line that contains the
bleed valve. The bleed valve and piping should be positioned to provide an open air break, yet
result in a minimum amount of acid loss. One method of accomplishing this is by looping the bleed
line. The block and bleed valves should be arranged to minimize the quantity of acid wasted to
drain during each bleed sequence. Bleed valves should be spring to open, air to close. Block valves
should be air to open, spring to close.
When diluting sulfuric acid with water, it is possible to achieve temperatures in excess of 200° F
(90° C). For this reason, the plastic lined pipe should be used for acid dilution. Plastic lined piping
should be carbon steel or ductile iron lined with PTFE (Teflon®) or PFA, in accordance with
ASTM F1545, and manufactured by Crane Resistoflex or an acceptable equivalent. Connections
should be molded, raised faced, flanged, or an acceptable equivalent. The pipe exterior surfaces
should be coated with a high temperature, acid-resistant novolac epoxy coating system in
accordance with the Coating System and Blast Media Selection Procedure.
The dilution water rate set and shutoff valves and the dilution water check valve should be located
as close as practical to the mixing tee to minimize the quantity of plastic lined piping required.
The acid dilution piping should be sized and laid out to ensure turbulent flow to aid in mixing and
to reduce hot spots. Downstream of the acid mixing tee, the piping should make several turns to
ensure adequate mixing. If the pipe routing from the acid mixing tee is insufficient to result in
complete mixing of the acid and the dilution water prior to conductivity measurement, an in-line
static mixer should be included in the effluent line from the mixing tee. The static mixer should be
made of materials of construction suitable for the service, preferably nonmetallic PTFE (Teflon®).
The dilute acid conductivity cell should be located as far as possible from the mixing tee to ensure
adequate mixing of acid prior to conductivity measurement.
Tapped plastic spacers used in plastic lined piping systems should be steel armored. Tapped plastic
spacers in plastic lined piping should be minimized to reduce the potential for leakage. This is
especially important for spacers that require larger taps, such as for conductivity cells. Where
possible, fittings (such as a tee) should be used to mount the cells. Preferably, the cell insertion
should be at a tee that will allow the cell to be inserted directly into the flow path rather than
tangentially to the flow path.
Alloy 20 is not suitable for dilute sulfuric acid at concentrations less than 10 percent. At
concentrations less than 10 percent, 316 stainless steel is preferred. Plastic lined pipe or suitable
fiberglass reinforced plastic pipe is also acceptable for sulfuric acid downstream of the dilution
piping.
Drain piping should be acid-resistant pipe constructed of premium fiberglass reinforced plastic,
rated by the pipe manufacturer for concentrated sulfuric acid service, such as
Z-CORE (NOV FiberGlass Systems).
For installations in which overhead routing of concentrated acid piping above traffic areas cannot
be avoided, a guard sleeve may be used around the piping to prevent drips into traffic areas. The
guard sleeve should be made of PVC, or other acid-resistant piping materials, and should be sloped
to a chemical drain.
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Figure 22-4
Standard Drawing for Acid Diffuser Nozzle
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22.2.2.12 Acid Mixing Tee
A suggested arrangement for the acid mixing tee, which shows the flow orientation of the mixing
tee that has been used with success by Black & Veatch (B&V), is illustrated on Figure 22-5 (Note:
The proper orientation is with the acid entering the bottom of the mixing tee).
Figure 22-5
Standard Drawing for Acid Mixing Tee
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This orientation ensures water-acid mixing when in service and, since acid is more dense than
water, reduces the possibilities of getting water in the acid line or acid in the dilution water line
when the acid dilution system is not in operation. Because of the high temperatures possible when
mixing acid and water, a PTFE lined (Teflon® lined) steel tee should be used.
An acid mixing trough in the cooling tower basin can be used in some applications. Refer to
Figure 22-6.
Figure 22-6
22.2.3
Standard Drawing for Acid Mixing Trough
Sulfuric Acid Dilution System for Ion Exchange Regeneration
This section presents the standard method for the design of concentrated sulfuric acid dilution
systems for ion exchange regeneration. Each dilution system application should be evaluated
according to its particular needs when this standard is used.
When calcium is a significant portion of the cation load and sulfuric acid is used for regeneration of
the cation resin, it is necessary to regenerate the resin with increasing concentrations of acid
(normally in 2, 4, and 6 percent steps) to prevent the precipitation of calcium sulfate on the resin.
The desired acid concentrations are obtained by diluting concentrated sulfuric acid (66 degree
Baumé) with demineralized water.
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When sulfuric acid is diluted with water, heat is released, and material corrosion rates are
accelerated. The corrosion of the acid dilution system may be reduced by incorporating the
following elements into the system design:
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
Taking precautions to ensure that backflow cannot occur.
Ensuring proper dispersion to minimize areas where acid and water may mix under
stagnant conditions.
Choosing materials of construction suited for the service.
The components to which specific attention must be given in the overall design are the piping
materials and layouts, the type and location of valves, the materials and construction of the mixing
tee, the installed orientation of the tee, and the design of the system to ensure proper dispersion of
the acid. Design guidelines are given for each of these components.
Figure 22-7 provides a flow diagram of a typical demineralizer acid feed system.
Figure 22-7
Typical Demineralizer Acid Feed System
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22.2.4
Sulfuric Acid Safety Equipment
This section presents the preferred method of design for safety equipment for sulfuric acid
handling. Each sulfuric acid handling application should be evaluated according to its particular
needs.
Safety equipment components to which specific attention must be given in the overall design
include safety showers and eyewashes, and hose and hose bibbs. Design guidelines are provided for
each of these components.
22.2.4.1 Safety Shower and Eyewash Facilities
Safety shower and eyewash facilities should be located in accordance with applicable codes and
standards and as close as possible to the acid handling equipment that requires operator attention.
Multiple shower and eyewash facilities may be required depending upon the relative locations of
the acid handling equipment. Typically, safety shower and eyewash stations are located adjacent to
the fill station and pump skids/tank areas. Operator access to safety shower and eyewash facilities
should be unobstructed. Safety shower and eyewash facilities should be well illuminated and
identified by signs placed by the user. Safety showers and eyewash stations should not be located
within curbed areas unless operators will typically be inside the curbed areas. All safety showers
and eyewash facilities must be provided with potable quality water.
22.2.4.2 Hose and Hose Bibbs
Fill stations must be provided with a hose and hose bibb. Hose and hose bibbs should be provided
for flushing of acid drips and spills following neutralization with lime or soda ash and for
washdown of acid handling equipment areas. Multiple hose bibbs may be required to ensure that
washdown capabilities can be provided to all acid handling equipment areas. Hose bibbs may be
supplied by either plant service water or potable water. If potable water is used as the water
supply, a backflow preventer must be installed immediately upstream of the hose bibb.
Additional safety requirements, including the use of safety shields, rubber gloves, and protective
clothing for personnel, should be according to the manufacturers’ safety data sheets.
22.3
References

Coating System and Blast Media Selection Procedure.


Oil and Chemical Containment Procedure.
Mark Keleher, “Placement of Sulfuric Acid, Oxidizer, and Corrosives,” Black & Veatch
Position Paper, June 26, 2006 (Revised March 8, 2007), located on the Industrial Water
Treatment Community page.
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23.0 Carbon Dioxide Storage and Direct Gas Feed for pH Control
23.1
Purpose and Applicability
This section defines the design criteria for carbon dioxide (CO2) storage and direct gas feed
equipment for pH reduction of water and wastewater streams.
23.2
Approach
The CO2 storage and direct gas feed system covered by this section includes equipment necessary to
allow safe storage, handling, and metering of CO2 to reduce the pH of a water or wastewater stream.
The section also provides criteria to be used to estimate the required CO2 feed rate, feed rate
measurement, system operation and control, and injection point considerations.
The design conditions that are provided herein are those used by one supplier of CO2 equipment.
These design conditions may vary among suppliers and are provided for reference.
23.2.1
Overview
A CO2 storage and direct gas feed system typically includes the following pieces of equipment:









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
An insulated, low-pressure, liquid CO2 storage tank, designed and constructed in accordance
with the American Society of Mechanical Engineers (ASME) Boiler & Pressure Vessel Code
(B&PVC) Section VIII, Unfired Pressure Vessels, equipped with safety relief valves for
overpressure protection. Design working pressure is 350 pounds per square inch gauge
(psig) (2,413 kilopascal gauge [kPag]).
Refrigeration system.
Vaporizer.
Vapor heater.
Solenoid valve.
Pressure regulators and indicators.
Tank level indicator.
Feed line safety relief valve.
Flow indicator(s).
Automatic control valve, complete with actuator and manual bypass assembly.
Interconnecting piping between the CO2 storage tank and feed point.
Check valve.
In-line static mixer.
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
A pH electrode assembly.
A pH controller, complete with proportional and reset control functions. (If dual element
control is used, the control system will include a pH controller, a ratio controller, and
summing function.)
A typical CO2 storage and direct gas feed system is shown on Figure 23-1.
Figure 23-1
23.2.2
Typical Carbon Dioxide Storage and Direct Gas Feed System
Materials of Construction
The recommended materials of construction for the various items of equipment are listed as
follows:





Storage Tank - ASME SA-612 carbon steel, rated for moderate and lower temperature
service.
Piping Integral to Storage Tank Assembly - ASME SA-106 carbon steel, Schedule 80.
Valves - Carbon steel or brass with stainless steel internals.
Insulated Feed Piping - ASTM A106 carbon steel, Schedule 80, coated in accordance with the
Coating System and Blast Media Selection Procedure.
Uninsulated Feed Piping - ASTM A312, Type 304 stainless steel, Schedule 80.
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23.2.3
Estimation of Carbon Dioxide Requirements
Below a pH of approximately 8.5, the consumption of CO2 will increase significantly to achieve an
equivalent pH reduction. This is caused by the buffering action of the bicarbonate ions (HCO3-) that
are formed. The use of CO2 for pH reduction is limited to applications in which the desired pH is not
lower than approximately 8.5. However, to be conservative, it is suggested that the determination
of the CO2 feed rate required for pH reduction be based on treatment to a final pH of 8.0.
The amount of CO2 required is equivalent to the change in acidity that is necessary to reduce the pH
to 8.0.
23.2.4
System Operation and Control
Liquid CO2 should be stored in an insulated storage unit. The storage unit should be furnished with
the equipment necessary to maintain the liquid CO2 around 0° F (-18° C). A vaporizer is generally
provided to change the liquid CO2 to a vapor. A pressure building vaporizer is required to maintain
the operating pressure in the storage unit during periods of high liquid or vapor withdrawal. Liquid
CO2 is drawn from the storage unit through the vaporizer and returned to the tank as a vapor to
maintain the storage pressure. There is a cooling effect when product is withdrawn from the
storage unit, resulting in decreasing pressure and temperature. For every pound of vapor
withdrawn, approximately 120 British thermal unit (Btu) is pulled from the liquid CO2 in the vessel.
In metric units, approximately 280 kilojoules (kJ) is pulled from the CO2 for each kilogram of vapor
that is removed. (To fill the space left by the drawn vapor, an equal amount of liquid is vaporized.
The energy is required to vaporize the liquid into vapor.) CO2 vapor for process use is then
withdrawn from the tank and passed through regulators, metering equipment, and other
accessories, depending on the type of feed equipment used.
CO2 units must maintain pressure between 250 and 300 psig (1,720 and 2,070 kPag) for most CO2
applications. When product is withdrawn from the unit, heat is removed and must be replaced to
maintain proper working pressure. Due to the insulation value on storage units, very little heat
entry occurs. As CO2 is withdrawn from the storage unit, a self-refrigeration effect occurs, and
pressure in the storage unit is reduced. This self-refrigeration effect is more pronounced in vapor
withdrawal. As noted before, for every pound of vapor withdrawn, approximately 120 Btu (280 kJ
per kilogram of vapor removed) must be added back to the CO2 to offset the drop in pressure. If the
withdrawal rate is great enough to require more thermal energy to be introduced into the product
than are available from normal heat entry through the insulation, an outside source of heat must be
introduced. When additional heat is required, a vaporizer is introduced into the system design to
replace the lost heat and maintain the proper operating pressure. If the pressure inside the unit is
allowed to drop below 60.4 psig (416.4 kPag), the CO2 will convert to dry ice inside the unit. The
unit will then have to be removed from service for a prolonged period of time to allow pressure to
return to normal operating conditions.
Example: A storage unit has a normal heat entry of 1,955 British thermal units per hour (Btuh)
(2,063 kilojoules per hour [kJ/h]) at 70° F (21° C) ambient temperature. Product is withdrawn as a
vapor at a rate of 300 pounds per hour (lb/h) (136 kilograms per hour [kg/h]). Heat must be
introduced into the product at a rate of 300 lb/h x 120 British thermal units per pound (Btu/lb) =
36,000 Btuh (or 136 kg/h x 280 kilojoules per kilogram [kJ/kg] = 38,080 kJ/h).
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An outside heat source, such as an electric vaporizer must be provided with a capacity of
36,000 - 1,955 = 34,045 Btuh (or 38,080 kJ/h - 2,063 kJ/h = 36,017 kJ/h) to maintain pressure in
the storage unit. In the case of an electric vaporizer, this would be equivalent to a 10 kilowatt (kW)
unit.
In the previous example, a refrigeration unit is not required as long as vapor is being withdrawn. In
fact, as long as vapor is being withdrawn at a rate as low as 1,955 Btuh/120 Btu/lb = 16.3 lb/h (or
2,063 kJ/h = 7.37 kg/h), no refrigeration is required. The only time that the product would be
vented would be during withdrawal rates less than 16.3 lb/h (7.37 kg/h), or during total shutdown
periods greater than 6 to 10 days.
The insulation selection of a vessel will have a significant role in the determination of the normal
heat entry for the anticipated location of a vessel. Most importantly, the application and frequency
of usage and amount of product withdrawn will determine the best type of insulation and
accessories required. The engineer should take this into consideration when planning for and sizing
the refrigeration and vaporization systems.
When CO2 is required by the process, the CO2 gas is heated to near room temperature by a vapor
heater. The requirement for a vapor heater is determined by the length of interconnecting feed
piping, ambient conditions, and the maximum CO2 feed capacity. One supplier of CO2 feed systems,
Tomco Equipment Company, recommends that a vapor heater be furnished only on systems with a
maximum feed capacity at or above 500 pounds (227 kg) of CO2 per 24 hours. Therefore, smaller
capacity systems usually do not require a vapor heater. The vapor heater is required on larger
systems to heat the CO2 gas to prevent freeze-ups in small orifices in the downstream feed
equipment. The gaseous CO2 is then piped to two pressure regulators in series to reduce the
pressure required by the application. Some contractors may prefer to use one pressure regulator to
accomplish the required pressure reduction. A safety relief valve is installed in the feed line
downstream of the pressure regulator(s) to protect downstream feed equipment from
overpressurizing.
The solenoid valve controls the on/off operation of the CO2 feed based on any of several interlocks
that are specific to the particular process design, such as process control valve closure or process
pump shutoff. The CO2 gas flow rate is regulated by the automatic control valve. The pH measuring
circuit provides a signal to the proportional mode controller based on the pH of the water being
treated. The controller compares the measured pH to a desired pH set point value. The resulting
differential is used by the controller to generate an output signal that is used to control the
operation of the automatic control valve. The CO2 gas is then conveyed to the injection point. The
check valve serves to prevent backflow of process fluid into the CO2 feed line.
Although not normally required, a dual element control system should be considered for
applications in which the process flow rate varies widely over short periods. The dual element
control system would use the process pH and the process flow rate as control signal inputs.
The piping in which the pH cell is mounted should be arranged to maintain the wetness of the pH
cell at all times. If wetness is not maintained, the pH cell will dry out and generate erratic readings
after re-exposure to the process fluid.
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The CO2 storage tank should be equipped with a bleeder type relief valve and a safety relief valve.
The bleeder type relief valve provides self-refrigeration in the event of a temporary refrigeration
system shutdown. The safety relief valve, set for the maximum allowable working pressure,
protects against overpressure in the event of refrigeration system problems that exceed the
compensation capability of the bleeder valve. The bleeder relief valve should be set at 330 psig
(2,275 kPag). The safety relief valve should be set at 350 psig (2,413 kPag).
23.2.5
Injection Point Considerations
The greater the process pressure, the more CO2 a liquid can hold in solution. The reaction of the CO2
with the wastewater will therefore be quicker and more efficient if fed to a pressurized line. To
further increase the reaction rate of the CO2 with the water, an in-line static mixer should be
installed in the process line downstream of the CO2 injection point.
The process line to which the CO2 is fed should not contain any vapor spaces from the CO2 injection
point to the downstream pH monitoring point. This will ensure that the CO2 will react with the
water, rather than collect in vapor spaces in the piping.
System design should allow for a minimum reaction time of 30 seconds between the CO2 injection
point and the downstream pH monitoring point, based on process design flow condition.
If the CO2 must be fed to a gravity flow line, such as an open channel, the CO2 should be dispersed by
means of diffusers. Because bubbles of CO2 will rise to the surface, special consideration must be
given to the depth of submergence of the diffusers to allow adequate residence time for the
reaction. A minimum depth of 10 feet (3 m) is recommended.
23.2.6
Feed Rate Measurement
It is recommended that the CO2 feed equipment be specified to provide a 20 to 1 turndown ratio on
the feed range capability. This adjustable range may necessitate the use of two flow indicators. The
design CO2 feed rate should be in the midrange of the control extremes. Because CO2 gas is a
compressible fluid, it will experience changes in density as changes in operating pressure
conditions occur. To ensure accurate flow measurement, provisions must be made to either adjust
for deviation from the design pressure or to maintain the design pressure at the flow indicator(s).
Accurate flow measurement is ensured by either of the following methods:


23.3

A chart providing correction factors for different operating pressures may be mounted on
the flow indicator(s). The use of the chart would be based on the reading on the upstream
pressure indicator.
Pressure regulators may be installed on each side of the flow indicator(s) to maintain the
design pressure at the flow indicator(s). This arrangement would be considered in cases
where very accurate flow measurement is required.
References
Coating System and Blast Media Selection Procedure.
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24.0 Gas Chlorination Chemical Feed System
24.1
Purpose and Applicability
This section provides design criteria for gas chlorination systems installed in Black & Veatch (B&V)
power projects. This section provides recommendations as well as specific design criteria for
system sizing and design for gas chlorination equipment.
24.2
Approach
This section is intended to be used as a basis for the design of gas chlorination systems. It is
important to note that this information should only be considered as a starting point. Additional
research on the treatment methods is warranted when a project uses a gas chlorination system.
24.2.1
Overview
Sodium hypochlorite feed is the most common disinfection method used for the circulating water
system and raw/service water systems in B&V power projects. Another disinfection method used is
a gas chlorination system. Gas chlorination is typically used outside of the United States.
Most chlorine manufactured today is made using an electrolytic cell, either membrane, diaphragm,
or mercury type. The manufactured chlorine gas is then liquefied by refrigeration and pumped to
storage tanks before being repackaged and distributed to customers. In elemental form, chlorine is
a greenish yellow gas. It is packaged as a liquefied gas under pressure. This liquid will vaporize
quickly at ambient temperature and pressure.
The volume of liquid chlorine increases rapidly with increasing temperature. Liquid chlorine is also
noncompressible. Because of this, it is extremely important in liquid chlorine applications to
prevent ruptures in containers or pipelines by allowing adequate vapor space in each for
expansion.
Chlorine gas can be dissolved in water to form a chlorine solution. This solution is then used to
disinfect a process stream such as cooling tower makeup or service water. The reaction for this is
shown as follows:
Chlorine + Water = Hypochlorous Acid + Hydrochloric Acid
Cl2 + H2O  HOCl + HCl
The hydrochloric acid will completely dissociate.
HCl  H+ + Cl-
The hypochlorous acid will partially dissociate.
HOCl  H+ + OCl-
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The extent of dissociation is pH and temperature dependent. At pH 5, the chlorine exists as
hypochlorous acid (HOCl). At pH 10, the chlorine exists as hypochlorite (OCl-). Either form is
considered free chlorine residual or free available chlorine, but HOCl at the lower pH is more
effective at killing bacteria. More information regarding chlorine chemistry can be found in
Section 24.3, References.
24.2.2
Gas Chlorination Major Equipment and Appurtenances
Chlorine is delivered to the power plant as a liquefied gas under pressure, usually in cylinders, ton
containers, or tank cars. Generally, chlorine ton containers are used for power plants; therefore,
this section emphasizes ton container design for gas chlorination systems. Other container design
information can be found in Section 24.3, References. To become familiar with the properties of
chlorine and system design considerations, the designer should read the references before
designing a gaseous chlorine system.
Chlorine can be withdrawn from ton containers as a liquid or a gas. This occurs under pressure.
There are two valves located on a container, and when placed properly on the trunnions, the top
valve will feed chlorine gas and the bottom valve will feed liquid chlorine. When liquid chlorine is
withdrawn from ton containers, it must be vaporized before it is fed to the process. Gaseous
chlorine is educted into a dilution water line through a vacuum regulator to create a chlorine
solution and is fed into the process as the disinfectant. The required chlorine feed rate typically
determines if liquid or gaseous chlorine is withdrawn. Refer to Subsection 24.2.3 for design details.
An example gas chlorination system piping and instrument diagram is shown on Figure 24-1.
System design is described in the following subsections.
24.2.2.1 Gas Chlorination Storage and Handling
24.2.2.1.1 Chlorine Ton Containers
A chlorine ton container holds 2,000 pounds (907 kg) of chlorine. Ton containers can vary in
physical size but have a maximum outside diameter of 30 inches (762 mm) and are 82.5 inches
(2,096 mm) long.
Ton containers must be handled with mechanical equipment. Generally, they are delivered by truck
and must be lifted off the truck with a crane or hoist equipped with special lifting beams and hooks.
Monorail cranes are used most often in B&V power projects. Frequently, container delivery trucks
will have a lift mechanism on the truck that can move cylinders from/to any position on the truck
but no ability to put the cylinders anywhere off the truck.
Several ton containers are typically connected on a common header to produce the chlorine feed
rate required by the system. This is called a manifold. Two manifolds are typically provided to
allow one manifold to be in operation while the other manifold is being connected to new
containers.
24.2.2.1.2 Ton Container Trunnions
Ton containers (regardless of whether they are cylinders in storage, in use, or empty cylinders
waiting for replacement) are placed on trunnions for support. There are two types of trunnions
available: fixed trunnions and roller trunnions. Roller trunnions are typically used because they
allow the containers to be rotated while sitting on the trunnions.
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24.2.2.1.3 Ton Container Scales
The ton containers are typically placed on scales to monitor the amount of liquid chlorine in the
container. There are two types of ton container scales: hydraulic and electronic. B&V power
projects generally use electronic scales. Sometimes one scale is used on one container of each
manifold, and it is assumed that all the containers in that manifold will weigh the same because the
common manifold will result in all cylinders equalizing. If this method is used, the containers need
to be placed at the same height and kept at the same temperature. This is not an accurate way to
measure chlorine content but will give a good idea of when to order new containers. Some clients
require that each container have a scale. The container scales can be integrated with roller
trunnions to facilitate rotation of the containers.
24.2.2.1.4 Ton Container Manifold Assemblies
The ton containers are connected to each other with a manifold assembly to feed the required
amount of chlorine. The manifold hard piping is 3/4 inch (19 mm) or 1 inch (25 mm) Schedule 80
seamless carbon steel pipe with 3,000 pounds per square inch (psi) (200 bar) rated forged steel
fittings. Only chlorine resistant threaded sealant should be used. A horizontal section of the
manifold should be in front of and above the containers on the container side with the discharge
valves. The horizontal collection section should be at a height of approximately 48 inches (1.2 m). A
clearance of at least 8 inches (21 cm) must be allowed at both ends of the containers to leave room
for the lifting bar. For each container, a header valve should be installed on the horizontal piping
directly in front of the container valves. These header valves shall be separated at approximately
30 inches (76 cm) apart to match the separation of the valves on the ton containers. The horizontal
pipe should be sloped down at approximately 2 to 3 degrees in the direction of the gas flow to allow
liquid chlorine to flow in that direction. After three or four containers, a vertical section of pipe
(drip leg) should be installed to capture the liquid. A 25 watt heater must be installed and operated
continuously toward the bottom of the drip leg to keep it hot at all times to ensure evaporation of
any liquid chlorine. A manual ball valve should be installed after the drip legs to allow isolation of
the ton containers.
The Chlorine Institute recommends that liquid chlorine containers not be manifolded together for
simultaneous liquid chlorine withdrawal. Manifolding can cause overpressurization and rupture.
The distance between the manifold assembly and the vacuum regulator should be minimized, and
piping should be routed with minimal turns and changes in elevation. Liquid chlorine will corrode
piping if allowed to collect and sit in piping.
24.2.2.1.5 Switchover Device
A switchover device may be used to ensure uninterrupted flow of chlorine fed to the chlorine feed
equipment if required by the system functionality. The switchover device automatically switches
the empty container manifold to the spare container assembly. Switchover devices operate based
on either pressure or weight of the containers. A system providing intermittent shock chlorination
could provide a “loss of chlorine” annunciation that would alert the operators to manually
reestablish the chlorine containers before the next chlorination period.
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24.2.2.2 Chlorine Feed System
24.2.2.2.1 Gas Filters
A gas filter should be included to remove impurities that can cause fouling in vacuum regulators
and chlorine feeders. It should be located immediately upstream of the vacuum regulator.
24.2.2.2.2 Vaporizers or Evaporators
Liquid chlorine must be vaporized before it is fed to the chemical feed equipment. This is done by
using a vaporizer that applies heat indirectly to the chlorine to vaporize it. Liquefaction of chlorine
can lead to operating problems and failures; therefore, superheat in the chlorine gas is helpful.
24.2.2.2.3 Pressure Reducing Valves
For gaseous chlorine to be fed safely, the gaseous chlorine pressure must be reduced to vacuum. In
areas that have extreme ambient temperature fluctuations, this may be done in two stages with a
pressure-reducing valve and then a vacuum regulator.
Gaseous chlorine withdrawal systems should have a pressure reducing valve in the outlet piping of
each switchover assembly, when used.
Liquid withdrawal systems should have a combination pressure reducing and shutoff valve in the
outlet piping of each evaporator. The discharge from an evaporator should also run at a partial
vacuum.
24.2.2.2.4 Vacuum Regulators
Vacuum regulators are used to reduce the gaseous pressure to a regulated vacuum. The vacuum is
established by the chlorine ejectors, which are located downstream in the feed system. Without the
vacuum induced by the chlorine ejectors, the vacuum regulators stay closed and stop the flow of
chlorine. Vacuum regulators can be either wall mounted, container mounted, or pipeline mounted
in the header at the chlorine cylinders. Container mounted devices are often mounted in parallel,
with several units on separate ton containers and the discharges tied together (refer to the piping
and instrument diagram on Figure 24-1). When container mounted vacuum regulators are used,
each container must be placed on a dedicated scale.
24.2.2.2.5 Chlorinators and Chlorine Ejectors
Chlorine is metered as it passes through a chlorinator. The chlorinator is placed between the
vacuum regulator and the ejector to control the chlorine feed rate. The chlorine ejector generates
the vacuum for the system through the Bernoulli effect and draws the chlorine through the system.
The chlorine ejector mixes the chlorine with water; after which, it is fed to the process as a chlorine
solution. A chlorine diffuser is typically used to mix the chlorine solution with the process water.
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There are two types of chlorinators: sonic type and pressure-balanced type. The sonic type
chlorinators are small and are usually mounted to the vacuum regulators, which are mounted
directly to the ton containers or cylinders. The pressure-balanced type chlorinators are used on
larger systems and are either floor or wall mounted. A pressure-balanced chlorinator consists of a
remote vacuum regulator, a rotameter, a variable orifice control valve, and a discharge pressure
regulating valve.
24.2.2.3 Gas Chlorination System Safety Requirements
Chlorine is a toxic chemical. A detailed code review should be undertaken for each new chlorine
system design with respect to the most recent code. If a project requires a chlorine scrubber
system, all chlorine vent piping must terminate adjacent to the scrubber intake duct and gas
detector.
Safety equipment to be included with a gas chlorination system is listed as follows:




24.2.3
Chlorine leak detectors.
Respiratory protection.
Chlorine emergency kit.
Alarm horn and light.
Gas Chlorination System Design
The gas chlorination design should consider operator and public safety and maintaining long-term
system reliability and operability. The following documents, in addition to project specifications,
should be reviewed before initial design:


Regulations such as Environmental Protection Agency (EPA) - Risk Management, the
Occupational Safety and Health Administration (OSHA) - Process Safety Management, Clean
Air Act, and the Uniform Fire Code should be thoroughly reviewed for site-specific
requirements.
Reference information defined at the end of this section regarding chlorine equipment
design, especially the reference that gives an overview of chlorine handling.
24.2.3.1 Determination of Required Chlorine Feed Rate
The required chlorine feed rate is determined for the system in pounds or kilograms per day as
chlorinator models are sized based on this. The chlorine feed rate is determined by defining the
parts per million of chlorine feed to the process water stream, the process water flow rate over a
24 hour period, and the number of hours per day chlorine will be fed. Sample calculations can be
found on the Industrial Water Treatment Community page. It is beneficial to determine the
instantaneous chlorine feed rate and the average chlorine feed rate, if applicable to the process.
The flow rates are included in the equipment specifications for vendor use in determining the
correct chlorinator model for the project.
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24.2.3.2 Determination of Required Chlorine Storage
Recommended chlorine dosing rates are discussed in Section 11.0. The amount of chlorine
required on-site is calculated to determine the type of chlorine container to have, the number of
containers required on site, and the number of containers required to be in operation
simultaneously to provide the required feed rate. The various dependable continuous discharge
rates are as follows and can also be found in Section 24.3, References:



The maximum dependable, continuous discharge rate of chlorine gas from a single
150 pound (68 kg) cylinder is approximately 1.5 lb/day/°F (1.1 kg/day/°C). This discharge
rate assumes an ambient temperature of at least 60° F (15° C) and natural air circulation.
The maximum dependable discharge rate for a ton container under similar conditions is
about 7.5 lb/day/°F (5.4 kg/day/°C).
The maximum amount of liquid chlorine withdrawal from a ton container is 400 lb/h
(182 kg/h).
The chlorine feed rate defined as pounds per day divided by the dependable continuous discharge
rate of chlorine gas (also in pounds per day) will give the number of containers needed
simultaneously to meet the required feed rate. The number of days of chlorine storage on-site is
also calculated to determine the overall number of containers required to be on-site. Fifteen to
thirty days of storage is optimal.
24.2.3.3 Determination of Chlorine Ejector Size
The chlorine ejector size is determined using ejector design curves included in equipment
manufacturer’s literature and the backpressure at the chlorine ejector and the required chlorine
solution feed rate. This is calculated by knowing the pressure at the process application point, the
difference between the elevation of the chlorine ejector and the process diffuser/injector, the
pressure drop across the diffuser, and friction loss due to piping and fittings between the injector
and the chlorine ejector.
24.2.3.4 Injection Water Booster Pump Sizing
The chlorine ejector requires a water source to mix and make the chlorine solution fed to the
process. A booster pump is typically required to meet the pressure requirements at the chlorine
ejector for the quantity of water dictated by the chlorine ejector size.
24.2.3.5 Piping, Valves, and Fittings
A pressure relief valve shall be located on the chlorine vacuum line within the vacuum regulator to
prevent gas pressurization of the chlorinator. This valve should be vented outdoors to a safe
location.
The piping upstream of vacuum regulators is carbon steel American Society for Testing and
Materials (ASTM) A105, seamless Schedule 80, and the piping downstream of vacuum regulators is
polyvinyl chloride (PVC) Schedule 80.
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24.2.3.6 Chlorine Leak Detection System
Chlorine gas leak detectors are needed for the chlorination equipment room and the chlorine
storage area. Each detection system should have a visual and audible alarm.
24.2.3.7 Equipment Location
Chlorination equipment should be located in a room separate from but adjacent to the chlorine
storage area. The storage area should be under cover in a well-ventilated location protected from
fire hazards and adequately protected from extreme weather conditions. If a room is provided for
container storage, local building code regulations require review because regulations vary
according to the local jurisdiction.
The layout should minimize the need to enter the storage area to adjust feed rates and minimize the
potential for equipment damage caused by chlorine leaks.
An example of a gas chlorination system layout is given on Figure 24-2.
24.3
References

White’s Handbook of Chlorination and Alternative Disinfectants, Fifth Edition, Black & Veatch
Corporation, John Wiley & Sons, Inc., 2010.



Hydro InstrumentsTM, Ton Container Manifolds for Gas Withdrawal Systems Design
Considerations Guideline, TCMGWS-DC, Rev. 2/3/14.
The Chlorine Institute, Inc., Pamphlet 1, Chlorine Basics, Edition 8, May 2014.
Wallace & Tiernan Chlorine Gas Feed Systems Brochure.
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25.0 On-Site Sodium Hypochlorite Generation and Feed System
25.1
Purpose and Applicability
This section provides design criteria for on-site hypochlorite generation and feed systems installed
in Black & Veatch power projects. This section provides recommendations as well as specific design
criteria for system sizing and design for this equipment.
25.2
Approach
This section is intended to be used as a basis for the design of an on-site hypochlorite generation
and feed system. It is important to note that this section should only be considered as a starting
point. Additional research on the treatment methods is warranted when a project will use a
hypochlorite generation system. On-site hypochlorite generation is also known as
electrochlorination.
25.2.1
Overview
On-site sodium hypochlorite generation systems produce sodium hypochlorite on-site by
electrolyzing sodium chloride in seawater or a brine solution.
25.2.2
Major Equipment and Appurtenances
25.2.2.1 Electrolytic Cell
The electrolytic cell is the principal component of the on-site sodium hypochlorite generation
system. Each electrolytic cell consists of compartments containing electrode plate pairs (cathode
and anode) vertically assembled to form an array of electrodes that serve as the flow path for the
dilute brine solution. As the brine solution flows between the electrode plates and is electrolyzed,
its concentration decreases, the sodium hypochlorite concentration increases, and hydrogen gas is
formed. The parallel back configuration facilitates hydrogen purge and minimizes scale. The
number of electrode plate pairs in the cell compartments can be adjusted to match the desired unit
capacity.
Within the electrolytic cell, the sodium chloride solution supports a current applied between the
positive electrode (anode) and negative electrode (cathode), thus electrolyzing the sodium chloride
solution. This results in chlorine (Cl2) gas being produced at the anode, while sodium hydroxide
(NaOH) and hydrogen (H2) gas are produced at the cathode. The chlorine further reacts with the
hydroxide to form sodium hypochlorite (NaOCl). The reactions are shown as follows:
At Anode
At Cathode
Overall
2Cl- + 2e2Na+ + 2H2O + 2e2NaCl + 2H2O
Cl2
2NaOH + H2
2NaOCl + 2H2
The system of electrolytic cells is called the generator. The generation process works on a constant
seawater/brine solution flow principle with a variable supply current to control the sodium
hypochlorite concentration. The chlorine equivalent (sodium hypochlorite) concentration attained
is a function of the electrolytic cell design and is directly proportional to the direct current passed
through the cells.
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A typical arrangement of this equipment is shown on Figure 25-1.
Figure 25-1
Typical Electrolytic Cell and Hydrogen Dilution Arrangement
25.2.2.2 Seawater Electrochlorination System Equipment
In a seawater electrochlorination system, seawater is directed across an electrolysis cell producing
a weak sodium hypochlorite solution and hydrogen gas as a byproduct. The sodium hypochlorite
product solution is typically 500 to 2,000 parts per million (ppm) concentration. The main
components of a seawater system are described in the following subsections. The amount of
system redundancy will depend on user preference; however, all major rotating equipment, such as
pumps, strainers, and blowers, should have redundancy.
25.2.2.2.1 Automatic Backwash Strainers
Automatic backwash strainers are required to protect downstream equipment from damage from
large suspended solids. The strainers should be automatic so they can be cleaned without requiring
operator attention.
25.2.2.2.2 Seawater Booster Pumps
Feedwater pressure below 40 pounds per square inch gauge (psig) (2.8 bar) is not normally
acceptable for reliable sodium hypochlorite generators. Booster pumps are required in the water
feed system to increase pressure to acceptable levels.
25.2.2.2.3 Seawater Sodium Hypochlorite Generator
There are two major manufacturers of seawater sodium hypochlorite generators: Evoqua
(purchased as Wallace & Tiernan) and Severn Trent De Nora. Evoqua (Wallace & Tiernan) offers
two different configurations of electrolytic cells: a bipolar concentric tubular electrode (CTE) cell
assembly and a bipolar parallel plate electrode (PPE) cell assembly. Severn Trent De Nora offers
three different configurations of electrolytic cells: bipolar electrolysis cells assembly placed in a
cylindrical electrolyzer body (SEACLOR), SANILEC-Plate Type, and electrolysis SANILEC-Tube Type.
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25.2.2.2.4 Transformer/Rectifier
The generators operate under constant seawater flow rate while the direct current is adjusted so
that the generation of chlorine instantaneously matches the demand. A rectifier converts the
alternating current supplied by the utility to the direct current used for electrolysis. Each generator
rack should have a dedicated rectifier sized to produce direct current for the associated generator.
25.2.2.2.5 Sodium Hypochlorite Storage Tank and Dilution Air Blowers
A product storage tank is located downstream of the generators to collect the hypochlorite solution
generated. The tank is also used to degas the electrolysis process. Air from dilution air blowers is
mixed with the hydrogen byproduct in the tank to dilute the hydrogen byproduct well below its
lower explosion limit (LEL) as the hydrogen byproduct is vented out of the tank.
A typical arrangement of this equipment is shown on Figure 25-2.
Figure 25-2
Typical Sodium Hypochlorite Bulk Storage and Metering Equipment Arrangement
25.2.2.2.6 Sodium Hypochlorite Solution Pumps
Sodium hypochlorite solution is delivered to the discharge point (typically the raw water intake
structure or cooling tower basin) by solution pumps. Diaphragm metering pumps are commonly
used in power plants.
25.2.2.2.7 Acid Cleaning Equipment
Sodium hypochlorite generator electrode cells require periodic acid cleaning to remove calcium
and magnesium scaling. Hydrochloric acid at a concentration ranging from 5 to 10 percent is
typically used for acid cleaning. Acid cleaning equipment includes a solution tank with mixer and a
recycle pump.
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25.2.2.3 Brine On-Site Hypochlorite Generation System
A brine on-site hypochlorite generation system combines salt, water, and electricity to produce
hypochlorite in the electrolytic cells. The sodium hypochlorite product solution is typically
0.8 percent by weight (8,000 ppm) concentration, with approximately 0.067 pound of available
chlorine per gallon (54.4 kilogramper cubic meter [kg/m3]).
A typical brine on-site sodium hypochlorite generation system schematic is shown on Figure 25-3.
A brine on-site hypochlorite generation system consists of brine preparation equipment and on-site
hypochlorite generation equipment.
The equipment downstream of the hypochlorite generators, which includes the sodium
hypochlorite storage tank, air blowers, and sodium hypochorite metering pumps, is the same as
required for the seawater electrochlorination system.
A brine on-site hypochlorite generation system starts with the preparation of a concentrated brine
solution by diluting sodium chloride salt stored in a brine maker/saturator tank with water to
make a 26.4 percent by weight sodium chlorine solution. The main components of a brine
preparation system are shown on Figure 25-3.
Figure 25-3
Typical Brine Preparation Equipment
25.2.2.3.1 Water Softener
A water softener is used to remove calcium and magnesium hardness from the brine dilution water
and sodium hypochlorite generator feedwater. Hardness in the water can develop into a hard scale
that reduces electrolytic cells efficiency, which increases their electricity demands. Scale also
inhibits flow through the cell and causes blockage so that sodium hypochlorite solution and
hydrogen byproduct cannot exit the cell. The water used for the saturator and dilution of the brine
solution should not exceed 17 mg/L as CaCO3 hardness. With this hardness level in the water, cell
cleaning is typically required every 6 months.
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25.2.2.3.2 Brine Saturator System
The brine saturator system consists of a storage tank, a brine saturator assembly, a dust collection
filter, a salt level indicator, and a brine level indicator. The tank shall be of fiberglass reinforced
plastic (FRP) construction. The tank is typically capable of making approximately 26.4 percent by
weight brine solution for feeding to on-site hypochlorite generators and also regeneration of water
softeners. A water spray distribution system shall be provided for the inlet water. A liquid level
control system shall be provided to maintain the liquid level in the tank. The tank includes a
pneumatic dust suppression system. A brine saturator tank installed outdoors where temperature
is lower than 32° F (0° C) should be provided with heating pads and pipe heat tracing.
25.2.2.3.3 Soft Water Heater/Soft Water Chiller
Sites with a feedwater temperature below 65° F (18° C) may require a soft water heater. Sites with
a feedwater temperature over 80° F (27° C) may require a soft water chiller. To get the most
efficient operation from on-site electrolytic cells, the cell feed temperature and the temperature rise
through the cell are best controlled between 60° F (15° C) and 95° F (35° C).
25.2.2.3.4 Brine Metering
Brine solution from the brine saturator system is fed to the hypochlorite generator by using an
eductor system or by metering pumps.
The saturated brine, approximately 26.4 percent by weight, from the brine saturator system is
diluted at the electrolytic cell skid to the brine solution concentration of 2.5 percent to 3 percent by
weight, which is the optimal brine concentration for electrolysis.
25.2.2.3.5 Brine Solution Hypochlorite Generator
There are two major manufacturers of brine solution hypochlorite generators: Evoqua (Wallace &
Tiernan) and Severn Trent De Nora. Evoqua (Wallace & Tiernan) offers on-site electrolytic
chlorination (OSEC®). Severn Trent De Nora offers ClorTec®.
25.2.2.3.6 Transformer/Rectifier
The generators operate under constant makeup water flow rate while the direct current is adjusted
so that the generation of chlorine instantaneously matches the demand. A rectifier converts the
alternating current supplied by the utility to the direct current used for electrolysis. Each generator
rack should have a dedicated rectifier sized to produce direct current for the associated generator.
25.2.2.3.7 Sodium Hypochlorite Storage Tank and Dilution Air Blowers
A product storage tank is located downstream of the generators to collect the hypochlorite solution
generated. The tank is also used to degas the electrolysis process. Air from dilution air blowers is
mixed with the hydrogen byproduct in the tank to dilute the hydrogen byproduct well below its
lower explosion limit (LEL) as the hydrogen byproduct is vented out of the tank.
A typical arrangement of this equipment is shown on Figure 25-2.
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25.2.3
On-Site Hypochlorite Generation System Safety Requirements
Electrolysis of sodium chloride solution generates hydrogen gas. Hydrogen gas is a safety hazard
because of its flammability and explosiveness limit. The generation of hydrogen gas requires special
equipment to dilute and vent it to the atmosphere to keep the concentration below 4 percent (the
LEL threshold). Most installations require special diluting and degassing equipment as specify in
Subsections 25.2.2.2.5, and 25.2.2.3.7.
To reduce the likelihood of accumulation of large volumes of hydrogen gas in electrolyzer cells,
electrolyzers should remove hydrogen at the point of generation. Diluted sodium hypochlorite and
hydrogen gas should leave the sodium hypochlorite generator in 2 percent inclined, non-isolating,
straight outlet piping to avoid hydrogen traps along the lines to the sodium hypochlorite product
tank. Standpipes, downward sloped piping, or isolation valves (unless outfitted with position
switch) are not recommended. At the hypochlorite storage tank, forced air blowers and pressure
differential switches are used to safely ensure that hydrogen gas is being force vented from the
process to atmosphere.
25.2.3.1 Hazardous Area Classification
The areas adjacent to hypochlorite generation equipment and degassing/sodium hypochlorite
storage tank(s) do not have to meet Class 1, Division 1 and /or Class 1, Division 2 requirements of
the National Electrical Code when the following systems are installed:


The hypochlorite generation equipment building is designed to have a proper ventilation
system. Emergency or standby power is required for a high rate ventilation system.
An hydrogen detection monitor with alarm is provided in the hypochlorite generation
equipment building and at the sodium hypochlorite storage tank.
25.2.3.1.1 Codes and Standards
NFPA 70 Section 500.5 (B)(1) is referenced as evidence of acceptability of the clarification
confirmation. Class I, Division 1 rating does not apply to a hypochlorite generation equipment
building and a degassing/sodium hypochlorite storage tank for the following reasons:



Ignitable concentration of hydrogen does not exist under normal operating conditions.
Ignitable concentration of hydrogen does not exist frequently because of repair or
maintenance.
If hydrogen gas is released in an accident, it will not cause electrical equipment failure.
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NFPA 70 Section 500.5.(B)(2) is referenced as evidence of acceptability of the clarification
confirmation. Class I, Division 2 rating does not apply to a hypochlorite generation equipment
building and a degassing/sodium hypochlorite storage tank for the following reasons:

The Lower Explosive Limit (LEL) of hydrogen is 4 percent by volume; therefore, hydrogen
gas is flammable only when its concentration in air is above 4 percent by volume. The
degassing/sodium hypochlorite storage tank is designed to dilute hydrogen to lower than
1 percent by volume, and the tank is also located outside the building.
In the hypochlorite generation equipment building (in the event of an accident), the outside
air ventilation system will pull hydrogen air from the building and replace it with outside
air. The building HVAC system must be designed to perform air exchanges at a rate that
maintains hydrogen level below 1 percent.
In addition, the sodium hypochlorite generation system has an emergency stop. Once an
accident or abnormal operation conditions occur, sodium hypochlorite and hydrogen
production immediately stops. Therefore, only the hydrogen contained in the system would
be released and no additional hydrogen is produced.

The sodium hypochlorite generation equipment is designed to increase the safety of the
system and prevent equipment rupture. The greatest risk of rupture is at the hypochlorite
generators. The hypochlorite generators must be provided with temperature switch, level
switches, and flow switches. These three switches provide protection against an abnormal
condition that could damage the sodium hypochlorite generator cells. Once these functions
reach a factory setpoint, an alarm is activated and the entire sodium hypochlorite
generation system shuts down.
Ignitable concentrations of hydrogen gas are not normally prevented by positive
mechanical ventilation. Ignitable concentrations of hydrogen are only prevented in the
event of an accident.
25.2.3.2 Hydrogen Leak Detector
As a minimum, hydrogen detectors must be installed to continuously monitor the level of hydrogen
in the hypochlorite generation building, and in the hydrogen release tank exhaust air (sodium
hypochlorite storage/degassing tank). A detector must be provided for each tank. Detection of a
high hydrogen concentration shall be alarmed on the system control panel and detection of a highhigh hydrogen concentration shall shut down the system power supply. Monitoring and alarming of
hydrogen detection system should be displayed on both local control panel and main plant DCIS.
Alarm LED and audible alarm horn should be provided.
25.2.3.3 Equipment Location
The hypochlorite generator equipment should be under cover in a well-ventilated location
protected from fire hazards and adequately protected from extreme weather conditions. The
building HVAC system design must include provisions for the removal of hydrogen gas from the
hypochlorite generation equipment building in case of an accidental release. The provisions include
the use of outside air to dilute the hydrogen concentration to a level below the LEL for hydrogen
(4 percent by volume).
Degassing/sodium hypochlorite storage tank is recommended to be located outdoors.
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25.2.3.4 Hypochlorite Generator Equipment Building HVAC System
The HVAC system design for the hypochlorite generator equipment building must include
provisions for the removal of hydrogen gas from the building in case of an accidental release. The
provisions include the use of outside air to dilute the hydrogen concentration to a level below the
LEL for hydrogen (4 percent by volume).
If the building is air conditioned using a system that re-circulates air within the space, a high rate
ventilation system should be installed. The high rate ventilation system should consist of an exhaust
fan and inlet louver. Operation of the high rate fan should be controlled through the hydrogen
alarm system.
If the building is ventilated using outside air to maintain the space temperature, this general
ventilation system may also be used as the high rate ventilation system. If the general ventilation
system size is sufficient, the operation of the system should also be controlled through the
hydrogen alarm system in addition to normal temperature controls. If the room ventilation system
size is not sufficient, a second high rate system should be included to supplement the building
ventilation system.
25.2.3.4.1 Standby or Emergency Power for HVAC System
Standby or emergency power should be provided for the high rate ventilation system. The decision
to provide standby power or emergency power for the HVAC system must be decided on a case-bycase basis and should be discussed with the electrical design engineer.
25.2.4
On-Site Hypochlorite Generation System Design
25.2.4.1 Seawater
The chlorination rate is determined on the basis of the flow rate of the water stream to be treated
and the dosage rate. The sodium hypochlorite production flow rate required is calculated using the
required chlorination rate and the sodium hypochlorite product concentration.
1.
2.
Required chlorination rate (Cl2) = Water stream flow rate * dosage rate (ppm).
Hypochlorite feed rate (NaOCl solution) = Required chlorination rate * sodium
hypochlorite production concentration (ppm).
The sodium hypochlorite feed pumps and storage tank sizing calculations can then be done.
It is also helpful to do a utility usage calculation for the hypochlorite generator to determine the
required amount of seawater and electricity. The power consumption required for the entire
treatment and feed system should be calculated and shared with the electrical engineers as soon as
possible so they can include it in their initial power feed plan.
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The seawater system design should use the following design information:



The sodium hypochlorite product solution can vary between 500 to 2,000 ppm
concentration.
Energy consumption is approximately 2.0 kilowatt-hour per pound (kWh/lb) of chlorine
(4.4 kWh/kg of chlorine) to 2.5 kWh/lb of chlorine (5.5 kWh/kg of chlorine).
Sodium hypochlorite solution product pipeline should be sloped 2 percent upward to the
sodium hypochlorite storage tank.
25.2.4.2 Brine
The brine system design is similar to the seawater system with the following design information:



The sodium hypochlorite product solution is typically 0.8 percent by weight (8,000 ppm)
concentration, with approximately 0.067 pound of available chlorine per gallon
(54.4 kg/m3). The density of the solution is approximately 8.44 lb/gal (1,012 kg/m3).
Salt consumption is approximately 2.8 pounds salt per pound of chlorine (2.8 kg salt/kg of
chlorine) to 3.5 pounds salt per pound of chlorine (3.5 kg salt/kg of chlorine).
Energy consumption is approximately 2.0 kWh/lb of chlorine (4.4 kWh/kg of chlorine) to
2.5 kWh/lb of chlorine (5.5 kWh/kg of chlorine).

The brine demand for water softener regeneration is approximately 15 lb/ft3 (240 kg/m3)
of resin and may vary depending on the resin manufacturer.
25.3
References

Sodium hypochlorite solution product pipeline should be sloped 2 percent upward to the
sodium hypochlorite storage tank.
1.
White’s Handbook of Chlorination and Alternative Disinfectants, Fifth Edition, Black &
Veatch Corporation, John Wiley & Sons, Inc., 2010.
3.
Leonard W. Casson and James W. Bess, Jr.,”On-Site Sodium Hypochlorite Generation”
Proceedings of the Water Environment Federation, WEFTEC 2006, University of
Pittsburgh, Pennsylvania, 2006.
2.
4.
5.
ClorTec On-Site Sodium Hypochlorite Generation, Severn Trent De Nora.
NFPA 70. National Electric Code, 2017 Edition.1.04, Section 500.5 (B)(1) and
Section 500.5 (B)(2).
Evoqua On-Site Electrolytic Chlorination Skid-Mounted OSEC B-Pak System.
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